California Wildfires—Insurance Tips for Policyholders
The recent wildfires in California have clearly had a catastrophic impact, destroying a vast number of homes and business premises across the region. Homeowners and businesses may have limited means to protect against nature’s forces, but, in this alert, we provide tips on steps that can be taken to protect against denials of coverage by insurers. Careful and proactive attention to insurance coverage considerations could be the key to restoring homes and business operations and weathering the financial storms that follow from such disastrous events.
Potentially Relevant Insurance Policies
It is vital for affected homeowners and businesses to review all relevant or potentially relevant insurance policies promptly, including excess-layer policies, and to comply with loss notification procedures. The most common source of coverage for most individuals and businesses is likely to be first-party property coverage insuring the damaged premises and other assets, including against the risk of fire, smoke, and related damage. In many cases, this insurance will be supplemented by specialty coverages that apply to specific situations.
For businesses, the coverage will typically include the following:
Property damage where losses are caused to the business premises and assets, including computers and machinery.
Business interruption (BI) where the business experiences loss of earnings or revenue due to property damage or loss of use caused by an insured peril, for a specified period of time after the insured event or until normal business operations have been resumed.
Contingent BI which generally covers loss of revenue arising from damage to the property of a supplier, customer, or other business partner.
Denial of access, where use or access to the insured property is prevented or restricted for a specific period of time, for example, if roads or bridges leading to the property have been blocked or destroyed.
Civil authority coverage, which covers losses arising from an order made by a civil or government authority that interferes with normal business operations.
Service interruption coverage, which typically covers the insured for losses related to electricity or interruption of other utilities or supplies.
Extra expense incurred to enable business operations to be resumed or to mitigate other losses.
When presenting an insurance claim, it is important that policy provisions are considered against the backdrop of potentially applicable insurance coverage law to ensure that the policyholder is taking the steps necessary to maximize coverage. Many property policies are written on an “all risks” basis, but there will typically be exclusions, sublimits, or restrictions applicable to certain perils or circumstances. Some coverages may be subject to different policy limits and policy deductibles that impact the amount of coverage available. A proper analysis of the policy wording is vital to enable the insured to take full advantage of the coverage provided.
Practical Tips to Maximize Coverage
There are several steps policyholders should consider when making an insurance claim arising from natural disasters like the California fires:
Be Proactive in Notifying Insurers
Most policies identify specific procedures to be followed in presenting a claim, and there are likely to be timing deadlines associated with them. Failure to comply may result in insurers seeking to restrict or deny coverage for a claim otherwise covered by the policy. Policyholders should carefully consider any notice requirements, including any clause allowing for notice of a loss or an event that may or is likely to give rise to a claim. Prompt notification may assist policyholders in securing early access to loss mitigation resources and related coverages.
Early Assessment of Coverage
There are significant benefits in evaluating coverage at an early stage to understand any issues that may impact the way in which the claim is presented. Consultation with experienced coverage lawyers will assist in identifying and analyzing responsive policies as well as anticipating coverage issues or exclusions insurers might seek to rely upon.
Collate and Preserve Relevant Documents
Insurers typically require proof of loss and damage along with extensive supporting documentation. It is critical to take steps early on to ensure that potentially relevant documents and electronic records are located and preserved. In particular, insurers may argue that some part of the revenue loss is attributable to other causes, such as poor business decisions or economic downturn, such that historical records often must be examined and relied upon.
Preparation of Proof of Loss
The preparation of a detailed inventory and proof of loss is a time-consuming and challenging process but can prove invaluable in seeking to challenge any settlement offers made by the insurers or any loss adjustors appointed on their behalf. Many commercial policies include claim preparation coverage, which covers costs associated with compiling a detailed claim submission. The appointment of independent loss assessors or forensic accountants can prove particularly beneficial for collating BI losses, which are often challenged by insurers. For example, insurers may adopt a narrow view of what constitutes “interruption” to the business, particularly where certain business activities are ongoing.
Advance Payments
Any delays by insurers in making appropriate and periodic payments will delay the rebuilding of premises and the resumption of business operations. Insureds should consider requests for interim or advance payments, prior to completion of the loss adjustment process, particularly if the policy expressly provides for this.
Evaluating and Challenging Insurer Positions
The validity of any coverage defenses or limitations raised by insurers will be impacted by the precise wording of the insurance contract and by the applicable governing law. Experienced coverage counsel will be able to assist an insured in assessing the merit and viability of any coverage issues raised by insurers, or by their appointed loss adjusters, and in maximizing the insured’s potential recovery.
New U.S. Sanctions Targeting Russia’s Energy Sector
On Jan. 10, 2025, the U.S. Department of Treasury announced several new types of sanctions that will affect U.S. and global service providers to the Russian energy sector.
The first of these sanctions will prohibit U.S. persons, including U.S. persons located abroad, from providing petroleum services to any person located in Russia. The Treasury Department’s Office of Foreign Assets Control (OFAC) plans to issue regulations defining “petroleum services,” but they are likely to include services related to exploration, drilling, well completion, production, refining, processing, storage, maintenance, transportation, purchase, acquisition, testing, inspection, transfer, sale, trade, distribution, or marketing of crude oil and petroleum products.
These sanctions will enter into effect on Feb. 27, 2025, so U.S. persons have a limited time to wind down affected transactions.
In addition, the U.S. Secretary of the Treasury issued a determination under Executive Order 14024 that authorizes imposing economic sanctions on any person – whether U.S. or non-U.S. – that is subsequently determined to be operating in the Russian energy sector. OFAC plans to define the “energy sector of the Russian Federation economy” to encompass not just petroleum products, but also natural gas, biofuels, coal, nuclear and other renewable energy.
This determination has broad extraterritorial implications, because it exposes non-U.S. entities to potential sanctions. As a preview, OFAC simultaneously used the determination to impose sanctions on Russia’s major oil companies, Gazprom Neft and Surgutneftegas. However, the determination could be used to impose sanctions on entities from any country that operate in the Russian energy sector.
