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Energy Law: Month in Review - July 2025

August 7, 2025

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AUTHORS
Zev Simpser, Brian Bell, and Tim Bagshaw.

Welcome to Dorsey’s Energy Law: Month in Review. We provide this update to our clients to identify significant developments in the previous month. Please reach out to any of the authors, listed above, to discuss these issues. 

Table of Contents

LITIGATION AND DISPUTES

Ninth Circuit Court of Appeals Affirms FERC’s Decision to Deny Grid Incentive to PG&E

In a July 11, 2025, unpublished decision from a three-judge panel, the Ninth Circuit Court of Appeals declined to disturb the Federal Energy Regulatory Commission’s (FERC) decision to deny a Pacific Gas & Electric Co. (PG&E) request to include an incentive adder in its transmission rates designed to incent public utilities to join a regional transmission organization. It concluded that PG&E did not need an incentive to encourage it to participate in the California Independent System Operator (CAISO), because California law already mandates participation. California law mandates that utilities “shall participate” in CAISO, and because members cannot withdraw from CAISO, “their participation is not voluntary.” The court also rejected PG&E’s contention that federal law preempts section 362(c) of the California Public Utilities Code, the rule mandating CAISO participation. California’s CAISO mandate regulates within a domain that Congress assigned to the states in a way that “indirectly affects interstate wholesale rates.” These “indirect effects do not trigger field preemption.” 

REGULATORY DEVELOPMENTS

FERC Approves Fast-track Interconnection Reviews

On July 21, 2025, FERC approved a fast-track interconnection proposal from the Midcontinent Independent System Operator, Inc. (MISO). In proposing the process, MISO emphasized the necessity for bringing power supplies online quickly to meet near-term grid needs. State utility commissions or other “relevant electric retail regulatory authorities” would assess potential projects being considered in MISO’s review process. State regulators mostly supported the proposal, but renewable-energy companies and public-interest groups criticized FERC’s approval arguing, in part, that the proposal violates FERC’s principles of providing nondiscriminatory access to the grid. Furthermore, critics argued, the proposal could disrupt development for projects waiting in interconnection queues. The approved proposal will allow planned resources meeting certain eligibility requirements to sidestep MISO’s standard interconnection-queue reviews. Critics contend that gas-fired power plants will be the main beneficiaries of the fast-track process. 

State Utility Regulators Ask FERC to Reject MISO’s $21.8 Billion Transmission-development Plan

In a complaint filed on July 30, 2025, state utility regulators from Arkansas, Louisiana, Mississippi, Montana, and North Dakota have requested that FERC reject MISO’s $21.8 billion transmission-development plan, contending that MISO overstated the benefits and underestimated the costs associated with the latest tranche of its Multi-Value Project (MVP) program. MVPs are transmission projects MISO has identified as having regional economic, reliability, or public-policy benefits that are, therefore, eligible to have their costs shared across MISO’s footprint. The latest MVP tranche contains 24 transmission projects covering more than 3,600 miles of MISO’s Midwest subregion. MISO claims its benefits could exceed $72 billion. The complaining states contend that MISO used unreasonable metrics overstating the benefits of the latest MVP projects. They further contend that the MVP projects impose unreasonable costs by allowing states with more aggressive clean-energy goals to shift transmission costs to states that do not share those same goals or that have decided to build their renewable and other resources closer to load.

David LaCerte to fill FERC Vacancy

On July 16, 2025, President Donald Trump named David LaCerte, an official from the U.S. Office of Personnel Management (OPM) to fill a vacant position at FERC. LaCerte has served as the principal White House liaison and senior advisor of OPM, which serves as the primary human-resources agency for the federal government, since January 2025. He also served as acting Managing Director of the U.S. Chemical Safety and Hazard Investigation Board at the end of President Trump’s first term in office. LaCerte was special counsel at Baker Botts for two years beginning in January 2023, where he worked on energy litigation and environmental, safety, and incident-response issues. If confirmed, LaCerte would serve the remainder of former FERC Chair Willie Phillips’ term that expires June 30, 2026, and he would break a 2-2 tie and give Republicans a 3-2 FERC majority.

