Tax – Page 3 – Law Ivy

Homelessness Crisis Demands Action

We have seen a dramatic increase in housing insecurity among our pro bono clients in recent years. Unfortunately, it’s part of an alarming nationwide trend. According to a recent report issued by the U.S. Department of Housing and Urban Development (HUD), homelessness reached a record high in 2024. Indeed, the report found that the number of people experiencing homelessness in the United States – more than 770,000 – grew by 18% from the previous year, while the number of people in families with children experiencing homelessness increased by 39%. In a post-pandemic economy that is generally considered to be doing well, it seems counterintuitive that we would now be experiencing such growing hardship. The report points to several factors driving these numbers:
Our worsening national affordable housing crisis, rising inflation, stagnating wages among middle- and lower-income households, and the persisting effects of systemic racism have stretched homelessness services systems to their limits. Additional public health crises, natural disasters that displaced people from their homes, rising numbers of people immigrating to the U.S., and the end to homelessness prevention programs put in place during the COVID-19 pandemic, including the end of the expanded child tax credit, have exacerbated this already stressed system.
Economic insecurity makes any legal issue more difficult to handle and, as discussed in a recent post about a client whose child was temporarily removed from her care because she had trouble finding stable housing, it can also be the very cause of a legal issue. HUD’s eye-opening report reinforces the importance of taking on more pro bono matters in housing and family courts. As a profession, lawyers also need to expand the scope of assistance that nonlawyers can provide to unrepresented litigants and prioritize the development of AI and other technology to help bridge the justice gap. A great example of this type of advocacy is Housing Court Answers, a legal services organization in New York City embracing AI to help litigants in housing repair actions.
Taking a step back, HUD’s report underscores the urgent need to develop affordable housing and provide greater assistance to secure the safety and security of families and children. Not only is this sense of urgency lacking across the country, but the response to homelessness from local authorities is too often punitive in nature. Of note, last summer, the Supreme Court in Grants Pass v. Johnson upheld a local Oregon law prohibiting camping inside parks, sidewalks and other public property. The Court rejected the argument that punishing people for sleeping outside when they have no place to go constituted cruel and unusual punishment under the Eighth Amendment. Regardless of the Eighth Amendment’s reach, however, one thing is clear: relying on criminal law to solve the homelessness problem does not work. As Justice Sotomayor explained in her dissent, “[f]or people with nowhere else to go, fines and jail time do not deter behavior, reduce homelessness, or increase public safety.”

Powering Progress: Navigating the Intricacies of On-Site Nuclear Generation

Key Points:

Behind-the-meter nuclear projects require careful coordination with grid operators and utilities, involving detailed interconnection studies and agreements to manage power flows and ensure system reliability.
Regulatory challenges may arise from state laws granting exclusive service territories to utilities, particularly when third-party ownership structures are involved. These issues require state-specific analysis and navigation.
Project developers must engage early with regulators, secure necessary approvals, and navigate complex state and federal regulations, including potential state commission proceedings for larger projects.
Successful development hinges on understanding local economic, environmental, and tax policies, building strong relationships with regulators and supporters, and securing experienced legal representation familiar with large-scale energy projects.

Small modular reactors (SMRs) can be collocated with high demand customers such as data centers and large manufacturing and chemical facilities to provide electric energy and capacity to them directly. Behind-the-meter nuclear generation may be a practical response to issues related to the cost, reliability, and schedule availability of power from incumbent utilities particularly given the size, scalability, constructability, safety, efficiency, and reliability of SMRs. Clients considering such a colocation strategy should consider a range of practical and regulatory issues.
NRC Licensing
Under the 1954 Atomic Energy Act, the Nuclear Regulatory Commission (NRC) is mandated to license nuclear power generating facilities. For traditional large scale nuclear reactors, which typically produce more than 700 MW(e), the NRC process for approval of design and siting has been very expensive and time consuming. There are current proposals by developers, states, and Congress, to either re-interpret or amend the NRC’s “utilization facility rule” to allow the design and siting of SMRs and microreactors, which typically produce no more than 300 MW(e) – with some as low as 10 MW(e) – to be exempted from much of this traditional approval process. Despite potential changes, the NRC will likely still need to approve the design and location of SMRs before they can be deployed. Additionally, state regulators may play a larger role in this process.
Compatibility with Load
Nuclear power plants are designed to operate continuously at high capacity, making them ideal for supplying electricity to consumers with steady, round-the-clock demand. These consumers typically don’t experience significant fluctuations in their energy needs on a daily or seasonal basis. Industries or facilities with consistent energy requirements, regardless of time of day or season, are particularly well-suited to the output profile of nuclear plants.
However, it’s important to recognize that all electrical loads have some degree of short-term variability. Additionally, allowances must be made for both planned maintenance outages and unexpected events, which can affect both the nuclear power plants and the facilities they serve.
While some operations, such as remote mining or refining facilities, can function as isolated microgrids without a connection to the main utility grid, this is not feasible for all potential users with variable loads. Many users (data centers, for example) must rely on additional measures to ensure uninterrupted processes. These backup options may include battery storage systems, peaking facilities for handling demand spikes, or maintaining a connection to the main power grid.
This approach ensures a reliable power supply that can accommodate both the steady baseload provided by nuclear plants and the inevitable fluctuations in demand, planned outages, and unforeseen circumstances.
Utility Service Agreements
When using the electric grid to supplement on-site nuclear generation or absorb excess power, project developers must coordinate with the incumbent public utility. The terms of the electric service agreement will vary based on the utility’s tariffs and regulatory structure.
In regions with vertically integrated investor-owned utilities (common in the South and Mountain West), a single agreement may cover both power supply to the facility and excess power sent to the grid.
In competitive markets, the incumbent utility provides grid interconnection and possibly emergency supply, while competitive suppliers handle other services. This may result in separate agreements for grid connection and power market transactions.
Qualified Facility (QF) Status
On-site generation facilities that can utilize waste heat or steam from nuclear units may qualify for Qualified Facility (QF) status under federal law. This status can provide significant advantages for selling power back to the grid. QF status creates a must-take obligation for the incumbent electrical supplier, primarily in areas without wholesale competition. Consequently, these benefits are mainly available in regions where power supply markets are not deregulated.
The Terms of Utility Service Agreements
The terms of the electric service agreement will depend on which utility serves the location in question and the specific market structures tariffs, regulatory policies and statutes that govern that utility’s operations. Forty-two regional transmission operators (RTOs), independent system operators (ISOs) and major electric utilities serve 85% of U.S. load, but there are many more electric utilities and cooperatives that operate under RTO and ISO umbrellas. Among the hundreds of incumbent utilities, there is tremendous variation in the rules and practices that might determine what sort of utility service agreement might be negotiated to support on-site nuclear generation. There is no one-size-fits-all answer. A case-by-case review of the statutory and regulatory structure for each location is necessary.