“The United States is taking sweeping action against Russia’s key source of revenue for funding its brutal and illegal war against Ukraine . . . With today’s actions, we are ratcheting up the sanctions risk associated with Russia’s oil trade, including shipping and financial facilitation in support of Russia’s oil exports.”
home.treasury.gov/…
Treasury Department and IRS Release Final Regulations for Section 45V Clean Hydrogen Production Tax Credit
On January 3, 2025, the Treasury Department and the Internal Revenue Service issued final regulations under Internal Revenue Code (Code) Section 45V (the Final Regulations) with respect to credits for the production of clean hydrogen (the 45V Credit). The Final Regulations generally retain the requirements set forth in the proposed regulations under Code Section 45V (the Proposed Regulations)[1] with respect to the “three pillars” (incrementality, temporal matching and deliverability) for hydrogen produced using clean power but provide leniency with respect to each pillar. The Final Regulations also provide critical new guidance on hydrogen produced using methane reformation technologies. Taxpayers may rely on the Final Regulations as of January 10, 2025.
Background
Code Section 45V provides a tax credit for the production of clean hydrogen at a qualified clean hydrogen production facility for 10 years beginning on the date the facility is placed in service. The 45V Credit is technology agnostic in that qualification for the credit is not dependent on how the clean hydrogen is produced. The 45V Credit is generally calculated as the product of the kilograms of qualified clean hydrogen produced at a qualified clean hydrogen production facility and the applicable rate. The applicable rate is based on the lifecycle greenhouse gas (GHG) emissions rate of the hydrogen production process. Taxpayers qualify for an increased 45V Credit amount if the construction, alteration and repair of the qualified clean hydrogen production facility complies with the prevailing wage and apprenticeship requirements.
Electricity Used in Hydrogen Production
The Final Regulations generally retain the requirements of the three pillars set forth in the Proposed Regulations regarding the utilization of energy attribute certificates (EACs) to establish a GHG emissions rate. As compared to the Proposed Regulations, the Final Regulations provide leniency with respect to each pillar.
Incrementality. The incrementality requirement is met if the electricity generating facility that produced the electricity has a commercial operation date, or increase in rated nameplate capacity, no more than 36 months before the relevant hydrogen production facility was placed in service. The Final Regulations include three new sources of electricity generation that will be considered incremental regardless of whether the 36-month requirement is satisfied: (i) electricity generated at certain nuclear facilities (with a cap of 200 megawatt-hours per operating hour per reactor); (ii) electricity generated in states with GHG emissions policies meeting certain criteria (such as California and Washington); and (iii) electricity generated at a facility that added carbon capture and sequestration (CCS) equipment within 36 months prior to the date the hydrogen production facility is placed in service.
Temporal Matching. The temporal matching requirement is met if the electricity is generated (i) until 2030, in the same year as, or (ii) beginning in 2030, in the same hour as, the taxpayer’s hydrogen production facility uses electricity to produce hydrogen. The Proposed Regulations provided that hourly matching described in clause (ii) would be required beginning in 2028.
Deliverability. The deliverability requirement is met if the electricity is generated by a facility in the same region as the hydrogen production facility. The Final Regulations provide flexibility for demonstrating certain electricity transfers between regions and allow taxpayers to import clean power from other regions under certain circumstances.
Methane Used in Hydrogen Production
The Final Regulations provide rules for how taxpayers can claim the 45V Credit for hydrogen produced using methane reformation technologies, including those using CCS, renewable natural gas (RNG) and fugitive sources of methane (e.g., from wastewater, animal waste, landfill gas and coal mine operations). The Final Regulations provide rules on how to calculate lifecycle GHG emissions from these sources.
Alternative Fate Standard. The Final Regulations do not include a “first productive use” requirement contemplated by the Proposed Regulations, which would require hydrogen produced using RNG and coal mine methane systems to originate from the first productive use. Instead, the Final Regulations take into account the “alternative fate” of feedstocks.
Gas EACs. The Final Regulations introduce the “gas energy attribute certificate” (Gas EAC), which is defined as a tradeable contractual instrument, issued through a qualified Gas EAC registry or accounting system, that represents the attributes of a specific unit of RNG or coal mine methane. Hydrogen producers using RNG or coal mine methane will be able to acquire and retire Gas EACs as a mechanism for establishing such sources were used in the production of clean hydrogen.
Temporal matching and deliverability requirements similar to those described in the context of hydrogen produced using electricity apply to Gas EACs. The Final Regulations require monthly matching for a Gas EAC to satisfy the temporal matching requirement, and require geographic matching within the contiguous United States to satisfy the deliverability requirement.
Book-and-Claim. The Final Regulations endorse a book-and-claim framework for hydrogen produced using RNG or coal mine methane systems. Book-and-claim systems will enable taxpayers to claim use of RNG or coal mine methane despite the absence of a direct exclusive pipeline connection to a facility that generates RNG or from which fugitive methane is being sourced. Taxpayers will be able to begin using book-and-claim systems no earlier than in 2027, after the Secretary of Treasury determines when a system meets the requirements set forth in the Final Regulations.
GREET Model
The Final Regulations require that lifecycle GHG emissions be measured “well-to-gate” as determined under the most recent Greenhouse gases, Regulated Emissions, and Energy use in Technologies (GREET) model. Well-to-gate emissions are the aggregate lifecycle GHG emissions related to the hydrogen produced at the hydrogen production facility during the taxable year through the point of production. Well-to-gate emissions include emissions associated with feedstock growth, gathering, extraction, processing and delivery to a hydrogen production facility.
The Final Regulations allow hydrogen producers to use the version of the 45VH2-GREET model that was in effect when the hydrogen production facility began construction for the duration of the credit. This provision enhances investment certainty by ensuring that hydrogen producers are not subject to unexpected changes to the 45VH2-GREET model over the credit period.
The Final Regulations provide that upstream methane leakage rates will be based on default national values in the 45VH2-GREET model. Future releases of the 45VH2-GREET model, however, are expected to incorporate facility-specific upstream methane leakage rates based on data provided by the Environmental Protection Agency.
[1] We discussed the Proposed Regulations in a previous client alert.
Environmental Developments to Watch in California in 2025
Contaminants of Concern
Perfluoroalkyl and polyfluoroalkyl substances (PFAS)
In September 2024, California’s legislature enacted two new bills restricting the use of PFAS in consumer products.
