TSCA Developments — A Conversation with Richard E. Engler, Ph.D. [Podcast]
This week, I discuss Toxic Substances Control Act (TSCA) developments with my colleague, Dr. Richard E. Engler, Director of Chemistry for B&C and The Acta Group (Acta®), our consulting affiliate. The U.S. Environmental Protection Agency’s (EPA) implementation of the 2016 Frank R. Lautenberg Chemical Safety for the 21st Century Act amendments has been a dynamic, evolving, and unpredictable work in progress for almost nine years. Given the new Administration, we are at a most uncertain time because of the lack of clarity regarding what the new leaders at the Office of Chemical Safety and Pollution Prevention (OCSPP) will do to address new chemical review concerns, risk evaluation under TSCA Section 6, and risk management actions resulting from those evaluations. As listeners know, all final risk management rules are being challenged and the disposition of those cases is the subject of considerable speculation. So also is OCSPP’s consideration of not yet final risk evaluations and how the new Administration intends to interpret TSCA Section 6 in general. There are growing calls for legislative action to remedy some of Lautenberg’s deficits, particularly in the area of new chemicals, another important variable that is destabilizing the status quo. Rich and I discuss these topics and many others.
Commission Releases Its Awaited Omnibus Sustainability Package Triggering a New Legislative Process
The European Commission published on 26 February 2025 its awaited Omnibus simplification package proposing the amendment of several pieces of sustainability and ESG-related legislations adopted under the previous Commission mandate (the EU Green Deal).
The proposals, which were announced by Ursula Von der Leyen in November 2024, include:
A proposal for a Directive amending implementation and transposition deadlines of the Corporate Sustainability Reporting Directive (CSRD) and Corporate Sustainability Due Diligence Directive (CSDDD)
A proposal for a Directive amending the scope and requirements of the CSRD and CSDDD
A proposal for a Regulation (not yet published) amending the Carbon Border Adjustment Mechanism (CBAM) Regulation (see available Annex)
A draft amendment to the EU Taxonomy Delegated Acts, open for public consultation until 26 March 2025
The issuance of the proposals triggers the start of a legislative process that is expected to lead to substantial debates and possible dissentions between the European Parliament and the Council.
Corporate Sustainability Reporting Directive
On the CSRD, the proposal noticeably includes a narrower scope of application (beyond 1,000 employees), a postponement of reporting obligation by two years for companies not yet subject to reporting, voluntary taxonomy reporting and reliance on partial alignment (under some conditions). If the double-materiality assessment is retained, the Commission commits to simplified European Sustainability Reporting Standards (ESRS) and to abandon sectoral ESRS.
Corporate Sustainability Due Diligence Directive
The transposition of the CSDDD and the applicability of its obligations are postponed by one year (respectively 2027 and 2028), while the Commission should issue guidance by 2026. The scope of due diligence is proposed to be limited to Tier 1 suppliers, unless there is “plausible” information of adverse impacts beyond in the supply chain.
Importantly, the amended CSDDD would preclude more stringent requirements by Member States (relying on so-called maximum harmonization) leaving it up to them to rule on civil liability and the amount of penalties for breach of CSDDD obligations rather than this being established by the directive.
The choice of a separate proposal addressing the postponement of deadlines may ensure a swift adoption of the proposed postponements, ahead of the application of the concerned reporting and due diligence requirements under the CSRD and CSDDD.
Amendments on the substance of the text on the other hand are expected to face more hurdles, due to important disagreements between the European Parliament and the Council and within their members.
Contentious points notably include:
For the CSRD, the reduction of the scope of the reporting (companies subject to reporting & value chain information reported)
For the CSDDD, restriction of the scope of the due diligence assessment to tier 1 (direct) supplies and removal of civil liability provisions
On the same day, another package on investments was also released with an aim of simplification and increased efficiency
Those proposals open a hybrid momentum where companies need to continue working on complying with their existing or forthcoming obligations under the existing legislations, while factoring the likeliness of important amendments in the coming months. Recent examples of legislative processes at the EU level have shown that the outcome of those processes are uncertain, although the Commission has in the present case sought to anticipate the position of the co-legislators, i.e. the European Parliament and the Council.
Combining the public policy, compliance and legal expertise of our various practice groups on those topics, we can support in helping you understand these changing regulations.
Simplifying The EU CBAM Mechanism – The Commission Releases Its Proposals
As part of the so-called Omnibus 1 package, the European Commission has proposed a regulation (with annex) to amend several parts of the Carbon Border Adjustment Mechanism (CBAM) Regulation, Regulation (EU) 2023/956.
The most significant changes include:
Introduction of a mass-based threshold set at 50 tonnes of net mass, excluding electricity and hydrogen, on a cumulative basis per calendar year, replacing the previous “de minimis” rule, which was set at €150 per consignment. If approved, the new rule would exempt the vast majority of importers (the Commission estimates the 90% of importers) from CBAM obligations, while, according to the Commission’s proposal, still ensuring that more than 99% of embedded emissions remain within the scope of the CBAM.
Delayed obligation to purchase CBAM certificates: Importers will only be required to purchase CBAM certificates starting in 2027 for emissions embedded in goods imported during the year 2026. It is important to note that the financial obligations will still begin in January 2026, as provided by Regulation (EU) 2023/956. However, while the financial obligations will apply, the purchase of certificates will not be mandatory in 2026 and will only become mandatory starting in 2027.
Revised deadline for emissions reporting: The deadline for surrendering via the CBAM registry CBAM certificates would be moved to 31 August 2027, instead of the original 31 May 2027 deadline, as indicated in the initial proposal.
Additionally, the proposal introduces the possibility for authorized CBAM declarants to claim a carbon price paid in a third country, rather than only the country of origin, as was previously required.
Other notable changes include:
Modifications to the emission calculation to facilitate the calculation of embedded emissions for aluminium and steel downstream goods.