Flexibility in the Terms of Utility Service Agreements
Currently, there’s little standardization in utility contracts for behind-the-meter nuclear projects. In supportive utility and regulatory environments, developers may have room to negotiate agreements tailored to their specific needs.
Many utilities have tariff provisions for traditional behind-the-meter generation and net metering, often limiting capacity to very low megawatts. These tariffs typically target much smaller projects and should not be considered definitive for behind-the-meter nuclear developments.
Project developers may negotiate with utilities and seek regulatory approval for customized terms on a case-by-case basis. In jurisdictions supportive of behind-the-meter nuclear generation or the facilities it will serve, even statutory limitations might be addressed through potential amendments.
Transmission Interconnection
Facilities using behind-the-meter nuclear generation will connect to the grid at transmission voltages. The incumbent transmission system operator, typically a Balancing Area Authority (such as an RTO, ISO, or utility), must study potential power flows to and from the facility. These studies determine the cost and schedule for grid interconnection.
The studies assess the grid’s ability to handle the facility’s maximum anticipated electricity demand and energy injection, particularly during peak demand periods. They identify necessary facility additions or upgrades to accommodate these power flows within system operating parameters. This includes specific transmission lines and transformers for the facility, as well as any required system-wide upgrades.
These interconnection studies rely on reliability criteria and power flow models maintained by utilities to comply with National Electric Reliability Council (NERC) standards, as enforced by the Federal Energy Regulatory Commission (FERC).
The process typically occurs in phases: feasibility studies or transmission impact assessments (TIAs), followed by interconnection studies and facilities studies. Each phase provides greater detail on costs and schedules.
Transmission providers usually require developers to demonstrate a binding commitment to proceed beyond feasibility studies. Developers must pay for these studies or agree to cover costs if the project does not reach completion or justify the expense through sufficient load.
The process concludes with an Interconnection Agreement, which establishes a fixed price for transmission upgrades and an interconnection schedule. Utilities may face FERC penalties for failing to meet agreed timelines.

Queuing Projects
Behind-the-meter nuclear projects often transfer excess power to the grid when generation exceeds on-site demand. Consequently, these projects join the transmission provider’s generation interconnection queue alongside solar, wind, and fossil fuel projects.
Recent Federal Energy Regulatory Commission orders require transmission utilities to analyze multiple interconnection requests in batches at least annually. The timing of these requests significantly impacts both cost and interconnection timeline.
As customer demand grows, more extensive upgrades become necessary to accommodate additional power, increasing interconnection costs and delays. Therefore, securing an early position in the queue is crucial for behind-the-meter generation projects to optimize both cost and schedule.
Siting Acts and Certificate of Public Necessity and Convenience Statutes
Many states require utility commission approval for major electric transmission and generation projects before construction begins. This is typically mandated by siting acts or certificate of public necessity and convenience statutes. These laws often define major generation projects as those with at least 75-80 MW capacity.
Behind-the-meter nuclear generation projects in this range may require pre-construction approval through a state commission proceeding. Similarly, the incumbent utility must seek approval for any associated major transmission facilities.
While behind-the-meter nuclear projects should easily meet the substantive requirements for a certificate due to their direct link to on-site load, these proceedings can attract political opposition. Therefore, project developers should approach this process with careful preparation and not take approval for granted.
Third Party Ownership
Financial structures where a third party owns the nuclear facility, rather than the on-site energy user, can create regulatory challenges. These issues arise from state statutes and regulatory frameworks that either grant exclusive service territories to incumbent utilities or classify any entity providing electric service to the public as a regulated electric utility.
These regulatory hurdles are typically avoided when a party operates generation resources solely for its own consumption or only sells excess generation into wholesale markets. However, in states with strict interpretations of territorial service rights, transactions may be prohibited if the nuclear facility owner differs from the on-site energy user. This arrangement could be viewed as violating the incumbent utility’s exclusive territorial service rights.
It is important to note that states vary widely in their interpretation of these statutes. Consequently, there’s no one-size-fits-all solution to this regulatory landscape. A thorough state-by-state analysis of relevant statutes, commission orders, and appellate court decisions is essential to navigate these complexities effectively.
Economic Development, Land Use, Zoning, Environmental, and Tax Issues
Developing a successful behind-the-meter nuclear generation project demands careful navigation of state-specific laws, policies, and practices. This includes economic development, land use, zoning, environmental, and tax issues.

Early engagement is crucial. Establishing strong relationships with staff and regulators at the project’s outset can be decisive in withstanding potential disruptions from other parties or interest groups. Identifying champions and supporters, and securing entitlements early, are key strategies.
Legal representation with local knowledge and experience in similar large-scale development projects is essential. Such expertise can help anticipate challenges and streamline the complex regulatory process.
By addressing these factors proactively, developers can create a solid foundation for their project, enhancing their chances of success in the face of potential obstacles.

