January 12, 2026

There has been a recent flurry of regulatory activity in both Washington, DC and Colorado as federal and state regulators work to establish new frameworks for data center interconnection and co-located generation. The Secretary of Energy directed FERC to consider an Advanced Notice of Proposed Rulemaking on large load interconnection procedures, FERC issued an order requiring PJM to develop co-location tariff provisions, the Colorado Public Utilities Commission directed Xcel Energy to file large-load tariff principles by January 2026, and FERC rejected Tri-State’s proposed large load tariff on jurisdictional grounds. These developments underscore ongoing efforts to adapt existing frameworks to how utilities and regulators approach data center interconnection, cost allocation, and co-located generation.

DOE’s Direction to FERC

On October 23, 2025, Secretary of Energy Chris Wright directed the Federal Energy Regulatory Commission (FERC or Commission) to consider an Advanced Notice of Proposed Rulemaking (ANOPR) addressing interconnection procedures for large loads (defined as those exceeding 20 megawatts (MW)), and requesting that FERC issue a final rule by April 30, 2026. Secretary Wright issued the ANOPR pursuant to Section 403 of the Department of Energy Organization Act, which empowers the Secretary of Energy to propose rules to FERC, but does not require FERC to implement them. Additionally, FERC issued a notice inviting comments regarding the ANOPR on October 27, 2025 in Docket No. RM26-4-000.

DOE’s proposed ANOPR advances the position that FERC has jurisdiction over large load interconnections through FERC Order No. 888, based on four legal theories:

• large load interconnections are a critical component of open access transmission service analogous to generator interconnections under FERC Order No. 2003;
• such interconnections directly affect jurisdictional wholesale rates;
• the proposal does not intrude on states’ retail electricity jurisdiction; and
• FERC’s exclusive jurisdiction over transmission of electric energy in interstate commerce encompasses interconnection service.

The ANOPR enumerates 14 guiding principles, including limiting FERC’s authority to interconnections directly to transmission facilities, applying reforms only to new loads greater than 20 MW, studying load and hybrid facilities alongside generation projects, implementing standardized deposits and withdrawal penalties, and allocating 100% of network upgrade costs to the load.

Whether FERC has statutory authority to regulate large load interconnections remains uncertain. Any rules promulgated will face scrutiny under the major questions doctrine (West Virginia v. EPA) and review under Loper Bright Enterprises v. Raimondo, which held that courts should not apply Chevron deference to agency interpretations of ambiguous statutes. FERC’s notice inviting comments on the ANOPR was procedural only and did not discuss or endorse the four legal theories noted above. FERC’s own precedent also highlights this ambiguity: in rejecting Tri-State’s large load tariff (discussed below), FERC stated that the proposal may regulate ‘terms and conditions of a Customer’s retail service in ways that are beyond the Commission’s authority.’ Additionally, the National Association of Regulatory Utility Commissioners (NARUC) has urged FERC to substantially modify the ANOPR, asserting it infringes on states’ retail electricity jurisdiction. These challenges create substantial uncertainty as to whether FERC will adopt the ANOPR in whole, in part, or at all.

FERC’s PJM Co-Location Order

On December 18, 2025, FERC unanimously issued an order directing PJM Interconnection (PJM) to revise its tariff to address co-located loads at generating facilities. The order arose from FERC’s show cause proceeding following high-profile co-location arrangements, including Amazon’s data center at Talen Energy’s Susquehanna nuclear plant located in Pennsylvania and Microsoft’s Three Mile Island restart agreement.

FERC found PJM’s existing tariff unjust and unreasonable due to lack of clarity regarding co-located loads. The order requires PJM to offer four transmission service options:

• traditional Network Integration Transmission Service for entire nameplate load;
• interim non-firm service permitting expedited construction before grid upgrades are completed, with acceptance of curtailment risk;
• firm contract demand service for only the portion of load expected to be served by the grid; and
• non-firm contract demand service (which carries curtailment risk).

The order directs PJM to propose mechanisms, such as minimum monthly charges, to ensure that costs of maintaining grid reliability and backup capability are appropriately allocated, even for facilities with limited grid usage or rarely used backup service. Final tariff details remain pending PJM’s compliance filings (due in January 2026) and further FERC review.

While Colorado is not within PJM’s footprint, FERC’s order signals potential federal regulatory approaches to co-location and may inform or influence Colorado’s frameworks. For example, Xcel Energy’s large-load tariff filing due in January 2026 could potentially incorporate concepts from the PJM order.