The addition of electricity to the list of CBAM goods for which only direct emissions are to be considered in the calculation of embedded emissions.
Finally, the Annexes contain several simplifications to the embedded emission calculation, such as default values or precursors produced in the EU, to facilitate reporting obligations.
It’s important to remember that this is the Commission’s proposal, and not yet an adopted law. The European Parliament and the Council will now need to develop their positions and agree on a final text. Therefore, the provisions outlined above are subject to change in the coming weeks.
We are monitoring these regulatory changes to prepare companies for compliance and can assist in influencing the law-making process where necessary.
Powering the Digital Future: Navigating the Nuclear Option for Data Centers
Key Points:
Nuclear energy is well suited to meet the demands of AI data centers and data center customers have multiple options for nuclear power integration, including Small Modular Reactors (SMRs) vs. full-sized units, on-site vs. off-site generation, and new construction vs. reactivating existing facilities – each with distinct trade-offs in terms of cost, scale, and implementation complexity.
Potential developers will need to navigate a welter of state and federal regulations, statues and tariffs regarding grid interconnection, utility rights, and behind-the-meter arrangements. Current rules were not designed for large-scale, single-customer nuclear generation facilities.
We await key developments stemming from:
FERC’s Show Cause Proceeding: There is a 30-day deadline for PJM and PJM Transmission owners to defend why the current tariff is just or propose changes to remedy concerns on reliability impacts and cost causation.
Talen’s petition for review in review in the Fifth Circuit Court of Appeals regarding FERC’s rejection of the Amazon/Pennsylvania connection agreement
Consolidated proceedings
Commissioner-led Technical Conference on Large Loads Co-Located at Generating Facilities (Docket No. AD24-11-000)
Constellation complaint (EL25-20-000)
These will help establish “rules of the road” for co-location arrangements in PJM territory
Modern data centers are the foundation of our information society and now use artificial intelligence to generate new forms of machine intelligence and learning – though at the cost of considerable energy consumption. Their energy demand outstrips the ability of existing generation and transmission systems to meet that demand, making nuclear energy particularly well-suited to supply the shortfall given its base load (round-the-clock) generation profile, low fuel cost and insulation from carbon emissions concerns. Powering data centers with purpose-built, reactivated, or newly-completed nuclear generation is an attractive way to accelerate power supply to meet the needs of the AI economy.
The path for powering data centers with nuclear energy depends on multiple factors including whether the power will come from:
Full-sized units or a series of small modular reactors (“SMRs”).
Existing nuclear units that are already connected to the grid or new nuclear units to be constructed off site.
Nuclear power wheeled to the data center through the grid or new nuclear units to be constructed at or adjacent to the data center site.
The Electric Grid
More than 65 individual balancing authorities manage the United States electric grid, and most are either regional transmission organizations or large investor-owned or publicly-owned power utilities. Many smaller utilities, electric cooperatives, and municipal power systems operate behind those larger balancing authorities.
The commercial and operational terms by which new nuclear capacity will be integrated onto the grid will depend on the laws, regulations and tariffs that apply to each of these entities. This is true even for on-site or ‘behind the meter’ nuclear generation, since connecting data centers to the grid is typically required for emergency or standby generation, moment to moment load balancing, and the export of excess power when power consumption at the data center drops. The costs of operating without a robust grid connection can be quite expensive considering the cost of building and maintaining high-capacity battery or gas-fired generation back up.
Full-Sized Units vs. SMR
Data center developers are increasingly viewing SMRs as an attractive alternative to traditional large-scale nuclear reactors for powering their facilities considering their automatic or ‘walk-away’ safety features, their scalability (300 MW or less per unit vs. approximately 1,000 MW per full-scale unit), and the ability of SMR reactor units to be manufactured in factories and transported fully assembled to their final location for installation.
But substantively, the costs and benefits of the two technologies are closely balanced since, like SMRs, today’s full-scale reactors have comparable walk-away safety features and key components can be built in a series of modules on factory floors. Both SMRs and full-sized units require significant on-site ‘stick built’ construction for balance-of-plant equipment (including steam turbines, condensers, water cooling systems, switchyards, and control, maintenance and administration facilities) as well as site-specific NRC licensing and environmental permitting. Neither represents a true plug-and-play solution. In addition, full-scale units have significant economies of scale in the form of lower per-unit staffing and operating cost and produce less high-level waste for future disposal. Outside of the United States, there have been a number of successful recent projects to build new, full-scale reactors.
In short, SMRs represent nuclear capacity that data center developers can install in smaller increments reducing financial risk (capital costs) and time to start up, while creating the redundancy inherent in multiple units that can produce energy independently of each other. Full-scale reactors have significant operating economies, but in a single generating package.
SMRs represent nuclear capacity that data center developers can install in smaller increments reducing financial risk (capital costs) and time to start up, while creating the redundancy inherent in multiple units that can produce energy independently of each other. Full-scale reactors have significant operating economies, but in a single generating package.
On-Site Nuclear
Locating nuclear capacity on data center sites can create significant cost and time saving if major transmission upgrades can be avoided. But the savings may evaporate if for operational requirements grid connectivity must still match the nuclear facility’s total output or the data center’s peak power needs. These requirements include maintaining reliability standards, managing excess power, balancing loads, or meeting the data center’s full power demands. Where robust standby transmission access is required, the same transmission-related regulatory and construction issues will arise with on-site generation as with generation located elsewhere on the grid. In those cases, the primary operating advantage of on-site nuclear generation, or other onsite generation, may be accelerating availability of capacity or insulation from the effects of curtailments of service or loss-of-load (“LOA”) events on the grid.
Completing or Recommissioning Existing Units
As we will discuss with more depth in an upcoming installment of our “Going Nuclear” series, completing or restarting existing but non-operating units is currently being considered for multiple plants including the Palisades Unit, the Bellefonte Units, Three Mile Island Unit 2, and V. C. Summer Units 2 and 3. Completions and restarts leverage investments already made) and transmission interconnectivity already in place. Assuming land use patterns and the constraints of nuclear exclusion zones would support doing so, building new data centers alongside such completions and restarts can be a powerful strategy for delivering new capacity quickly.