Let It Be…Taxed? The Carried Interest Debate Continues

On February 6, Congressional Republican leaders met with President Donald Trump to address the Trump Administration’s 2025 budget and tax priorities. During that meeting, the Trump Administration proposed to eliminate capital gains tax treatment on carried interest.
On that same day, Democrats in the House and Senate introduced bills to completely eliminate capital gains tax treatment on carried interest.
Background and Takeaways

Carried interest is generally a form of equity compensation granted to investment fund managers (e.g., private equity, venture capital or hedge funds) in exchange for investment services provided to the fund. The typical fund structure used by sponsors enables fund managers to benefit from long-term capital gains tax treatment (e.g., 20%) on their carried interest when underlying fund investments are sold, as opposed to ordinary income tax treatment more typically imposed on wage or service income (e.g., up to 37%).
The tax benefits provided by carried interest to fund managers have been under political pressure since 2006. Under the Trump Administration in 2017, the Tax Cuts and Jobs Act of 2017 (TJCA) was enacted and increased the one-year holding period requirement to a new three-year holding period requirement for fund managers to generate long-term capital gains treatment on their carried interest.
Most recently, carried interest survived more pressure during the enactment of the Inflation Reduction Act of 2022, when Senator Kyrsten Sinema (D-AZ) successfully opposed an increase to the three-year holding period requirement for carried interest.
It remains to be seen how the Trump Administration’s tax priorities with respect to carried interest will be implemented and how quickly tax legislation will move through the legislative process during 2025.
The Senate has taken the lead in the budget reconciliation process and is marking up a budget resolution this week, suggesting that a two-bill approach to 2025 tax legislation may be more likely than the one-bill approach favored by House Republican leadership. The Senate’s two-bill approach would likely push substantive tax legislation to the latter half of 2025. However, the House Budget Committee announced yesterday it will move forward with its markup of a budget resolution in tandem with the Senate this week, throwing into question the two-bill approach favored by Senate Republicans. In short, the timing of when substantive tax legislation will move through Congress is currently in flux.
Fund managers and investors should remain focused on 2025 tax legislation. Many fund agreements provide general partners the right to make certain unilateral changes to their fund agreements in the event of a change in taxation of carried interest. Thus, fund managers and investors should review existing fund documents to determine their potential strategic options if modifications to carried interest rules are enacted (e.g., does the fund agreement include provisions addressing such changes in law?).
Fund managers and investors looking ahead to future (or current) negotiations of fund documents should consider including protective language in such fund documents to mitigate downside economic exposure to changes in law that reduce the after-tax value of their carried interest or that could otherwise affect investors’ legal or commercial positions.

Final Regulations Issued on Allocation of Partnership Liabilities Under Section 752

Introduction
On December 2, 2024, the U.S. Department of the Treasury (“Treasury”) and the Internal Revenue Service (the “IRS”) published final regulations (the “Final Regulations”) on section 752[1] regarding the allocation of partnership recourse liabilities in situations in which multiple partners and related parties bear part or all of the economic risk of loss (“EROL”) for partnership liabilities.[2] The Final Regulations largely adopt the proposed regulations (the “Proposed Regulations”) published on December 16, 2013 and, as such, should not result in substantial changes to the application of the rules under section 752.[3] In particular, these rules generally do not limit the ability of partners and related parties to use contractual arrangements, including guarantees, to specify the manner in which debt will be allocated among the partners.[4]
Background
Very generally, section 752 governs the allocation of liabilities and income or loss arising from debt among partners in a partnership and specifies how these liabilities affect a partner’s tax basis in its partnership interest.[5] Section 752 has been interpreted in the Treasury Regulations as intending to maintain the proper alignment between a partner’s basis and its share of a partnership’s debts based on the partner’s economic risk of loss with respect to the partnership, an approach which Congress has broadly endorsed.
The rules for determining a partner’s share of a partnership’s liabilities depend on whether the debt is recourse or nonrecourse. For a liability to be considered recourse, a partner or a related person must bear the EROL in respect to that liability – roughly speaking, a liability is nonrecourse to the extent that no partner or related person bears the EROL with respect to the liability. The Final Regulations address only the allocation of a partnership’s recourse liabilities.
A partner generally bears the EROL for a partnership liability to the extent that, in a constructive liquidation of the partnership where all of its assets (including cash) become worthless and all of its liabilities become due and payable, the partner or a related person would have a payment obligation to any person (or a capital contribution obligation to the partnership) with respect to the liability. Additionally, a partner generally bears the EROL for a partnership liability to the extent that the partner or a related person (i) is a lender of a nonrecourse loan for which no other partner bears the EROL; (ii) guarantees interest payments on a partnership nonrecourse liability (but only with respect to liability for such guaranteed interest); or (iii) pledges property as security for the partnership liability. The basic rule under section 752 is that a partner is allocated a share of a partnership liability to the extent that it bears the EROL with respect to that liability. The Final Regulations provide details on various, more complicated fact patterns that frequently arise in interpreting the EROL principle of allocating partner recourse debt for purposes of section 752.
The Final Regulations
As discussed in further detail below, the Final Regulations provide guidance on the (i) allocation of liabilities where there is overlapping EROL, (ii) application of section 752 in situations involving tiered partnerships, and (iii) allocation of liabilities among related parties. The Final Regulations additionally modify the section 704 regulations to provide clarity in rules for allocating nonrecourse deductions in tiered partnerships.
I. Overlapping EROL
The Final Regulations include a proportionality rule for determining each partner’s share of a partnership liability in situations in which multiple partners bear the EROL with respect to the same liability (“overlapping EROL”).
When the proportionality rule is triggered, each partner’s EROL for a partnership liability (or portion thereof) is determined by multiplying the total amount of the partnership liability (or portion thereof) by the following fraction: (i) the amount of EROL borne by the partner (i.e., the numerator); divided by (ii) the aggregate the EROL borne by all partners (i.e., the denominator). This rule prevents double counting of EROL with respect to the same liability.
For example, assume that A and B are 50:50 partners in partnership AB, which has borrowed $100 from a bank. A has guaranteed repayment of $100, and B has guaranteed repayment of $50 (if any amount of the loan is not repaid). The partnership liability is $100, or the amount of the loan.[6] The sum of the EROL borne by all partners with respect to this liability (as determined prior to application of the overlapping EROL rules) is $150. Thus, the amount of EROL borne by each of A and B is calculated as follows.

With respect to A: $100 (the total partnership liability) multiplied by the quotient of $100/$150 (the amount of EROL borne by A individually over the aggregate EROL borne by both A and B) for an EROL of $66.67 for A.
With respect to B: $100 (the total partnership liability) multiplied by the quotient of $50/$150 (the amount of EROL borne by B individually over the aggregate EROL borne by both A and B) for an EROL of $33.33 for B.

