Table of Contents

• SEC Proposes New Regulation E-Delivery
• Rev. Rul. 2026-20: IRS Ruling on ETF Seeding Transactions Involving Sections 351 and 852(b)(6)
• SEC Division of Examinations Staff Issues Observations Regarding Investment Adviser Annual Compliance Reviews
• No-Action Relief for ETF Creation Baskets During Passive Concentration Exceedances
• SEC No-Action Letter Regarding Directed Voting Programs
• SEC Amends Its Quorum Rule to Allow a Single-Commissioner Quorum

SEC PROPOSES NEW REGULATION E-DELIVERY

On July 16, the U.S. Securities and Exchange Commission (the “SEC” or “Commission”) proposed Regulation E-Delivery (“Reg E-Delivery”), a new rule that, if adopted, would expand the ability of issuers, broker-dealers, investment advisers, and others (“Covered Entities”) to use electronic delivery (“e-delivery”) to satisfy information delivery requirements under the federal securities laws. Reg E-Delivery would permit, but not require, Covered Entities to use e-delivery as the default method for delivering required regulatory information, subject to certain conditions, in place of the current framework under which paper is effectively the default unless the recipient affirmatively elects e-delivery.

Background

The Commission’s current approach to e-delivery is governed by interpretive guidance issued in 1995, 1996, and 2000 (collectively, the “Existing E-Delivery Guidance”). That guidance is built around three factors: notice, access, and evidence of delivery, and identifies an investor’s informed consent as a principal means of satisfying the evidence-of-delivery factor. Because of the guidance regarding informed consent, issuers and market intermediaries generally deliver regulatory documents and reports in paper unless the recipient consents, or “opts in,” to delivery. As a result, paper delivery has remained the default for most required regulatory disclosures and reports.

The proposal reflects growth in internet use and investor polling by the SEC’s Office of the Investor Advocate finding that nearly 80% of U.S. investors prefer some form of e-delivery for financial disclosure documents that do not include personal financial information. Reg E-Delivery, if adopted, would be the Commission’s primary rule addressing e-delivery and would generally supersede the Commission’s current guidance-based framework.

Substance of the Proposal

Scope. Reg E-Delivery would be broad in scope. It would reach virtually every corner of the securities disclosure ecosystem:

Who delivers? “Covered Entities” would include public companies, registered investment companies, broker-dealers, investment advisers, and any other person required to deliver information under the federal securities laws.

What’s covered? “Covered information” would include fund prospectuses, shareholder reports, proxy statements, trade confirmations, Form CRS disclosures, Form ADV Part 2 Brochures, and other required disclosures—essentially any information required to be delivered under the federal securities laws, other than information delivered under Regulation Crowdfunding, Rule 15c2-11, and the security-based swap trade acknowledgment rule, each of which already has a tailored e-delivery framework.

Who receives? “Covered recipients” would include current or prospective customers, clients, investors, security holders, counterparties, or similar recipients of information.

Default E-Delivery Framework. Reg E-Delivery would reverse the current model. Rather than requiring affirmative consent before going electronic, Covered Entities could use e-delivery as the default. Whether or not a Covered Entity chooses default e-delivery, it could rely on Reg E-Delivery to satisfy its delivery obligations where three conditions are met:

Electronic address on file. The covered recipient has provided an electronic address to the Covered Entity.

Prominent disclosure. The Covered Entity has provided a prominent disclosure that it will send covered information to that electronic address.

No opt-out. The covered recipient has not opted out of e-delivery.

Delivery Methods. Reg E-Delivery contemplates two permissible methods of e-delivery, which depend on the nature of the covered information:

Direct Delivery: For covered information that does not include personal financial information (“PFI”), a Covered Entity could deliver covered information directly to a covered recipient’s electronic address.

Statement of Availability: For covered information that includes PFI, a Covered Entity would be required to deliver a statement of availability (e.g., an email with a link to a website where the covered recipient can access the information). This method may also be used for covered information that does not include PFI. Where a statement of availability is used, the covered information would need to be posted on a website (other than a Commission filing system such as EDGAR) that satisfies certain requirements, including that the information remain available for at least three years (for information containing PFI) or one year (for information without PFI), unless the federal securities laws provide a different availability period, and that PFI be accessible only through a process reasonably designed to safeguard the information, such as the use of passwords. 

Disclosure Requirements. Covered Entities relying on Reg E-Delivery would be required to provide prominent disclosures to covered recipients explaining how to (1) obtain a paper version of covered information free of charge; (2) opt out of e-delivery and receive paper delivery; and (3) update the covered recipient’s electronic address. These disclosures would be required to direct covered recipients to a website where they can take these actions. Covered Entities would be required to send a requested paper copy free of charge within three business days and to promptly honor opt-out elections.

Additional Compliance Requirements. In addition to the conditions described above, Reg E-Delivery would require Covered Entities to adopt and implement written policies and procedures reasonably designed to identify and remediate failed e-delivery. Reg E-Delivery would include further requirements addressing timing, manner, and form of e-delivery, including that covered information be delivered separately from non-covered communications (such as marketing materials).

Transition Process. For covered recipients currently receiving paper, Covered Entities would be required to provide two written notices before switching to e-delivery: (1) an initial notice at least 180 days before the transition and (2) a follow-up notice 30 days before the transition.

Each notice would be required to explain the covered recipient’s right to opt out, request paper delivery, and update their electronic address. Notably, covered recipients retain the right to opt out of e-delivery at any time and receive paper free of charge. The proposal would also exempt electronic delivery made in compliance with Reg E-Delivery from the consent requirements of the E-SIGN Act.

Amendments to Existing Rules

To facilitate Reg E-Delivery, the Commission also proposed amendments to existing rules:

Rescission of Rule 30e-3. Rule 30e-3, which provides alternative means for registered closed-end funds and certain insurance company separate accounts to satisfy shareholder report delivery requirements through a notice-and-access model, would be rescinded. The Commission indicated that Rule 30e-3 would no longer be necessary because Covered Entities eligible to use Rule 30e-3 would instead rely on Reg E-Delivery.

Amendments to Regulations 14A and 14C, and Rule 14d-5. The Commission proposed several changes to conform the proxy and tender offer delivery rules under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), to the Reg E-Delivery framework, including:

Elimination of the standalone paper Notice of Internet Availability of Proxy Materials. The current paper notice would be replaced by a statement of availability delivered electronically in accordance with Reg E-Delivery.

Removal of the 40-day advance deadline. The federal requirement to send paper notices at least 40 calendar days before a meeting would be removed; timing would align with general federal rules and state-law meeting requirements.

Electronic dissemination of third-party tender offer materials. Rule 14d-5 would be amended to permit e-delivery in accordance with Reg E-Delivery in place of mailing; stockholder lists provided to bidders would need to include electronic addresses, or the subject company would have to disseminate the materials itself.

Comment Period and Next Steps

The public comment period closed on September 21, 2026. The Commission proposed that any final rule become effective 60 days after its publication in the Federal Register, followed by a two-year compliance period. At the end of that compliance period, the 1995 and 1996 guidance would be rescinded, and only certain sections and examples of the 2000 guidance (principally those addressing telephonic consent, global consent, and PDF delivery) would be superseded; the remainder of the 2000 guidance would be retained, and Covered Entities would be required to comply with Reg E-Delivery. Going forward, funds, advisers, broker-dealers, and other market participants should monitor rulemaking and evaluate how the proposed transition to e-delivery as the default may affect their current delivery practices and investor communications.

REV. RUL. 2026-20: IRS RULING ON ETF SEEDING TRANSACTIONS INVOLVING SECTIONS 351 AND 852(B)(6)

On September 28, the Internal Revenue Service (“IRS”) released Revenue Ruling 2026-20 (the “Revenue Ruling”) on certain investment fund strategies involving exchange-traded funds (“ETFs”).

The Revenue Ruling outlined the IRS’s analysis regarding the federal income tax characterization of certain multi-step seeding transactions that rely on the combination of Section 351 and Section 852(b)(6) of the Internal Revenue Code of 1986, as amended (the “Code”), involving seeding ETFs with appreciated assets followed by an in-kind distribution of those assets to an authorized participant (an “AP”).

By way of brief background, a newly formed ETF may be initially capitalized through an in-kind seeding transaction in which one or more investors contribute securities to the ETF in exchange for shares of the ETF. These in-kind contributions are often structured to qualify as tax-deferred transactions described in Section 351. Section 351 provides that a person contributing appreciated assets to a corporation in exchange for stock in the corporation does not recognize gain on such contribution if certain requirements are met. Among other things, the assets contributed by each contributor must constitute a “diversified portfolio” and persons contributing assets to the corporation as part of the plan must collectively own at least 80% of the corporation following the contributions.

Under Section 852(b)(6), a regulated investment company (“RIC”) (such as an ETF or open-end mutual fund) generally recognizes no gain or loss on an in-kind distribution of property to a shareholder in redemption of the shareholder’s stock upon demand. Accordingly, the redemption of the AP’s shares is intended to qualify for non-recognition treatment under Section 852(b)(6).

The facts of the ruling are as follows. As part of a plan, an investor transfers a portfolio of securities to a newly formed ETF. For federal income tax purposes, the ETF is a corporation that intends to qualify as a RIC under Section 851 and to be taxed under Subchapter M of the Code. When the investor makes the transfer, the securities are appreciated, and the transferred portfolio is diversified within the meaning of Treasury Regulation Section 1.351-1(c). Two further transactions take place under the same plan. First, the ETF issues shares to an AP in exchange for either securities consistent with the ETF’s investment thesis or cash that the ETF intends to use to buy such securities. Second, shortly afterward, the ETF redeems those shares in a transaction intended to qualify under Section 852(b)(6), paying the AP with securities the investor transferred to the ETF. Once the planned transactions are complete, the ETF holds a portfolio that is consistent with its investment thesis and materially different from the portfolio the investor transferred.

The Revenue Ruling addressed the issue of whether a transfer of securities to a newly formed ETF that is intended to qualify as a tax-free exchange under Section 351 should fail to so qualify if, as part of the same plan, some or all of the transferred securities are distributed under Section 852(b)(6) to redeem shares held by an AP.

Applying generally applicable principles of tax law, such as substance-over-form and step-transaction doctrines, the Revenue Ruling concludes that the investor’s transfer of assets to the ETF is “recharacterized to reflect the substance of the transactions carried out pursuant to the plan.” Accordingly, the ETF’s transitory ownership of the transferred securities is disregarded, and the investor is treated as exchanging with the AP, in a taxable transaction, the securities it contributed to the ETF that are used by the ETF to redeem the AP’s shares. As a result, the Revenue Ruling sets forth the position of the IRS that Section 351 and Section 852(b)(6) cannot be combined, under a prearranged plan, to achieve a non-taxable exchange of one portfolio for a materially different portfolio.

SEC DIVISION OF EXAMINATIONS STAFF ISSUES OBSERVATIONS REGARDING INVESTMENT ADVISER ANNUAL COMPLIANCE REVIEWS

On September 14, the staff of the SEC Division of Examinations (the “Staff”) issued a risk alert (the “Risk Alert”) summarizing what examiners observed from recent examinations of SEC-registered investment advisers’ annual reviews of their compliance programs, as required under Rule 206(4)-7 (the “Compliance Rule”) under the Investment Advisers Act of 1940, as amended (the “Advisers Act”). Of note, the Risk Alert addresses investment advisers only. The Staff last released observations about registered fund annual compliance reviews under Rule 38a-1 under the Investment Company Act of 1940, as amended (the “1940 Act”), in a separate risk alert dated November 4, 2024.

Under the Compliance Rule, each adviser must adopt and implement written policies and procedures reasonably designed to prevent violation of the Advisers Act and the rules thereunder (together with the related compliance infrastructure, a “Compliance Program”), designate a chief compliance officer (“CCO”) responsible for administering those policies and procedures, and review the adequacy and effectiveness of its policies and procedures no less frequently than annually (an “Annual Review”). The Compliance Rule does not require that the CCO conduct the Annual Review, although in many cases the CCO will be tasked with the responsibility. As the Risk Alert notes, the Commission’s 2003 adopting release states that each Annual Review should consider (i) any compliance matters that arose during the previous year; (ii) any changes in the business activities of the adviser or its affiliates; and (iii) any changes in the Advisers Act or applicable regulations that might suggest a need to revise the adviser’s policies and procedures. The release also states that advisers should consider interim reviews between Annual Reviews in response to significant compliance events, changes in business arrangements, and regulatory developments.

To the extent that advisers create or use certain documents or other records in connection with the Annual Review, Rule 204-2(a)(17)(ii) under the Advisers Act (the “Recordkeeping Rule”) separately requires advisers to keep and maintain such records in a true, accurate, and current manner. Although the Compliance Rule does not require it, many advisers (or their CCOs) prepare, as a matter of best practice, a written annual report similar to the annual written report a registered fund’s CCO must provide to the fund’s board. An adviser that writes such a report into its own procedures must follow through, however. The Staff cited advisers whose policies required written Annual Review reports covering specified topics, yet no report was prepared.

Among other things, the Staff highlighted the following categories of issues identified in its examinations:

• Timeliness: The most basic failure the Staff found was that some advisers did not perform a review at least annually. Some advisers skipped years entirely, such as reviewing 2021 and 2023 but not 2022. Other advisers let review periods run beyond 12 months, including after CCO departures. Some advisers completed their first review 18 months after registration. The Staff explained that the 18-month window described in the adopting release was available only for the first Annual Review following the Compliance Rule’s October 5, 2004 compliance date, and that every later review must be performed at least annually. A more conceptual failure involved advisers that treated compliance training, or annual attestations that personnel follow firm policies, as satisfying the review requirement.

• Completeness of review procedures: The Staff found that certain advisers’ policies required the review to be documented and to include testing and validation, yet there was no written guidance on how to perform the tests, what factors to weigh in evaluating the results, or what level of documentation to keep. The Staff also observed compliance manuals that required certain practices, services, or operations to be assessed during the Annual Review in one section, while the review procedures themselves left those topics out, so the reviews did not cover them. In one example, the adviser’s identity theft policies called for annual testing, but the Annual Review omitted the topic.