AB 347 – This statute gives California’s Department of Toxic Substances Control (DTSC) enforcement authority over existing PFAS restrictions on textile articles (AB 1817), juvenile products (AB 652), and cookware and food packaging (AB 1200) (the “covered products” under the “covered PFAS restrictions”). AB 347 also requires manufacturers of covered products to submit a registration to DTSC by July 1, 2029, pay a registration fee, and submit a statement of compliance to DTSC confirming that each covered product complies with the covered PFAS restriction on the sale or distribution of the product that contains regulated PFAS. DTSC will begin enforcing this legislation after July 1, 2030. Given DTSC is the enforcement authority for the above-mentioned covered products, we expect DTSC to release guidance on interpreting AB 1817, AB 652, and AB 1200 in the future.
AB 2515 – This statute prohibits companies from manufacturing, selling, or distributing menstrual products that contain regulated PFAS. “Regulated PFAS” means PFAS “intentionally added to a product” as of January 1, 2025, and will mean “PFAS in a product at or above a limit determined by the department” beginning January 1, 2027. Like AB 347, AB 2515 requires manufacturers to register with DTSC by July 1, 2029, pay a registration fee, and submit a statement of compliance confirming that menstrual products do not contain regulated PFAS.
We expect DTSC to initiate the rulemaking process for both statutes, which would include regulations regarding accepted testing methods for PFAS levels in menstrual products and third-party laboratory accreditations, and regulations to implement, interpret, and enforce the statutes. Both statutes require DTSC to adopt these regulations before January 1, 2029.
Proposition 65
California’s Safe Drinking Water and Toxic Enforcement Act of 1986, Health & Safety Code Section 25249.5 et seq. (“Proposition 65”) prohibits persons in the course of doing business from knowingly and intentionally exposing individuals to certain listed chemicals above a safe harbor level, where one exists, without first providing a “clear and reasonable” warning to such individuals. (Health & Safety Code § 25249.6). The law applies to consumer product exposures, occupational exposures, and environmental exposures that occur in California. Presently, there are approximately 900 listed chemicals known by the State of California to cause cancer, reproductive harm, or both.
In 2025, we will continue to see developments in the implementation and enforcement of this law, of which manufacturers and retailers selling products in California should be aware.
Vinyl Acetate
On December 19, 2024, the Office of Environmental Health Hazard Assessment’s (OEHHA) Carcinogenic Identification Committee (CIC) voted to list vinyl acetate as a carcinogen under Proposition 65. Vinyl acetate is primarily used in glues, plastics, paints, paper coatings, and textiles. Exposure to the chemical can occur through dermal contact, inhalation, or ingestion.
Vinyl acetate was listed despite industry groups claiming that none of the recognized Proposition 65 authoritative bodies consider the chemical to be a carcinogen. OEHHA published evidence of the carcinogenicity of vinyl acetate, which was used by the CIC to support the listing.
Once listed, businesses have 12 months to provide any required warnings.
Warning Labels
Safe harbor regulations provide examples of long-form and short-form warnings deemed “clear and reasonable,” which, if followed, offer businesses an affirmative defense in the event of enforcement. On December 6, 2024, OEHHA amended Proposition 65 to require companies to add at least one chemical name—or the name of two chemicals, if the warning covers both cancer and reproductive toxicity, unless the same chemical is listed for both endpoints—to the short-form warning on the product label for products manufactured and labeled after January 1, 2028. For example:
“[the warning symbol] WARNING: Cancer risk from exposure to [name of chemical]. See www.P65Warnings.ca.gov.”
OEHHA has authorized the continued used of the earlier short-form warning template (that does not name the chemical) for products manufactured and labeled before January 1, 2028:
“[the warning symbol] WARNING: Cancer – www.P65Warnings.ca.gov.”
Manufacturers and retailers selling products in California containing listed chemicals should review their product labeling protocols, as non-compliance may result in an enforcement action. Some manufacturers have employed generic short-form warnings to forestall enforcement actions without determining whether their products actually exposed consumers to listed chemicals. This practice will not be effective after 2027.
Amended Acrylamide Warning Label
On January 1, 2025, OEHHA’s amendments to acrylamide warning label requirements took effect. The new regulation provides:
Warnings must now contain either:
“WARNING”
“CA WARNING”; or
“CALIFORNIA WARNING.”
The warning must be followed by either:
“Consuming this product can expose you to acrylamide;” or
“Consuming this product can expose you to acrylamide, a chemical formed in some foods during cooking or processing at high temperatures.”
The warning must also be followed by at least one of the following:
“The International Agency for Research on Cancer has found that acrylamide is probably carcinogenic to humans;”
“The United States Environmental Protection Agency has found that acrylamide is likely to be carcinogenic to humans;” or
“The United States National Toxicology Program has found that acrylamide is reasonably anticipated to cause cancer in humans.”
The warning may be followed by one or more of the following:
“Acrylamide has been found to cause cancer in laboratory animals”;
“Many factors affect your cancer risk, including the frequency and amount of chemical consumed”’ or
“For more information including ways to reduce your exposure, see www.P65Warnings.ca.gov/acrylamide.”
The newly amended warning language comes after years of ongoing litigation alleging that the previous warning mandate violated the First Amendment (California Chamber of Commerce v. Rob Bonta (2:19-cv-2019 DJC JDP)). Challengers allege that the warning remains unconstitutional as the state has failed to show that the warnings are purely factual and uncontroversial. As described below, the First Amendment is proving to be an effective defense in some circumstances.
Litigation Update: The Personal Care Products Council vs. Rob Bonta
In recent years, the First Amendment has served as a powerful tool for companies subject to Proposition 65 labeling requirements. A 2025 ruling in The Personal Care Products Council vs. Rob Bonta (2:23-cv-01006) will determine the legality of warning labeling requirements regarding titanium dioxide in consumer products. In 2025, the U.S. District Court for the Eastern District of California is poised to rule on the parties’ motions in the case. If the Court grants the Personal Care Products Council’s (PCPC) summary judgment motion, the ruling will have far-reaching impacts on the enforcement of Proposition 65, bolstering the First Amendment defense to Proposition 65 claims where there is a reasonable scientific debate about the hazards of the listed chemical.
The action was brought in 2023 by PCPC a non-profit association of businesses in the cosmetic and personal care products industry, which sued California Attorney General Rob Bonta in his official capacity.