Administrative Law Judge recommends that the Minnesota PUC to Reject $6.2 Billion Private Equity Deal

On July 15, 2025, Administrative Law Judge (ALJ) Megan McKenzie recommended that the Minnesota Public Utilities Commission (MPUC) reject a $6.2 billion private-equity deal. Under the deal, the Canada Pension Plan Investment Board and Blackrock’s Global Infrastructure Partners would buy Allete, parent company of Minnesota Power and Superior Water, Light and Power. In a recommended decision, ALJ McKenzie concluded that the deal does not meet Minnesota’s public-interest standard and poses foreseeable risks to Minnesota’s energy transition, Allete’s long-term financial health, and ratepayers. Allete and its buyers, she stated, failed to adequately support primary arguments for supporting the deal, including improving access to capital and expertise. Allete criticized the recommendation, contending that ALJ McKenzie did not fully consider the benefits of a July 11, 2025, settlement agreement with the Minnesota Department of Commerce, in which Minnesota Power would freeze its base rates for one year and reduce its return on equity from 9.78% to 9.65% until a future rate case. Allete contended that this reduction would provide immediate ratepayer benefits. However, ALJ Mckenize cited September 2024 warnings from “FERC that asset managers like Blackrock could hurt ratepayers by trying to maximize profits from utilities their portfolios, concluding that “[o]n balance, the risks of the deal, as proposed, outweigh the possible benefits.” 

Executive Order Tightens Restrictions on Wind and Solar Development

On July 7, 2025, President Donald Trump issued an executive order curtailing federal subsidies on wind, solar, and electric vehicles. The order states that renewables have distorted markets, undermined grid reliability and national security by reliance on foreign-controlled supply chains, and imposed unsustainable costs on taxpayer. The order instructs the Secretary of the Treasury to publish guidance within 45 days “to ensure the policies concerning the ‘beginning of construction’ are not circumvented” by wind and solar projects whose eligibility for clean-energy tax credits were significantly reduced in the July 4, 2025, budget legislation. The legislation restricts the ability of renewables projects to qualify for the 48E investment tax credit or the 45Y production tax credit, shortens the timeline for those credits, and terminates residential-solar and electric-vehicle tax credits by the beginning of 2026. The order directs the Treasury to strictly enforce the termination of these credits and to focus on closing perceived loopholes in “beginning of construction” definitions and safe-harbor provisions that may otherwise be used to lock-in benefits through minimal pre-development work. Treasury must also implement the Foreign Entity of Concern restrictions in the budget legislation to ensure that projects with ownership, financing, or supply-chain links to specified foreign states are ineligible for clean-energy credits. 

Ohio Regulators Approve AEP Data Center Interconnection Rules

The Ohio Public Utilities Commission (OPUC) unanimously approved a July 9, 2025, settlement agreement between AEP Ohio and various stakeholders setting new terms and conditions for connecting data centers to the power grid. The OPUC ordered AEP Ohio to file updated tariffs and to lift a moratorium on connecting new data centers. The order sets minimum monthly bills for new data centers larger than 24 MW based on a percentage of their highest previous monthly billing demand over the past eleven months or their contract capacity. Those data centers will need to pay for at least 85% of the energy they expect to need each month, even if they use less, to cover the costs associated with infrastructure needed to bring electricity to the facilities. The order also requires data centers to show that they are financially viable and to pay an exit fee if their project is cancelled. The Ohio Consumers Council, which represents ratepayers; the Ohio Partners for Affordable Energy; and others supported the agreement. The Data Center Coalition—an industry group representing, among others, Google, Amazon, Microsoft—opposed the agreement, contending that it would dampen investment by inflating data centers’ costs and imposing unnecessary regulation on behind-the-meter energy generation.

Michigan’s Palisades Nuclear Power Plant Closer to Restarting after Recent NRC Approvals

On July 24, 2025, the U.S. Nuclear Regulatory Commission (NRC) granted multiple approved needed for the 800-MW Palisades Nuclear Power Plant (Palisades) in Michigan to restart later this year. The former owner, Entergy, shut the plant down in May 2022 and sold it to Holtec in June 2022. Holtec began plans to restart Palisades in late 2023. With NRC’s decision, Holtec is now authorized to receive new fuel and to formally transition licensed reactor operators to on-shift status. In May, NRC concluded that Holtec’s efforts to restart Palisades poses “no significant impact” to human health or the environment. NRC noted that there are still several licensing actions under review, and additional requirements will need to be met before Palisades can begin producing under the original operating license, which expires March 24, 2031. 