• Consistency with written procedures: The Staff observed timely Annual Reviews that departed from the adviser’s own procedures. These reviews did not cover the defined review period or scope, did not use the specified workpapers, or skipped required tasks and tests. Some reviews assessed outdated policies and procedures that had been superseded before the review period began.

• Alignment of policies with practices: The broadest category of observations concerned the gap between what an adviser’s policies say and what the adviser actually does. The Staff found advisers whose reviews did not recognize that their policies failed to address, or did not match, actual practices. Some advisers had no policies at all for risk areas central to their business. Other advisers failed to account for business changes relevant to the review, for example by not informing the CCO of business or operational changes that could affect the review’s scope. The Risk Alert highlighted specific areas in which Annual Reviews failed to spot problems, including fee and expense billing, proxy voting, custody, marketing, regulatory filings, and oversight of third-party vendors.

• Documentation and corrective action: The Staff found that some advisers created documentation during their reviews, including test results and recommended corrective actions, but did not keep it in their books and records. Other advisers prepared no written report even though their policies required one, or only partly completed required checklists, workpapers, or templates. Each of these failures leads back to the Recordkeeping Rule requirement to keep true, accurate, and current records of the review. The Staff observed advisers that did not act on Annual Review recommendations to change compliance policies, disclosures, or business practices. The unaddressed recommendations included improving proxy voting disclosures, documenting client risk tolerances, and conducting more thorough best execution analysis and third-party due diligence on broker-dealers. In some cases, written Annual Review reports stated that corrective actions had already been taken, yet the issues persisted.

The Risk Alert signals that the Staff views the Annual Review as a substantive requirement rather than a formality. Advisers should anticipate that the Staff will evaluate whether the review was timely, methodical, faithful to the adviser’s own procedures, matched to actual business practices, fully documented, and followed by effective remediation. The Staff often finds gaps by comparing problems it observes in an adviser’s core business areas with that adviser’s Annual Reviews and written policies. Advisers should also expect that because the Recordkeeping Rule requires true, accurate, and current records of the review, an Annual Review that the adviser cannot document may be treated, at least during an examination, as functionally equivalent to not having conducted an Annual Review at all. Because the Staff routinely requests Annual Review materials as part of the examination process, advisers should keep a complete, retrievable file for each review year that includes the report, workpapers, test results, and evidence of remediation.

NO-ACTION RELIEF FOR ETF CREATION BASKETS DURING PASSIVE CONCENTRATION EXCEEDANCES

On July 27, the staff of the Division of Investment Management (the “Division”) issued a no-action letter to the Investment Company Institute addressing how ETFs may continue creation unit activity when such activity causes an ETF to passively exceed its disclosed industry concentration policy. The request that prompted the Division’s no-action letter asked for relief under Sections 13(a)(3) and 34(b) of the 1940 Act.

Under the 1940 Act, a registered fund must disclose its policy on concentrating in an industry or group of industries, and Section 13(a)(3) of the 1940 Act bars a registered investment company from departing from its stated policy on concentrating without approval by a majority of its outstanding voting securities. Additionally, Section 34(b) of the 1940 Act makes it unlawful for any person to make an untrue statement of a material fact (or to omit any fact necessary to prevent the statements from being materially misleading) in a registration statement, report, or other document filed or transmitted under the 1940 Act.

The request highlighted a handful of reasons for requesting no action under Sections 13(a)(3) and 34(b) of the 1940 Act, including the following:

1. Under longstanding SEC staff positions reflected in Form N-1A, a fund “concentrates” if it invests more than 25% of its total assets in a single industry or group of industries. Changes in market value can push an ETF’s holdings in one industry above 25% of its total assets, even when the ETF has a stated policy not to concentrate. The request described this kind of exceedance as passive and caused by factors outside management’s control.
2. ETFs differ from traditional mutual funds in that they issue shares in creation units through APs who deliver creation baskets, and ETFs generally cannot control when creations happen. As a result, a creation order can add to an industry position that is already in passive exceedance, at a time the portfolio manager would not choose.
3. Accepting a pro rata basket is not an investment decision by the manager, and it leaves shareholders’ proportional exposure to the industry unchanged apart from market movements. Cash-in-lieu purchases capped at pro rata amounts are also not a manager’s choice, because the need for cash-in-lieu usually comes from operational issues such as small lots or limits on in-kind transfers. Without no-action relief, ETFs could have to (i) change basket composition or substitute assets in ways that hurt shareholders or (ii) pay the significant cost of a shareholder vote to change the concentration policy.

Considering the facts and representations set forth in the request, the Division’s response letter indicated that it would not recommend enforcement action to the Commission if, during a passive exceedance, an ETF:

1. receives a pro rata creation basket that includes investments in the affected industry;
2. uses cash received in place of a basket component in that industry to buy that security, up to the amount a pro rata basket would have delivered; or
3. receives a non-pro rata basket in which the industry’s weighting matches what a pro rata basket would have had.

The relief applies to both actively managed and index-based ETFs; however, the staff of the Division clarified that its views and opinions are fact-specific and different circumstances could lead to a different outcome.

SEC NO-ACTION LETTER REGARDING DIRECTED VOTING PROGRAMS

On September 29, the staff of the Division issued a no-action letter (the “MFDF Letter”) to the Mutual Fund Directors Forum (“MFDF”) that allows registered investment companies (each, a “Fund”) to implement voluntary directed voting programs (each, a “Directed Voting Program”). Under such a program, retail shareholders would have the ability to give revocable standing voting instructions that would require the Fund to vote their shares in accordance with the recommendation of the Fund’s board of directors (“Board”) (including all of the fund’s independent directors).

The MFDF Letter defines a “retail” shareholder as “any person that has, or is entitled to have, voting authority with respect to the shares of a Fund by virtue of owning beneficially and/or of record such shares, regardless of whether the person owns their shares via a bank, broker, or other financial intermediary.”

A Fund’s Board, including all of the independent directors, would be required to approve the Directed Voting Program prior to its implementation and, at least every three years, reexamine the Directed Voting Program and reapprove it only upon determining that the Directed Voting Program remains in the best interests of shareholders. The MFDF Letter clarifies that a Directed Voting Program may not apply to contested director elections or changes to the Fund’s investment advisory agreement with its primary investment adviser that require a shareholder vote (“Exclusions”).

Shareholders would be required to opt-in to the program and would have two choices for the kinds of matters to which the instructions would apply: (1) all matters, except the Exclusions; or (2) all matters, except (i) the Exclusions; (ii) Fund mergers that, under any of the 1940 Act and its rules, applicable state law, the Fund’s organizational documents, or applicable exchange listing standards, require approval of the Fund’s shareholders; and (iii) adoption of, or changes to, a Fund’s Rule 12b-1 Plan that result in an increase in 12b-1 fees (Items (2)(ii) and (iii), together, the “Opt-Out Items”). Shareholders would have the ability to opt out of the Directed Voting Program at any time and would receive annual reminders of their enrollment in the program and their standing voting instruction. Additionally, any shareholders that have elected for their standing voting instructions to apply to all matters except the Exclusions would receive an additional reminder before any meeting involving an Opt-Out Item, to provide such shareholders an additional opportunity to opt out of the Directed Voting Program or override their instruction prior to any meeting involving an Opt-Out Item.

Because votes for which a Fund has received a standing voting instruction would be cast on the same day that the Fund files a definitive proxy statement or definitive registration statement on Form N-14 for an upcoming meeting, a cancellation of the standing voting instruction would only apply to future meetings. Shareholders could, however, override a standing voting instruction by voting using the proxy for that meeting.

SEC AMENDS ITS QUORUM RULE TO ALLOW A SINGLE-COMMISSIONER QUORUM

On September 30, the Commission adopted an amendment to its quorum rule, 17 CFR 200.41. Under the amendment, a single commissioner can form a quorum on a matter if all other sitting commissioners are disqualified from the matter. This change is intended to give the Commission more flexibility and finality in its rulemaking and other actions.

The Exchange Act does not set a quorum requirement; however, the SEC’s long-standing practice of a three-member quorum became a formal rule in 1995. That rule let two commissioners act on a matter where disqualifications left only two commissioners available, but, at the time, the SEC decided not to allow a one-commissioner quorum. The SEC has now changed course, pointing to past periods when it had fewer than three commissioners and to cases in which multiple commissioners have been disqualified from a matter.

With the new amendment, three commissioners will generally still constitute a quorum, with two exceptions:

1. If only one or two commissioners are in office, that number is a quorum.
2. If the number of commissioners in office, minus those disqualified from a particular matter, is two or one, that number is a quorum for that matter.

The amendment lowers the risk that vacancies or recusals will delay SEC action on rulemakings, exemptive applications, and other matters. It also helps support the finality of actions taken when few commissioners are available.

2026
Date	Host*	Event	Location
10/26-28	ICI/IDC	Fund Directors Conference	Scottsdale, AZ
11/10	ICI/IDC	Defined Contribution Alternatives Summit	New York, NY
11/10	ICI/IDC	Retail Alternatives and Closed-End Funds Conference	New York, NY
11/2	MFDF	ETF Market Analysis and Tax Considerations	Webinar
11/4	MFDF	Mutual Fund CCO Compensation: The MPI Annual Survey Update	Webinar
11/5	MFDF	SEC Enforcement and Exams Update	Webinar
11/9	MFDF	In Focus – Usage of AI in the Boardroom	Virtual
12/14	MFDF	Are we in Kansas Anymore? Understanding Board Oversight of Liquidity, Leverage, and Derivatives in Alternative Investment Products	Webinar
12/16	MFDF	2026 Fair Valuation Pricing Survey Update	Webinar

2027
Date	Host*	Event	Location
2/1	MFDF	2027 Directors’ Institute	Amelia Island, FL
2/3-5	ICI/IDC	ICI Innovate	Phoenix, AZ
2/19	MFDF	Director Discussion Series – Open Forum (Naples)	Naples, FL
3/9	MFDF	Board Oversight of Subadvisers: Performance, Fees, Industry & Product Trends	Webinar
3/12	MFDF	Director Discussion Series – Open Forum (Atlanta)	Atlanta, GA
3/14-17	ICI/IDC	Investment Management Conference	San Diego, CA
4/8	MFDF	2027 Fund Governance & Regulatory Insights Conference	Washington, DC
5/10-12	ICI/IDC	Leadership Summit	Washington, DC
5/10-12	ICI/IDC	Fund Directors Workshop (IDC)	Washington, DC
6/7-9	ICI/IDC	ETF Conference	New Orleans, LA
8/4	MFDF	Director Discussion Series – Open Forum (Milwaukee)	Milwaukee, WI
9/19-22	ICI/IDC	Tax and Accounting Conference	Phoenix, AZ
10/25-27	ICI/IDC	Fund Directors Conference	Scottsdale, AZ
11/9	ICI/IDC	Retail Alternatives and Closed-End Funds Conference	New York, NY

*Host Organization Key: Mutual Fund Directors Forum (“MFDF”), Independent Directors Council (“IDC”), and Investment Company Institute (“ICI”)

© 2026, Davis Graham & Stubbs LLP. All rights reserved. This newsletter does not constitute legal advice. The views expressed in this newsletter are the views of the authors and not necessarily the views of the firm. Please consult with your legal counsel for specific advice and/or information.

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CONTACT US
Peter H. Schwartz
Alena Prokop
Stephanie Danner
Martine Ventello
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Table of Contents

• SEC Proposes Amendments to Form N-PORT Reporting Requirements
• SEC Proposes Expanded “Small Entity” Definitions for Purposes of the Regulatory Flexibility Act
• Federal Court Dismisses Shareholder Suit Against Mutual Fund Directors for Failure to Auto-Convert Money Fund Share Classes
• SEC Orders Adviser to Pay $900,000 for Principal Trade Pricing Failures During Market Disruption
• SEC Division of Enforcement Announces Updates to Enforcement Manual 

INVESTMENT COMPANY INSTITUTE SURVEY ON THE GROWING BURDEN OF FUND PROXY CAMPAIGNS

In March 2026, the Investment Company Institute (“ICI”) published a survey analyzing the escalating costs and challenges of proxy campaigns for U.S. registered investment funds, finding that the U.S. fund proxy system is both inefficient and ineffective. The survey involved 62 investment firms that represented 85% of the U.S.-registered fund assets. The report covered fund proxy campaigns that were conducted between 2020 and 2025. Among other key findings, the survey found that:

• Total campaign costs ranged from $675 million to $1.14 billion, with many of the fund campaigns costing tens of millions of dollars each.
• Special campaigns (362 total) accounted for an estimated $621 million to $1.06 billion, with six campaigns each exceeding $25 million and the most expensive totaling $111 million.
• Contested closed-end fund (“CEF”) campaigns (39 total involving activists) cost between $24 million and $36 million, while uncontested CEF campaigns (698 total) cost between $29 million and $52 million.
• Respondents indicated that CEF proxy campaigns have gotten harder and more expensive since 2020, with almost no respondents reporting that campaigns had become easier or cheaper.

Additionally, the survey found that while shareholders often overwhelmingly support proposals, it can be very difficult to reach a quorum. For example, the survey analyzed a subset of special campaigns seeking to change their Investment Company Act of 1940 sub-classifications from “diversified” to “non-diversified.” Although most of these proposals had average approval rates of 85% of shares present, more than one-third of the proposals could not meet quorum without at least one adjournment, and six of the proposals failed for lack of quorum.