On June 12, 2024, the District Court issued an Order granting PCPC’s request for a preliminary injunction enjoining Bonta and all private enforcers of Proposition 65 from filing new lawsuits to enforce the law’s warning requirement for exposures to titanium dioxide. The District Court agreed with PCPC that the “Prop 65 warning requirements for Listed Titanium Dioxide are not purely factual because they tend to mislead the average consumer” since the warnings may convey a “false and/or misleading message that Listed Titanium Dioxide causes cancer in humans or will increase a consumer’s risk of cancer.” This, according to the District Court, renders PCPC likely to prevail on the merits of its First Amendment claim under Zauderer v. Off. of Disciplinary Couns. of Supreme Ct. of Ohio, 471 U.S. 626 (1985) (government may compel commercial speech so long as it is reasonably related to substantial governmental interest, purely factual, noncontroversial, and not unjustified or unduly burdensome).
PCPC’s pending summary judgment motion was filed on September 10, 2024. If granted, this will be the third case successfully challenging Proposition 65 warnings on First Amendment grounds, with previous cases involving designated glyphosate and acrylamide. See Nat’l. Assoc. of Wheat Growers v. Bonta, 85 F.4th 1263 (9th Cir. 2023); Cal. Chamber of Comm. v. Bonta, 529 F. Supp. 3d 1099 (E.D. Cal. 2021).
Here, the District Court’s June 12, 2024 ruling dramatically halted the prosecution of countless pending claims against cosmetic companies and retailers of cosmetics. A favorable ruling for PCPC in 2025 may embolden companies subject to Proposition 65 requirements to bring an array of constitutional challenges with respect to other designated chemicals, specifically businesses selling products containing a designated chemical where the underlying scientific basis for its designation is controversial. The District Court’s language strongly casts doubt on the constitutionality of “misleading” Proposition 65 labels that lack an adequate scientific basis.
Extended Producer Responsibility (EPR) and Recycling
California continues to pave the way for EPR laws that affect various products. Rulemaking efforts will continue through 2025.
AB 863 – Carpets
Governor Newsom approved AB 863 on September 27, 2024, governing carpet recycling in California. California enacted its first carpet stewardship law in 2010 and has since amended it multiple times. The latest law maintains several basic facets and updates the governance structure of California’s current carpet stewardship program but nominally converts it to a carpet producer responsibility program following the expiration of the current 2023-2027 five-year carpet stewardship plan. The new law punts many specifics of the new program to the discretion of CalRecycle, including performance standards and metrics, key definitions, deadlines, and grounds for approving or revoking an approved plan. CalRecycle must adopt implementing regulations effective no earlier than December 31, 2026. The law purports to deem CalRecycle’s adopted “performance standards” as immune from judicial review under the California Administrative Procedure Act. The law also calls for certain amendments to the existing carpet stewardship plan to be proposed and adopted sooner.
The new law requires all carpet producers doing business in California to form and register with a single producer responsibility organization (PRO). The law requires the PRO to develop a producer responsibility plan for the collection, transportation, recycling, and safe and proper management of covered products in California, along with related public outreach regarding the plan; review the plan at least every five years after approval; and submit annual reports to CalRecycle. An approved plan must be in place within 24 months of the effective date of CalRecycle’s regulations under the new law, which may result in a deadline as early as December 31, 2028. All reports and records must be provided to CalRecycle under penalty of perjury. The law restricts public access to certain information collected for the purpose of administering this program.
The PRO must establish and provide a covered product assessment to be added to the purchase price of a covered product sold in the state by a producer to a California retailer or wholesaler or otherwise sold for use in the state. Each retailer and wholesaler is then required to add the assessment to the purchase price of all covered product sold in the state. This assessment of carpet sales in California parallels existing law. The new law does not specify any other available funding methods for implementing its requirements. The new law also requires the PRO to pay fees to CalRecycle, not to exceed CalRecycle’s actual and reasonable regulatory costs to implement and enforce the program. It further newly requires all carpet sold in California to contain 5% of post-consumer recycled carpet content by 2028, and grants CalRecycle authority to set new rates for 2029 and beyond.
Additionally, the new law requires carpet producers to provide additional information to CalRecycle regarding California carpet sales and compliance with the requirements of an approved plan. CalRecycle must post on its website a list of producers that are in compliance with the requirements of the program. The existing carpet stewardship plan must be amended to allocate 8% of collected assessments to unions for apprenticeship program grants. Compared to current law, penalties for violations increase from $5,000 per day to $10,000 per day, and from $10,000 per day to $25,000 per day if the violation is intentional, knowing, or negligent. CalRecycle may audit a carpet stewardship organization and individual producers annually The law also clarifies that a carpet stewardship organization cannot delegate decision-making responsibility regarding a carpet stewardship plan to a person who is not a member of the organization’s board.
SB 707 – Textiles
In September 2024, California’s legislature enacted the first, and only current, statewide EPR textile program in the U.S. with the Responsible Textile Recovery Act of 2024. The Act requires qualified producers of apparel or textile articles to form and join a PRO that CalRecycle will approve by March 1, 2026. All eligible producers must join the PRO by July 1, 2026. Once formed, the PRO must submit a statewide plan for the collection, transportation, repair, sorting, recycling, and the safe and proper management of covered clothing and textiles to CalRecycle for review. Once the plan is approved, retailers, importers, distributors, and online marketplaces will not be permitted to sell, distribute, offer for sale, or import a covered product into the state unless the producer of the covered product is listed as in compliance. The PRO will charge each participant-producer annual fees for its operation.
By July 1, 2030, or upon approval of the plan, whichever occurs first, noncompliant producers of covered products will be subject to administrative civil penalties up to $50,000 per day.
The Act directs CalRecycle to adopt regulations to implement its provisions with an effective date of no earlier than July 1, 2028. The rulemaking process will be carried out in accordance with California’s Administrative Procedure Act, which provides opportunities for the public, including industry representatives, to shape the policy going forward. Rulemaking efforts associated with SB 707 are not yet listed on CalRecycle’s website, but given the short deadlines imposed by the Act, we can expect updates in the near future.