II. Tiered Partnerships
Under the Final Regulations, with respect to a partnership (the “upper-tier partnership” or “UTP”) that owns an interest in another partnership (the “lower-tier partnership” or “LTP”), the liabilities of the LTP are allocated to the UTP in a total amount equal to (without duplication) (i) the EROL directly borne by the UTP with respect to such liabilities, plus (ii) the EROL for such liabilities borne by any partner of the UTP, but only if the partner is not also a partner in the LTP. The Final Regulations also clarify that if an LTP liability is treated as a UTP liability under Treas. Reg. Sec. 1.752-4(a), the UTP is considered to bear the EROL for that liability, and therefore, partner nonrecourse deductions attributable to the LTP’s liability must be allocated to the UTP under Treas. Reg. Sec. 1.704-2(i). If a partner of the UTP is also a partner of the LTP, such partner bears the EROL with respect to a LTP liability directly, then prior to determining the amount of LTP liabilities that are allocated to the UTP, the LTP must first determine the allocation of the LTP liability to the direct partner, applying the proportionality rule discussed above as necessary.
An example adapted from the Final Regulations that illustrates the application of the proportionality rule in the case of a tiered partnership is below.
A and B (which is unrelated to A) contribute $810 and $90 to UTP, a limited liability company treated as a partnership for U.S. federal income tax purposes, in exchange for a 90% and 10% respective interest in UTP. UTP contributes the $900 to LTP, a partnership for Federal tax purposes, in exchange for a 90% interest in LTP and A contributes $100 directly to LTP in exchange for a 10% interest in LTP. UTP and LTP both reported losses in their initial years that reduced the basis of each partner in UTP and LTP to zero. LTP borrows $100 UTP and LTP both had no income in the year at issue. A and B both provide their personal guaranty for the entire amount of the LTP’s liability.
A’s share of the LTP liability is calculated by determining A’s EROL and then applying the proportionality rule. A and B each have an EROL of $100 with respect to the LTP liability as a result of their personal guarantees. Applying the proportionality rule, A’s share of the LTP liability is $50, or the product of $100 (the total amount of the LTP liability) by $100 (A’s EROL) over $200 (the aggregate EROL borne by A and B). B’s share of the LTP liability is similarly $50.
The LTP allocates $50 of liabilities to A for A’s direct interest in the LTP liability. LTP allocates $50 of liabilities for which B bears the EROL to UTP under the tiered partnership rules. The UTP treats its $50 share of the LTP liability as a liability of UTP. Because the $50 liability allocated to UTP only includes amounts for which B alone bears the EROL, UTP allocates all $50 to B and none to A.[7]
III. Related Party Rules
A partner is generally treated as bearing the EROL with respect to a partnership liability to the extent a person related to the partner directly bears the EROL.[8] The preamble to the Final Regulations include a “related partner exception,” which provides that “if a person who owns (directly or indirectly through one or more partnerships) an interest in a partnership is a lender or has a payment obligation with respect to a partnership liability, or portion thereof, then other persons owning interests directly or indirectly (through one or more partnerships) in that partnership would not be treated as related to that person for purposes of determining the EROL borne by each of them for the partnership liability, or portion thereof.”
For example, assume AB partnership is owned 60/40 by A and B. A and B are related persons for purposes of the section 752 regulations. A personally guarantees a $100 loan made to AB. Under the related party exception, because A directly bears the EROL for the loan as a result of its guaranty, B and A are not treated as a related persons for purposes of determining B’s EROL with respect to the loan. Because A is bears the EROL for the entire $100 liability and B does not bear any EROL, the $100 liability is allocated solely to A.
In addition, the Final Regulations include a special rule for an instance of overlapping EROL where a person (other than a direct or indirect partner of the partnership) that directly bears the EROL for a partnership liability is considered related to multiple partners of the partnership.[9] Under this rule, those partners related to the person directly bearing the EROL for the partnership liability share the liability in proportion to each related partner’s interest in the partnership.
For example, assume that A owns all of the stock of a corporation X, which in turn owns all of the stock of corporation Y. A and X are 70:30 partners in AX, a partnership for U.S. federal income tax purposes, which borrows $100. Y has guaranteed repayment of the $100 loan. Applying constructive ownership rules, Y is related to both A and X. Under the Proposed Regulations, because A and X are both related to the person directly bearing the EROL, the $100 liability would be allocated equally between A and B. In contrast, under the Final Regulations A and X share the liability in proportion to their interests in AX profits, with $70 allocated to A and $30 allocated to X.
Finally, the Final Regulations provide an ordering rule for the related party rules and proportionality rules. Under this ordering rule, the related partner exception applies first, followed by the rule for allocating liabilities where multiple partners are related to a non-partner directly bearing the EROL for a partnership liability, and then finally the proportionality rule.
Implications & Effective Date
As the Final Regulations largely adopt the Proposed Regulations, for many taxpayers, the Final Regulations will not result in substantial changes to the application of the section 752 rules that have existed in proposed form since 2013. Still, the Final Regulations helpfully clarify ambiguities in the Proposed Regulations, which results in greater certainty for taxpayers.
The Final Regulations are generally effective for all partnership liabilities incurred or assumed on or after December 2, 2024. However, the Final Regulations do not apply to any liabilities incurred or assumed by a partnership pursuant to a written binding contract in effect prior to December 2, 2024. Further, partnerships may elect to apply the Final Regulations to all liabilities with respect to returns filed on or after December 2, 2024 (including preexisting partnership liabilities), as long as the partnership applies the rules consistently and in their entirety to all its liabilities. In addition, the Final Regulations treat certain refinanced debt of a partnership that is modified or refinanced on or after December 2, 2024 as incurred or assumed by the partnership prior to December 2, 2024 to the extent of the amount and duration of the pre-modified debt; accordingly, the Final Regulations do not apply to such refinanced debt (absent the election described above).
Partnerships may wish to consult with their tax advisors regarding the desirability of an election to apply the Final Regulations to all liabilities with respect to returns that will be filed on or after December 2, 2024.