Based on the findings of the survey, the ICI made the following recommendations to the U.S. Securities and Exchange Commission (the “SEC” or the “Commission”):

1. Create a new approval mechanism by coupling a lower quorum requirement (more than 33.33%) with a higher affirmative vote requirement (at least 75%).
2. Adopt alternatives to shareholder approval, such as board approval with advance notice to shareholders, for certain items, including fundamental policy changes.
3. Permit boards to appoint a greater number of new independent directors without shareholder approval.
4. Permit funds to adopt retail voting programs to boost retail investor participation.
5. Allow exchanges to remove the annual meeting requirement for listed CEF and business development companies, returning governance decisions to the states.
6. Revise processing fees and shareholder communication provisions to permit funds to select their own vendors and directly contact shareholders.
7. Reduce proxy statement length by allowing greater use of links and layered formatting to improve shareholder engagement.

SEC PROPOSES AMENDMENTS TO FORM N-PORT REPORTING REQUIREMENTS

On February 18, 2026, the SEC proposed amendments to Form N-PORT reporting requirements for applicable registered investment companies (other than money market funds and small business investment companies) and exchange-traded funds (“ETFs”) organized as unit investment trusts (“UITs”). In light of industry feedback, a challenge in the Fifth Circuit Court of Appeals, and in accordance with the January 2025 Presidential Memorandum entitled “Regulatory Freeze Pending Review”—which directed federal agencies to consider postponing any rules that had not yet taken effect to review questions of fact, law, and policy—the SEC sought to revise (and in some cases reverse) amendments to Form N-PORT that were adopted in 2024 (the “2024 Amendments”). The proposed amendments focus on three areas: filing timeframe, publication frequency, and reporting requirements.

Under the proposal, the deadline for registered funds to file monthly Form N-PORT reports would be extended from 30 to 45 days. According to the Commission, this change is designed to alleviate operational burdens associated with the accelerated timeline of the 2024 Amendments and to reduce the potential for errors and resubmissions.

Additionally, the proposed amendments would restore the quarterly publication schedule that was in place prior to the 2024 Amendments, requiring registered funds to publicly disclose their portfolio holdings every three months, with a 60-day delay following fiscal quarter end, rather than monthly disclosure with a 60-day delay, as adopted in 2024.

Lastly, the proposed amendments would streamline certain N-PORT reporting requirements by:

1. Narrowing the scope of information collected on portfolio-level risk metrics and returns;
2. Eliminating certain information collected regarding payoff profiles of non-derivatives instruments, convertible bonds, and the reasons a single holding has multiple liquidity classifications; and
3. Removing the Names Rule reporting requirements added to Form N-PORT in connection with the 2023 amendments to rule 35d-1 under the Investment Company Act of 1940 (the “1940 Act”).

Additionally, the proposed amendments would require registered funds with ETF share classes to report certain information on net assets and shareholder flows and would require funds to report certain identifying information, including ticker symbols.

In connection with these proposed amendments, the SEC also extended the dates for compliance relating to the Names Rule under the 1940 Act for Form N-PORT reporting funds. Compliance for fund groups with net assets of $10 billion or more as of the end of their most recent fiscal year was extended to November 17, 2027. For fund groups with less than $10 billion in net assets as of the end of their most recent fiscal year, compliance was extended to May 18, 2028.

The deadline for providing comments on the Form N-PORT amendments is April 24, 2026.

SEC PROPOSES EXPANDED “SMALL ENTITY” DEFINITIONS FOR PURPOSES OF THE REGULATORY FLEXIBILITY ACT

On January 7, 2026, the SEC proposed amendments to modernize the definitions of “small entity” applicable to investment companies and investment advisers under the Regulatory Flexibility Act (the “RFA”). If adopted, the proposal would substantially increase the asset-based thresholds used to determine small entity status and would introduce a mechanism for periodic inflation adjustments to reduce the likelihood that the thresholds become outdated over time.

The SEC adopted its current definitions of “small business” and “small organization” for investment advisers under Rule 0-7 of the Advisers Act and for investment companies under Rule 0-10 of the 1940 Act in 1982, with the most recent amendments made in 1998. The RFA requires the SEC to conduct an initial regulatory flexibility analysis and a final regulatory flexibility analysis in connection with proposed and final rulemakings, respectively.

Under existing Rule 0-10 of the 1940 Act, an investment company is deemed a “small entity” if it, together with other investment companies in the same “group of related investment companies,” has net assets of $50 million or less as of the end of its most recent fiscal year (the “Net Asset Threshold”).

Under existing Rule 0-7 of the Advisers Act, an investment adviser is deemed a “small entity” if it satisfies each of the following conditions: (i) it has regulatory assets under management (“RAUM”) of less than $25 million (the “RAUM Threshold”); (ii) it did not have total assets of $5 million or more on the last day of its most recent fiscal year (the “Total Assets Threshold”); and (iii) it does not control, is not controlled by, and is not under common control with (a “control relationship”) another investment adviser that has assets under management of $25 million or more, or any person (other than a natural person) that had total assets of $5 million or more on the last day of its most recent fiscal year (the “Control Relationship Threshold”). By way of brief background, the RAUM Threshold and Total Assets Threshold measure different concepts. As reported on Form ADV, RAUM reflects the value of client assets for which an adviser provides continuous and regular supervisory or management services. By contrast, the Total Assets Threshold refers to assets held on the adviser’s own balance sheet, such as cash, receivables, or ownership interests in affiliated entities.

For investment advisers, the proposal would increase the RAUM Threshold from $25 million to $1 billion. The assets under management component of the Control Relationship Threshold would increase correspondingly from $25 million to $1 billion to conform with the revised RAUM Threshold; however, the total assets component of the Control Relationship Threshold ($5 million) would remain unchanged pending receipt of public comment. The current $5 million Total Assets Threshold would remain unchanged, although the Commission is requesting comment on whether and how it should be revised.

For registered investment companies, the proposal would increase the Net Asset Threshold from $50 million to $10 billion and update the methodology by which the assets of related investment companies are aggregated when determining the small entity status of a registered fund complex. The proposal would also replace the concept of “group of related investment companies” with “family of investment companies,” as defined in Form N-CEN Item B.5, thereby leveraging existing reporting data.

The proposal also provides for inflation adjustments to the applicable asset thresholds every 10 years, which could be effectuated by order of the Commission rather than through formal notice-and-comment rulemaking. Such adjustments would be calculated using the Personal Consumption Expenditures Chain-Type Price Index.

The proposal also provides for Form ADV Amendments. Item 12 of Part 1A of Form ADV would be revised so that investment advisers with RAUM of less than $1 billion (rather than $25 million) would be required to complete the small entity determination questions. Instruction 17 of Form ADV, which provides for a continuing hardship exemption from electronic filing, would be similarly updated to reflect the new $1 billion threshold.

Under the proposed $1 billion RAUM Threshold, the SEC estimates that approximately 15,850 of 21,650 total investment advisers (roughly 75%) would report RAUM below the threshold. After application of the revised Control Relationship Threshold, however, approximately 1,225 advisers (5.7%) would be excluded, resulting in an estimated 14,620 advisers (approximately 70%) satisfying the revised RAUM and Control Relationship Thresholds. This represents a substantial increase from the approximately 3% of SEC-registered advisers that currently qualify as small entities under the existing definitions.

Advisers with RAUM between $25 million and $1 billion that do not have a control relationship with a larger affiliate would be newly classified as small entities, with the result that future RFA analyses would be required to assess the regulatory burden of proposed and final rules on these firms. The direct compliance impact of the proposed amendments is modest: approximately 10,051 additional SEC-registered investment advisers would be required to complete Item 12 of Form ADV, at an estimated cost of approximately $95 per adviser per year. The continuing hardship exemption from electronic filing would also become available to a broader set of advisers, although the SEC expects that few, if any, would qualify for the exemption given the current ubiquity of electronic filing capabilities.

The SEC accepted public comments on the proposal through March 13, 2026.

FEDERAL COURT DISMISSES SHAREHOLDER SUIT AGAINST MUTUAL FUND DIRECTORS FOR FAILURE TO AUTO-CONVERT MONEY FUND SHARE CLASSES

On March 26, 2026, the U.S. District Court for the Southern District of New York dismissed a shareholder lawsuit against a money market fund (the “Fund”), its board of directors, and certain officers, alleging breaches of fiduciary duty and related claims arising from the failure to automatically convert shareholders’ Fund holdings into lower-cost share classes.

In their complaint, two shareholders claimed that the Fund’s board of directors allowed clients to continue paying higher fees despite being able to convert their holdings into a more cost-efficient share class. Through the board’s inaction, the plaintiffs alleged that the directors breached their fiduciary duty and implied covenant of good faith and fair dealing, demonstrating willful negligence.

Members of the Fund’s board along with Fund officers and executives were named in the lawsuit. Notably, the asset manager oversees other financial products that offer a multi-class structure with automatic conversion to lower expense classes; however, no such mechanism was created for the Fund. In response to the claim, the Fund asserted that a mutual fund’s officers and directors do not have a fiduciary duty or legal obligation to ensure shareholders are automatically converted to lower-expense share classes once they are eligible.

In dismissing the case, the court rejected the plaintiff’s assertions, stating that their claim was a “far cry” from the standard that courts have applied to breaches of the duty of care under Delaware law. As such, the court held that the Fund, its officers, and its board did not (i) breach their fiduciary duty by failing to automatically convert the holdings of two shareholders in the Fund despite allegedly being eligible for a lower-cost premium share class, (ii) aid and abet the alleged breach of fiduciary duty, or (iii) unjustly enrich themselves through the additional expenses the shareholders paid by remaining in the higher-cost share class.  The court also ruled that there was no breach of an implied covenant of good faith or fair dealing.

SEC ORDERS ADVISER TO PAY $900,000 FOR PRINCIPAL TRADE PRICING FAILURES DURING MARKET DISRUPTION

On February 25, 2026, the SEC announced that an investment adviser (the “Adviser”) consented to the entry of a cease-and-desist order, censure, and $900,000 civil money penalty in connection with the Adviser’s fair market value determinations when conducting principal trades with pooled investment vehicles it advised (the “Order”).

According to the Order, from March 2020 to May 2020 (the “Relevant Period”), the Adviser offered lending services to companies that were acquired by private equity firms to help them purchase middle-market companies through leveraged buyouts. The Adviser would then originate senior loans, which it would subsequently sell portions of such loans to private funds (the “Private Funds”) that it advised.

In connection with these transactions, the loans that the Adviser made and subsequently sold to the Private Funds were to be sold at par value less the unamortized loan fee to create a “fair market value,” as required by the Private Funds’ advisory agreements and disclosures the Adviser made to investors. This practice was based on the Adviser’s belief that the closing price of recently originated loans generally represented fair market value.

However, during the Relevant Period and at the outset of the COVID-19 pandemic, the Adviser continued to sell performing loans it originated prior to the market disruption at par value minus the unamortized loan fee without determining whether the fair market value of those loans had declined as a result of deteriorating market conditions.

During this same period, the SEC noted in its Order that credit spreads experienced significant dislocation across the fixed income space, which resulted in widespread price declines for many existing fixed income investments. Despite that, the Adviser made 143 sales to the Private Funds during the three-month period, utilizing the original fair market value methodology while also affirmatively stating to the Private Funds’ independent review agent that each sale was at fair market value based on current market conditions.

Based on these findings, the SEC determined that the Adviser willfully violated Section 206(2) of the Investment Advisers Act of 1940 (the “Advisers Act”), which prohibits fraudulent or deceptive conduct, Section 206(4) of the Advisers Act—and Rule 206(4)-8 thereunder—which prohibit material misstatements and fraudulent conduct with respect to investors in pooled investment vehicles. In accepting the Adviser’s settlement offer, the Commission considered remedial acts undertaken by the Adviser, including voluntary reimbursement of slightly over $5 million, plus over $200,000 in interest, to the Funds in May 2021, as well as enhancements to disclosures and policies regarding loan transfer practices.

SEC DIVISION OF ENFORCEMENT ANNOUNCES UPDATES TO ENFORCEMENT MANUAL

On February 24, 2026, the SEC’s Division of Enforcement (the “Division”) announced updates to its enforcement manual (the “Manual”). The Manual is used by the Division’s staff in connection with investigations into potential federal securities law violations. It contains general policies and procedures but is not binding on the Commission.

According to the press release announcing the updates, the updated Manual “emphasizes the importance of open, informed, and thoughtful dialogue between SEC staff and potential respondents and defendants, with the goal of producing better outcomes and ensuring the fair and timely resolution of investigations and recommendations of possible enforcement actions.” With the aim of encouraging dialogue and facilitating consistency in the Wells process, the Manual updates include that Wells notice recipients will ordinarily receive four weeks to make Wells submissions. Wells meetings will include a member of the senior leadership of the Division and will be scheduled within four weeks of receipt of the Wells notice.

The updated Manual also reflects that the Commission restored its practice of permitting a settling party to request that the Commission simultaneously consider a settlement offer and any related waiver requests. The updated Manual also includes (i) changes intended to encourage more consistent internal collaboration, (ii) updates regarding the formal order process, (iii) an updated framework for referrals to criminal authorities, and (iv) other changes intended to conform the Manual to current Division practices.