AB 187 – Mattresses
California’s legislature established the Used Mattress Recovery and Recycling Act (Mattress EPR Act) in 2013 and most recently updated it in 2019. The Mattress EPR Act, which CalRecycle administers, applies to manufacturers, renovators, distributors, and retailers that sell, offer for sale, or import a mattress into California. At least once every five years, the mattress recycling organization reviews the plan for the recovery and recycling of used mattresses and determines whether amendments are necessary. Each year, CalRecycle, through the Mattress Recycling Council, posts lists of compliant manufacturers, renovators, and distributors on its website. If the manufacturer, brand, renovator, or distributor is not on this list, no retailer or distributor may sell a mattress in the state until the department affirms they are in compliance.
CalRecycle may impose an administrative civil penalty of not more than $500 per day on any manufacturer, mattress recycling organization, distributor, recycler, renovator, or retailer violating the Mattress EPR Act. However, if the violation is intentional, knowing, or reckless, the department may impose an administrative civil penalty of not more than $5,000 per day.
SB 551 – Beverage Containers
SB 551, or the California Beverage Container Recycling and Litter Reduction Act, took effect on September 29, 2024 as an urgency statute, necessary for the immediate preservation of the public peace, health, or safety within the meaning of Article IV of the California Constitution. Plastic beverage containers sold by a beverage manufacturer must contain a specified average percentage of post-consumer recycled plastic per year. Manufacturers of beverages sold in a plastic beverage container subject to the California Redemption Value fee must report to CalRecycle certain information about the amounts of virgin plastic and post-consumer recycled plastic used for those containers for sale in California in the previous calendar year. The law authorizes certain beverage manufacturers to submit a consolidated report to CalRecycle with other beverage manufacturers, in lieu of individual reports, if those beverage manufacturers share rights to the same brands or the products of which are distributed, marketed, or manufactured by a single reporting beverage manufacturer. This consolidated report must be submitted under penalty of perjury and pursuant to standardized forms prescribed by CalRecycle.
SB 54 – Plastics and Packaging
At the start of this year, CalRecycle was required to adopt any necessary regulations to implement and enforce its Plastic Pollution Prevention and Packaging Producer Responsibility Act (SB 54). SB 54 imposes EPR on “producers” of packaging materials for achieving the source reduction, recyclability or composability, and recycling rates for their products. Producers may comply with SB 54’s requirements by either joining the Circular Action Alliance (CAA), the PRO selected by the state to administer SB 54, or through assuming individual responsibility for compliance.
CalRecycle met its regulation deadline under SB 54 by publishing the Source Reduction Baseline Report on December 31, 2024, followed by updates to the list of Covered Material Categories regulated by SB 54 on January 1, 2025. The updates to the Covered Material Categories include an increase in materials considered to be “recyclable” or “compostable” while the Source Reduction Baseline Report establishes a baseline measurement for the Department and CAA to define source reduction targets, develop plans and budgets, and the track progress of SB 54’s implementation.
On January 1, 2025, SB 54’s prohibition on the sale, distribution, or importation of expanded polystyrene (EPS) food service items—unless the producer can demonstrate that all EPS used in the state meets a recycling rate of least 25%—went into effect. EPS food service producers may now be subject to notices of violation from CalRecycle and enforcement of penalties for noncompliance of up to $50,000 per violation, per day. Recycling rate mandates for plastic-covered materials do not go into effect until 2028.
SB 1143 – Paint
In September 2024, California enacted SB 1143, which expands the state’s existing Architectural Paint Recovery Program to include a wider range of paint products. “Paint product” is now defined to include interior and exterior architectural coatings, aerosol coating products, nonindustrial coatings, and coating-related products sold in containers of five gallons or less for commercial or homeowner use.
The law tasks CalRecycle with administering the program and approving a stewardship plan for the newly covered paint products. Retailers, importers, distributors, and online marketplaces will be prohibited from selling, offering for sale, or importing these products in California unless the producers are in compliance with the stewardship plan. Producers may comply with SB 1143 requirements by either joining PaintCare, the only recognized paint stewardship organization representing paint manufacturers in California, or through assuming individual responsibility for compliance.
All eligible products must comply with the new requirements by January 1, 2028, or an earlier date set by an approved stewardship plan. By July 1, 2030, or upon approval of the plan, whichever comes first, noncompliant producers will face administrative civil penalties up to $50,000 per day.
Climate Regulation
SB 261 and SB 253
After a year of uncertainty driven by budget constraints, California seems poised to implement its climate disclosure laws (SB 261 and SB 253) that were first passed in 2023. In September 2024, the Legislature passed SB 219, which granted the California Air Resources Board (CARB) a 6-month extension to issue the requisite rules that must be adopted by no later than July 1, 2025. CARB is responsible for administering SB 261 and SB 253.
On December 16, 2024, CARB posted an Information Solicitation that calls for public comments on the implementation of the laws and related issues. The Information Solicitation also invites input on key aspects of the climate disclosure framework that have been subject to speculation since the laws were enacted, such as the definition of “entity that does business in California” (clarifying the cohort within the scope of the laws); the methods for measuring and reporting scope 1, scope 2, and scope 3 emissions; and third-party verification and assurance requirements. The deadline to submit comments through CARB’s website is February 14, 2025.
Cal Chamber v. CARB
On January 30, 2024, the U.S. Chamber of Commerce and other business groups filed Chamber of Commerce of the United States of America et al. v. California Air Resources Board (CARB) et al., No. 2:24-cv-00801 (C.D. Cal. 2024) challenging SB 253 and SB 261 for violation of the First Amendment, the Supremacy Clause, and the U.S. Constitution’s limitations on extraterritorial regulation, including the dormant Commerce Clause.
Regarding the First Amendment facial challenge, the Plaintiffs alleged the laws “compel companies to publicly express a speculative, noncommercial, controversial, and politically-charged message that they otherwise would not express.” Concerning the Supremacy Clause, they argued that by requiring companies to make speculative public statements about emissions and climate-related financial risk, the laws enable “activists and policymakers to single out companies,” pressuring them to reduce emissions within and outside California. As for the constitutional claims, the Plaintiffs alleged that California lacks authority to regulate greenhouse gas emissions outside of the state and that the laws are invalid under the U.S. Constitution’s limitations on extraterritorial regulation because they heavily intrude on Congress’s authority to regulate interstate and foreign commerce.