FERC Rejects Petition to Limit Market Monitor’s Transmission Planning Oversight

On July 18, 2025, FERC rejected a petition from MISO and its transmission owners calling for MISO’s independent market monitor to be effectively barred from transmission-planning oversight. FERC’s petition followed the market monitor’s (Potomac Economics) criticism of MISO’s needs and cost-benefit analysis supporting its $22 billion Tranche 2.1 transmission portfolio that FERC approved in December 2024. Potomac Economics contended that MISO overstated its transmission needs and the benefits flowing from its proposed project portfolio. In rejecting the request, FERC emphasized that MISO’s tariff “unambiguously” authorizes MISO’s market monitor to review and analyze MISO’s actions affecting the competitiveness, economic efficiency, and operation of the grid operator’s markets and services, and transmission planning is among those actions subject to review.

Oregon Legislature Approves First-in-Nation Microgrid Framework

To improve grid reliability and combat rising energy costs, the Oregon House of Representatives and Senate passed two bills designed to make communities more resilient as the state’s grid faces rising electricity demand, extreme weather events, and power shutoffs to mitigate wildfire risk. Governor Tina Kotek signed the bills on July 17, 2025. HB 2065 seeks to reduce bottlenecks to microgrid deployment by allowing third-party consultants or contractors to evaluate customer requests to connect to the public power grid and by requiring public utilities to approve or deny microgrid applications “based on safety, reliability and compliance with published standards.” HB 2066 directs the Oregon Public Utility Commission (OPUC) to develop a regulatory framework for community-owned and private microgrids. It also requires the Department of Consumer and Building Services to establish rules allowing existing buildings to connect to community microgrids and allows local governments to design “microgrid zones” with special land-use regulations, subject to local utility or OPUC. Community microgrids combine individually owned solar, batteries, and other energy-generation or -storage systems located at facilities that have high reliability or “uptime” needs, such as hospitals, schools, police and fire stations, wastewater-treatment plants, critical infrastructure facilities, data centers, grocery stores, and other businesses. 

DOE Retracts $4.9 Billion Conditional Loan Commitment to Grain Belt Express

On July 23, 2025, the Department of Energy (DOE) revoked its conditional commitment to a $4.9 billion loan guarantee for the first phase of the Grain Belt Express, a transmission line proposed to traverse parts of Kansas, Missouri, Illinois, and Indiana. DOE stated that the conditions needed to issue the loan guarantee were unlikely to be met and that federal support for the 5,000-MW direct current transmission line is not critical. Grain Belt Express had argued that the 800-mile, open-access transmission line would increase grid reliability and significantly reduce energy costs for ratepayers. In response, DOE stated that the conditional commitment was among those “rushed out the door” at the end of the Biden Administration. 

Firm Highlights

Regulatory Affairs Partner Randy Dann Joins Dorsey

News

Regulatory Affairs Partner Randy Dann Joins Dorsey

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Insights

The Supreme Court Update - October 14, 2026

Attorney John Cooney Returns to Dorsey in the Finance & Restructuring Group in Minneapolis

News

Attorney John Cooney Returns to Dorsey in the Finance & Restructuring Group in Minneapolis