UPCOMING CONFERENCES

2026
Date	Host*	Event	Location
4/20	ICI/IDC	Overview of the CRI Financial Services AI Risk Management Framework	Virtual
4/22	ICI/IDC	Valuing Private Credit in Retail Vehicles: Governance Considerations, Methodologies, and Market Reality	Virtual
4/29 – 5/1	ICI/IDC	Leadership Summit	Washington, DC
4/29 – 5/1	ICI/IDC	Fund Directors Workshop	Washington, DC
5/11	MFDF	Somewhere Over the Product Rainbow: Interval Funds, Tender Offer Funds, and BDCs… Oh My!	Webinar
5/13	MFDF	Update on Fund Industry Claims Trends: An Insurer’s Perspective	Webinar
5/21	MFDF	Mutual Fund Director Compensation: The MPI Annual Survey	Webinar
5/27	MFDF	Director Discussion Series – Open Forum (San Francisco)	Webinar
6/2	MFDF	MFDF Spotlight: APs and Market Makers – Helpful Takeaways for Fund Boards	Webinar
6/4	MFDF	2026 Conference of Fund Leaders Roundtable	Chicago, IL
6/8-10	ICI/IDC	ETF Conference	Nashville, TN
6/17	MFDF	Financial Statement Review for RIC Boards: What Independent Directors Need to Know	Webinar
6/23	MFDF	Director Discussion Series – Open Forum via Zoom	Virtual
6/25	MFDF	Series Trust Funds – Audits	Webinar
7/14	MFDF	An Introduction to RIC Taxation and Mid-Year Updates	Webinar
7/16	MFDF	Director Discussion Series – Open Forum (Chicago)	Chicago, IL
7/21	MFDF	Board Oversight of Subadvisers: Compliance and Regulatory Issues	Webinar
7/28	MFDF	Director Discussion Series – Open Forum (NYC)	New York, NY
7/29	MFDF	Closed-End Fund Roundtable	New York, NY
9/14	MFDF	Intermediary Fees: What Today’s Trends Mean for Independent Directors	Webinar
9/27-30	ICI/IDC	Tax and Accounting Conference	Marco Island, FL
10/26-28	ICI/IDC	Fund Directors Conference	Scottsdale, AZ
11/10	ICI/IDC	2026 Retail Alternatives and Closed-End Funds Conference	New York, NY
9/15-17	ICI/IDC	Compliance, Risk, and Legal Conference	Nashville, TN
11/2	MFDF	ETFs, Mutual Funds, and Taxes: A Structural Comparison for Fund Boards	Webinar

2027
Date	Host*	Event	Location
2/1	MFDF	2027 Directors’ Institute	Amelia Island, FL
4/8	MFDF	2027 Fund Governance & Regulatory Insights Conference	Washington, DC
2/3-5	ICI/IDC	ICI Innovate	Phoenix, AZ
3/14-17	ICI/IDC	Investment Management Conference	San Diego, CA
5/10-12	ICI/IDC	Leadership Summit	Washington, DC
5/10-12	ICI/IDC	Fund Directors Workshop (IDC)	Washington, DC
6/7-9	ICI/IDC	ETF Conference	New Orleans, LA
9/19-22	ICI/IDC	Tax and Accounting Conference	Phoenix, AZ
10/25-27	ICI/IDC	Fund Directors Conference	Scottsdale, AZ
11/9	ICI/IDC	Retail Alternatives and Closed-End Funds Conference	New York, NY

*Host Organization Key: Mutual Fund Directors Forum (“MFDF”), Independent Directors Council (“IDC”), and Investment Company Institute (“ICI”)

© 2026, Davis Graham & Stubbs LLP. All rights reserved. This newsletter does not constitute legal advice. The views expressed in this newsletter are the views of the authors and not necessarily the views of the firm. Please consult with your legal counsel for specific advice and/or information.

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CONTACT US
Peter H. Schwartz
Alena Prokop
Stephanie Danner
Martine Ventello
Mackenzie Coupens
Robert Hill

Produced water – the fluid that surfaces alongside oil and gas during extraction, typically carrying high concentrations of dissolved salts and minerals – has long been the industry’s largest waste stream and one of its most persistent cost centers. That is changing. A convergence of disposal constraints, treatment technology advances, legislative reform, institutional-scale capital deployment, and the strategic importance of critical minerals is transforming produced water from a disposal liability into a managed resource. Across multiple U.S. basins, produced water is now at the center of billion-dollar infrastructure transactions, first-of-a-kind treatment and mineral extraction projects, and a rapidly evolving regulatory landscape that cuts across state, federal, and Tribal jurisdictions.

This client alert surveys the current state of the U.S. produced water value chain – spanning the Permian Basin, DJ Basin, Smackover Formation, and beyond – and identifies the legal, regulatory, commercial, and transactional issues that energy companies, investors, landowners, midstream operators, technology providers, and critical minerals developers should be watching.

I. Scale of the Problem and the Opportunity

Every barrel of oil produced in the Permian Basin brings with it roughly three to five barrels of produced water, and in parts of the Delaware Basin those ratios can reach ten to one. At current production levels, the Permian alone generates more than 20 million barrels of produced water daily. New Mexico’s oil and gas operations generate nearly two billion barrels of produced water per year. In Colorado’s DJ Basin, by contrast, water-to-oil ratios are significantly lower – roughly one barrel of water for every eight barrels of oil – but freshwater consumption for completions is substantial, with the basin consuming approximately five billion gallons of fresh water in 2022 alone.

An estimated 50% to 60% of Permian produced water is currently recycled for use in hydraulic fracturing – the simplest and cheapest form of reuse. The remainder must be disposed of by injection into deep underground formations, and decades of injection have raised formation pressures, triggered seismicity concerns, and prompted regulatory restrictions that increasingly limit disposal capacity in core producing areas.

Advanced treatment technologies capable of converting produced water to higher-value uses – agricultural irrigation, industrial supply, aquifer recharge – exist but face a persistent cost gap. Disposal currently runs roughly $0.75 to $1.25 per barrel. Treatment for frac reuse costs a similar amount, whereas treatment to agricultural quality can run $2 to $4 per barrel, and treatment to drinking water standards $4 to $7 per barrel or more. Until that gap narrows through technology maturation, regulatory incentives, new co-product revenue streams such as mineral extraction, or a supply-and-demand shift that drives prices higher for treated water and equivalent alternatives, large-scale beneficial reuse beyond the oilfield will remain in the pilot and early-commercial phase.

Induced seismicity is likely to be a primary driver in closing that gap. Decades of high-volume saltwater injection have triggered measurable seismic events across the Permian, prompting the Texas Railroad Commission to impose volume reductions and geographic restrictions on injection wells in affected areas. Similar concerns have led the New Mexico Oil Conservation Division to tighten disposal oversight. These constraints are not temporary; as formation pressures continue to rise, the physical and regulatory capacity for disposal-as-usual is narrowing, strengthening the economic case for recycling, treatment, and beneficial reuse.

II. A National Regulatory Landscape in Flux

Produced water regulation is evolving rapidly – and divergently – across multiple states and at the federal level. Oil and gas operators, investors, and technology providers in Texas, New Mexico, Colorado, or on federal lands should closely track simultaneous developments in those states and Washington, D.C.

Texas. The Texas Supreme Court, in Cactus Water Services, LLC v. COG Operating, LLC (June 2025), held that produced water is oil-and-gas waste belonging to the mineral lessee absent an express contrary conveyance – resolving a longstanding ownership ambiguity that had clouded midstream contracting, surface-use agreements, and reuse project development.

The 89th Texas Legislature also enacted a suite of changes in 2025 that collectively represent the most significant produced water legislative package in the state’s history:

• SB 1145 transferred land-application permitting authority for treated produced water from the Texas Railroad Commission to the Texas Commission on Environmental Quality (TCEQ), which is expected to propose implementing rules in April 2026.
• HB 49 limits tort liability for entities involved in the treatment, transfer, or beneficial use of treated produced water, effective September 1, 2025, with exceptions for gross negligence, regulatory noncompliance, or intentional wrongful conduct.
• HB 4426 establishes permit durations and renewal procedures for commercial surface disposal facilities for produced water, setting a maximum 10-year permit term.

Despite these advances, significant legal questions remain. SB 1763, which would have clarified ownership of brine minerals within the mineral estate, stalled in the Senate Natural Resources Committee during the 2025 session. The resulting ambiguity over brine mineral ownership may hamper investment in lithium and other mineral extraction from produced water until the legislature or courts resolve the issue.

New Mexico. New Mexico is taking a more cautious approach. Governor Lujan Grisham signed the Strategic Water Supply Act (HB 137) in April 2025, creating a $75 million program to fund brackish water (naturally occurring saline groundwater, as distinct from produced water) treatment projects as part of the state’s 50-Year Water Action Plan. The legislature removed all produced water reuse provisions from the bill during the committee process, however, reflecting persistent concerns about the adequacy of treatment science and the risks associated with reuse of water from hydraulically fractured wells. The enacted version imposes a three-cent-per-barrel fee on produced water disposed of in the state, with revenue directed to the Strategic Water Supply Program Fund. The New Mexico Environment Department’s Water Quality Control Commission continues to develop rules for produced water reuse outside the oilfield, but the agency has expressed skepticism about permitting surface discharges of treated produced water, noting that the scientific basis for protective permitting does not yet exist for all relevant constituents. As of March 2026, New Mexico does not permit surface discharge of treated produced water.

Colorado. Colorado has taken the most prescriptive approach to produced water recycling of any major producing state. In March 2025, Colorado’s Energy and Carbon Management Commission (ECMC) adopted first-in-the-nation rules requiring operators to use an increasing percentage of recycled produced water in oil and gas operations: approximately 4% for developments permitted after January 1, 2026, increasing to 10% after January 1, 2030, with a mandatory 2028 rulemaking to set targets for 2034 and 2038 (defaulting to 20% and 35%, respectively, if no new rules are adopted). The rules also establish a recycled produced water credit trading system to enable compliance flexibility. These rules were informed by the Colorado Produced Water Consortium – a 31-member multi-stakeholder body established by Colorado HB 23-1242 – which published nine data-driven reports to the legislature and will continue to evaluate implementation. Air emissions from produced water handling remain a subject of active rulemaking, with a reporting framework expected in 2026.

Colorado’s regulatory framework for produced water is also shaped by the state’s unique “nontributary” groundwater classification. Under C.R.S. Section 37-90-137(7) and the Produced Non-tributary Ground Water Rules (2 CCR 402-17), the vast majority of oil-and-gas-producing geologic formations in Colorado – including nearly all in the DJ Basin – have been designated as nontributary based on comprehensive geologic mapping and determinations. Produced water withdrawn from nontributary formations can be used for oil-and-gas-related purposes (broadly construed) in the same geologic basin from which it was withdrawn without a Water Court decree, overlying landowner consent, Division of Water Resources well permit, or other standard approvals. This facilitates in-field recycling and oil and gas reuse but limits beneficial reuse for non-oilfield purposes (e.g., agriculture, municipal supply, or aquifer recharge), which generally requires landowner consent, payment, or additional water rights authorization.

Other States. Produced water management challenges are not confined to western basins. In the Appalachian Basin, Pennsylvania has effectively prohibited underground injection of oil and gas wastewater since the 1990s, forcing operators to truck produced water to disposal wells in Ohio or to centralized treatment facilities – a dynamic that has driven early investment in treatment technology but at significantly higher per-barrel costs. Wyoming and North Dakota permit produced water discharges and reuse under state-administered programs, and Utah has adopted regulations expanding reuse opportunities and limiting freshwater consumption for oil and gas operations. Practitioners operating across multiple basins should expect continued divergence in state approaches.

Federal. At the federal level, EPA Administrator Lee Zeldin announced in March 2025 that the agency will revise its effluent limitation guidelines (ELGs) for oil and gas extraction, consistent with the Trump Administration’s Unleashing American Energy Executive Order. The current ELGs date to the 1970s, and their modernization could significantly alter the federal framework for produced water management. The revision could also expand federal pathways for beneficial reuse and surface discharge of treated produced water. The timeline for a proposed rule, however, remains uncertain. Separately, the EPA’s National Water Reuse Action Plan continues to study oil and gas extraction wastewater management practices – work that could inform future federal guidance on treatment standards, monitoring protocols, and discharge criteria for produced water reuse projects.

III. Partnerships and Infrastructure: The Midstream Water Buildout

The produced water midstream sector is undergoing a wave of consolidation and infrastructure investment that mirrors the buildout of hydrocarbon gathering and processing systems over the past two decades.

The partnership between Texas Pacific Land Corporation (TPL) and WaterBridge illustrates the emerging model. In 2022, TPL – one of the largest landowners in West Texas – and WaterBridge – the largest U.S. produced water network operator – formed a Delaware Basin water development alliance covering a 64,000-acre contiguous area of mutual interest. By combining fragmented surface rights with midstream infrastructure and operating capability, they created a single counterparty for comprehensive water management across entire development areas.

WaterBridge’s infrastructure includes approximately 2,500 miles of pipeline and over 4.5 million barrels per day of handling capacity. Its Speedway pipeline – an 80-mile system moving water out of the most pressurized core areas of the Delaware Basin into peripheral formations with better disposal capacity – reflects a broader geographic shift in disposal strategy toward lower-pressure formations in Andrews County and eastern Loving County. WaterBridge handled 2.4 MMbbl/d of produced water in 2025 (up 15% year-over-year) and expects volumes of 2.5 MMbbl/d to 2.7 MMbbl/d in 2026. Phase I of Speedway is expected online mid-2026; a February 2026 open season is underway for Phase II, which would double capacity to 1 MMbbl/d by moving volumes from Eddy and Lea counties, New Mexico, to out-of-basin pore space. Executives have signaled a potential Phase III expansion and system looping, with CFO Scott McNeely stating “the short answer is yes” given strong demand (timing subject to Phase II commercial outcomes). The company also expects to begin construction in Q4 2026 on a new produced water infrastructure project tied to Devon Energy under a ten-year agreement with a 7.5-year minimum volume commitment starting April 2027.

Two landmark 2025 capital markets transactions confirmed that institutional investors now view produced water infrastructure as a distinct, investable asset class. WaterBridge completed an upsized IPO in September 2025, raising approximately $634 million (with full exercise of the underwriters’ option) at $20 per share (top of range) on the NYSE. Western Midstream Partners completed an approximately $2 billion acquisition of Aris Water Solutions in October 2025, combining over 1,600 miles of produced water pipeline. The combined system created what Western Midstream described as a fully integrated produced water value chain – spanning gathering, disposal, recycling, desalination, mineral extraction, and long-haul transport. These transactions signal that the produced water midstream sector is transitioning from a fragmented, operator-by-operator service model to a consolidated, infrastructure-backed platform business. That shift brings attendant legal demands – long-term commercial agreements, acreage dedications, pore space rights, surface access, and regulatory compliance across multiple agencies.