Colorado PUC Directive to Xcel Energy

On November 6, 2025, the Colorado Public Utilities Commission (PUC) issued Decision No. C25-0747 in Proceeding No. 24A-0442E (Xcel’s 2024 Just Transition Solicitation), adopting guiding principles for service to large-load customers and directed Xcel Energy to file a more detailed large-load tariff proposal by January 31, 2026 as part of Xcel’s Just Transition Solicitation Plan proceeding (Proceeding No. 24A-0442E). The PUC-adopted guiding principles include measures such as upfront fees and security deposits, minimum 15-year service contracts, minimum bill requirements for reserved capacity, and early exit fees if the developer terminates service before the contract term.

Xcel’s forthcoming large-load tariff proposal is expected to address how co-located generation affects cost allocation. This may include differentiated transmission charges that reflect actual grid usage rather than full nameplate capacity for data centers with onsite generation, though minimum charges for maintaining backup grid service could also apply, similar to concepts in FERC’s PJM order.

Xcel’s formal tariff filing (original deadline January 31, 2026; Xcel filed a variance petition on January 26, 2026, requesting an extension to April 2, 2026) could inform approaches by other Colorado utilities and cooperatives addressing large loads, though structural and governance differences among utilities may limit direct applicability, and the tariff’s terms are expected to materially affect project economics and feasibility for data centers requiring grid-supplied power or backup service.

Tri-State’s Rejected Large Load Tariff

In August 2025, Tri-State proposed a High-Impact Load Tariff at FERC (Docket No. ER25-3316) for loads exceeding 45 megawatts. On October 27, 2025, FERC rejected the tariff, determining that provisions requiring member cooperatives’ retail customers to execute agreements and related security deposit requirements exceeded FERC’s jurisdiction over wholesale transactions under Federal Power Act sections 205 and 206. As of this writing, no revised tariff has been proposed.

FERC’s rejection underscores the jurisdictional tensions evident in DOE’s ANOPR. Developers considering sites in Tri-State member cooperative territories (which include 15 Colorado cooperatives) may want to consider engaging early with both the local distribution cooperative and Tri-State to understand capacity availability and study timelines. Until a revised framework is in place, large load interconnection in Tri-State territories will follow existing procedures.

Potential Colorado Implications

These federal and state actions signal several key themes:

Cost Allocation Based on Actual Use. Both FERC’s PJM order and Colorado’s emerging frameworks signal emerging interest in charging data centers based more closely on grid usage, rather than full nameplate capacity, though minimum charges for backup service could still apply.

Developer Financial Commitments. Utilities and regulators are requiring upfront security deposits, long-term contracts, and early exit fees to ensure speculative projects do not force infrastructure investments that other ratepayers ultimately bear. These measures aim to protect existing ratepayers from bearing costs of speculative or withdrawn projects, while FERC’s PJM order also creates pathways for developers willing to accept curtailment risk to potentially expedite timelines.

Co-Location Frameworks. FERC’s PJM order and DOE’s ANOPR signal that co-located generation can be a viable model when structured to protect ratepayers. However, the requirement that generators and co-located loads fund transmission upgrades to maintain service for existing customers means co-location does not eliminate grid-related costs.

Federal-State Jurisdictional Tensions. The DOE ANOPR and Tri-State’s rejected tariff filing at FERC highlight ongoing tensions between federal and state authority. FERC’s own statement in the Tri-State rejection regarding the limits of its authority, combined with NARUC’s opposition to the ANOPR, suggests that any expansion of federal jurisdiction will be contested.

Interconnection Timelines. Despite efforts to clarify rules, physical interconnection timelines (driven by studies, network upgrade design, and construction) remain lengthy (currently estimated at anywhere from 24 to 48 months).

Considerations for Colorado Stakeholders

Companies considering data center investments in Colorado may wish to consider the following:

• Xcel’s large-load tariff filing will establish initial service terms, cost allocation, and co-location treatment for the state’s largest utility. Interested stakeholders should review the filing (Docket No. 24A-0442E).
• Early engagement with Xcel, Tri-State, or other serving utilities during site selection can provide clarity on capacity availability, interconnection study timelines, and how emerging tariff frameworks may affect project economics.
• With regulatory clarity increasing and cost allocation frameworks becoming more defined, co-located generation should be evaluated. However, financial models should account for network upgrade obligations that may be required when generators “leave the grid.”
• Stakeholders may wish to monitor FERC Docket No. RM26-4-000 and consider filing comments to ensure any federal framework accommodates Colorado’s regulatory structures, particularly given ongoing jurisdictional contests and active comment proceedings. Additionally, monitoring PJM’s January 19, 2026 report to FERC and subsequent tariff implementation may provide insights into frameworks that could be adopted in other regions.
• Power supply strategy – whether traditional utility service, co-located generation, hybrid models, or acceptance of curtailment risk through non-firm arrangements – should be determined early and integrated with cooling design, air permitting, water rights strategy, and land use review.

The convergence of federal action by DOE and FERC, Colorado PUC directives, and Tri-State’s jurisdictional challenges creates a dynamic regulatory environment for data centers and large loads in Colorado. While some clarity is emerging, significant questions remain regarding implementation, cost allocation details, and the interplay between federal and state authority.