[1] All references to “section” are to the Internal Revenue Code of 1986, as amended, or to the Treasury Regulations promulgated thereunder.
[2] T.D. 10014.
[3] REG-136984-12.
[4] Such allocations must correspond to economic reality and in particular the allocation of debt must generally be to creditworthy partners.
[5] More specifically, section 752(a) treats an increase in a partner’s share of partnership liabilities (or an increase in a partner’s individual liabilities through its assumption of the partnership’s liabilities) as if the partner contributed money to the partnership (thus, increasing the partner’s tax basis in its partnership interest). Section 752(b) treats a decrease in a partner’s share of partnership liabilities (or a decrease in a partner’s individual liabilities through the partnership’s assumption of the partner’s liabilities) as if the partnership distributed money to the partnership (thus, decreasing the partner’s tax basis in its partnership interest).
[6] This example further assumes that no applicable state or local law or contract provides for reimbursement from the other party or otherwise differently allocates responsibility for the liability as between A and B.
[7] This assumes that no state or local law or contract specifies otherwise.
[8] Parties are considered related when one party has a significant level of ownership or control over another party. To determine relatedness for these purposes, the constructive ownership rules under sections 267 and 707 apply. The Proposed Regulations and Final Regulations apply the constructive ownership rules of sections 267 and 707, except that “80 percent or more” is substituted for “more than 50 percent” in each section; a person’s family is determined by excluding brothers and sisters; and sections 267(e)(1) and 267(f)(1)(A) are disregarded. Under the Proposed Regulations, these rules applied with certain modifications but still resulted in a partner being treated as bearing the EROL with respect to a partnership liability, even when that partner’s risk was limited to its equity investment in the partnership. The Final Regulations adopt two additional modifications to the constructive ownership rules: disregarding section 267(c)(1) (upward attribution through entities) with respect to the determination of whether a UTP’s interest in an LTP is owned proportionally by the UTP’s partners; and disregarding section 1563(e)(2) when determining whether a corporate partner in a partnership and a corporation owned by the partnership are members of the same controlled group.
[9] This rule is a deviation from the Proposed Regulations in response to comments expressing concern that the multiple partners rule may result in related partners recognizing uneconomic gain.
Rita N. Halabi & Mary McNicholas also contributed to this article.

Summary of Tax Proposals in Leaked Document Detailing Policy Proposals

I. Introduction
On January 17, 2025, news sources reported that Republican members of Congress circulated a detailed list of legislative policy options, including tax proposals. This blog post summarizes some of the tax proposals and corresponding revenue estimates mentioned in the list.
II. Individuals
(a) SALT Reform Options
The $10,000 cap on the deductibility of state and local tax (“SALT”) from federal taxable income for most non-corporate taxpayers is set to expire at the end of the year. The list includes several alternative proposals for SALT deductibility going forward.

Repeal SALT Deduction: The SALT deduction would be repealed for individual and business tax filers. This would raise $1 trillion over ten years, as compared to extending the current TCJA deduction cap.
Make $10,000 SALT Cap Permanent but Double for Married Couples: The current TCJA deduction cap for individual and business tax filers would remain, but the cap would be raised for married couples to $20,000 at an estimated cost of $100-200 billion over 10 years, as compared to extending the current TCJA deduction cap.
$15,000/$30,000 SALT Cap: The current SALT deduction cap would be increased to $15,000 for individual taxpayers and $30,000 for married couples, with an estimated cost of $500 billion over 10 years, as compared to extending the current TCJA deduction cap.
Eliminate Income/Sales Tax Deduction Portion of SALT: Only property taxes would be eligible for the SALT deduction, and the deduction would not be capped. This proposal would cost $300 billion over 10 years, as compared to extending the current TCJA deduction cap.
Eliminate Business SALT Deduction: This policy option would eliminate the SALT deduction for business filers only, while maintaining the TCJA deduction cap for individuals. It would raise $310 billion over 10 years.

(b) Repeal or Reduce Mortgage Interest Deduction
The TCJA lowered the amount on which homeowners may deduct home mortgage interest to the first $750,000 ($375,000 if married filing separately) of indebtedness. One proposal would repeal the deduction on primary residences, which would raise $1.0 trillion over 10 years dollars, as compared to extending current TCJA deduction caps.A second proposal would lower the cap on the deduction to the first $500,000 of indebtedness. This proposal would raise $50 billion over 10 years, as compared to extending current TCJA deduction caps. Both savings estimates are Tax Foundation scores.
(c) Repeal Exclusion of Interest on State and Local Bonds
Under current law, interest earned on bonds issued by states and municipalities is excluded from federal taxable income.One proposal would repeal this exclusion, which would raise $250 billion over 10 years. Interest on certain “private activity bonds” is also exempt from federal income tax. A second proposal would repeal the exemption for private activity bonds, Build America bonds, and other non-municipal bonds. It would raise $114 billion over 10 years.
(d) Repeal the Estate Tax
Estates are generally subject to federal tax. The TCJA raised the estate tax exclusion to $13,990,000 in 2025. The list includes a complete repeal of the estate tax. The proposal would cost $370 billion over 10 years.
(e) Exempt Americans Abroad from Income Tax
The foreign earned income exclusion allows U.S. citizens who are residents of a foreign country or countries for an uninterrupted tax year to exclude up to $130,000 in foreign earnings from U.S. taxable income in 2025. The list suggests the limit could be raised, or that all foreign earned income could be exempted from U.S. tax. The Tax Foundation has estimated that the cost is $100 billion over 10 years, though it is not clear which proposal the estimate is related to. This is a Tax Foundation Score.
III. Businesses
(a) Corporate Income Tax
The current corporate income tax rate is 21%. The list posits reductions in the rate to either 15% (at a cost of $522 billion over 10 years) or 20% (at a cost of $73 billion over 10 years).
(b) Repeal the Corporate Alternative Minimum Tax
The Inflation Reduction Act of 2022 (“IRA”) imposed a 15% corporate alternative minimum tax (“CAMT”) on the adjusted financial statement of certain very large corporations. One proposal would repeal the CAMT, at a cost of $222 billion over 10 years.
(c) Repeal Green Energy Tax Credits
The IRA enacted various “green” tax credits, including for clean vehicles, clean energy, efficient building and home energy, carbon sequestration, sustainable aviation fuels, environmental justice and biofuel. These tax credits are proposed to be repealed. The repeal would save up to $796 billion over 10 years.
(d) End Employee Retention Tax Credit
The Employee Retention Tax Credit (“ERTC”) was established under the Coronavirus Aid, Relief, and Economic Security Act in 2020. The ERTC provided “Eligible Employers” with a refundable tax credit for wages paid between March 12, 2020 and January 1, 2021 for keeping employees on payroll despite economic hardship related to COVID-19.The proposal would extend the current moratorium on processing claims for credits, eliminate the credit for claims submitted after January 31, 2024 and impose stricter penalties for fraud related to the credit at an estimated savings of $70-75 billion over 10 years.
IV. Nonprofits
(a) Endowment Tax Expansion for Private Colleges and Universities
The TCJA imposed a 1.4% excise tax on total net investment income of private colleges and universities with endowment assets valued at $500,000 or more per student (other than assets used directly in carrying out the institution’s exempt purpose). One proposal would increase the excise tax to 14%, which would raise $10 billion over 10 years. A related but separate proposal would change the counting mechanism for the per student endowment calculation to include only students who are U.S. citizens, permanent residents or are able to provide evidence of being in the country with the intention of becoming a citizen or permanent resident. This proposal would raise $275 million over 10 years.
(b) Repeal Nonprofit Status for Hospitals
Generally, hospitals are eligible for federal tax-exempt status. The list proposes to eliminate tax-exempt status for hospitals. The Committee for a Responsible Federal Budget has estimated that the proposal would raise $260 billion over 10 years.
V. Enforcement
Repeal IRA’s IRS Enforcement Funding
The IRA resulted in supplemental funding to the IRS, for enforcement purposes. The list states that if this funding is repealed, outlays would be reduced by $20 billion and revenues by $66.6 billion, for a net cost of $46.6 billion over 10 years.
Mary McNicholas and Amanda H. Nussbaum also contributed to this article.