News

Dorsey’s London Corporate Practice and Partners Earn Chambers UK 2027 Rankings

Regulatory Affairs Partner Jeff Beelaert Joins Dorsey in Boise

News

Regulatory Affairs Partner Jeff Beelaert Joins Dorsey in Boise

Insights

Energy Law: Month in Review - September 2026

Welcome to Dorsey’s Energy Law: Month in Review. We provide this update to our clients to identify significant developments in the previous month. Please reach out to any of the authors, listed above, to discuss these issues. Regulatory Developments Massachusetts Ratchets Up State and Local Regulation of AI Data Centers In early September, Governor Maura Healey of Massachusetts signed an executive order requiring that artificial intelligence data centers secure the approval of local communities as a precondition to proceeding with a given project. According to the terms of the order, data center developers will need to secure a “community benefits agreement” as a precondition to receiving permits from numerous state agencies, including the Department of Environmental Protection, the Energy Facilities Siting Board, and the Massachusetts Environmental Policy Act Office. Beyond requiring community benefits agreements, the order also mandates that developers mitigate utility costs to consumers, prohibits the use of nondisclosure agreements, and requires various state agencies to develop measures to limit data center impacts on the environment. North Carolina Regulators Decline Approval of Duke Energy Gas Turbine On September 18, 2026, North Carolina Utilities Commission (NCUC) denied Duke Energy’s application for a certificate of public convenience and necessity required to construct a gas-fueled combustion turbine at its Smith Energy Complex in North Carolina. The NCUC objected strongly to the $584 million price tag and noted that Duke appeared to be constructing the facility “based on anticipated data center customer additions.” The NCUC rejected that anticipated growth as “insufficiently reliable for the Commission to act at this point.” In rejecting Duke’s application, the NCUC also noted that Duke had signed the White House Ratepayer Protection Pledge, in which it represented that it would not shift data center costs to consumers. The NCUC observed that the record did not demonstrate how Duke “intends to adhere to its commitments under the Ratepayer Protection Pledge with regard to the Proposed Facility.” Notably, commission staff had actually supported the construction of the turbine, citing concerns about Duke’s reserve margins. The NCUC noted that it “understands the Public Staff’s expressed concerns,” but those concerns were outweighed by the NCUC’s reservations, including questions of demand. Department of Energy Approves Funds for Grid Improvement The U.S. Department of Energy (DOE) recently announced that it would fund 31 grid-improvement projects in 26 states. The funding initiative is part of the DOE’s “SPARK” initiative. The funding will include $1.9 billion in federal funding from DOE and $3.35 billion in recipient cost-sharing funding. The funds will go to projects designed to improve grid reliability and lower electricity costs. Recipients plan to reconductor over 1,500 miles of transmission lines and will deploy grid-enhancing technologies across approximately 21,000 miles. DOE stated that this initiative will make available over 23 additional gigawatts of electricity. Texas Moderates Rules Governing Data Center Interconnection The Texas Public Utility Commission adopted new regulations governing large-load interconnections. The rules impose a flat study fee of $100,000 for all proposed interconnections, which departs from the initial proposal to impose study fees using a tiered system based on project size. Additionally, the final rule eliminates the PUC’s previous proposal to impose a non-refundable interconnection fee of $50,000 per MW of contracted peak demand. The final rule also moderates the initially proposed regulations governing Electric Reliability Council of Texas (ERCOT) notifications for large-load customers’ non-utilized capacity. The proposed rules would have required notifying ERCOT within 30 days of missing a scheduled energization milestone by six months. The final rules, however, do not require informing ERCOT unless a scheduled energization milestone is missed by 24 months. FERC Denies TransAlta 202(c) Cost-Recovery Plan The Federal Energy Regulatory Commission (FERC) recently rejected TransAlta’s plan to recover $19.9 million in expenses stemming from a DOE order in which DOE prohibited TransAlta from retiring its coal-powered Centralia power plant. TransAlta had previously intended to retire the facility at the end of 2025. TransAlta’s cost recovery plan proposed spending an additional $23 million on repairs to continue operating the unit. FERC’s main objection had to do with geographic scope. TransAlta’s recovery plan called for recovering costs from California Independent System Operator (CAISO) and the Southwest Power Pool (SPP), but the DOE’s order requiring operation of the plant was designed to ensure reliability in the Northwest assessment area (Montana, Oregon, Washington, and parts of northern California and northern Idaho). Accordingly, FERC was unwilling to allow cost recovery from CAISO and SPP when the order that precipitated the additional costs only related to the Northwest assessment area. FERC informed TransAlta that it would only approve cost recovery from load-serving entities in the Northwest assessment area. FERC’s decision comes amid a rush of DOE emergency orders requiring the continued operation of coal-fired generating units. Litigation Appeals Court Upholds Washington Hydropower Plant With Caveats In a September 21, 2026, opinion, the Washington Court of Appeals largely upheld a Clean Water Act water quality certification by the Washington Department of Ecology for the Goldendale Energy Storage Project, a proposed pumped-water storage hydropower system adjacent to, but off-stream from, the Columbia River. A nonprofit (Columbia Riverkeeper) and the Confederated Tribes and Bands of the Yakama Nation appealed the certification, contending that it failed to impose necessary conditions and monitoring requirements to protect the water quality of the Columbia River. Most saliently, the plaintiffs argued that the project had the potential to leak 100 acre-feet of water per year into tributaries of the Columbia River. The Court of Appeals broadly rejected plaintiffs’ challenge to the state’s conclusion that “the project was designed not to leak.” That said, the Court of Appeals did reverse on one narrow issue. Specifically, the court determined that the state’s conclusion that “leakage from the project’s tunnels would be monitored and reported” was not supported by the evidence because the certification “does not explicitly require monitoring and reporting to determine whether there is any leakage.” Accordingly, the court remanded the matter to the state to impose monitoring and reporting requirements but otherwise affirmed the certification. Legislative Developments California Legislates Restrictions on Data Center Energy Use and Grid Costs On September 21, 2026, California Governor Gavin Newsom signed seven bills broadly regulating data centers in the state. SB 1168 directed the California Public Utilities Commission to assess the energy used by data centers. It also requires the PUC to pass costs of transmission and distribution upgrades and load increases on to data centers, rather than customers. SB 886 and SB 887 compel data centers to pay for infrastructure upgrade and generation costs, and wildfire mitigation costs, in addition to imposing environmental review. The statutes additionally increase local oversight of data centers. AB 1577 imposes a monthly reporting requirement that requires data centers to supply energy consumption and efficiency data to the California Energy Commission. AB 2383 contains incentives for data centers to use onsite clean energy generation. Finally, AB 2469 and AB 2619 require data center developments to assess water supply and develop a water scarcity plan. The statutes also mandate statewide water reporting as a precondition to obtaining and renewing business licenses.