Corrections & Amplifications

The Colorado PUC issued Decision No. C25-0747 on November 6, 2025, adopting guiding principles for large-load service and directing Xcel Energy to file its large-load tariff proposal by January 31, 2026 (original deadline). An earlier version of this article referred to the decision as occurring in “late October 2025” with a December 2025 written decision and described the filing deadline vaguely as “January 2026.” Xcel requested an extension to April 2, 2026 via variance petition filed January 26, 2026. (Corrected February 19, 2026)

For questions about energy regulatory developments impacting data centers, please contact RJ Colwell.

Effective January 14, 2026, the Colorado Division of Securities has adopted amendments to its rules under the Colorado Securities Act, including certain rules (the “Colorado Rules”) affecting Colorado licensed investment advisers and Colorado Licensed Investment Adviser Representatives (“IARs”). These amendments will affect how individuals can qualify to serve as an IAR and the ability of such IARs to keep exam results “alive” while out of the industry. These amendments are consistent with those adopted in 2023 by the North American Securities Administrators Association(“NASAA”), which, among other things, promulgates model statutes, rules, and regulations that seek to maintain consistency among the states.

What Changed?

• In light of the Investment Adviser Association no longer offering the Chartered Investment Counselor (“CIC”) designation, Colorado has removed the CIC designation from the list of credentials that can be used in lieu of the examination requirement to qualify as an IAR. Any individual who is currently licensed in Colorado as an IAR will not be affected by the removal of the designation so long as such license remains in effect. Any individual who is not licensed in the state and intends to rely on their CIC designation should instead consider relying on their designation as a Chartered Financial Analyst (“CFA”) granted by the Association for Investment Management and Research, since all CIC holders must also be a CFA. Alternatively, individuals can consider other recognized pathways to be properly licensed as an IAR in the state of Colorado, such as by obtaining a satisfactory score on the Series 65 exam, the Series 66 plus Series 7 exams, or by holding a different eligible credential, such as a Chartered Financial Consultant (“ChFC”) certification granted by The American College.
• Colorado also adopted NASAA’s Investment Adviser Representative Exam Validity Extension Program (the “Program”). Under the Program, so long as an individual meets the specified criteria described below, any person who terminates their IAR license may nevertheless maintain the validity of their Series 65 exam or the IAR portion of the Series 66 exam despite no longer being employed or associated with an investment adviser or federal covered investment adviser for up to five (5) years following their termination.[1] In order to rely on this new rule, the IAR must:
• Have previously taken and successfully passed the examination for which they seek to rely on for the purposes of licensure;
• Have previously been licensed as an IAR for at least one (1) year immediately preceding the termination of their IAR license;
• Not be subjected to statutory disqualification under Section 3(a)(39) of the Securities Exchange Act of 1934 while licensed as an IAR or at any period after termination of the license;
• Elect to participate in the Program within two (2) years from the effective date of the termination of the IAR license;
• Be compliant with, and not have a deficiency under, the IAR continuing education program under Colorado Rule 51-4.4.1(IA) at the time the IAR license becomes ineffective; and
• Complete on an annual basis on or before December 31 of each year in which the IAR is relying on the Program:
  • Six (6) Credits of IAR Continuing Education (“CE”) Ethics and Professional Responsibility Content offered by an Authorized Provider as defined in Colorado Rule 51-4.4.1(IA)(J)(2), including at least three (3) hours covering the topic of ethics, and
  • Six (6) Credits of IAR CE Products and Practice Content offered by an Authorized Provider as defined in Rule 51-4.4.1(IA)(J)(2).

Anyone who elects to participate in the Program must complete the credits specified in paragraph (6) above for each calendar year after their IAR license becomes ineffective, regardless of when they elect to participate in the Program. However, individuals who comply with the Financial Industry Regulatory Authority (“FINRA”) Maintaining Qualification Program under FINRA Rule 1240(c) will be considered in compliance with paragraph (6) above as well.

Key Takeaways for Colorado Licensed Investment Advisers and Licensed IARs

• If you engage an individual with prior industry experience, consider adding to your intake process a method for determining whether they were relying on the Program for the basis of a non-expired license. In these instances, seeking documentation to confirm Program compliance by reviewing records maintained by that individual while a part of the Program as well as other third-party sources, principally as it relates to statutory disqualification and continuing education, would be advised.
• If you are an individual leaving the industry and intending to return within five (5) years, evaluate the positive and negative ramifications of enrolling in the Program. If you decide to enroll, pay close attention to the required continuing education requirements to remain in compliance with the Program and to remain eligible to once again become a fully licensed IAR without having to sit for examinations or otherwise seek exemptive relief.