GeTtin’ SALTy Episode 46 | Oregon’s Tax Landscape: Revenue, Legislation, and Local Changes with Jeff Newgard [Podcast]

In this episode of GeTtin’ SALTy, host Nikki Dobay is joined by Jeff Newgard, president of Peak Policy, to discuss Oregon’s 2025 legislative session. They explore Oregon’s revenue outlook fueled by personal income tax gains and the expiration implications of federal tax provisions. They delve into the state’s budgetary and tax policy processes, highlighting the nuances of legislative priorities, including a potential transportation package and tweaks to the longstanding estate tax. Jeff and Nikki reflect on the potential political and fiscal impacts of recent voter sentiment against tax increases, while also considering the challenges posed by anticipated federal tax reforms. The conversation rounds out with a look at local tax dynamics within Portland’s government structure, and Jeff offers insights into maintaining a sunny disposition during Oregon’s gray winter months—a glimpse into his astrophotography hobby.

Cafeteria Plan, Meet 401(k) Plan

Viewpoints
The IRS’s recent ruling offers increased flexibility for employers in structuring 401(k) contributions within cafeteria plans, benefiting both employers and employees.

More Employee Benefit Choices: Employers can now make discretionary contributions more ways, including combining some 401(k) and welfare benefit choices.
Opportunities for Competitive Benefits: The ruling enables employers to design more tailored, competitive benefits packages, enhancing employee satisfaction and retention.

The IRS has surprised employers with a new interpretation of how 401(k) contributions can be made in connection with a cafeteria plan. Many employers offer cafeteria plans, allowing employees to choose from various health and welfare benefits or taxable compensation. Historically, the IRS’s “contingent benefit rule” has prevented employers from offering a similar choice to employees regarding 401(k) plan contributions, because the rule prohibited other benefits from being contingent on 401(k) plan benefit elections. However, the IRS’s new ruling now allows an employer to make a discretionary contribution that employees may allocate to different plans, including a 401(k) plan, without the contribution being included in the employee’s taxable income.
What Did the Proposed Plan Look Like?
An employer asked the IRS for its ruling on several proposed plan amendments, which would change the discretionary contributions to the 401(k) plan without changing the safe harbor non-elective contribution. Specifically:

The proposed amendment to the 401(k) plan allowed eligible employees to choose where to receive an annual, irrevocable employer contribution — in the employer’s 401(k) plan, the employer’s Health Reimbursement Account (HRA), the employer’s Educational Assistance Program (EAP) or the employee’s Health Savings Account (HSA). If no employee election was made during open enrollment, the contribution would be made to the 401(k) plan. Employees could not receive the contribution as cash or a taxable benefit.
An amendment to the EAP proposed allowing student loan payments to be made directly from the EAP to the lender if the employee allocated the employer contribution to the EAP.
The proposed amendment also allowed employees to allocate the employer contribution to the EAP or as an employee’s HSA contribution but prohibited receiving other benefits from the EAP or making pre-tax payroll contributions to the HSA, until after March 15 of the following year. This timing would prevent contributions greater than the limits set under the Code.

How Did the IRS Respond?
The IRS provided several helpful rulings on the changes proposed by the employer. Specifically, the IRS ruled that:

The proposed 401(k) plan amendment would not cause the plan to violate the contingent benefit rule (described above).
The employer’s contribution would not be considered an employee pre-tax contribution, which would be subject to the lower elective deferral limit, rather than the much larger annual additions limit.
The allocation of the employer contribution to the HSA would be excludable from the employees’ taxable income.
The EAP amendment would not affect the treatment of tuition or loan payments made under the EAP as excludable from the employee’s taxable income.
The employee’s ability to allocate the contribution between different programs would not prevent the EAP from qualifying as an EAP under section 127 of the federal tax code.

IRS “private letter rulings,” like this one, are technically directed only at the requesting employer and cannot officially be followed as precedent. However, because they often guide practitioners on the IRS’s perspective on issues, this ruling increases flexibility for employers designing competitive benefits packages.