Behind the Meter
State statutes and regulations generally allow customers to build and operate their own generation. But where that generation is connected to the grid (i.e., behind a utility meter) it may fall under the provisions of state distribution energy resources (DER) legislation that typically were drafted for smaller solar and renewable projects and prohibit large behind the meter installation. These caps, however, are not the last word, and can be removed or waived especially if the incumbent utility agrees.
Some jurisdictions may prohibit interconnection behind the meter facilities that do not sell their capacity and energy to the grid, and where the facility will be located inside an RTO or ISO, FERC may have jurisdiction over interconnection. FERC recently rejected an agreement to power an Amazon data center in Pennsylvania through a direct connection with an adjacent operating nuclear station based on the potential impact taking existing nuclear generation out of PJM’s constrained capacity markets.
FERC is also considering a request by Constellation Energy to require PJM to adopt tariff provisions to support co-located or directly connected nuclear and other generation while addressing concerns about effects on reliability and rate payer costs.
Off-Site New Nuclear
If a data center plans to purchase power from an offsite nuclear unit, a power purchase agreement (PPA) with the owner and operator of the unit will determine the terms of sale. If the unit will operate in a competitive retail market, then the PPA delivery will take place under the open access transmission tariff (OATT) of the resident transmission operator, and retail power delivery tariffs of the local distribution entity. However, the structure of most deregulated markets involves all generation being sold into a single market, with contracts for differences giving end-users the economic benefit of their PPA transactions. A data center customer will want some assurance that service will not be curtailed so long as the nuclear capacity it is providing is online and supplying power to the grid. The terms of existing tariffs should not be considered to be the last word on what is possible. It may be possible to negotiate and obtain regulatory approval for contractual terms or special tariff provisions tailored to the specific transaction.
A data center customer will want some assurance that service will not be curtailed so long as the nuclear capacity it is providing is online and supplying power to the grid.
State Regulation: Certificates of Public Convenience and Necessity (“CPCNs”), Territorial Assignment and Retail Tariffs
Most states require electric generation developers to obtain some form of CPCN to construct systems sized at 75-85 MW or more, and nuclear construction would almost certainly require certification under those statutes. These requirements often apply whether or not the new unit is considered self-generation, i.e., it is owned by and serves only the data center owner. These statutes were not typically drafted with single customer, large-scale generation in mind, and so adapting a new nuclear project under their terms may require some creativity.
State Regulation
Vertically Integrated Markets: If the state follows a vertically integrated utility service model (i.e., non-deregulated), then the local utility will likely have territorial service rights which extend to generation construction. This may allow the utility to block the construction of new generation to serve a customer within its service territory, especially if it is to be owned by an entity other than the data center and its customers. However, there can be exceptions. Some states have statutes or tariffs that allow industrial choice, distribution energy resources (DER), or voluntary renewable energy projects (“VREPs”). Otherwise, regulatory support from the incumbent utility and a one-off agreement may be needed with to site new nuclear generation. Further , the incumbent utility’s public service commission will need to approve, and such agreement would be a contractual exception to the utility’s generally applicable tariffs.
State Regulation: Retail Standby Service
A data center that is connected to the grid for backup power purposes will be a retail customer of the incumbent electric utility. The upside of being a retail tariff customer is that the data center can use its grid connection to buy standby power to deal with fluctuations in its energy demand (and to sell excess power onto the grid when necessary). But the presence of a retail meter will make the data center subject to the costs built into its retail tariff. The tariff may be out of alignment with the standby nature of the service being purchased and may include services that do not benefit the data center owner (e.g., cost for renewable portfolio standards, demand side management (DSM) programs, and other social or environmental costs). Depending on the tariffs, the data center may be subject to curtailment in times of system emergency even if the nuclear plant is producing sufficient power to meet its demands.
Looking Ahead
Nuclear power presents a compelling solution for meeting the exponentially growing energy demands of modern data centers, particularly those supporting AI operations. However, successful implementation requires careful navigation of multiple regulatory and licensing complexities.
Whether choosing SMRs or full-scale reactors, data center operators must carefully evaluate their specific needs against various factors: initial capital costs, operational economies, regulatory requirements and uncertainties, and grid integration challenges. The decision between on-site and off-site generation, or whether to participate in recommissioning existing facilities, requires thorough analysis of federal, regional, and local regulations, transmission infrastructure, and operational requirements.
FERC Moves Forward Quickly on Generator Co-Location With Large Loads
During last week’s 20 February 2025 open meeting, the Federal Energy Regulatory Commission (FERC) initiated a show cause proceeding, directing grid operator PJM Interconnection, L.L.C. (PJM) and PJM’s transmission-owning utilities (Transmission Owners) to address the need for tariff changes to govern rates, terms, and service conditions for co-location arrangements.1 The order is likely to have implications nationwide given the growth of data centers and other large loads seeking dedicated energy sources. Co-location, as defined by the order, is a configuration through which end-use customer load is physically connected to the facilities of an existing or planned generator on the interconnection customer’s side of the point of interconnection to the interstate electric grid.2 Data centers and other large loads may use co-location arrangements with various configurations, including grid connections, to arrange for energy supplies.
Chairman Mark Christie’s remarks during the open meeting recognized FERC action to be imperative “because there’s not only billions of dollars of investment waiting for us to act… issues of reliability are directly implicated.”3 He also added, “[t]here’s no question a key utility principle is serve all customers… but [that] has to be done in a way that’s fair and [consistent with] cost causation.”4
The show cause order is directed at PJM following several co-location-related disputes involving entities in PJM. PJM is the largest grid operator in the nation, covering 13 states and the District of Columbia, and is home to the largest concentration of data centers in the nation. PJM is expecting 30 gigawatts of peak load to be added over the next five years.5
While the show cause proceeding focuses on the PJM region, industry is expected to track these developments closely given the broad scope of issues to be addressed. FERC’s decisions here will likely shape the federal regulatory framework governing co-location of data centers and other large loads in those regions or, at a minimum, guide the development of co-location rules adopted by other regional grid operators.
