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Indiana Notification of Health Care Transactions Law Takes Effect

June 24, 2024 – Dorsey Health Law

by Randall Hanson and Neal N. Peterson

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On July 1, 2024, Indiana’s new health care transactions notification law takes effect.[1] The law is designed to increase government oversight of mergers and acquisitions involving health care entities. Indiana joins a growing number of states that have passed similar legislation implementing notice requirements and increasing antitrust evaluations for certain health care transactions.[2] The following provides a general overview of Indiana’s new law.

General Purpose and Key Definitions

Indiana’s health care transactions notification law grants the Indiana Attorney General (AG) the authority to review certain mergers and acquisitions between two health care entities if at least one of the entities is an Indiana health care entity.[3] To enforce this oversight power, the law establishes specific notice requirements for the transacting health care entities. Such notice must be provided to the Indiana AG at least ninety (90) days before the date of the merger or acquisition.[4] Upon reviewing a submission of notice, the Indiana AG may issue a civil investigative demand for more information regarding the merger or acquisition.

Below are key definitions from Indiana’s law defining the applicable scope:

Transactions affected by the new notification requirements include mergers and acquisitions.

  • “Merger” is defined as any change of ownership including:
    • An acquisition or transfer of assets, or
    • The purchase of stock effectuated by a merger agreement.
  • “Acquisition” is defined as any agreement, arrangement, or activity that results in a person acquiring, directly or indirectly, control of another person.

Entities affected by the new law are those specifically falling within the statute’s definition of health care entities.[5]

  • “Health care entity” is defined as:
    • Any organization or business that provides diagnostic, medical, surgical, dental treatment, or rehabilitative care.
    • An insurer that issues a “policy of accident and sickness insurance,”[6] which generally includes a policy or contract covering bodily injury, disablement by injury or illness, or death by accident or disease.[7]
      • The statute provides specific exceptions for several types of coverage.[8]
    • A health maintenance organization.
    • A pharmacy benefit manager, which refers to an entity that performs certain administrative functions on behalf of a health plan, state agency, insurer, managed care organization, or other third party payor.[9]
    • An administrator, meaning a person who, on behalf of an insurer, “underwrites, collects charges or premiums from, or adjusts or settles claims on residents of Indiana in connection with life, annuity, or health coverage offered or provided by an insurer.”[10]
      • The statute provides several specific exclusions for persons not considered an administrator.[11]
    • A private equity partnership, regardless of where the private equity partnership is located, seeking to enter a merger or acquisition with any entity described above.[12]

If a transaction meets the definition of merger or acquisition, and the entities involved are “health care entities” under the statute, then the transaction may be subject to certain notification requirements.

Notification Requirements

Indiana’s health care transactions notification law requires an Indiana health care entity “involved in a merger or acquisition with another health care entity with total assets, including combined entities and holdings, of at least ten million dollars ($10,000,000)” to provide written notice to the Indiana AG at least ninety (90) days before the date of the merger or acquisition.[13]

For notice to be required under Indiana’s health care transactions notification law, the transaction must: (1) satisfy the statute’s definition of either a merger or acquisition; (2) involve two or more “health care entities,” one of which must be based in Indiana; and (3) concern at least ten (10) million dollars in total assets. If these characteristics are met, then the transacting health care entities must submit notice as outlined below.

If the transaction is subject to Indiana’s notice requirements, each health care entity involved in the transaction must submit written notice to the Indiana AG, which must include the following information:

  • The entity’s business address and federal tax number.
  • The name and contact information of a representative of the health care entity concerning the merger or acquisition.
  • A description of the health care entity.
  • A description of the merger or acquisition, including the anticipated timeline.
  • A copy of any materials that have been submitted to a federal or state agency concerning the merger or acquisition.[14]

Attorney General Obligations and Oversight Powers

Following a health care entity’s compliance with the above notice requirements, the Indiana AG will review the information submitted and provide a written analysis of any antitrust concerns regarding the merger or acquisition. The Indiana AG must provide its analysis not later than forty-five (45) days following the health care entity’s submission of notice. The analysis is given to the representative of the health care entity that submitted notice.

Additionally, the Indiana AG has the power to issue a civil investigative demand to collect further information regarding the merger or acquisition from the health care entities submitting notice. The civil investigative demand must be made pursuant to Indiana’s existing law, which, in part, requires the attorney general to have reasonable cause to believe a person has violated a statute enforced by the attorney general.[15]

Finally, Indiana’s health care transactions notification law imposes certain confidentiality requirements. The Indiana AG must keep confidential all nonpublic information provided through the notice requirements. Furthermore, any information received or produced by the Indiana AG is also considered confidential.

If you have any questions regarding Indiana’s health care transactions notification law and how your organization or transaction may be impacted, please contact the authors or your regular Dorsey attorney.

Summer Associate Katelyn Tarrolly provided substantial assistance researching and drafting this blog post.

[1] Burns Ind. Code Ann. §§ 25-1-8.5-1—25-1-8.5-4.