Insights

EPA Limits Title V Re-Litigation of NSR Permits

Overview On September 25, 2026, the U.S. Environmental Protection Agency (“EPA”) published a final rule that significantly limits the ability of third parties to use the Clean Air Act (“CAA”) Title V permitting process to revisit New Source Review (“NSR”) permitting decisions years after those decisions were made. The rule establishes that NSR permitting determinations generally must be challenged during the original permitting proceeding, thereby providing regulated sources with greater permitting certainty and finality for major capital projects. Published in the Federal Register titled Clarifying the Scope of “Applicable Requirements” Under State Operating Permit Programs and the Federal Operating Permit Program (Docket ID No. EPA-HQ-OAR-2023-0401), the rule amends 40 C.F.R. Parts 70 and 71 to codify EPA’s interpretation regarding when requirements established under other CAA programs may be reviewed, modified, or implemented through the Title V operating permit program. The rule becomes effective 30 days after publication. The rule addresses two principal issues: (1) the relationship between NSR preconstruction permitting and Title V operating permits, and (2) the treatment of the General Duty Clause under CAA section 112(r)(1). Most significantly, the rule provides greater certainty for sources navigating the NSR permitting process. EPA’s amendments are intended to ensure that NSR permitting decisions made through an approved public process are generally not revisited later through Title V permit proceedings. The rule responds to a circuit split between the U.S. Courts of Appeals for the Fifth and Tenth Circuits. In Environmental Integrity Project v. EPA, 969 F.3d 529 (5th Cir. 2020), the Fifth Circuit upheld EPA’s interpretation, concluding that it was consistent with the text, structure, and purpose of Title V. In contrast, the Tenth Circuit reached the opposite conclusion in Sierra Club v. EPA, 964 F.3d 882 (10th Cir. 2020), finding that the then-existing regulatory definition of “applicable requirement” did not support EPA’s position. By amending the regulatory language on which the Tenth Circuit relied and codifying the interpretation approved by the Fifth Circuit, EPA has established a nationwide framework governing the interaction between NSR and Title V. NSR and Title V: EPA Establishes a Uniform Nationwide Framework At the core of the rule is EPA’s effort to define the respective roles of NSR and Title V. The rule codifies the approach EPA has applied since 2017: once a source obtains an NSR permit under an EPA-approved permitting program, and that permit was issued following public notice with an opportunity for comment and judicial review, the permit establishes the NSR-related “applicable requirements” of the State Implementation Plan (“SIP”) or Federal Implementation Plan (“FIP”) for Title V purposes. Under this framework, Title V is not a vehicle for re-examining underlying NSR permitting decisions. EPA does not intend to use the Title V process to revisit applicability determinations, emissions calculations, control technology determinations, permit conditions, or other issues resolved through the NSR permitting process. This principle applies regardless of the stage of the Title V proceeding; whether the NSR permit was issued pursuant to a SIP or FIP; the type of NSR issue involved; or whether the NSR permit is incorporated into Title V sequentially or concurrently. Limited Exceptions EPA recognizes several circumstances in which NSR issues may still be reviewed through the Title V program: No NSR permit was issued at all; The permit was issued without public notice and an opportunity for comment and judicial review; or The issue involves substantive overlap between Title V and NSR requirements, such as the adequacy of monitoring provisions. As a result, the rule does not insulate unpermitted projects or foreclose review of matters that independently arise under Title V. Key Regulatory Amendments The rule revises the definition of “applicable requirement” in 40 C.F.R. §§ 70.2 and 71.2. Paragraph (1): Where an NSR permit is issued with public notice and an opportunity for comment and judicial review, the permit establishes and defines the applicable SIP or FIP requirements for Title V purposes. Paragraph (2): All NSR permit terms, including terms contained in minor NSR permits, constitute applicable requirements that must