WaterBridge is also at the center of a significant regulatory enforcement dispute. In September 2024, the Texas Railroad Commission spent approximately $6.95 million to plug a Ward County well that experienced a produced-water blowout. The Texas Railroad Commission canceled the permit for a nearby WaterBridge disposal well – located half a mile from the blowout site, at a 1950s-era legacy well – and initiated proceedings to recover the plugging costs. WaterBridge disputes the findings, arguing that its well was properly permitted and operating within its permit limits, that causation has not been proved, and noting three other disposal wells within a two-mile radius as potential contributors. The company has called the action “unprecedented”; as of this writing, a hearing has not yet been scheduled. The case is significant for the broader midstream sector because it raises questions about operator liability for blowouts at legacy wells compromised by cumulative injection pressure from multiple operators – a dynamic likely to recur as formation pressures rise across the Delaware Basin.

IV. Treatment Technologies: From Pilot to Near-Commercial

Multiple treatment approaches are advancing through the pilot phase in the Permian and elsewhere. WaterBridge alone reported 10 to 12 treatment technology pilots underway in the Permian in 2025, evaluating both distillation and reverse osmosis approaches.

The most advanced near-commercial project is TPL’s Transmissive Water Services Phase 2 system, which combines freeze distillation (leveraging temperature differentials to separate clean water from brine) with reverse osmosis to achieve approximately 75% water recovery. The system has secured a surface-discharge permit from the Texas Railroad Commission, with a separate TCEQ discharge authorization pending. Construction paused in 2025 for additional testing and equipment enhancements. If approvals and construction proceed as currently planned, the system could begin treating approximately 10,000 barrels per day by mid-2026, with potential applications in agriculture and aquifer recharge.

A potentially significant new end-use is also emerging: data-center cooling and co-located power generation. Tetra Technologies is advancing its Oasis desalination platform – pre-treatment for contaminant removal, membrane-based desalination to reduce salinity from the Permian’s typical 130,000-150,000 mg/L to below 200 mg/L, and post-treatment polishing. Tetra executives describe the opportunity as “huge,” noting that one gigawatt of data-center and power-generation capacity can require 250,000-350,000 bbl/d of treated water. Larger installations require still more – in a basin that produces over 20 MMbbl/d of produced water daily amid limited fresh-water availability. An EOG pilot has run consistently since Q3 2025 with encouraging agricultural growth study results. According to Tetra, economics are converging as disposal costs rise and treatment costs decline.

Treatment technology selection depends heavily on the source water’s total dissolved solids (TDS), constituent chemistry, and intended end use. Produced water in the Delaware Basin can be five to eight times saltier than seawater, and also contains a complex mix of hydrocarbons, heavy metals, naturally occurring radioactive materials (NORM), and chemical additives from completions. Treating to agricultural or drinking water quality requires addressing constituents – many of which lack established federal or state toxicity standards – at costs that remain significantly above disposal.

PFAS (per- and polyfluoroalkyl substances) are another emerging concern. PFAS have been detected in produced water from multiple basins, and EPA’s evolving PFAS regulatory framework (including the 2024 National Primary Drinking Water Regulation for six PFAS compounds) may impose additional treatment requirements and liability exposure for produced water reuse projects. Rice University’s WaTER Institute has established a dedicated PFAS Alternatives and Remediation Center (R-PARC) focused on destruction and removal technologies for these persistent contaminants.

Research efforts at Texas Tech University (through the Texas Produced Water Consortium), Texas A&M, and the University of Texas are evaluating advanced membranes, hybrid thermal-membrane systems, and treatment process trains targeting beneficial reuse quality. Rice University’s WaTER Institute – launched in January 2024 and building on a decade of work through the NSF-funded Nanotechnology Enabled Water Treatment (NEWT) Center – is pursuing a particularly ambitious research agenda. Its focus areas include beneficial disposition of produced waters from oil and gas fields, critical elements recovery from wastewaters, and advanced membrane and catalytic separation technologies designed to reduce the energy intensity and cost of fit-for-purpose treatment. Rice has also established the Center for Membrane Excellence (RiCeME) to advance separation technologies for energy and environmental applications, and its researchers are developing more efficient lithium extraction methods – work that sits squarely at the intersection of produced water treatment and critical mineral supply chains. The Department of Energy’s National Energy Technology Laboratory continues to fund research across multiple institutions. Colorado’s Produced Water Consortium has also separately evaluated analytical and toxicological methods for assessing treatment adequacy.

V. Lithium and Critical Mineral Extraction: A New Co-Product Revenue Stream

Strategic partnerships between landowners, midstream companies, and operators are expanding to include mineral extraction – particularly lithium, a critical input for EV batteries and energy storage listed on the USGS 2025 List of Critical Minerals – from briny waters, including produced water.

Smackover Formation (Arkansas and East Texas). The most advanced domestic lithium-from-brine plays are in the Smackover Formation, where lithium concentrations in natural brine exceed 300 ppm and have been measured above 600 ppm in some wells. ExxonMobil (through its subsidiary Saltwerx) has acquired brine rights to over 300,000 net acres, completed an eight-well appraisal drilling program, received Arkansas Oil and Gas Commission approval for a 56,245-acre brine production unit and a 2.5% lithium royalty rate, and is targeting first lithium production in 2027 under its Mobil Lithium brand. Equinor has partnered with Standard Lithium for direct lithium extraction (DLE) in the same formation. The Smackover play has also drawn entry from Chevron, TETRA Technologies, PotlatchDeltic, and Albemarle, among others.

Permian Basin. In the Permian, the massive aggregate volumes of produced water create a significant brine resource, but lithium concentrations are far lower (15-40 ppm). Element3, a Fort Worth-based extraction company, is commissioning the first commercial-scale DLE unit at Double Eagle Energy’s recycling facility, with first customer deliveries targeted for the first half of 2026. This is expected to be the first commercial lithium extraction from Permian produced water. The economic thesis is integration: where water is already being handled as part of oil operations, lithium extraction becomes an incremental co-product rather than a standalone venture, potentially improving the economics of both water handling and mineral supply.

Broader U.S. DLE Activity. California’s Salton Sea natural geothermal brine has attracted DLE investment from Occidental Petroleum (through a joint venture with All-American Lithium) and others, supported by DOE research. Nevada has seen DLE pilot activity by oilfield services firms including SLB (formerly Schlumberger).

Practitioners should note that lithium extraction from brine implicates a complex and still-developing web of legal issues. These include ownership of brine minerals (unsettled in Texas), unitization and royalty frameworks (newly established in Arkansas), federal land and Tribal consultation requirements where applicable, water rights and return-flow obligations, and environmental permitting for brine production and reinjection. Federal incentives add a further dimension: the Inflation Reduction Act’s Section 45X Advanced Manufacturing Production Credit applies to domestically produced critical minerals, and the Section 30D clean vehicle credit sourcing requirements incentivize U.S.-origin lithium – both of which may materially affect project economics and offtake structuring for DLE ventures.

VI. Legal & Transactional Issues for Practitioners

The produced water value chain implicates a wide range of practice areas. We highlight several that are particularly active.

Ownership and Property Rights. The Texas Supreme Court’s Cactus Water decision clarified that produced water belongs to the mineral estate absent express contrary language, but it did not resolve ownership of brine minerals, leaving ambiguity that affects commercial agreements for mineral extraction. Practitioners should review existing mineral leases, surface use agreements, and water handling contracts for produced water and brine mineral allocation language. In prior appropriation states such as Colorado and New Mexico, the interaction between produced water reuse and state water rights law raises additional questions – including whether treated produced water discharged to surface waters or applied to land creates new appropriation obligations, triggers return-flow requirements, or implicates existing senior water rights. In Colorado, the nontributary produced water framework adds a further layer of complexity, as reuse of nontributary produced water is generally restricted to oil-and-gas-related purposes absent landowner consent or other authorization. These issues are particularly acute where beneficial reuse projects propose to introduce treated produced water into watersheds or aquifers that are already over-appropriated.

Commercial Agreements. Produced water midstream agreements – water gathering, disposal, and recycling agreements with acreage dedications and volume commitments – are becoming increasingly complex, approaching the commercial sophistication of hydrocarbon midstream contracts. Pore space access and disposal rights, take-or-pay structures, treatment specifications, regulatory risk allocation, and mineral extraction rights are all subjects of active negotiation.

Regulatory Compliance. The multi-agency regulatory landscape – spanning the Texas Railroad Commission, TCEQ, the New Mexico Environment Department, the Colorado ECMC, EPA, state water agencies, and (where applicable) the Bureau of Indian Affairs and Tribal regulatory bodies – requires careful navigation. Permits for surface discharge, land application, subsurface injection, and beneficial reuse are governed by overlapping and sometimes conflicting state and federal requirements. The pending WaterBridge/Ward County enforcement proceeding (discussed in Section III) highlights emerging liability exposure for permitted disposal operations that may contribute to subsurface pressure buildup affecting nearby legacy wells. Practitioners should address this risk in disposal agreements and infrastructure transaction diligence.

Capital Markets and M&A. The WaterBridge IPO and Western Midstream/Aris acquisition establish produced water infrastructure as an institutional asset class. Expect continued M&A activity as operators pursue scale, integration, and pore space access across the full value chain. The Devon-Coterra all-stock merger, announced in February 2026 with a combined enterprise value of approximately $58 billion, is expected to close in Q2 2026, subject to regulatory approvals and shareholder votes, and could further reshape produced water contracting in the Delaware Basin, where, as analysts have noted, Coterra’s Franklin Mountain acreage overlaps WaterBridge’s Speedway system. Diligence for these transactions requires careful evaluation of disposal well capacity and induced seismicity risk, regulatory compliance posture, surface and pore space rights, and the adequacy of environmental and water rights arrangements.

Tort and Environmental Liability. Texas HB 49 limits tort liability for treated produced water beneficial use, but its exceptions (gross negligence, regulatory noncompliance, intentional misconduct) and effective-date limitations mean that liability risk has been reduced, not eliminated. Operators, landowners, and technology providers should assess the scope of these protections in the context of their specific operations and contractual risk allocation.

Financial Assurance and Insurance. Regulators are increasingly requiring financial assurance for produced water operations. New Mexico’s Strategic Water Supply Act mandates financial assurance for the life of any project receiving a program contract, and the Texas Railroad Commission’s bonding requirements for disposal wells remain under periodic review. Investors and lenders should evaluate the adequacy of existing bonding, insurance, and indemnification structures – particularly for long-lived disposal and treatment assets where decommissioning and remediation obligations may extend well beyond the operational period.

Tribal Consultation and Federal Lands. Where produced water operations, mineral extraction, or treatment projects involve federal lands or Tribal resources, consultation and compliance obligations under NEPA, the National Historic Preservation Act, the Endangered Species Act, and applicable Tribal regulatory frameworks add an additional layer of complexity. This is particularly relevant for DLE projects in formations that cross jurisdictional boundaries or involve split estates.

VII. What to Watch

• TPL Transmissive Phase 2B completion: mid-2026 target (following 2025 construction pause); the first near-commercial beneficial reuse project in the Permian.
• Element3 commercial lithium deliveries: targeted for first half of 2026; expected to be the first commercial lithium extraction from Permian produced water.
• TCEQ land-application rulemaking: rules expected April 2026; the most consequential near-term regulatory milestone for Texas beneficial reuse.
• EPA ELG revision: timeline uncertain; could reshape the federal framework for produced water discharge and reuse nationally.
• Colorado ECMC recycling mandate implementation: approximately 4% recycling requirement phases in for developments permitted after January 1, 2026, with air quality rulemaking to follow.
• New Mexico WQCC produced water rulemaking: continued development of rules governing reuse outside the oilfield; a key indicator of the state’s long-term position on beneficial reuse.
• ExxonMobil/Saltwerx first lithium production in Arkansas: targeted for 2027; the largest DLE project under development in the U.S.
• Continued M&A and infrastructure investment: midstream operators pursuing scale, integration, and pore space access across the full produced water value chain, with particular activity expected around disposal-constrained basins and integrated treatment/mineral extraction platforms.
• Brine mineral ownership legislation: whether Texas, Arkansas, or other states act to clarify ownership of minerals dissolved in produced water.
• Colorado nontributary produced water framework: potential evolution of limits on reuse beyond oil-and-gas purposes amid rising recycling requirements and beneficial reuse pilots.
• WaterBridge/Texas Railroad Commission Ward County enforcement proceeding: outcome of the still-unscheduled hearing and potential precedent on operator liability for cumulative injection pressure effects on legacy wells.
• WaterBridge Speedway Phase II/III and Devon project: sanctioning and mid-2026 ramp-up amid continued northern Delaware Basin takeaway demand.
• Data-center cooling demand: commercial progress on treated produced water desalination for cooling and power generation, including Tetra’s Oasis platform.

VIII. How We Can Help

Davis Graham’s Energy & Mining, Environmental, and Water Law groups advise clients across the full produced water value chain – from upstream operators and midstream infrastructure developers to landowners, technology providers, investors, and critical minerals companies. Our team brings particular depth to this space: decades of experience in western water rights and environmental permitting; hands-on transactional work in midstream energy, critical minerals, and carbon management; and recognized capabilities in Tribal engagement and consultation, federal lands, and NEPA and NHPA compliance for resource extraction projects. We counsel on transactions, regulatory compliance and permitting, water rights, commercial agreements, environmental and water rights litigation and enforcement, and Tribal and public lands matters related to produced water, brine mineral development, and beneficial reuse projects.

For more information or if we can be of assistance, please contact a member of the Clean Energy & Sustainability Group.

This alert is intended to provide a general overview of the legal, regulatory, commercial, and transactional considerations relevant to produced water management, beneficial reuse, and critical mineral extraction across the U.S. It does not constitute legal, financial, or investment advice, and the appropriate approach will depend on the specific facts, jurisdiction, and circumstances applicable to each project.

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An environmental self-audit is a systematic, documented, and objective evaluation of how well an organization, its management systems, and its equipment perform and comply with federal, state, and local environmental statutes, regulations, and permit provisions. When conducted properly, these detailed self-assessments can identify areas of non-compliance, inefficiencies, and opportunities for improvement before they become costly compliance issues. More broadly, environmental self-audits also lead to improved protection of human health and the environment.