[2] See Lillie Cox, Randall Hanson, Jamie McCarty & Neal Peterson, Minnesota Attorney General Notification of Health Care Transaction, Dorsey Health Law Blog (May 30, 2023), https://www.dorseyhealthlaw.com/minnesota-attorney-general-notification-of-health-care-transactions/ (noting several states have enacted or are considering similar legislation, including California, Connecticut, Delaware, Massachusetts, Minnesota, Nevada, New Jersey, New York, Oregon, Rhode Island, and Washington).

[3] To trigger Indiana’s transactions notification requirements, both entities must be health care entities. Additionally, the law requires at least one of those entities to be an “Indiana health care entity.” The statute does not define “Indiana health care entity.” Currently, there is no guidance that clarifies the criteria for being considered an “Indiana health care entity” under the new law. Burns Ind. Code Ann. § 25-1-8.5-4.

[4] The statute provides that notice shall be given “at least ninety (90) days prior to the date of the merger or acquisition[.]” This likely means notice must be given ninety (90) days prior to the closing date of the merger or acquisition; however, there is no guidance currently clarifying the correct interpretation of this provision. Burns Ind. Code Ann. § 25-1-8.5-4.

[5] “Health care entity” does not include the Medicaid program or the Medicare program. Burns Ind. Code Ann. § 25-1-8.5-2(b).

[6] Burns Ind. Code Ann. § 25-1-8.5-2.

[7] See Burns Ind. Code Ann. § 27-8-5-1 (“‘[P]olicy of accident and sickness insurance’, as used in this chapter, includes any policy or contract covering one (1) or more of the kinds of insurance described in Class 1(b) or 2(a) . . . .”).; see also Burns Ind. Code Ann. § 27-1-5-1 (defining Class 1(b) and Class 2(a) insurance).

[8] An insurer that issues one or more of the following types of coverage is explicitly excluded from the definition of health care entity: “(A) accident only, credit, dental, vision, long term care, or disability income insurance; (B) coverage issued as a supplement to liability insurance; (C) automobile medical payment insurance; (D) a specified disease policy; (E) a policy that provides indemnity benefits not based on any expense incurred requirements, including a plan that provides coverage for: (i) hospital confinement, critical illness, or intensive care; or (ii) gaps for deductibles or copayments.; (F) worker’s compensation or similar insurance; (G) a student health plan; (H) a supplemental plan that always pays in addition to other coverage. Burns Ind. Code Ann. § 25-1-8.5-2(a)(2).

[9] A pharmacy benefit manager is an entity that: “(1) contracts directly or indirectly with pharmacies to provide prescription drugs to individuals; (2) administers a prescription drug benefit; (3) processes or pays pharmacy claims; (4) creates or updates prescription drug formularies; (5) makes or assists in making prior authorization determinations on prescription drugs; (6) administers rebates on prescription drugs; or (7) establishes a pharmacy network.” Burns Ind. Code Ann. § 27-1-24.5-12.

[10] Burns Ind. Code Ann. § 27-1-25-1.

[11] Administrator does not include: (1) an employer or wholly owned direct or indirect subsidiary of an employer acting on behalf of the employees of: (A) the employer; (B) the subsidiary; or (C) an affiliated corporation of the employer; (2) a union acting for its members; (3) an insurer; (4) an insurance producer licensed under IC 27-1-515.6 that has a life or accident and health or sickness qualification and whose activities are limited exclusively to the sale of insurance; (5) a creditor acting for its debtors; (6) a trust established under 29 U.S.C. 186 and the trustees, agents, and employees acting pursuant to that trust; (7) a trust that is exempt from taxation under Section 501(a) of the Internal Revenue Code; (8) a financial institution that is subject to supervision or examination by federal or state banking authorities to the extent that the financial institution collects and remits premiums to an insurance producer or an authorized insurer in connection with a loan payment; (9) a credit card issuing company that: (A) advances for; and (B) collects from, when a credit card holder authorizes the collection; credit card holders of the credit card issuing company, insurance premiums or charges; (10) a person that adjusts or settles claims in the normal course of the person’s practice or employment as an attorney at law and that does not collect charges or premiums in connection with life, annuity, or health coverage; (11) a health maintenance organization; (12) a limited health maintenance organization; (13) a mortgage lender to the extent that the mortgage lender collects and remits premiums to an insurance producer or an authorized insurer in connection with a loan payment; (14) a person that is licensed as a managing general agent and acts exclusively within the scope of activities under the license; (15) a person that (A) directly or indirectly underwrites, collects charges or premiums from, or adjusts or settles claims on residents of Indiana in connection with life, annuity, or health coverage provided by an insurer;

(B) is affiliated with the insurer; and (C) performs the duties specified in clause (A) only according to a contract between the person and the insurer for the direct and assumed life, annuity, or health coverage provided by the insurer. Id.

[12] The statute does not define “private equity partnership.” Currently, there is no guidance interpreting what is considered a “private equity partnership.” Burns Ind. Code Ann. § 25-1-8.5-2(a)(6).

[13] Burns Ind. Code Ann. § 25-1-8.5-4(a).

[14] Burns Ind. Code Ann. § 25-1-8.5-4(b).

[15] Burns Ind. Code Ann. § 4-6-3-3.

Firm Highlights

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

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?

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.