be incorporated into Title V permits. Paragraph (4): CAA section 112(r)(1) (the General Duty Clause) is expressly excluded from the definition of “applicable requirement,” while section 112(r)(7) Risk Management Program requirements remain included. EPA also amended 40 C.F.R. §§ 70.8 and 70.12 to clarify that alleged defects in requirements established outside the Title V process generally do not provide a basis for EPA objection to a Title V permit or for a Title V citizen petition. General Duty Clause Exclusion The rule also codifies EPA’s longstanding position that the General Duty Clause in CAA section 112(r)(1) is not an “applicable requirement” for Title V purposes. EPA points to several considerations supporting that conclusion, including the distinction between the General Duty Clause and Title V permit terms, the provision’s origins in the Occupational Safety and Health Act’s general duty clause, and the different enforcement structures applicable to the General Duty Clause and Title V permit requirements. Importantly, excluding section 112(r)(1) from the definition of “applicable requirement” does not eliminate EPA’s authority to enforce the General Duty Clause independently of the Title V program. The final rule instead clarifies that the General Duty Clause need not—and should not—be incorporated into Title V permits as an applicable requirement. Practical Implications for Regulated Sources Greater Finality for NSR Permits  For projects requiring PSD, nonattainment NSR, or minor NSR permits, the permitting process becomes the primary forum for resolving disputes regarding applicability determinations, emissions calculations, control technology requirements, offsets, and permit conditions. Once an NSR permit is issued through a qualifying public process, regulated sources should face substantially reduced risk that those same issues will be challenged years later through Title V permit proceedings. Reduced Risk of Collateral Permit Challenges Stakeholders have sometimes sought to use Title V permit issuance, renewal, revision, or citizen-petition proceedings to challenge underlying NSR determinations. The final rule makes clear that Title V is not the appropriate vehicle for challenging whether an applicable requirement was correctly established in the first instance. This should reduce the risk of permit delays and uncertainty associated with collateral challenges to previously issued NSR permits. The rule does not, however, eliminate all Title V challenges relating to an NSR permit. Challenges concerning the Title V permit itself—including whether it appropriately incorporates applicable requirements or contains adequate compliance provisions—remain possible. Increased Importance of the Initial NSR Proceeding Because Title V generally will not provide a second opportunity to challenge the substantive validity of an NSR determination, the administrative record developed during the NSR process becomes increasingly important. Permit applicants should ensure that applicability analyses, emissions calculations, control technology evaluations, modeling demonstrations, and supporting technical documentation are thoroughly developed during the original permitting proceeding. For significant projects, applicants may therefore have an additional incentive to identify and resolve potential permitting issues before the NSR permit is issued rather than assuming that unresolved issues can be addressed during a subsequent Title V proceeding. Potential Incentive for Broader Public Participation EPA also notes that permitting authorities may choose to provide public notice and an opportunity for comment for a broader range of NSR permits because permits issued through a qualifying public process receive the benefit of the finality framework established by the rule. Some permitting authorities may conclude that greater public participation at the NSR stage is preferable to uncertainty during subsequent Title V proceedings. Conclusion The final rule is principally a permitting-certainty measure. For sources that obtain NSR permits through a public process, EPA has substantially limited the ability of third parties to revisit underlying NSR determinations through the Title V program. As a result, regulated entities should benefit from greater finality regarding key permitting decisions, reduced risk of collateral permit challenges, and increased certainty when planning and implementing capital projects.