To expedite the District Court’s ruling, the Plaintiffs moved for summary judgment on the First Amendment challenge. Simultaneously, CARB moved to dismiss the Plaintiffs’ Supremacy Clause and extraterritorial regulation claims. On November 5, 2024, the District Court denied the Plaintiffs’ motion. The Court held that the First Amendment applied to SB 253 and 261; however, it concluded that the constitutional challenge involves factual questions that go beyond pure legal analysis and thus, completing a “fact-driven task” was necessary to decide which of the laws’ applications violate the First Amendment. It held that further discovery is required to complete this “fact-driven” task.
The District Court indicated that it would address CARB’s motion to dismiss in a separate order. That motion is pending as of the date of this publication.
SB 1383 – Organic Waste & Food Collection
Since CalRecycle adopted regulations implementing SB 1383, California communities have made progress in diverting and reducing the disposal of organic waste and thereby reducing the amount of methane emissions from landfills. According to California’s Short-Lived Climate Pollutant Reduction Strategy, 93% of jurisdictions with requirements for collection reported having residential organics collection, and 100% of California communities expanded programs to send still-fresh, unsold food to Californians in need, reducing the waste large food businesses send to landfills every year. Through SB 619, 126 jurisdictions have been granted additional time to comply with SB 1383 regulations.
While progress has been made, local jurisdictions continue to struggle to meet the law’s mandates (namely, reduce organic waste disposal by 75% and reduce edible food waste by 20% by 2025). Rather than revising those mandates or pausing the implementation of SB 1383 to ensure jurisdictions weren’t sanctioned for missing implementation deadlines, the legislature enacted a number of laws to address some of the concerns raised by the regulated community. These include SB 2902, AB 2346, and SB 1046.
SB 2902 extends the rural jurisdiction exemption to comply with organics collection and procurement requirements until January 1, 2027. AB 2346 allows jurisdictions to count specified compost products toward their goals and adopt a five-year procurement target instead of annual goals, and SB 1046 directs CalRecycle to create a programmatic environmental impact report for small to medium composting facilities, aiding local governments and composters by streamlining permitting.
Although CalRecycle initiated formal enforcement actions in 2024, there is no indication that the agency has fined or sanctioned any jurisdiction for non-compliance. As the 2025 target date has now passed, expect enforcement efforts to increase in the months and years ahead.
Energy Efficiency Standards
As covered in our December 10, 2024 news alert, manufacturers and sellers of consumer products in California should be aware that the California Energy Commission continues to bring more enforcement actions and assess large civil penalties for violations of its Title 20 Appliance Efficiency Program. At a time when federal appliance efficiency standard enforcement is expected to recede due to the recent presidential election and imminent transition, California enforcement is likely to continue to grow. Regulated businesses, therefore, should pay increasing attention to Title 20 compliance, not only to avoid large fines but also to ensure continued access to their products in the lucrative California market.
Stationary Source Regulation
AB 1465 – Air Quality Management Districts (AQMDs) Granted Authority to Seek Triple Penalties
For years, the penalty ceilings in California’s Health & Safety Code have limited the ability of California’s regional AQMDs to collect civil penalties for rule violations. Starting January 1, 2025, AB 1465 tripled these ceilings. For example, the typical maximum penalty for strict liability violations—previously $12,090 per violation—has escalated to $36,270 per violation. The new law also requires that air districts (or a court) consider items like health impacts and community disruptions when evaluating penalty amounts (in addition to other factors required to be considered by law). These elevated ceilings only apply to stationary sources that have a Federal Clean Air Act Title V permit and emit certain defined compounds. How air districts will wield this new authority has yet to be seen, but we expect to see increasing penalties for many sources as a result.
Indirect Source Rules Will Continue to be a Hot Topic
While regional air districts are generally limited in their legal authority to regulate mobile sources (that authority is reserved for California’s state air regulator, CARB), indirect source rules (regulation of stationary sources that attract emissions from mobile sources) have received renewed attention as a means by which air districts seek to curb air pollution. With the incoming Trump administration signaling its intent to limit California’s ability to regulate mobile sources, air districts will likely be incentivized to find creative ways to indirectly regulate mobile sources within their districts.
In 2024, the South Coast AQMD received U.S. Environmental Protection Agency (EPA) approval to include such an indirect source rule (ISR) for warehouses as part of its state implementation plan. South Coast AQMD also adopted an ISR in 2024 applicable to rail yards and has been working on a rule applicable to ports for years, which it promises to bring before its board for approval in 2025.
Perhaps observing the South Coast AQMD’s recent ISR adoptions, the Bay Area AQMD also included an ISR in its 2025 rulemaking forecast. However, exactly what such a rule for this district might look like or what source it might seek to regulate remains to be seen.
New National Ambient Air Quality Standard for PM 2.5 Will Likely Drive Rulemaking Activity
California’s major regional air quality districts (the Bay Area AQMD, the South Coast AQMD, and the San Joaquin Valley Air Pollution Control District) have jurisdiction over areas considered to be in non-attainment of national standards regarding particulate matter (PM) 2.5. Areas in persistent non-attainment status risk federal sanctions and the loss of federal highway funding. In early 2024, EPA tightened the PM 2.5 standards even further. As a result, some air districts may consider rulemakings designed to reduce PM2.5 pollution within their jurisdictions. Given that mobile sources are a major contributor of this pollutant, ISR options may become even more appealing in 2025 and beyond.
Mobile Source Regulation
The Clean Air Act preempts states from adopting their own emission standards for new motor vehicles and new motor vehicle engines. However, Section 209 of the Clean Air Act allows California to set its own emissions standards if EPA grants a waiver from the federal preemption or EPA authorizes California to enforce its own standards despite the preemption. In the past year, CARB submitted requests for waiver or authorization for several regulations.
Advanced Clean Fleets Regulation – This regulation applies to trucks performing drayage operations at seaports and railyards; fleets owned by State, local, and federal government agencies; and high-priority fleets that are entities that own, operate, or direct at least one vehicle in California and that have either $50 million or more in gross annual revenue, or that own, operate, or have common ownership or control of a total of 50 or more vehicles. The regulation imposes restrictions on purchasing internal combustion engines, requires fleet owners to phase in zero-emission vehicles (ZEVs) or near-ZEVs beginning in 2024, and imposes reporting and recordkeeping requirements on fleet owners and operators. On January 13, 2025, CARB withdrew the request for waiver and authorization. In a response letter, EPA stated that it, therefore, “considers the matter closed.”