Expanded Section 232 Tariffs on U.S. Imports of Steel and Aluminum Articles

On February 10, 2025, President Trump signed proclamations expanding the existing 25% tariffs on steel articles and increasing the tariffs on aluminum imports from 10% to 25% under Section 232 of the Trade Expansion Act of 1962, as amended (Section 232). The proclamation revokes all current alternative arrangements under the Section 232 regime and reimposes tariffs on imports of steel and aluminum articles from all countries, including Canada, Mexico and the European Union (EU), effective March 12, 2025. In addition, the proclamations immediately terminate the product-specific exclusion process set forth in the prior actions.
The February 10 proclamation generally takes effect March 12, 2025, with some immediate interim impacts:

Aluminum Duties Increase: The proclamation directs an increase in aluminum import tariffs to 25% for all U.S. imports as of 12:01 ET on March 12, 2025.
Alternative Arrangements Revoked: The proclamation revokes the alternative arrangements, including absolute quotas, tariff rate quotas and country exemptions, made with respect to countries and regions including Argentina, Australia, Brazil, Canada, Mexico, the EU, the United Kingdom, Japan and Korea for all U.S. imports as of 12:01 ET on March 12, 2025. As of that date, imports of steel articles from all countries will be subject to the Section 232 tariffs that were imposed during President Trump’s first term.
No Exclusions: The Section 232 product-specific exclusion process is terminated, effective immediately (11:59 PM ET on February 10, 2025), with the portal currently deactivated. Commerce is directed not to consider or grant any exclusion requests as of February 11, 2025. However, granted product exclusions will remain effective until their expiration date or until excluded product volume is imported, whichever occurs first. Commerce is directed to terminate all existing general approved exclusions (GAEs) as of March 12, 2025.
Subject Products: As of March 12, 2025, certain derivative steel and aluminum products (not yet defined) will become subject to Section 232 tariffs in addition to upstream steel and aluminum products covered in the original proclamations implementing the Section 232 tariffs. The lists of the derivative products will be published in the Federal Register and are not yet available, so the scope as it relates to prior actions on steel and aluminum derivatives is unclear. Derivative products produced with steel melted and poured in the United States or aluminum extruded in the United States will not be subject to the expanded Section 232 tariffs, and for all other derivative products, the new tariffs will be assessed on the value of the underlying steel.
Inclusion Process: Within 90 days after the date of the proclamation (i.e., no later than mid-May 2025), Commerce is directed to establish a process for including additional derivative steel products within the scope of the Section 232 tariffs. When Commerce receives a request from a domestic producer/industry association, Commerce is directed to determine whether to include the derivative products within the scope of the Section 232 tariffs within 60 days of receiving the request.
CBP’s Enhanced Oversight: The proclamation directs U.S. Customs and Border Protection (CBP) to enhance oversight to prevent tariff evasion through the misclassification of steel products. Should CBP discover misclassification resulting in non-payment, CBP is directed to assess monetary penalties in the maximum amount permitted by law and to not consider any evidence of mitigating factors.
No Drawback: No drawback will be available with respect to the expanded Section 232 tariffs.
FTZ: For steel and aluminum articles or derivative articles that are admitted into a U.S. foreign trade zone (FTZ) on or after 12:01 AM ET on March 12, 2025, those products must be admitted in either domestic status or privileged foreign status, and articles that were admitted into a U.S. FTZ under privileged foreign status prior to, on, or after 12:01 AM ET on March 12, 2025, will be subject to the Section 232 tariffs imposed under this February 10 proclamation upon entry for consumption.

The White House Fact Sheet accompanying the proclamation highlighted that the expanded Section 232 action is to protect and restore fairness for the U.S. critical steel and aluminum industries harmed by unfair trade practices and global excess capacity. According to the Fact Sheet, the expanded Section 232 action is designed to eliminate loopholes that facilitated circumvention and diminished the effectiveness of the original Section 232 actions under previous proclamations.

Navigating Permanent Establishment Risks in Cross-Border Employment

As businesses continue to expand their operations across borders—by engaging contractors, hiring employees, or initiating other revenue-generating activities overseas—understanding permanent establishment risks becomes critical.
The creation of a permanent establishment (PE)—a tax concept that may trigger a company’s obligation to report, file, and pay corporate taxes in a foreign country—represents an additional administrative and financial obligation.
A foundational understanding of PE considerations can help global employers identify and mitigate potential issues—and better know when to seek appropriate professional guidance.

Quick Hits

Tax connections: Establishing a PE can result in the obligation to file corporate taxes abroad.
Local registration: Although PE is primarily a tax concept, it may coincide with requirements to register with local business authorities as a foreign entity conducting business in the country.

Understanding ‘Permanent Establishment’
A company’s business activities may create a significant economic presence that could trigger tax liability abroad. Usually, tax authorities look for revenue-generating activities in which the foreign company is engaged. Some countries have taken the position that if a key element of a product (including, in some instances, the use of intellectual property) is created on their soil that generates revenue—even outside of the relevant countries—the revenue is taxable. The business activities of a company that will trigger a PE are primarily governed by tax treaties between countries, or, in their absence, by local tax laws.
Key Triggers for Permanent Establishment Obligations

Fixed place of business: Traditionally, having a physical office, branch, factory, or any other fixed place where business activities are conducted, establishes a PE. This may include construction or installation projects that last for a certain period. The modern global economy and the rise of remote work, however, have complicated this definition.
Dependent agents: Engaging a dependent agent—whether an employee or an independent contractor who primarily works for the company and has the authority to enter into contracts on its behalf—may also trigger a PE. The agent’s financial dependence and exclusivity to the company are critical factors.
Rendering services: Providing services such as consulting, engineering, or management in a foreign country for a specified duration (often 183 days within 12 months) may establish a PE. This duration may vary by country, with some having shorter periods.

Remote Work and Permanent Establishment Risk
The COVID-19 pandemic has significantly impacted the concept of PE, particularly with the rise of remote work. Initially, many countries considered remote work arrangements as temporary activities that did not establish a PE. But as remote work has become more permanent, tax authorities have increased their scrutiny of these arrangements. Factors such as whether an employee’s home is at the company’s disposal, whether the company pays for home office expenses, the use of the home address for business purposes, and other indicia of company/employer control over the address are often considered by tax authorities in their PE determinations.
Special Considerations and Examples

Intellectual property: In some countries, such as Germany, creating intellectual property within the country and using it for revenue-generating activities abroad may establish a PE.
Sales activities: While supporting sales activities may not trigger a PE, actively selling within a foreign market likely will.
Country-specific rules: Some countries, such as India, have unique rules where employing individuals within the territory, even for non-revenue–generating activities, may trigger a PE.