Insights

SEC Proposes Expansion of Investment Adviser Performance-Based Compensation Rule

On September 30, 2026, the Securities and Exchange Commission (the “SEC”) proposed amendments to Rule 205-3 under the Investment Advisers Act of 1940, as amended (the “Advisers Act”), which provides an exemption from the general prohibition under Section 205(a)(1) of the Advisers Act on registered investment advisers receiving performance-based compensation (the “Proposal”) so long as performance-based compensation is limited to “qualified clients”.1 Most notably for private fund sponsors, the Proposal would expand the definition of “qualified client” to include any investors that satisfy the “accredited investor” definition under Regulation D. The Proposal may also have implications for private fund managers that rely on exemptions from investment adviser registration under state law because certain state-level investment adviser registration exemptions incorporate or otherwise reference the federal qualified client definition. Expansion of the Qualified Client Definition Under the current Rule 205-3, an investor generally may qualify as a qualified client if, among other alternatives, the investor has at least $1.4 million under management with the adviser or has a net worth exceeding $2.7 million. These thresholds are higher than the financial thresholds applicable to many accredited investors under Regulation D. As a result, an investor may currently qualify as an accredited investor for purposes of investing in a private offering without qualifying as a qualified client for purposes of paying performance-based compensation. The Proposal would expand the qualified client definition to include any natural person or legal entity investor that satisfies the accredited investor definition under Regulation D. The Proposal would also remove the assets under management and net worth thresholds under the current Rule 205-3 qualified client test. For private funds relying on Section 3(c)(1) of the Investment Company Act of 1940, this change could reduce the need to apply a separate qualified client standard to investors that already qualify as accredited investors. Dorsey Observations and Next Steps If adopted as proposed, the expanded qualified client definition could be particularly significant for private fund managers. Most private fund offerings are already limited to accredited investors under Regulation D. However, the Proposal could expand the pool of prospective investors available to emerging private fund managers while reducing the regulatory burden associated with complying with Rule 205-3. The Proposal could also benefit advisers operating below the SEC registration threshold that rely on a state private fund adviser exemption. A number of states have adopted exemptions modeled on the North American Securities Administrators Association (“NASAA”) private fund adviser exemption, which may condition relief for advisers to certain funds relying on Section 3(c)(1) on each beneficial owner satisfying the federal qualified client definition. However, state requirements vary, and any effect of the Proposal would depend on the text of the applicable state exemption and how it incorporates Rule 205-3. Many emerging private fund managers may have a larger network of accredited investor relationships than qualified client relationships during the early stages of their investment advisory business. Currently, under Rule 205-3, private fund managers may receive performance-based compensation from investors who do not satisfy the qualified client definition if those investors were admitted to their private funds prior to registration with the SEC. Following registration with the SEC, however, managers may continue to permit investors that are not qualified clients to invest in future private funds but may not receive performance-based compensation from those investors with respect to such investments. In addition, because the net worth and assets under management thresholds for qualified client status are adjusted for inflation every five years, the pool of qualified client investors may diminish over time as previously eligible investors no longer satisfy the applicable thresholds. The Proposal could provide the dual benefit of greater flexibility for private fund managers to establish and maintain relationships with accredited investors as their businesses scale and they become registered with the SEC, and greater flexibility for certain accredited investors to participate in investment strategies that historically have been restricted to much larger institutional investors. Unless and until the Proposal is adopted, investment advisers should continue to comply with the existing qualified client requirements. If the Proposal is adopted, private fund sponsors should consider whether corresponding changes are appropriate for their subscription documents, investor questionnaires, and other offering materials. Advisers that are state-registered or rely on a state-level exemption should also consult the laws and regulations of each relevant jurisdiction before changing investor eligibility standards or performance-based compensation practices, because adoption of the federal amendments may not automatically modify state requirements. Comments on the Proposal will be due 60 days after publication in the Federal Register. 1 Investment Adviser Performance-Based Compensation Modernization, Investment Advisers Act Release No. IA-7022 (Sept. 30, 2026), available at https://www.sec.gov/rules-regulations/2026/09/s7-2026-28#33-11443proposed.