Many states have environmental audit laws and policies that incentivize voluntary self-evaluation by offering benefits such as possible penalty reduction or avoidance and immunity from enforcement.[1] State programs vary in both scope and benefit—some apply broadly across all state agencies, while others target specific areas of regulation, such as hazardous waste enforcement only, for example. State-level audit protections, where available, apply only to violations of that state’s environmental laws and regulations, including certain programs where states have delegated authority to administer federal regulatory programs on behalf of the U.S. Environmental Protection Agency (EPA). Importantly, however, state audit protections typically do not provide immunity from federal enforcement. And, in some instances, EPA maintains an independent right of enforcement, even in the case of delegation.

EPA also maintains its own environmental self-audit policy applicable to violations of major federal environmental laws such as the Clean Air Act and Clean Water Act.[2] The agency’s policy, however, offers discretionary rather than guaranteed protection, and its availability can shift with changing presidential administration priorities. State programs historically have provided more predictable opportunities for companies to mitigate enforcement risk through self-audit.

The current presidential administration has signaled a preference for companies that take a proactive “find and fix” approach to environmental compliance, creating a favorable environment for self-auditing at the federal level.[3] This convergence of state audit protections and a receptive federal posture presents a unique opportunity for companies to leverage both state and federal audit programs, where applicable and appropriate, to identify and mitigate compliance issues across multiple environmental media. Given this alignment, environmental self-audits are an especially valuable tool for companies to deploy now.

A given self-audit approach will vary based on company resources, applicable laws, regulatory agencies, and compliance goals. Self-audits can be broad—covering facilities in one or more states—or they can be more targeted—reviewing specific equipment, certain facilities, or areas of particular environmental concern. A typical self-audit will include review of site conditions and operations, applicable regulatory and legal requirements, environmental permits, facility records and reporting, and other relevant company reports and information.

Effective self-audits require a multidisciplinary team that typically includes facility personnel, consultants and other subject matter experts, and legal counsel. This collaborative approach ensures comprehensive coverage of multiple regulatory areas while minimizing blind spots that single-discipline reviews can often miss. Including legal counsel in the multidisciplinary team may also offer additional legal protections for the work. Under some, but not all, state self-audit programs, audit findings are shielded by statutory privilege, preventing their use by government agencies or adverse parties in litigation, but when audits are also conducted at the direction of legal counsel, attorney-client privilege and attorney work-product protections can offer another layer of protection for companies that choose to voluntarily assess their compliance status.

Through systematic self-audit, a company’s compliance team can identify and correct common problems before they become subject to enforcement. The team can then use audit data and findings to build or enhance targeted environmental monitoring and management programs. This proactive approach minimizes future government enforcement by ensuring early identification and correction of environmental compliance issues before discovery by regulatory compliance inspectors.

Enhanced environmental compliance can bolster a company’s reputation in the clean energy and sustainability industries, where stakeholders, and in some cases, shareholders, increasingly scrutinize environmental performance. In competitive markets, companies may be able to leverage a strong environmental compliance track record to outpace competitors. For example, Texas regulators have the discretion to expedite the permitting process and relax oversight for companies that engage in environmental audits.[4] This benefit provides a possible competitive advantage given that Texas leads in many energy technologies, including wind, solar, and battery storage. In many other states, a history of self-audit may improve a company’s credibility with regulators and ease relationships with enforcement and permitting agencies. Accordingly, companies that prioritize environmental audits position themselves for both regulatory success and market advantage in the evolving energy landscape.

Self-audits may also offer financial benefit through penalty avoidance. Under most federal and state audit laws, voluntarily disclosing and correcting a violation may eliminate or significantly reduce civil penalties. These penalties can otherwise amount to tens of thousands of dollars per day, per violation. Regulatory agencies frequently increase fines for repeat or knowing violations, and in some instances, agencies can bring criminal charges against companies and individuals with heightened culpability. Given these escalating penalty structures, self-disclosure of properly identified violations has the potential to provide significant financial benefit that often outweighs the cost of conducting the self-audit. Notably, some self-audit laws allow companies acquiring facilities through mergers and acquisitions to take advantage of audit incentives for noncompliance discovered during due diligence—making self-audits particularly valuable during or immediately after corporate transactions.

Self-audit benefits are heightened in the current political climate, where some state and federal officials have become critical of certain forms of energy, especially renewables. Penalty and privilege protections may help insulate companies if regulators engage in politically motivated enforcement actions targeting certain industries or companies.

Finally, beyond environmental regulation, improved compliance achieved through self-audit may also result in protection for companies in other regulatory areas. Environmental noncompliance has the potential to trigger employee complaints, enhanced customer or shareholder scrutiny, or enforcement from other agencies, such as the U.S. Occupational Safety and Health Administration, making environmental compliance a cornerstone of broader regulatory risk management.

In sum, environmental audits have the potential to offer companies a powerful combination of legal protection, financial savings, and competitive advantage—benefits that are increasingly valuable as energy markets expand and regulatory landscapes evolve. By proactively identifying and addressing compliance issues, companies have the opportunity to avoid costly penalties, shield sensitive findings under legal privilege, and demonstrate the environmental track record that investors, customers, and regulators increasingly demand.

For more information about environmental audits, state and federal self-disclosure programs, or how these tools can benefit your organization, please contact a member of the Environmental & Public Lands Group.

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[1] See, e.g., Colo. Rev. Stat. § 25-1-114.5; Tex. Health & Safety Code § 1101.001.

[2] https://www.epa.gov/compliance/epas-audit-policy.

[3] Memorandum from Craig J. Pritzlaff to OECA Office Directors and Deputies, Reinforcing a “Compliance First” Orientation for Compliance Assurance and Civil Enforcement Activities, U.S. Env’t Protection Agency (Dec. 5, 2025).

[4] See 30 Tex. Admin. Code § 60.3.

As interconnection queues swell and approval timelines stretch to five years or more, data center developers are increasingly turning to behind-the-meter generation to secure reliable power. While natural gas offers the fastest path, its carbon footprint clashes with net-zero commitments. Small modular reactors are emerging as a compelling carbon-free alternative. This article examines the current state of SMR deployment for data centers and the key regulatory considerations developers should keep in mind.

The Power Problem

American data centers consumed approximately 4% of total U.S. electricity in 2023, a figure projected to reach as high as 12% by 2028 as artificial intelligence workloads proliferate. A single large-scale AI training facility can demand 150-500 megawatts of continuous power. Yet FERC’s interconnection queues now contain over 2,600 gigawatts of proposed generation – more than twice the nation’s installed capacity – with average approval timelines stretching to five years.

These delays have driven data center developers toward behind-the-meter generation strategies: building or contracting for dedicated power sources that bypass the queue entirely. Natural gas is the fastest, most commercially proven option. But a 500 MW gas plant operating at 60% capacity factor emits roughly 1.5 million tons of CO₂ annually – a figure fundamentally at odds with the net-zero commitments that most major data center operators have made. Renewable behind-the-meter generation faces its own challenges: intermittency requires oversizing, storage, or backup, often making it more expensive and complex than gas.

This sustainability paradox – needing reliable power now while committing to decarbonization – is fueling serious interest in advanced nuclear technology, particularly small modular reactors (SMRs).

What SMRs Offer – and Where Things Stand

SMRs offer a potentially compelling package for data center power: carbon-free baseload generation, high projected capacity factors, compact site footprints relative to equivalent wind or solar installations, and modular factory fabrication that proponents contend will shorten construction timelines.

However, commercial SMR deployment remains in its early stages, and projected cost and timeline advantages have yet to be proven at scale. NuScale Power’s cancellation of the UAMPS Carbon Free Power Project in November 2023 – after years of development – illustrated the gap between aspiration and execution.

Several developers are nonetheless moving forward with data-center-focused plans. X-energy has partnered with Amazon, which anchored approximately $500 million in Series C-1 financing, targeting up to 5 GW of new nuclear capacity by 2039. NuScale has announced plans to deploy its NRC-certified SMR technology for data center operator Standard Power at two facilities in Ohio and Pennsylvania, targeting nearly 2 GW of clean energy for data center loads. And TerraPower broke ground on its 345 MW Natrium demonstration reactor at a retired coal plant in Kemmerer, Wyoming, in June 2024.

Realistic industry projections place first commercial SMR units in the early 2030s, though most industry observers suggest that mid-2030s is more likely for broad commercial availability.

The Regulatory Landscape

Developers considering SMR-powered data centers should anticipate navigating several overlapping regulatory regimes:

NRC Licensing. All commercial nuclear facilities require Nuclear Regulatory Commission licensing – a multi-year process addressing safety, security, environmental impacts, and design certification. This is the most significant timeline constraint for any SMR project.

FERC Jurisdiction. SMRs interconnected to the transmission system will likely trigger FERC jurisdiction over wholesale sales, consistent with the principles FERC has articulated in recent orders addressing co-located data center loads – including the November 2024 Talen Energy order and the December 2025 PJM co-located load order. However, radial-connected SMRs serving dedicated loads may avoid wholesale jurisdiction depending on how the arrangement is structured.

State Siting. States retain authority over siting and economic need for generation facilities, and the landscape varies considerably. Wyoming and Utah maintain nuclear-supportive regulatory environments – TerraPower’s Kemmerer project reflects Wyoming’s receptiveness. Colorado added nuclear to its statutory definition of “clean energy” in 2025, making it eligible for clean energy project financing. Texas has moved most aggressively, establishing a $350 million Texas Nuclear Development Fund in June 2025 – described by Governor Greg Abbott as the largest state-level nuclear commitment in the country – following its Advanced Nuclear Reactor Working Group’s release of a comprehensive deployment roadmap in November 2024.

Self-Supply Classification. SMRs purpose-built to serve data centers likely constitute self-supply exempt from utility regulation, provided sufficient ownership integration exists between the generation facility and the consuming load. How ownership and offtake arrangements are structured from the outset will be critical to maintaining this classification.

What Developers Should Be Doing Now

Although commercial SMR deployment is years away, the groundwork – site identification, NRC pre-application engagement, state regulatory positioning, and corporate partnership structures – requires significant lead time. A few practical considerations:

First, jurisdictional selection matters. Texas’s ERCOT market avoids FERC wholesale jurisdiction entirely and now offers dedicated nuclear funding. Wyoming’s minimal regulatory barriers and existing advanced nuclear presence create a supportive ecosystem. Developers should match jurisdictional frameworks to project characteristics and timelines early in the planning process.

Second, transaction structure determines regulatory outcomes. The recent FERC orders on co-located loads make clear that how ownership, interconnection, and power delivery are arranged dictates whether federal wholesale jurisdiction is triggered. Thoughtful structuring at the outset is far less costly than retrofitting a deal after the fact.

Third, regulators are increasingly attentive to large loads that island themselves from the grid. Developers planning SMR-powered data centers should consider voluntary grid support commitments – demand response, emergency generation, reliability contributions – that build goodwill and may prove decisive in siting proceedings.

Finally, the regulatory frameworks for SMRs serving dedicated loads remain largely undeveloped. Current rules assume grid-connected facilities selling to multiple customers. Developers and energy providers have a meaningful opportunity to help shape these emerging frameworks through comment proceedings and direct regulatory engagement – including the national rulemaking on large load interconnection that Secretary of Energy Chris Wright directed FERC to initiate in October 2025.

Davis Graham’s Clean Energy & Sustainability Group counsels clients across a broad range of clean energy matters, including project development, permitting, and regulatory compliance. Contact R.J. Colwell or a member of the group for guidance on structuring SMR-powered data center projects or navigating these evolving regulatory pathways.

1. Reflecting on your time at Davis Graham, what was the most valuable lesson you learned?
   • Figure out how to practice the way that works best for you. Take what you like from others, avoid what you don’t like, put all that together with your own strengths and weaknesses. I think “authenticity” is the applicable buzzword. 
2. What are some pro bono or community service experiences that have had a significant impact on your career? What did you learn from these opportunities, and how have they influenced your path?
   • The City Attorney’s trial advocacy program and the US District Court’s pro bono panel program. I learned from my mistakes. I learned to do more with less. I had a lot of fun. I gained experience that helped opened doors to work for paying clients. 
3. What is the biggest difference between working at Davis Graham and being Assistant General Counsel of a Fortune 500 company?
   • People. More people = more personalities, more complexity, more process, procedure, and politics, more time and effort spent figuring out how best to communicate with all the people. 
4. Who are some of the people at Davis Graham that had the greatest influence on you and why?
   • This question is a trap. See the first question and answer. There’s no better group of people to help you work towards being the best lawyer you can be. 

Table of Contents

• SEC Withdraws 14 Rule Proposals
• SEC Signals Expanding Retail Investor Access to Private Funds Through Certain Fund of Funds
• SEC Extends Compliance Deadline for Form N-PORT
• SEC Extends Compliance Deadline for Form PF
• SEC Charges Individual and His Advisory Firm with Fraud and Other Violations

SEC WITHDRAWS 14 RULE PROPOSALS

In June 2025, the U.S. Securities and Exchange Commission (the “SEC” or the “Commission”) announced that it was withdrawing 14 rule proposals (the “Proposals”) issued during the prior administration. A table detailing each withdrawn Proposal and the applicable SEC division is listed below.

The final rule announcing the SEC’s withdrawal of the Proposals included that the Commission is withdrawing the Proposals because it no longer intends to issue final rules on the Proposals. In the event the Commission determines to pursue regulatory action in the areas covered by a Proposal, the Commission will publish a new proposed rule or other issuance.