Mitigating Risk and Maintaining Compliance
Businesses carefully evaluating their cross-border activities to avoid unintended tax obligations may want to consider the following:

Remote work: Do the benefits of allowing employees to work remotely from another country outweigh the potential tax risks? Employers might also consider pushing back on paying remote work expenses to mitigate PE risks.
Contract structuring: Businesses often attempt to mitigate PE risk by structuring contracts such that significant decisions and signatures occur outside the foreign country. Tax authorities might question this strategy, focusing on the substance over the form of the business activities.
Preparatory and auxiliary activities: Activities considered preparatory or auxiliary, such as administrative tasks, research and development, or marketing support, generally do not establish a PE. However, sales activities that directly generate revenue in the foreign country may fall within a gray area.
Tax professionals: Engaging tax advisors to navigate the complex and evolving landscape of international tax laws and treaties often makes good sense.

Conclusion
Understanding, strategically planning for, and managing permanent establishment risks are crucial steps for businesses operating abroad. While labor and employment attorneys and HR professionals may not specialize in tax law, they play a vital role in issue-spotting and ensuring that potential tax implications are addressed with the help of seasoned tax professionals. By staying informed and proactive, businesses can navigate PE complexities and considerations, avoid unintended tax consequences, and maintain compliance in the global marketplace.

Missing Participants – New State Unclaimed Property Fund Option for Small Balances

Takeaways

On January 14, 2025, the DOL issued Field Assistance Bulletin (FAB) 2025-01, providing sponsors and administrators of ongoing defined contribution plans with a new option for missing participant balances of $1,000 or less: transfer to the state unclaimed property fund associated with the participant’s last known address.

President Trump Resets US Tariffs on Imports of Steel and Aluminum from All Countries

On 10 February 2025, President Trump announced that he was increasing tariffs on US imports of aluminum from 10% to 25% and ending various exemptions and exclusions to the US tariffs of 25% on imports of steel. The tariffs were first imposed in President Trump’s first term under the authority of Section 232 of the Trade Expansion Act of 1962, which permits the President to impose import restrictions (tariffs and/or quotas) based on an investigation and affirmative determination by the US Commerce Department that certain imports threaten to impair US national security. Section 232 tariffs on aluminum and steel were originally imposed by President Trump in 2018 and continued under President Biden.
This latest tariff action revokes agreements with Argentina, Australia, Brazil, Canada, the European Union, Japan, Mexico, South Korea, Ukraine, and the UK that had suspended tariffs on certain aluminum and steel products imported from those countries. It also terminates the company and product-specific exclusions that had been granted by the US Commerce Department since 2018. Accordingly, unless further changes are implemented, effective 12 March 12 2025 at 12:01 am Eastern Time all steel and aluminum products identified in the President’s proclamations will be subject to 25% tariffs. Further, such tariffs will be extended to certain “derivative” steel and aluminum products (i.e., products made by further manufacturing basic steel and aluminum shapes) not previously covered by Section 232 tariffs.
President Trump’s decision to reset and increase tariffs is based on finding that the original Section 232 tariffs were not being effective in addressing findings that the global steel industry suffered from massive overcapacity. According to the original investigation and the latest findings, this global overcapacity is primarily due to China’s policies to promote its aluminum and steel industries and the spillover effects this build-out was continuing to have on third country markets, which, in turn, were channeling their own excess aluminum and steel to the US market.
Notably, in his press conference announcing the tariffs, President Trump indicated that countries may have room to negotiate potential settlements or modifications of the tariffs – especially if they are able to achieve relatively balanced trade with the United States or otherwise demonstrate economic benefits to the United States from trade and investment. When asked about the return of tariffs to imports of steel and aluminum from Australia, the President noted that the US has enjoyed a moderate trade surplus with Australia primarily due to that country’s purchases of aircraft from the United States and that he was in discussions with Australia’s prime minister about the tariffs and other issues.
The President also signaled that the tariffs may be extended to additional downstream products made from aluminum or steel. Specifically, the President’s action calls on the US Commerce Department to establish a process for interested parties to request that additional derivative aluminum or steel products be subject to Section 232 tariffs. This process must be in place by 12 May 2025.
The impending reset of aluminum and steel tariffs underscores the importance for companies and investors in sectors that produce or utilize these products to assess the impact on their own supply chains, pricing, business plans, and contractual and customer relationships. Companies and investors should also consider options under US law and contractual agreements to mitigate the potential impacts of the tariffs.

Not Cool, Man: Senate Proposal to Expand 280E Taxes on Cannabis Businesses Even if Rescheduled

Anyone who thought that the momentum towards federal liberalization of marijuana would be a straight line found themselves with a cold dash of water to the face. Late last week Republican senators filed a bill, entitled the “No Deductions for Marijuana Businesses Act,” which would preserve a punitive federal tax policy that bars cannabis companies from taking ordinary business deductions, regardless of whether marijuana’s status as a Schedule I substance is ever changed.
Courtesy of Kyle Jaeger at Marijuana Moment:
Two GOP senators have introduced a bill that would continue to block marijuana businesses from taking federal tax deductions under Internal Revenue Service (IRS) code 280E — even if it’s ultimately rescheduled.
Sens. James Lankford (R-OK) and Pete Ricketts (R-NE) filed the “No Deductions for Marijuana Businesses Act” on Thursday to maintain the tax barrier for the industry, which has been eagerly following the ongoing administrative process of moving cannabis from Schedule I to Schedule III of the Controlled Substances Act (CSA) in large part because it would address their 280E challenges under current law.
While rescheduling isn’t a guarantee, and Drug Enforcement Administration (DEA) hearings on the proposal have been delayed, the senators are aiming to preemptively take the wind out of the industry’s sails.
The bill would amend the IRS code to say that, in addition to all Schedule I and Schedule II drugs, businesses that work with marijuana specifically would be barred from taking tax deductions that are available to other industries.

If enacted into law, this could be a fatal blow to a number of cannabis businesses that have ordered their business models around no longer having to pay 280E taxes following the presumptive rescheduling of marijuana.
Let’s be clear, I don’t think this legislation will become law. But friends should be honest with each other. There will not be some panacea that absolves marijuana operators of their tax burdens without a tremendous fight. And operators should, in my opinion, pay their taxes when due. The failure to do so could cause them tremendous pain down the road.