Insights

The Supreme Court Update - October 8, 2026

On September 29, 2026, the Supreme Court granted certiorari in one case: Department of Homeland Security v. D.V.D., No. 26-426: This case concerns the Trump Administration’s “third-country removal” procedures, where immigrants are deported to countries not listed in the removal orders. In granting certiorari, the Court granted the Government’s application to stay a lower court decision halting the practice, which will allow third-country removals to continue pending resolution of the case. The issues presented are: (1) Whether the district court had jurisdiction over respondents’ claims; (2) whether the district court had authority to enter class-wide declaratory relief and APA vacatur under 8 U.S.C. § 1252(f)(1); (3) whether the Government’s guidance on third-country removals is unlawful under 8 U.S.C. § 1231(b), the due process clause, or FARRA/CAT and its implementing regulations; and (4) such other questions that the Government determines are appropriate for the proper disposition of the case. On October 1, 2026, the Court granted certiorari in three additional cases: Rhoney v. Barbosa da Cunha, No. 26-104: Immigration officials detained Ricardo Aparecido Barbosa da Cunha—a Brazilian citizen who had lived in the United States for approximately twenty years after entering without inspection—and denied him a bond hearing under 8 U.S.C. § 1225(b)(2)(A). The Second Circuit held that his detention was instead governed by § 1226(a), which permits release on bond, because § 1225(b)(2)(A)’s mandatory-detention requirement applies only to noncitizens apprehended while entering the country or shortly thereafter. The question presented is: Whether 8 U.S.C. § 1225(b)(2)(A) mandates the detention pending removal proceedings of aliens who, like Barbosa da Cunha, are present in the United States without having been admitted. Missionaries of St. John the Baptist, Inc. v. Frederic, No. 25-113: A Catholic religious organization sought to build a shrine to the Virgin Mary on land the organization owned adjacent to its church in Park Hills, Kentucky. Local zoning restrictions prohibited the proposed construction. The question presented is: Whether a land-use regulation that prohibits a religious institution from building a religious structure on its own property constitutes a “substantial burden” on religious exercise under the Substantial Burden Provision of the Religious Land Use and Institutionalized Persons Act, 42 U.S.C. § 2000cc(a). Marschner v. Marschner, No. 25-1349: Under the Uniformed Services Former Spouses’ Protection Act (“USFSPA”), a veteran’s longevity-based retirement pay can be divided in a divorce, but retirement pay based on disability and retirement pay that was waived to receive disability pay are indivisible. The question presented is: Does the USFSPA require state courts to refuse enforcement of indemnification provisions in a divorce settlement agreement?

News

Dorsey Recognized in Inaugural 2026 IAM/WTR Copyright 1000

Dorsey & Whitney LLP is pleased to announce its recognition in the inaugural edition of the Copyright 1000: The World’s Leading Copyright Professionals, published by IAM and World Trademark Review (WTR). Nine Dorsey attorneys were individually recognized, and the Firm’s Denver, Minneapolis, New York, Salt Lake City, and Seattle offices were recognized in the firm rankings. The following Dorsey attorneys were recognized in the inaugural guide: Lindsey Sadler Gregory Tamkin Charlene Krogh Evan Everist Jeffrey Cadwell Fara Sunderji Bruce Ewing Catherine Parrish Lake J. Michael Keyes The Copyright 1000 is the first dedicated ranking focused solely on the world’s leading copyright practitioners. The guide identifies leading copyright firms and practitioners across key jurisdictions worldwide. Dorsey’s intellectual property attorneys advise clients on a wide range of copyright matters, including protection, enforcement, licensing, litigation, transactions, and issues involving emerging technologies and digital content. The inaugural Copyright 1000 rankings are published by IAM and WTR.