In-Use Locomotive Standards – The regulation has four primary, interrelated components: (1) imposes restrictions on the operation of any locomotive that is “23 years or older” from the original engine build date unless the locomotive exclusively operates in zero-emission configuration within California; (2) requires railroads to make annual deposits into a “Spending Account” based on the locomotive’s emissions in California in the prior year and imposes restrictions on the use of funds in the “Spending Account”; (3) imposes idling requirements that would regulate a locomotive’s function and maintenance; and (4) imposes registration, reporting, and recordkeeping requirements, including the requirement to annually report emissions information for non-zero emissions locomotives. On January 13, 2025, CARB withdrew the request for waiver and authorization. By response letter, EPA stated it therefore “considers this matter closed.”
Amendments to the Small Off-Road Engines Regulations – The amendments include improvements to evaporative emissions certification procedures, revise the compliance testing procedure, update the evaporative emissions certification test fuel to represent commercially available gasoline, and align aspects of the regulation requirements with the corresponding federal requirements. EPA granted the authorization request on December 19, 2024.
The “Omnibus” Low NOx Regulation – The regulation establishes the next generation of exhaust emission standards for nitrogen oxides (NOx), PM, and other emission-related requirements for new 2024 and subsequent model year on-road medium- and heavy-duty engines and vehicles. EPA granted the authorization request on December 17, 2024.
Advanced Clean Cars II Program – The regulations amend the Zero-emission Vehicle Regulation to require an increasing number of ZEVs and amends the Low-emission Vehicle Regulations to include increasingly stringent particulate matter, Nox, and hydrocarbon standards for gasoline cars and heavier passenger trucks to continue to reduce smog-forming emissions. EPA granted the authorization request on January 6, 2025.
Amendments to California’s In-Use Off-Road Diesel-Fueled Fleets regulation – The amendments will require fleets to phase out use of the oldest and highest polluting offroad diesel vehicles in California, prohibit the addition of high-emitting vehicles to a fleet, and require the use of R99 or R100 renewable diesel in off-road diesel vehicles. EPA granted the authorization request on January 3, 2025.
If the current EPA administration does not grant the pending waiver requests, then it is unclear how EPA under the Trump administration will decide on the waiver requests. Our November 6, 2024 news alert discusses these waiver issues in more detail.
CARB also enacted the zero-emission forklift regulation on August 2, 2024. The regulation accelerates the transition towards zero-emission forklifts by restricting fleet operators/owners from owning, possessing, and operating Large Spark Ignition (LSI) forklifts starting on January 1, 2026, and requiring fleet operators to phase out Class IV LSI forklifts of any rated capacity, as well as Class V LSI Forklifts with rated capacity less than 12,000 pounds according to the compliance schedule in the Regulation. These forklifts will need to be phased out by January 1, 2038.
Cal/OSHA Developments
Cal/OSHA Lead Exposure Regulations
The California Division of Occupational Safety and Health’s (Cal/OSHA) updated lead standards, which were approved on February 15, 2024, and went into effect on January 1, 2025. These apply to both general and construction worksites and replace standards that are decades old, based on data from over 40 years ago. The amended standards modify the permissible exposure limit (PEL), action level (AL), workplace hygiene practices, and medical surveillance requirements relating to lead in the workplace.
The reduction of the PEL and AL is significant; the threshold that triggers various regulatory requirements is now considerably lower. Many new industries will likely be covered. The PEL is now 10 µg/m3 (8-hour-time weighted average), an 80% reduction from the earlier PEL (50 µg/m3). The AL is now 2 µg/m3, a 93% drop from the prior AL (30 µg/m3).
Regulations for General Industry now define certain tasks as “Presumed Significant Lead Work” (PSLW). Until employers perform an employee exposure assessment, they are required to provide employees performing PSLW with interim protections.
For the construction industry, the regulations also define various “trigger tasks” levels, which assume a certain level of employee exposure. These “triggers” require protective measures for employees performing these tasks until an employee exposure assessment is completed.
Cal/OSHA Silica Emergency Temporary Standard
Cal/OSHA stated that California is experiencing a “silicosis epidemic” among artificial stone fabrication workers. In December 2023, the Occupational Safety and Health Standards Board (OSHB) approved the Emergency Temporary Standard (ETS) on Respirable Crystalline Silica (RCS) in response to these circumstances. The ETS intends to protect employees working with artificial and natural stone containing more than 10% crystalline silica. Additional protections apply to workers performing “high exposure trigger tasks.”
On December 19, 2024, OSHB voted unanimously to make the Silica ETS permanent. The decision is a step towards making these emergency measures permanent. The current proposal continues the protections the ETS has introduced, with some changes. These include a new medical removal subsection and updates to the medical surveillance subsection.
The proposed medical removal provisions provide protections to employees when a physician or other licensed healthcare professional (PLHCP) recommends that they be removed from a job assignment or that the job be modified to reduce exposure to RCS. The proposed updates to the medical surveillance provisions include specific medical procedures to be conducted for the required initial and periodic examinations. PLCHPs and specialists would also be required to submit certain information to the California Department of Public Health for each silica medical examination conducted.
The Office of Administrative Law has 30 days to approve or deny the proposal. We expect a decision in mid-January 2025.
Cal/OSHA Increases Staffing for Its Bureau of Investigations Unit
In August 2024, Cal/OSHA announced that it had increased staffing for its Bureau of Investigations (BOI) unit. Cal/OSHA says this would “allow BOI to tackle more cases and ensure that the most negligent of employers are held accountable.”
The BOI is responsible for investigating employee fatality and serious injury cases, and preparing and referring cases to local and state prosecutors for criminal prosecution. Cal/OSHA was criticized in early 2024 for the short-staffed status of BOI. Given the recently enhanced staffing, employers should expect that BOI investigations will likely increase in 2025.