The expansive scope of the show cause proceeding covers issues concerning federal-state jurisdiction, operational reliability of the electric grid, generation resource adequacy, and interconnection study processes, including, e.g.:
Whether modifications to the tariff, market rules, or interconnection procedures and agreements would be necessary to address the identified issues of jurisdiction, cost causation, the beneficiary pays principle, reliability, and resource adequacy;
Whether and to what extent different co-location configurations benefit from or rely upon the transmission system, ancillary services, and black start services;
Whether and to what extent different co-location arrangements impose costs on the transmission system;
Whether co-located load configurations should be required to take transmission service, such as Network Integration Transmission Service, Point-to-Point Transmission Service, pay for ancillary services even if not taking traditional transmission service, or take a new form of transmission service;
Whether PJM’s necessary study process for proposed interconnections adequately addresses potential impacts or capabilities of co-location arrangements;
Whether it would be appropriate to establish an interconnection study process outside of PJM’s interconnection queue process for newly interconnecting co-location arrangements that do not exchange power with the transmission system and do not require network upgrades;
Whether revisions to PJM’s capacity market rules would be necessary to appropriately reflect the unique physical and operational characteristics of the co-location arrangement; and
Whether the PJM planning process should be modified to plan for and address resource adequacy impacts of co-location arrangements, particularly whether PJM should consider changes to its load forecasting methods.6
Although FERC has not committed to a date by which it will issue an order in the show cause proceeding, a press release issued 21 February 2025 commits that the agency will act as “quickly… as feasible,”7 and, during the open meeting, the four Commissioners participating in the decision pledged to act quickly. Further, the show cause order itself sets a fast-moving schedule, directing PJM and the Transmission Owners to submit their responses within 30 days, by 24 March 2025, and interested entities to submit comments 30 days later, by 23 April 2025.8 The order also consolidates the show cause proceeding with two other dockets,9 providing a supplement to the record upon which to take action in the show cause proceeding.
On the same day that FERC initiated the show cause proceeding, it also announced that it will convene a two-day Commissioner-led technical conference in Docket No. AD25-7-000 to address resource adequacy issues in regional transmission organization and independent system operator regions, to be held at FERC on 4 June 2025 and 5 June 2025.
The energy regulatory landscape is rapidly changing. The firm is closely monitoring these developments to assist its clients in navigating these evolving laws, regulations, and policies. Members of our Energy Storage and Distributed Resources practice group can assist in better understanding the regulatory issues surrounding the co-location of large loads with generation facilities, as well as the specific regulatory challenges facing data centers’ access to reliable electricity supplies.
Footnotes
1 PJM Interconnection, L.L.C., et al., 190 FERC ¶ 61,115 (2025) (Show Cause Order).
2 Id. at P 3.
3 Chairman Mark Christie, Comments at FERC’s February 2025 Open Meeting (Feb. 20, 2025) (Chairman Christie Comments) (official transcript forthcoming).
4 Id.
5 Commissioner David Rosner, Comments at FERC’s February 2025 Open Meeting (Feb. 20, 2025); see also Chairman Christie Comments (“We all know that the expansion of data centers, especially AI-driven data centers, is having a tremendous impact on load forecasts. We’re seeing load forecasts that as a state regulator for a long time I never thought were possible. We are seeing load forecasts in the double digits, and we have to meet those load forecasts and we have to meet it with generation.”).
6 See Show Cause Order at P 88.
7 FERC Chairman Issues Statement on Review of Issues Associated with the Co-Location of Large Loads at Generating Facilities, FERC (Feb. 21, 2025), https://www.ferc.gov/news-events/news/ferc-chairman-issues-statement-review-issues-associated-co-location-large-loads.
8 Show Cause Order at PP 2, 87.
9 Constellation Energy Generation, LLC, Complaint Requesting Fast Track Processing of Constellation Energy Generation, LLC, Docket No. EL25-20-000 (filed Nov. 22, 2024); Large Loads Co-Located at Generating Facilities, Notice of Commissioner-Led Technical Conference, Docket No. AD24-11-000 (issued Aug. 2, 2024); see also FERC to Hold Commissioner-Led Technical Conference to Discuss Co-location of Large-Load Customers with Generating Facilities, K&L GATES HUB (Aug. 7, 2024), https://natlawreview.com/article/ferc-hold-commissioner-led-technical-conference-discuss-co-location-large-load.
Major Changes in National Environmental Policy Act Process
The Council for Environmental Quality’s (“CEQ”) published an interim final rule yesterday repealing all of its implementing regulations for the National Environmental Policy Act (“NEPA”). The interim final rule becomes effective on April 11, 2025. In the meantime, CEQ is accepting public comments until March 27, 2025. CEQ states that it will respond to comments and provide any changes in a future final rule.
As federal agencies scramble to realign their NEPA procedures, businesses considering potential NEPA review in the short- and long-term face some significant uncertainty. As part of Womble Bond Dickinson’s effort to help you navigate change in the federal government, we unpack where this rule and CEQ’s accompanying guidance to federal agencies leave us in terms of permitting and NEPA review and what we can expect going forward.
Where We Are – CEQ’s Interim Final Rule and Guidance to Agencies
CEQ’s interim final rule repeals NEPA regulations issued since 1978, including NEPA’s implementing regulations at 40 C.F.R. Parts 1500-1508. However, the repeal does not get rid of NEPA review. NEPA, signed into law by President Nixon in 1970 and recently amended by the Fiscal Responsibility Act of 2023, is still congressionally-enacted law.