Rule Name	Division
Substantial Implementation, Duplication, and Resubmission of Shareholder Proposals Under Exchange Act Rule 14a-8	Corporation Finance
Conflicts of Interest Associated with the Use of Predictive Data Analytics by Broker-Dealers and Investment Advisers	Trading and Markets, Investment Management
Safeguarding Advisory Client Assets	Investment Management
Cybersecurity Risk Management for Investment Advisers, Registered Investment Companies, and Business Development Companies	Investment Management
Enhanced Disclosures by Certain Investment Advisers and Investment Companies About Environmental, Social, and Governance Investment Practices	Investment Management
Outsourcing by Investment Advisers	Investment Management
Position Reporting of Large Security-Based Swap Positions	Trading and Markets
Volume-Based Exchange Transaction Pricing for NMS Stocks	Trading and Markets
Regulation Best Execution	Trading and Markets
Order Competition Rule	Trading and Markets
Regulation Systems Compliance and Integrity	Trading and Markets
Cybersecurity Risk Management Rule for Broker-Dealers, Clearing Agencies, Major Security-Based Swap Participants, the Municipal Securities Rulemaking Board, National Securities Associations, National Securities Exchanges, Security-Based Swap Data Repositories, Security-Based Swap Dealers, and Transfer Agents	Trading and Markets
Amendments Regarding the Definition of “Exchange” and Alternative Trading Systems (ATSs) That Trade U.S. Treasury and Agency Securities, National Market System (NMS) Stocks, and Other Securities	Trading and Markets
Regulation ATS for ATSs That Trade U.S. Government Securities, NMS Stock, and Other Securities; Regulation SCI for ATSs That Trade U.S. Treasury Securities and Agency Securities; and Electronic Corporate Bond and Municipal Securities Markets	Trading and Markets
Proposed Amendments to the National Market System Plan Governing the Consolidated Audit Trail To Enhance Data Security	Trading and Markets

SEC SIGNALS EXPANDING RETAIL INVESTOR ACCESS TO PRIVATE FUNDS THROUGH CERTAIN FUND OF FUNDS

In remarks at the Practicing Law Institute’s SEC Speaks Conference held in Washington D.C. on May 19-20, 2025 (the “SEC Speaks Conference”), the staff of the SEC indicated that they have reconsidered a long-standing staff position that prevents certain closed-end funds from investing in private funds, opening the door for registered funds of private funds to be offered broadly to “retail investors.” Generally, retail investors are those who do not satisfy the “accredited investor” standard under Rule 501 of Regulation D under the Securities Act of 1933. The accredited investor test currently includes, among others, individuals who meet certain professional qualifications or have a net worth over US $1 million (excluding their primary residence) or income over US $200,000 (or US $300,000 if they file jointly with a spouse or partner) in each of the previous two years.

Since 2002, the SEC staff has taken the position that closed-end funds investing in underlying private funds (like hedge funds and private equity funds) must either: (1) limit such investments to no more than 15% of its assets or (2)(a) restrict sales of its own shares to investors that satisfy the accredited investor standard and (b) impose a minimum initial investment requirement of $25,000. Underlying private funds for these purposes are generally defined as investment companies but for the exclusions specified in sections 3(c)(1) or 3(c)(7) of the Investment Company Act of 1940.

Historically, the staff’s position was enforced through the SEC’s registration statement review process. For certain closed-end funds investing in private funds, the SEC required this limitation in their registration statements to declare them effective.

In a speech at the SEC Speaks Conference on May 19, 2025, SEC Chairman Paul Atkins called for the SEC to reconsider the 23-year-old policy regarding investments by closed-end funds in private funds to expand retail access to private markets and “give all investors the ability to seek exposure to a growing and important asset class, while still providing the investor protections afforded to registered funds.” 

In contrast to Chairman Atkins’s speech, Commissioner Caroline Crenshaw’s remarks at the SEC Speaks Conference on May 19, 2025, highlighted the risks inherent in removing the private fund investment limitation policy for retail investors, stating that “private markets are inherently riskier, entail less disclosure, and require a higher tolerance for volatility and illiquidity,” and warning that “private markets are not designed for the average Main Street investor.”

SEC Director of Investment Management Natasha Vij Greiner participated in a panel discussion with senior SEC staff members the next day at the SEC Speaks Conference. During this discussion, she announced that starting May 19, 2025, the SEC staff will no longer provide comments during the registration statement review process seeking to limit the ability of retail investors to invest in registered closed-end funds that invest more than 15% of their net assets in underlying private funds. Director Greiner noted that the “decision was made based on the ever-evolving industry, and we hope that this shift will provide investors with new investment opportunities to the extent they align with their risk tolerance and investment objectives.”

Without the above investment requirements imposed by accredited investor limitations, retail investors may gain greater access to private market exposure as the new staff position expands the universe of products that may be offered to retail investors who do not satisfy the accredited investor criteria.

Without the above minimum investment and accredited investor requirements, retail investors may gain greater access to private market exposure as the new staff position expands the universe of closed-end fund products and offerings available to them.

SEC EXTENDS COMPLIANCE DEADLINE FOR FORM N-PORT

In August 2024, the SEC adopted amendments to Form N-PORT. Form N-PORT is generally used by a mutual fund or certain exchange-traded funds (other than a money market fund or a small business investment company) to file monthly portfolio holdings risk metrics, and other data about the fund’s operations. The amendments require registered funds to file Form N-PORT on a monthly basis, rather than quarterly.

In April 2025, the SEC extended the compliance deadline for the Form N-PORT monthly filing requirement. For registered funds with $1 billion or more in assets as of the end of their most recent fiscal year, the filing deadline was extended from November 17, 2025 to November 17, 2027. For smaller funds (funds with less than $1 billion in assets as of the end of their most recent fiscal year), the filing deadline was extended from May 18, 2026 to May 18, 2028.

The compliance deadline may be further revised following the review process mandated by the January 2025 executive order by President Trump. Under the executive order, federal regulations that are not yet effective are to be paused to “[review] any questions of fact, law, and policy that the rules may raise.”

The compliance deadline for reporting requirements under Form N-CEN, however, has not been extended. Registered investment companies must file Form N-CEN on an annual basis, and the form includes basic fund information including the fund’s structure, service providers, and compliance practices.

The new reporting requirements under Form N-CEN, which were adopted by the SEC mandate the disclosure of liquidity service providers. Such disclosure must include the providers’ name, identifying information, the location and the asset classes for which they supply liquidity classifications, and a specification of whether the provider is affiliated with the fund or adviser. The compliance deadline for these new reporting requirements is November 17, 2025.

SEC EXTENDS COMPLIANCE DEADLINE FOR FORM PF

In June 2025, the SEC, together with the U.S. Commodity Futures Trading Commission, voted to extend the compliance deadline for amendments to Form PF. Certain investment advisers to private funds must file Form PF with the SEC and the data (which includes information about the structure, activities, and risk profiles of private funds) is used for the purpose of monitoring systemic risk in the financial system.

The amendments to Form PF were adopted on February 8, 2024, and the original compliance deadline was March 12, 2025. The compliance deadline was previously extended to June 12, 2025. The deadline was further extended to October 1, 2025.

SEC CHARGES INDIVIDUAL AND HIS ADVISORY FIRM WITH FRAUD AND OTHER VIOLATIONS

In March 2025, the SEC announced that it filed charges against an individual (“Defendant 1”) and his investment advisory firm (“Defendant 2” and together with Defendant 1, the “Defendants”) in connection with the operation of a mutual fund (the “Fund”).

According to the SEC’s complaint (the “Complaint”), since the Fund’s inception in 1998 until February 27, 2020, the Fund’s statement of additional information (the “SAI”) disclosed that the Fund had a fundamental investment policy that the Fund may not invest more than 25% of its total assets in securities of companies principally engaged in any one industry (the “Concentration Policy”), which could not be changed without the approval of a majority of the outstanding voting securities of the Fund. The Complaint noted that while the Fund’s SAIs filed in 2021, 2022, and 2023 reflected that the Fund’s Concentration Policy was subject to a 50% limit, the Defendants did not obtain shareholder approval to change the Fund’s Concentration Policy.

In 2018 and 2019, the SEC’s Division of Examinations (“EXAMs”) examined the trust, of which the Fund was a series (the “Trust”). At the close of the examination, EXAMs staff sent Defendant 1 a deficiency letter (the “Deficiency Letter”) detailing certain deficiencies and weaknesses identified by EXAMs staff, including that the Fund had violated its 25% Concentration Policy and used inconsistent industry classifications in different reporting periods. According to the Complaint, the Deficiency Letter also included that EXAMs staff had reviewed minutes of a meeting of the Board of Trustees of the Trust (the “Board”) indicating that the investment advisory agreement and administration contract between the Trust and Defendant 2 were “pre-approved” as of October 1, 2018, but that no documentation accompanied the minutes to substantiate the Board’s renewal of the contracts.

From 2019 to 2021, the SEC’s Division of Enforcement investigated the Defendants, focusing on many of the topics covered by the Deficiency Letter. Without admitting or denying the Commission’s findings, the Defendants consented to the entry of an order in 2021 (the “2021 Order”) that found that the Defendants violated the Concentration Policy between July 2017 and June 2020 by concentrating more than 25% of the Fund’s total assets in one industry, and in doing so, Defendants committed fraud and breached fiduciary duties to the Fund (among other securities law violations). The Complaint alleges that Defendants continued to invest more than 25% of the Fund’s total assets in a single company and in a single industry during certain periods after the 2021 Order.

The Complaint further alleges that between November 24, 2021 through at least June 23, 2024, the Defendants engaged in two sets of misconduct with respect to the Board, including that (a) the Defendants failed to provide or withheld key information from the Board, including information “reasonably necessary for the Board to evaluate the terms of [the firm’s] advisory contract,” which was not put to a vote and which Defendant 1 misrepresented in the Fund’s filings, and misleading the Board about the Defendants’ past securities law violations and (b) that Defendants hired an accountant to audit each series of the Trust, without first obtaining Board approval, as required by the Investment Company Act.

As further detailed in the Complaint, the SEC is requesting the court to enter a final judgment: (i) permanently enjoining the Defendants and their agents, servants, employees and attorneys and all persons in active concert or participation with any of them from violating, directly or indirectly, certain federal securities laws, (ii) ordering the Defendants disgorge all ill-gotten gains they received directly or indirectly, with pre-judgment interest thereon, as a result of the alleged violations under certain sections of the Exchange Act and Investment Company Act of 1940, (iii) ordering the Defendants to pay civil monetary penalties; and (iv) and any other and further relief the court may deem just and proper.

UPCOMING CONFERENCES

2025
Date	Host*	Event	Location
8/20	MFDF	Director Discussion Series – Open Forum	Columbus, OH
9/3	MFDF	The Audit Committee Chair’s Guide to Balancing Duties and Emerging Issues	Columbus, OH
9/8-10	ICI/IDC	ETF Conference	Nashville, TN
9/10	MFDF	Series Trust Funds – Compliance and Board Reporting	Webinar
9/11	MFDF	In Focus: Board Oversight of DEI in Current Landscape	Virtual
9/16	MFDF	MFDF 15(c) White Paper Webinar Series: Part 4 – Enforcement Action Takeaways	Webinar
9/23	MFDF	Latest in Closed-End Funds Litigations	Webinar
9/24	MFDF	Fixed Income Insights: Navigating Market Trends & Opportunities	Webinar
9/29	MFDF	Risk Management Essentials for RICs and Boards	Webinar
10/1	MFDF	Diligent – Tools for Fund Board Book	Webinar
10/5-8	ICI/IDC	Tax and Accounting Conference	Palm Desert, CA
10/14	MFDF	Essential Strategies in Board Oversight of Operational Risk Management	Webinar
10/15	MFDF	Series Trust Funds – Effective Board Relationship with Advisers	Webinar
10/27-29	ICI/IDC	Fund Directors Conference	Scottsdale, AZ
11/5	MFDF	In Focus: Audit Committee Chair	Virtual
11/13	MFDF	Mutual Fund CCO Compensation: The MPI Annual Survey Update	Webinar
11/20	ICI/IDC	2025 Closed-End Fund Conference	New York, NY

2026
Date	Host*	Event	Location
1/26-28	MFDF	2026 Directors’ Institute	Naples, FL
2/3-5	ICI/IDC	2026 ICI Innovate	Houston, TX
3/5	MFDF	2026 Fund Governance & Regulatory Insights Conference	Washington, DC
3/22-25	ICI/IDC	Investment Management Conference	Palm Desert, CA
4/29 – 5/1	ICI/IDC	Leadership Summit	Washington, DC
4/29 – 5/1	ICI/IDC	Fund Directors Workshop	Washington, DC
9/15-17	ICI/IDC	ETF Conference	Nashville, TN
9/27-30	ICI/IDC	Tax and Accounting Conference	Marco Island, FL
10/25-28	ICI/IDC	Fund Directors Conference	Scottsdale, AZ
11/10	ICI/IDC	Closed-End Fund Conference	New York, NY

*Host Organization Key: Mutual Fund Directors Forum (“MFDF”), Independent Directors Council (“IDC”), and Investment Company Institute (“ICI”)

© 2025, Davis Graham & Stubbs LLP. All rights reserved. This newsletter does not constitute legal advice. The views expressed in this newsletter are the views of the authors and not necessarily the views of the firm. Please consult with your legal counsel for specific advice and/or information.

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Peter H. Schwartz
Alena Prokop
Stephanie Danner
Martine Ventello
Mackenzie Coupens

The Colorado General Assembly’s First Regular Session convened on January 8, 2025, and adjourned on May 7, 2025, with over 650 bills introduced. The 2025 General Assembly considered a number of environmental and energy-focused legislation, some of which Governor Polis signed into law and some of which were either vetoed or failed to advance. A number of bills passed both houses and await signature or veto. Below is a summary of notable legislation.