Bird Flu
On December 18, 2024, Governor Newsom declared a state of emergency for Avian influenza (H5N1) (“bird flu”) in California. On December 27, 2024, the Division of Workers’ Compensation (DWC) advised employers and healthcare professionals to look for occupational cases of bird flu. There have been no cases of human-to-human transmission in California—nearly all affected persons had exposure to infected cattle. In light of DWC’s recommendations, employers should nevertheless review Cal/OSHA’s guidance on bird flu for employers.
Water Rights, Tribal Issues, Public Lands, Endangered Species
Threatened Species Listing of Monarch Butterfly
On December 12, 2024, the U.S. Fish and Wildlife Service (FWS) proposed listing the monarch butterfly as a threatened species with a special section 4(d) rule under the Endangered Species Act (ESA). The special 4(d) rule would provide very narrow exemptions to the ESA’s broad prohibition on unauthorized take for certain types of activities that may otherwise impact the species. FWS also proposed designating nearly 4,500 acres in California as critical habitat that would extend from the California Bay Area’s Marin County down the state’s western coast to Ventura County north of Los Angeles.
If finalized as proposed, this listing would stand as the largest listing decision in ESA history, affecting the entire lower forty-eight states. FWS is receiving public comment through March 12, 2025.
Central Valley Project and State Water Project
The U.S. Bureau of Reclamation (Reclamation)’s Central Valley Project (CVP), which is operated jointly with the California Department of Water Resources’ State Water Project (SWP), manages the collection, storage, and transport of many millions of acre-feet of water through the Central Valley for delivery to irrigators and municipalities and to meet state and federal ecological and species requirements. In 2018, California finalized revisions to its Water Quality Control Plan for the San Francisco Bay and San Joaquin-Sacramento River Delta (Bay-Delta) to require that more flows from the San Joaquin and Sacramento Rivers would reach the Bay-Delta for water quality and fish and wildlife enhancement, accordingly reducing water supplies for agricultural irrigators. In 2019, the previous Trump administration responded by committing to increasing CVP water supplies for agricultural users through changes to long-term operations of the CVP, pursuant to a 2019 ESA biological opinion or “BiOp.”
These ESA changes were promptly challenged by California and environmental organizations as insufficiently protective of Bay-Delta salmon and smelt populations, habitats, and spawning activities. They were first enjoined by federal court and later remanded to the National Marine Fisheries Service (NMFS) and FWS under the Biden administration. The cases were stayed during NMFS and FWS’s reconsideration of new CVP and SWP operating rules, in favor of an interim operations plan (IOP), which was extended through December 2024 to allow for the issuance of new CVP and SWP BiOps. See March 28, 2024 Order in Pacific Coast Federation of Fishermen’s Associations v. Raimondo, Civ. Nos. 20-00426, -00431 (E.D. Cal.). On December 20, 2024, on the verge of another change in administration, Reclamation issued its Record of Decision for the “Long-Term Operation of the Central Valley Project and State Water Project” based on 2024 BiOps, to mixed reviews from environmentalists and water users alike. It is likely that these new “California water rules” will spark new rounds of both litigation challenges and regulatory reconsideration in 2025.
Yurok Tribe v. Klamath Water Users Association
In this appeal before the Ninth Circuit (Nos. 23-15499 and 23-15521, consolidated), the Klamath Water Users Association (KWA) and Klamath Irrigation District (KID) sought review of a 2023 federal district court decision holding that an Oregon Water Resources Department (OWRD) order prohibiting Reclamation from releasing stored water subject to adjudicated irrigation rights from Upper Klamath Lake to protect and restore endangered fish species was preempted by the ESA. KWA and KID had sought declaratory relief that the ESA does not authorize Reclamation to release water from Upper Klamath Lake, arguing that the case does not involve any issue of preemption, because Reclamation does not have authority under its enabling act to appropriate rights to use water in violation of Oregon law, and the ESA does not expand these Reclamation authorities. OWRD subsequently withdrew its order.
The Ninth Circuit heard oral argument on June 12, 2024, but the court, just prior to the hearing, indicated that it perceived potential jurisdictional issues due to the OWRD withdrawal having mooted the initial challenge to its order. At oral argument, KID urged the court to certify key questions to the Oregon Supreme Court concerning Reclamation’s authority to use and control the use of water under Oregon law, arguing that Oregon’s water rights and laws governing the use and control of water in Upper Klamath Lake were established long before the ESA was enacted, that Section 8 of the Reclamation Act mandates compliance with state water law and water rights, and that controlling precedent makes clear that state law governs whether Reclamation has authority or discretion to meet its ESA obligations using stored irrigation water subject to adjudicated water rights. Therefore, these state law questions should be addressed independently of the federal question of Reclamation’s ESA obligations and their preemptive consequences. Briefing on KID’s motion for certification continued into December 2024, so a Ninth Circuit ruling on the merits, or as to whether the questions will proceed for now in state or federal court, can be expected in 2025.
Water
On November 20, 2024, EPA Region 9 published in the Federal Register its Final Designation of formerly unregulated stormwater discharges from commercial, industrial, and institutional (CII) properties for required National Pollutant Discharge Elimination System (NPDES) stormwater permitting. The designation applies to CII facilities consisting of five or more acres of impermeable surfaces (in the case of unpermitted facilities) or five or more total acres (in the case of unpermitted portions of facilities already holding a NPDES permit and no exposure certificate, and in the case of non-notice of non-applicability (NONA) covered portions of facilities with a NONA) in two watersheds in the Los Angeles County area. This expansion of stormwater regulation is a joint effort between EPA Region 9 and the Los Angeles Regional Water Quality Control Board. The Water Board prepared the corresponding draft CII General Permit and is expected to hold a public hearing on the draft permit now that EPA’s designation is final.
The incoming Trump administration may reevaluate the Final Designation and consider rescinding it, but it may take some time for new EPA staffers to address this action. In the interim, it will be critical for parties adversely affected by the Final Designation to expeditiously seek judicial review—and a stay or preliminary injunction—to protect their interests.
Additional Authors: Gary J. Smith, Patrick J. Redmond, Leticia E. Duarte, Sara M. Eddy, Gabriela Espir, Jeremy D. Faulkner, Nicole L. Garson, Ragini Gupta, Lauren M. Lankenau, Sharon Mathew, Claire S. McLeod Ruiz, Lauren M. Murvihill, and Megan V. Unger
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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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 . . .”
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.