NEPA review will continue to be governed by processes and procedures specific to each federal agency. But those agency-specific processes and procedures will change. Under CEQ guidance issued on February 19 to the heads of federal departments and agencies, agencies must revise their NEPA implementing procedures (or establish procedures if they don’t have any) by February 19, 2026. One focus of those revisions will be to expedite permitting approvals. In the meantime, CEQ provides the following guidance for how those agencies will proceed with NEPA review while NEPA implementing regulations are revised:
Federal agencies should follow their existing practices and procedures for implementing NEPA consistent with:
the text of NEPA as revised by the Fiscal Responsibilities Act of 2023;
President Trump’s January 20, 2025, Executive Order on Unleashing American Energy, and;
CEQ’s February 2025 guidance.
Agencies are directed not to delay pending or ongoing NEPA analyses while revising their NEPA procedures.
It’s not clear from these directives whether and how agencies will tweak (or wholly up-end) existing practices and procedures to be consistent with the authorities cited in this list. This compounds existing uncertainties, such as how an increasing shortage of qualified staff at federal agencies will continue to process existing NEPA reviews while revising NEPA procedures under the guidance’s short timeline.
CEQ’s guidance mandates certain considerations for agencies in revising their NEPA implementing procedures, including a caution that NEPA does not employ the term “cumulative impacts” and that NEPA documents should not include environmental justice analysis.
We’ll be watching this process closely at the U.S. Forest Service and the Bureau of Land Management, as these agencies are clear leaders in implementing NEPA:
U.S. Forest Service (Department of Agriculture): The Department of Agriculture codified the U.S. Forest Service’s NEPA procedures at 36 C.F.R. Part 220 in 2008 through notice and comment, with amendments finalized in 2020. The U.S. Forest Service provides additional NEPA information in its Handbook 1909.15. The procedures in these regulations and handbook will be subject to the CEQ guidance review process.
Bureau of Land Management (Department of Interior): The Department of the Interior’s NEPA regulations were also promulgated in 2008 through notice and comment rulemaking and are codified at 40 C.F.R. Part 46. The Department’s NEPA process is also outlined in Departmental Manual Part 516. The procedures in these regulations and manual will be subject to the CEQ guidance review process.
How We Got Here – The Political Pendulum and Questioning CEQ’s Authority
The recent history of CEQ’s NEPA regulations will be important to how these changes will play out at federal agencies and in federal courts. The CEQ NEPA regulations were revised during the first Trump administration in 2020, only to be rescinded and again revised in the Biden administration in a multi-phase regulatory process ending in 2023. Both the 2020 rule and the subsequent 2023 rule (the “Phase 2” rule) were challenged in litigation.
President Trump’s Unleashing American Energy Executive Order in January revoked a 1977 President Carter Executive Order directing the CEQ to issue regulations to federal agencies for NEPA implementation. The Unleashing American Energy Executive Order directed CEQ to provide guidance on implementing NEPA and propose rescinding CEQ’s NEPA regulations, all in an effort to expedite and simplify the permitting process.
Adding to the potential confusion about the status of NEPA regulations, recent court decisions have also questioned CEQ’s authority to issue regulations in the first instance. For example, the D.C. Circuit in 2024 in a matter unrelated to the CEQ’s rules and the North Dakota district court ruling this month in the Phase 2 rule litigation—stated that CEQ does not have the legal authority to issue binding regulations. In forthcoming publications, Womble Bond Dickinson will unpack these cases and how they may influence near-term agency actions.
In part to stem this confusion, CEQ opted to proceed directly to an interim final rule rather than a proposed rule in an effort to bring regulatory stability faster. In the rule, CEQ also concludes it may not have the authority to maintain its NEPA regulations in the absence of the Carter-era Executive Order. More to come on that topic.
What we can expect going forward – Rapid Regulatory Processes and Litigation
While this process plays out across federal agencies, this much is clear:
In order to finalize changes by next February, agencies will need to move quickly to propose changes for any required public comment. Affected businesses will need to be alert to changes and involved in the process if they want their interests considered.
If the past is prologue, CEQ’s interim final rule and regulatory changes across agencies will likely result in litigation, potentially prolonging a period of regulatory instability and process uncertainty.
While these changes will happen quickly over the next year, this road to permitting efficiency might continue to be a long one.
The experienced environmental team at Womble Bond Dickinson has decades of NEPA experience and continuously reviews developments in permitting and NEPA processes. We can help navigate these changes, advocate for your interests, and guide you successfully through the environmental review process.
The Trump Administration: Developments in Environmental Policy
From the outset, key goals of the incoming Trump Administration have been: supporting fossil fuel development, ending incentives for renewable energy and energy transition, removing “burdensome” environmental regulations and policies, and stepping back action on climate change and environmental justice initiatives. In his first week in office, President Trump rescinded several Biden Administration executive orders regarding action on climate change and environmental justice and issued executive orders seeking to boost fossil fuel development rather than renewable energy. Actions have continued in these particular areas indicating that the Trump Administration’s focus and goals remain consistent.
On February 4, 2025, new EPA Administrator Lee Zeldin announced the EPA’s “Powering the Great American Comeback” Initiative. The announcement outlined five key pillars, all of which focus on the EPA’s role of supporting American industry consistent with Trump’s campaign goals and reiterated by Administrator Lee Zeldin in his confirmation hearing. The five pillars are:
Clean Air, Land, and Water for Every American;
Restore American Energy Dominance;
Permitting Reform, Cooperative Federalism, and Cross-Agency Partnership;
Make the United States the Artificial Intelligence Capital of the World; and
Protecting and Bringing Back American Auto Jobs.
These goals highlight the Trump Administration’s goals of having the EPA take a supporting role in American industry and fossil fuel growth while working with states and across agencies to find efficiencies.