Bills Signed Into Law

• HB25-1040 – Adding Nuclear Energy as a Clean Energy Source. This legislation, sponsored by Reps. Alex Valdez (D) and Ty Winter (R) and Sens. Dylan Roberts (D) and Larry Liston (R), amends the statutory definition of clean energy to include nuclear energy under state law, making it eligible for clean energy project financing and allowing qualifying utilities to use it to meet the state’s 2050 clean energy target. Governor Polis signed the bill into law on March 31, 2025.
• HB25-1077 – Backflow Prevention Devices Requirements. The bill, sponsored by Reps. Tisha Mauro (D) and Rick Taggart (R) and Sens. Nick Hinrichsen (D), removes licensure requirements for individuals who inspect, test or repair backflow devices.  Under current law, individuals who install, remove, inspect, test or repair backflow protection devices are subject to licensure requirements for plumbers. The legislation exempts individuals engaged in the business of inspecting, testing, or repairing backflow prevention devices from licensure requirements but retains the licensure requirements for individuals engaged in the installation or removal of the devices. The purpose of the legislation is to provide more flexibility for qualified professionals while maintaining standards for public water system protection and is a response to confusion and compliance issues under the prior version of the law. Governor Polis signed the bill into law on March 28, 2025.

Enrolled Bills

• HB25-1165 – Geologic Storage Enterprise and Geothermal Resources. The bill, sponsored by Reps. Amy Paschal (D) and Matt Soper (R) and Sens. Cleave Simpson (R) and Cathy Kipp (D), creates the geologic storage stewardship enterprise in the Department of Natural Resources to manage geologic storage of carbon dioxide in the state, including plugging, abandoning and reclaiming geologic storage facilities. The stewardship will collect fees from operators of geologic storage facilities in the state and require them to pay annual stewardship fees for each ton of carbon dioxide they inject into geologic storage in the state. The bill also identifies how long-term stewardship of geologic storage locations will be managed. Finally, the bill updates laws concerning underground geothermal resources, including by exempting certain geothermal operations from needing a well permit from the state engineer and clarifying that the authority to regulate shallow geothermal operations is shared by the state engineer and the state board of examiners. The bill was enrolled on April 11, 2025.
• HB25-1269 – Building Decarbonization Measures. The bill, sponsored by Reps. Jenny Willford (D) and Alex Valdez (D) and Sens. Matt Ball (D) and Cathy Kipp (D), updates energy performance standards for certain buildings, including a requirement to meet 2040 performance standards and revising civil penalties for violations. The bill also creates a decarbonization enterprise to provide financial assistance, technical assistance, and other programmatic assistance to covered building owners to effectively and efficiently implement building decarbonization measures, including energy efficiency measures, electrification measures, energy upgrades, and participation in utility on-bill repayment programs. The enterprise is authorized to impose and collect from covered building owners an annual building decarbonization fee to cover the enterprise’s costs in providing the financial, technical, and programmatic assistance. The bill was enrolled on May 7, 2025.
• SB25-054 – Mining Reclamation and Interstate Compact.  The bill, sponsored by Sens. Cleave Simpson (R) and Jeff Bridges (D) and Reps. Matthew Martinez (D) and Karen McCormick (D), amends the Colorado Mined Land Reclamation Act and the Colorado Land Reclamation Act for the Extraction of Construction Materials to contemplate the expedited issuance of reclamation-only permits on less than 5 acres and updates restrictions and requirements concerning financial assurance for mine reclamation projects.
• SB25-182 – Embodied Carbon Reduction. The bill, sponsored by Sens. Matt Ball (D) and Cleave Simpson (R) and Reps. Kyle Brown (D) and Ron Weinberg (R), add embodied carbon improvements to the list of new energy improvements that are eligible for property-assessed clean energy financing provided by the Colorado new energy improvement district. An embodied carbon improvement is one or more installations or modifications to real property using eligible materials that result in the reduction of the installation’s or modification’s embodied emissions. The bill also modifies the industrial clean energy tax credit so that embodied carbon investments are greenhouse gas emissions reduction improvements. An embodied carbon investment is one that results in a 15% or greater reduction in cradle-to-gate embodied emissions of eligible materials when compared to the eligible materials’ cradle-to-gate baseline. The bill was sent to the Governor for signature.
• SB25-305 – Water Quality Permitting Efficiency. The bill, sponsored by Sens. Barbara Kirkmeyer and Jeff Bridges (D) and Reps. Shannon Bird (D) and Rick Taggart (R), aims to improve the efficiency of Colorado’s water quality permitting process by requiring CDPHE to streamline permit reviews, address backlogs, and provide greater transparency to permittees. It mandates rulemaking deadlines for timeframes on permit actions, allows for third-party technical assistance when applications are delayed, and ensures financial considerations for local governments when imposing new water treatment requirements. The bill also reallocates and appropriates millions in state funds to support these initiatives and adjusts related budget items accordingly.

Bills That Failed

• HB25-1099 – Water Quality Data Standards. The bill, introduced by Reps. Tisha Mauro (D) and Rick Taggart (R) and Sen. Nick Hinrichsen (D), would have required the Water Quality Control Commission to issue, on or before January 1, 2027, written guidance specific to the development of total maximum daily loads (“TMDLs”) (i.e., the daily maximum amount of a pollutant from all sources that is allowed to enter state water so that an applicable water quality standard is met).  The bill also would have required the Colorado Department of Public Health and Environment to determine, on or after January 1, 2028, a TMDL for state waters using credible data. The bill did not make it out of the House Committee on Energy and Environment. The bill was enrolled by the House on April 11, 2025.
• HB25-1119 – Require Disclosure of Climate Emission. The bill, introduced by Rep. Manny Rutinel (D), would have required entities doing business in Colorado that have a total revenue exceeding $1 billion in the preceding calendar year to disclose information concerning greenhouse gas emissions. The bill did not make it out of the Committee on Energy and Environment.
• HB25-1241 – Public Accessibility of Emissions Records. The bill, introduced by Reps. Bob Marshall (D) and Lorena Garcia (D) and Sens. Lisa Cutter (D) and Cathy Kipp (D), would have required stationary sources to maintain and make publicly available records that help the public determine whether the owner or operator is in compliance with air quality standards.
• SB25-117 – Reduce Transportation Costs Imposed by Government. The bill, introduced by Sen. Scott Bright (R), would have repealed certain transportation-related fees, including road use fees, fees on short-term vehicle rentals, passenger per-ride fees on car shares, and the waste tire enterprise fee on purchase of new motor vehicle and trailer tires.
• SB25-137 – Greenhouse Gas Credits for Water Quality Projects. The bill, introduced by Sen. Cleave Simpson (R), concerned eligibility for the greenhouse gas credit trading program for water quality green infrastructure projects that create greenhouse gas credits. The bill did not make it out of the Senate Committee on Transportation and Energy.

Renewable energy in the U.S. (and around the globe) is booming. Over the past decade, renewable energy generation across the country—primarily driven by solar, wind, and geothermal—has more than tripled. The U.S. Energy Information Administration, an agency of the Department of Energy, projects renewables deployment to grow to 59 gigawatts and account for more than a quarter of U.S. electricity generation in 2025. Although it is yet to be seen how the Trump Administration’s policies and actions will ultimately impact renewable energy in the U.S., it is safe to say that development of wind, solar, geothermal, and other renewable energy projects will continue to grow.

However, even though renewable energy in the U.S. is surging, fewer than one-fifth of proposed renewable energy projects actually reach commercial operation, according to research from the Lawrence Berkeley National Laboratory and several other sources. Project cancellations and delays can result in millions of dollars in sunk costs and a plethora of other wasted resources. Two of the leading causes of project disruptions, delays, and cancellations are: (1) onerous local regulation and permitting requirements; and (2) community opposition. Other hurdles include interconnection issues, shortage of skilled labor, lack of funding, and environmental restrictions.  But the first two enumerated are the most common and most difficult to predict and navigate. Below is a brief summary of these two crucial and ever-evolving topics, as well as several key considerations, strategies, and tips every developer should understand and employ when navigating these issues.

Local Control and Controversy

The majority of states, including Colorado, give principal jurisdiction over siting and permitting of renewable energy projects—mainly wind, solar, and battery storage—to local authorities. In Colorado, the primary use or development permit usually will be obtained from the County government, which comes in the form of a conditional use permit (“CUP”), special use permit (“SUP”), or what is known as a “1041 Permit.”[1] The requirements for approval and regulations applicable to renewable energy projects under local laws differ from county to county and state to state. And in some instances, usually wind facilities, a project may span several counties or even states. This local permitting process (aside from any other permitting and approval requirements) can take many months to years to complete.

Local governments generally view their authority and jurisdiction very broadly, sometimes demanding more than the law requires or allows. Over the last several years, this legal overstepping on the part of local governments—which may have little to no experience in the development and regulation of renewable energy projects—appears to be increasing in frequency and extent. Two primary examples are:

1. Assessment of excessive permit or impact fees. Counties more frequently are assessing impact fees in the hundreds of thousands, millions, and even tens of millions of dollars. This is done by assessing a dollar amount per megawatt (“MW”) (e.g., $10,000/MW) or a percentage (e.g., 1-2%) of total construction costs for a project. These fees—which are not tied to the actual impacts of a project—often are legally indefensible on multiple grounds, including running afoul of U.S. Supreme Court case law on unconstitutional takings.[2]
   
2. Unreasonable permit conditions and project requirements. Such permit conditions can take many forms, such as overly burdensome and unjustified mitigation measures, unlawful funding and reimbursement provisions, and requiring developers to construct or fund infrastructure or community improvements unrelated to the permitted project, among a variety of other things (e.g., requiring that all or most of hired labor have a permanent zip code within the county).

The burdensome, complex, time-consuming, and costly local permitting process is a primary impediment to renewable energy project success in Colorado and beyond, resulting in significant project delays and frequent project cancellations.

Community Opposition

The above-mentioned permitting process heightens public awareness of renewable energy projects and, more importantly, includes a legally prescribed public notice and participation component. This includes public notice, comment and hearing requirements, which provides the public an opportunity to submit written comments to the government and to speak out at public hearings. The public—as well as permittees and other stakeholders (e.g., environmental groups and tribes)—also can file administrative or judicial challenges to approved projects and permits after they are issued.[3]   

At the local level, community involvement, influence and impact can be magnified, particularly in smaller communities (where renewable energy projects often are sited). And although public support for renewable energy historically has been favorable, recent surveys and reports indicate that community opposition and controversy is “widespread and growing” (which the author of this article can confirm from direct experience).[4] Community opposition can result in significant project delays, more stringent permit requirements, scaled down projects, and even project abandonments.

Considerations, Strategies, and Tips to Navigate These Impediments and Maximize Project Success

Local control and community input will always be present and will continue to present challenges to renewable energy developers and project proponents. But that doesn’t mean developers are simply at the mercy of County governments and vocal residents. On the contrary, early identification and consistent execution of a strategic and calculated approach to project development can avoid significant pitfalls and help ensure project success.    

Some valuable considerations, strategies, and tips include:  

• Fully Understand the Regulatory Universe.  It is imperative that developers fully understand the regulatory landscape governing a project from inception to decommissioning—on the local, state, federal, and tribal levels. This includes a forecast of potential regulatory changes and policy shifts, such as permitting reforms at the state level (which is occurring in Colorado) and moratoriums, among other things. Understanding all permitting, regulatory, and other requirements from the outset allows developers to identify and address potential bottlenecks and hurdles (or even deal breakers) early on. It is best to put this in writing at project inception, such as through a comprehensive permitting and regulatory memorandum or matrix, which should be regularly updated.

• Build a Comprehensive Team. Project proponents should build a comprehensive team early on in the development process, consisting of in-house representatives, appropriate consultants, and outside legal counsel, among others. Although this may be more resource intensive, it ensures the right people are involved early on to identify and evaluate significant project issues and hurdles and avoids hasty onboarding when issues do come up, which can lead to missteps and mistakes.

• Coordination with Local Authorities. Early, frequent, and transparent communication and coordination with local regulators is key. The goals here are to establish rapport, define a comprehensive permitting strategy and timeline, and identify issues and challenges. Working collaboratively with the local government often results in a more streamlined and favorable process and outcome.

• Community Engagement. As with the local government, early, often, and significant community engagement is of vital importance. Identifying and addressing community input and concerns early on can minimize significant issues and opposition during the development and permitting process. When the community feels like they are heard and involved—rather than kept in the dark or misled—project opposition can be minimized or avoided altogether. In addition, community engagement can garner substantial support for a project, which can have significant positive impacts on the development and permitting process.

• Be Prepared to Seek and/or Defend Against Legal Recourse. Legal challenges to renewable energy projects are on the rise, by both project proponents and opponents.[5] Throughout the entire process, developers should provide and maintain a robust record of proof, compliance, objections, positions, etc. to, among other things, support any claims or defenses in potential legal challenges. Similarly, developers should continually evaluate any legal claims they may assert or need to defend against in relation to their projects with in-house and outside counsel.

Again, local regulatory challenges and community opposition often are inevitable.  But employing the above strategies can help streamline the process, minimize challenges and disputes, and set developers up for successful project completion.

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[1] A “1041 Permit” obtained under “1041 Regulations” refers to a specific permitting process, authorized by House Bill 1041 and codified at C.R.S. §§ 24-65.1-101 to -108, allowing local governments to regulate development activities that have statewide impacts or are considered to be of state interest.  The 1041 statute allows local governments to regulate—in almost any way they see fit—projects like major water and sewage systems, highways, and “major facilities of a public utility,” the latter of which has been interpreted to include wind, solar, battery storage, and other renewable energy facilities.  As an alternative to a CUP, SUP, or 1041 Permit, developers can enter into a development agreement with the local government, but this mechanism is less frequently used to authorize and regulate renewable energy projects.

[2] See, e.g., Sheetz v. County of El Dorado, 601 U.S. 267 (2024).

[3] See, e.g., C.R.C.P. 106(a)(4) (authorizing individuals and entities to challenge decisions that are judicial or quasi-judicial in nature made by a governmental body or official).

[4] See, e.g., Eisenson, et al., Opposition to Renewable Energy Facilities in the United States: June 2024 Edition, Sabin Center for Climate Change Law (June 2024).

[5] See, e.g., Davis Graham Osage Wind Update; Kiowa County Sued Separately by Invenergy & Northern Cheyenne Tribe Threatening Renewable Energy Projects (Apr. 26, 2024).