Another important action taken by the Trump Administration is a January 30 memo that temporarily froze all federally driven environmental litigation to allow for review and potential reconsideration by the new administration. In addition, an EPA spokesperson said in an email that there is a hold on new (not yet effective) and pending (not yet published) regulations, and that, “most major decisions are undergoing a quick review process to ensure transparency and accountability to the American people.” For companies dealing with the EPA on the resolution of ongoing matters, whether in litigation or on compliance matters, this will likely lead to delays, if it has not already.
President Trump’s day one executive order “Unleashing American Energy” targeted climate action taken by the Biden Administration, barred agencies from using methodologies such as the social cost of carbon in their environmental analyses, and ordered that the disbursement of funds appropriated through the Inflation Reduction Act (IRA) and the Infrastructure Investment and Jobs Act (IIJA) be paused, and ending the electric vehicle subsidy specifically. Funds from IRA and IIJA programs remain frozen despite court orders lifting the freeze from U.S. District Court Judges Loren AliKhan and John McConnell. Both judges have now ruled that the Trump Administration has defied the courts’ early orders lifting the spending freeze, but the issue remains unresolved. Companies and projects relying on IRA and IIJA grants, funds, or incentives should continue to watch this space as the legal considerations continue to play out over the upcoming months.
Consistent with general federal employee cuts and the Trump Administration’s goals, the administration has placed 168 employees in the EPA’s Office of Environmental Justice and External Civil Rights on leave and called for the elimination of any office or position involving environmental justice. President Trump also rescinded a number of President Biden’s environmental justice executive orders on January 24, including the rescission of EO 14096 which incorporated environmental justice into all executive branch decision making, and EO 14008 which, amongst other things, established the Climate & Economic Justice Screening Tool to help to identify disadvantaged communities.
Consistent with the Trump Administration’s disagreement with the Biden Administration’s stance towards climate action and environmental justice, the climate change sections of several government websites have been taken offline, including the White House’s climate change page and climate change section on the Department of State website. In addition, the EPA’s EJScreen tool, a tool to map community vulnerabilities and identify areas experiencing disproportionate exposure to environmental hazards and impacts, has also been taken offline. Companies and organizations relying on climate and environmental justice data for their sustainability work or when conducting due diligence on new projects will need to find alternatives. A number of universities and projects like the Public Environmental Data Project have worked to keep this data available to the public.
The funding freeze has impacted renewable energy and infrastructure projects, and all stakeholders involved in these projects from contractors and construction businesses to renewable energy companies, finance parties, as well as state and local governments and tribes.
Communities and businesses undertaking federally funded environmental projects have also been impacted by the funding freeze, as have farmers who were making use of the USDA’s many grant programs. The USDA made billions of funds available for the Climate-Smart Practices program and other conservation programs like the Environmental Quality Incentives Program, but farms relying on these funds are stuck in limbo until the funding freeze is resolved.
The loss of federal resources for environmental justice will also impact project developers. While disadvantaged communities will suffer from the loss of environmental justice resources, grants, and expertise, the loss of forecasting tools like EJScreen makes it more difficult for developers to make informed decisions about the communities they would like to operate in.
CSRD Slashed: EU’s Corporate Sustainability Regulations Significantly Reduced
On 26 February 2025, the European Commission (the “Commission”) adopted a new package of proposals to simplify the regulations on sustainability. Their aim is to combine the competitiveness and climate goals of the European Union, which we reported on here, as part of their aim for a “simpler and faster” Europe.
The proposals, packaged in an “Omnibus”, dramatically reduce the scope and reporting required under the Corporate Sustainability Reporting Directive (“CSRD”), the Corporate Sustainability Due Diligence Directive (“CSDDD”) and the EU Taxonomy (“Taxonomy”).
We set out below the key changes proposed for CSRD.
The Omnibus’ aims for the CSRD are to make it “more proportionate and easier to implement by companies” through:
Reduction of scope:
“large undertakings” in scope of CSRD are redefined as those with over 1000 employees on a group or standalone basis, rather than 250 employees, with the financial thresholds of EUR 50 million turnover or a balance sheet total above EUR 25 million remaining static. This is significantly impactful reducing the scope of companies in scope of CSRD by around 80% (and aligns more with the CSDDD threshold). Listed SMEs are no longer in scope unless they meet the “large undertakings” thresholds; and
non‑EU parents will only be in scope of CSRD if they generated EU‑derived turnover of EUR 450 million, rather than EUR 150 million, with either an EU large undertaking meeting the revised thresholds set out above or with an EU branch with EUR 50 million in turnover to align with that required of “large undertakings”, revised upwards from EUR 40 million.
Postponement of reporting: for those companies who were due to report on year 2025 in year 2026 who remain in scope as they have over 1000 employees, there will be a two‑year delay to reporting.
A shield – the value chain cap: for companies not in scope of the CSRD (those with less than 1000 employees), the Commission will adopt by a delegated act a voluntary reporting standard leveraging the standard that was developed for SMEs. This standard is intended to act “as a shield” by limiting the amount of information that companies and banks falling into scope of the CSRD can request from companies in their value chains with few than 1,000 employees.
Reporting standards to be revised: the European Sustainability Reporting Standards (“ESRS”), which are at the heart of CSRD’s requirements, are to be revised via a delegated act to substantially reduce the number of data points, clarify unclear provisions and improve consistence with other legislation. They will remove datapoints that are deemed least important for general purpose sustainability reporting, prioritise quantitative datapoints over narrative text and further distinguish between mandatory and voluntary datapoints. Clearer instructions will be provided on how to apply the materiality assessment process. There is also reference to making sure that there is “very high” interoperability with global reporting standards.
No sector‑specific standards will be required
Limited assurance to remain: there will be no uplift to reasonable assurance over time.
Next steps
There is no impact assessment on the potential economic, social and environmental effects as the Commission has deemed the Omnibus to be so urgent and important that a derogation from the need to provide the impact assessment was granted under the Commission’s Better Regulation Guidelines. However, the market and a range of stakeholders will no doubt hotly debate the impact across all these areas. The Commission itself acknowledges that the proposed changes to CSRD may “partially diminish the positive impacts” but that the “reduction of administrative burden” should lead to economic and competitive gains.
The Commission has called on the European Parliament and European Council to “reach rapid agreement” on the proposals. The legislation needs European Parliament approval with a majority of MEPs voting in favour and at least 55% (15 out of 27) of Member States voting in favour at the European Council. It will then come into force following its publication in the EU Official Journal.
This legislation is also in the form of a Directive and requires national transposition by each Member State, which had not yet occurred across the EU for the current guide of CSRD. It could be that we witness some gold‑plating or an emergence of a range of EU Member State expectations through national guidelines at a juxtaposition with the aims of the EU’s Single Market.
Lawsuit Alleges FDA Has Unduly Delayed Response to PFAS Petition
Last month a lawsuit filed by plaintiffs including the Tucson Environmental Justice Task Force (TEJTF) filed suit against FDA and now former FDA commissioner Robert Califf alleging that FDA had unduly delayed in responding to a petition filed by TEJTF in 2023 which had requested that FDA set tolerances for 30 types of PFAS in lettuce and blueberries and 26 types of PFAS in bread, milk, eggs, salmon, clams, and corn silage.
The lawsuit argues that FDA has unduly delayed because it has not acted consistent with its statutory mandate to “promote public health by promptly and efficiently reviewing clinical research and taking appropriate action on the marketing of regulated products in a timely manner” (21 USC § 393) and the delay allegedly is to the determinant of the public health. The lawsuit argues that prior decisions holding that courts should defer to FDA on whether to promulgate tolerances is no longer good law post-Chevron and that the “only discretion FDA may exercise for such chemicals [harmful substances] is the level of tolerance to be set.”
We will continue to monitor and report on the regulation of PFAS and other chemicals, including any changes in approach that may be implemented by the new administration.
Mass. “Unlocking Housing Production Commission” Recommends Land Use and Zoning Reforms
Last Friday, Massachusetts’ “Unlocking Housing Production Commission,” established by Gov. Maura Healey in October, 2023, released its report titled “Building for Tomorrow.” The report lays out a series of recommendations to address the Commonwealth’s housing crisis, organized into several categories: Economic Incentives and Workforce Development; Land Use and Zoning; Regulations, Codes, and Permitting; and Statewide Planning and Local Coordination. Some of the recommendations are realistic and achievable; others are pie-in-the-sky pipe dreams that could never happen in the current environment (or, in some cases, in any imaginable future environment).
Of interest to regular readers of this blog, the report makes the following recommendations under the heading of Land Use and Zoning.
Eliminating Parking Minimums. Noting the significant effect on housing costs of mandatory surface and structured parking, and the corresponding consumption of land that could be beneficially used for other purposes, the Report recommends: (1) Eliminating parking minimums statewide for residential uses; and (2) Requiring municipalities to establish transportation demand management requirements as a condition for allowing off-street parking associated with new housing.
40A Reforms. The Report makes six recommendations to reform the state Zoning Act, Chapter 40A:
(1) Adding a statement of the purposes of zoning back into Chapter 40A. Such a statement was part of the bill establishing the current Zoning Act in 1975, but was not included in the statute as codified in the General Laws. One of the stated purposes of zoning is “[encouraging] housing for persons of all income levels.” The Report sees re-inserting the statement of purposes into Chapter 40A as an opportunity to highlight the role of zoning in addressing the Commonwealth’s housing needs.
(2) Incentivizing or requiring zoning to align with municipal master planning. The Report notes that many communities create master plans with 10- or 20-year growth strategies, but outdated zoning regulations often hinder achievement of these goals.
(3) Codifying site plan review. The Report observes that site plan review, which has become a key component in most municipal permitting regimes, is a creature of the common law that’s unregulated by Chapter 40A or any other statute. As a result, the process varies greatly from one municipality to the next, and often has the effect of making the development of housing more difficult and costly. The Report recommends codifying site plan review under Chapter 40A, including setting time limits, establishing uniform, objective criteria, allowing for tiered review systems depending on the size and scope of a project, and clarifying that notice to abutters is not required.
(4) Converting zoning appeals to court from their current status as “de novo” appeals to proceedings limited to the record that was before the local zoning board. The Report describes the benefit of this change as “prevent[ing] abutters from raising new issues on appeal that were never raised during the local approval process for the explicit purpose of delaying a project.” Amen to that.
(5) Amending Chapter 40A to add appeals of building permits to the list of appeals for which the defendant may move the court to require the plaintiff to post a bond. Currently, the statute only authorizes the imposition of a bond in appeals of special permits, variances, and site plans. The Report suggests this change “will strengthen the appeals process and disincentivize parties from levying baseless appeals.” Amen to that too.
(6) Requiring that land use appeals concerning the construction of 25 or more housing units be heard in the Land Court’s Permit Session, which offers attentive case management by the court and expedited timelines. Currently, under M.G.L. c. 40A, § 3A, appeals concerning projects involving 25 or more dwelling units may be brought in the Permit Session, or transferred there on the motion of any party, but are not required to be heard there.
The Report cites the following benefits of these proposed changes to Chapter 40A: strengthen the legal foundation for zoning to support housing production; reduce legal challenges and uncertainty for housing development; ensure zoning supports long-term housing and economic goals; improve permitting transparency and efficiency; streamline development timelines and reduce project costs; and enhance coordination between planning and zoning implementation.
Expanding Multifamily Housing Options. The Report makes two recommendations in this regard: (1) the Commonwealth should allow, by right, two-family homes on all residential lots and four-family homes on all residential lots with existing water and sewer infrastructure; and (2) the Commonwealth should require all municipalities to create multifamily zoning zoning districts, including by-right zoning for multi-family units proportional to each municipality’s overall housing stock, minimum density standards, requirements to ensure suitability of units for families with children, protection for environmentally sensitive land, and flexibility for municipalities to determine the size and location of multi-family projects, “with incentives for development near transit, commercial corridors, and job centers.”
Minimum Lot Size Reform. Under this heading the Report has two recommendations: (1) eliminate residential minimum lot sizes statewide; and (2) allow residential lot mergers, lots splits, and use of substandard lots statewide to create multifamily housing by right, except in environmentally sensitive areas and on excluded lands. Whoa. Can you say “non-starter”?
40R Reforms. Chapter 40R is a 2004 law that offers incentive payments to municipalities that create zoning districts in which high-density residential and mixed-use development, with a minimum of 20% affordable housing, is allowed by right. The Report acknowledges that Chapter 40R has been mildly successful, producing over 7.000 housing units, but observes that this pace is inadequate to address the Commonwealth’s huge housing shortage. The Report makes two recommendations to improve Chapter 40R: (1) scale affordability requirements to density, meaning require a higher percentage of affordable units at higher density levels, while maintaining “a non-negotiable minimum percentage of affordable units for each tier of density”; and (2) amend the statute to eliminate so-called “zoning incentive payments” to municipalities and instead channel those funds into bonus payments for units actually built, with a portion of the funds paid to the municipality and a portion paid directly to the developer.
40B Reforms. The Report recommends several changes to Chapter 40B, the Commonwealth’s groundbreaking 1969 statute that offers developers the opportunity to get a single “comprehensive permit” from the local zoning board, and avoid local zoning and other regulations, in municipalities that don’t have at least 10% affordable housing. Those recommendations are to strengthen Chapter 40B by (1) streamlining and speeding up the appeals process, including by expanding staffing at the Housing Appeals Committee, which hears developers’ appeals from adverse local decisions; (2) require parties who appeal comprehensive permits to post a mandatory bond to discourage baseless appeals; (3) increase the frequency of housing stock counts and updates to the state’s Subsidized Housing Inventory (SHI); (4) eliminate the requirement that affordable units must receive a financial subsidy to count towards the municipality’s SHI and instead treat oversight by and technical assistance from the Executive Office of Housing and Livable Communities and affiliated agencies as a form of subsidy; and (5) offer major financial incentives to municipalities that exceed the 10% statutory baseline, including grants for infrastructure improvements and technical assistance.
As noted, some of the Report’s recommendations – for example, allowing two-family homes by right on all residential lots and eliminating minimum lots sizes statewide – are unrealistic and politically unachievable given Massachusetts’ strong Home Rule tradition. Others are plausible and something to strive for – particularly the proposed reforms to Chapter 40A, some of which have been bandied about for years, and which can be seen as a logical extension of the pro-housing reforms the Legislature enacted last summer (see our coverage of that important bill here).
California Bill Would Authorize The Secretary Of State To Revoke Business Licenses, But There Is Just One Problem . . .
In California’s continuing war on businesses, a legislator recently introduced a bill to enact the “Polluters Pay Climate Superfund Act of 2025”, AB 1243 (Addis). This bill would establish the a program to be administered by the California Environmental Protection Agency to require fossil fuel polluters to pay their “fair share” of the damage caused by greenhouse gases released into the atmosphere between 1990 and 2024, inclusive, that resulted from the extraction, production, refining, sale, or combustion of fossil fuels or petroleum products. The bill would require Cal-EPA to “name names” of “responsible parties” within 90 days of the effective date of the law. The bill defines a “responsible party” as an entity with a majority ownership interest in a business engaged in extracting or refining fossil fuels that, during the covered period, did business California or otherwise had sufficient contact with the state, and is determined by the agency to be responsible for more than 1 billion metric tons of covered fossil fuel emissions, as defined, in aggregate globally, during the covered period. Notably, the bill provides”
The Secretary of State shall have the authority to revoke or suspend the business license of a responsible party that fails to comply with this part.
The bill does not define “business license”. In any event, the Secretary of State does not issue business licenses. These are typically issued by local governments, such as cities and counties.
Joshua Tree Conservation Plan Remains Under Review
The California Fish and Game Commission (Commission) accepted public comment on the draft Western Joshua Tree Conservation Plan (Draft Conservation Plan) at its February 12, 2025 meeting, but no formal action was taken.
As detailed in our previous alert, the California Department of Fish and Wildlife (CDFW) released the Draft Conservation Plan to the Commission on December 12, 2024, as required by the Western Joshua Tree Conservation Act (Act). The Draft Conservation Plan sets forth management practices and guidelines for the avoidance and minimization of impacts to western Joshua trees.
The Commission’s February 12 meeting featured a presentation by CDFW, substantive discussion by the Commissioners, and robust public comment. Many commenters expressed concern about the cost and ultimate feasibility of the Draft Conservation Plan’s requirements. In particular, the Large Scale Solar Association voiced concerns regarding the Draft Conservation Plan’s potential to interfere with the siting and development of solar energy projects, indicating that additional costs generated by required mitigation measures would be passed on to ratepayers. Residents and politicians from desert communities — where Joshua trees are most abundant — focused on the Draft Conservation Plan’s costs and obligations as potential hindrances to affordable housing and local job opportunities. Commenters emphasized that collaboration with CDFW is essential in developing a workable and sustainable conservation effort.
CDFW acknowledged the public comments and ultimately declined to take any formal action at the meeting. Written comments are still being accepted on a rolling basis, though any substantive changes to the Draft Conservation Plan should be submitted by the beginning of March to be considered. The Act mandates that the Commission must take action to adopt the Conservation Plan by June 30, 2025.
The Commission will review the Draft Conservation Plan again at its April 16-17, 2025, meeting. In advance of that meeting, CDFW confirmed it will publish a revised set of Joshua tree relocation guidelines and a list of proposed changes to the Draft Conservation Plan. CDFW Director Bonham also suggested that, in the interim, CDFW may host workshops and/or other community outreach events to solicit further public feedback, though no further details have been provided.