For additional guidance or support, please reach out to a member of our Asset Management Group or another member of the Davis Graham Team.

[1] 3 CCR 704-1-51-4.4.2(IA).

On Monday, in Lind-Barnett v. Tender Care Veterinary Center Inc., 2025 CO 62, the Colorado Supreme Court announced a two-step test for determining whether challenged speech or conduct is made “in connection with a public issue or an issue of public interest” under Colorado’s anti-SLAPP statute. Courts must first assess whether the activity could reasonably be understood to relate to a public issue; then they must determine whether the activity contributed to public discussion or debate about that issue. The speaker’s motive plays no role in either inquiry. 

The dispute arose after two community members—one identifying herself as a long-time breeder, trainer, sitter, and caregiver—posted a series of negative, widely viewed Facebook reviews criticizing a veterinary clinic’s quality of care and business practices, including alleged misdiagnoses and retaliatory conduct. The posts, shared on multiple local community pages, generated dozens of reactions and over 140 comments, which included accounts of other people’s experiences and statements that the information “may save lives.” When the posters refused to remove their content, the clinic sued for defamation. 

The defendants moved to dismiss under Colorado’s anti-SLAPP statute, invoking the catchall provision that protects conduct or communication in furtherance of free speech or petition “in connection with a public issue or an issue of public interest.” § 13-20-1101(2)(a)(IV), C.R.S. (2025). The district court and the court of appeals denied the motion, concluding the posts were primarily private grievances that did not contribute to broader public discourse. 

The Supreme Court reversed, holding the division applied the wrong legal standard, and set forth the two-step analysis courts must apply when determining whether challenged speech is made “in connection with a public issue or an issue of public interest.” 

First, courts must ask whether an objective observer “could reasonably understand that the speech or conduct, considered in light of its content and context, is made in connection with a public issue or issue of public interest, even if it also implicates a private dispute.” While declining to define the full scope of “public issue” or “public interest,” the Court identified three nonexhaustive categories that often qualify: (1) statements that concern a person or entity in the public eye; (2) conduct that could directly affect a large number of people beyond the direct participants; and (3) topics of widespread, public interest. 

Second, courts must examine the relationship between the speech and the identified public issue to determine “whether the challenged activity contributed to public discussion or debate regarding that issue.” In this step, courts should consider factors such as audience, speaker, location, purpose, and timing. 

Crucially, the Court emphasized that a speaker’s motive is not relevant to either step of the anti-SLAPP analysis. The Court criticized the division’s reliance on motive—specifically, the defendants’ supposed desire “to exact some revenge”—in concluding the posts did not contribute to a broader public discussion about pet health care. At the same time, the Court recognized that while motive cannot be used to constrict the anti-SLAPP statute’s threshold protection, it may become relevant at a later stage—after the defendant establishes that the conduct is protected and the burden shifts to the plaintiff to show a likelihood of success on the claim, such as in defamation claims requiring proof of actual malice. 

Applying these principles, the Court agreed with the division that consumer information about veterinary services implicates a public issue given, the societal interest in animal welfare. It held that the division erred by discounting the anti-SLAPP protections based on the defendants’ perceived retaliatory intent and by treating the speakers’ private grievances as dispositive of the public-interest inquiry. The Court held the broader context—the speaker’s personal experiences and use of community forums, the sizeable local audience, the high level of engagement, and the posts’ focus on the quality and practices of a licensed veterinary facility—supports the conclusion that the posts reasonably implicated and contributed to public discussion on matters of public interest. 

The Supreme Court reversed the division’s judgment and remanded the case for the trial court to apply the clarified two-step test. 

Recent years have seen an explosion of interest in “deep” geothermal development – projects targeting energy extracted from heat sources hundreds of meters below the surface and available 24/7 as a baseload power source. As geothermal innovators seek to prove viability of their technologies and heat resources, driving down the per megawatt cost to be comparable to existing energy sources, legislatures in North Dakota and New Mexico have stepped in this year to encourage the use of existing infrastructure and know-how from the oil and gas sector for geothermal energy development.

This past March, New Mexico enacted House Bill 361, known as the “Well Repurposing Act”, which permits the New Mexico Energy, Minerals, and Natural Resources Department to convert oil and gas wells for geothermal energy and carbon storage purposes and authorizes the Department to establish financial assistance requirements for operators undertaking such conversions.[1] The bill’s sponsors specifically targeted New Mexico’s nearly 2,000 orphaned wells (unplugged oil and gas wells which have no responsible owner or operator) – identifying the potential for geothermal energy producers to leverage existing, drilled wells, while mitigating the public’s exposure to environmental risks and plugging liabilities such orphaned wells pose.[2]

Meanwhile, North Dakota passed Senate Bill 2360 in April 2025, pursuant to which the legislative management shall consider a feasibility study to evaluate the state’s potential for geothermal energy production, including the potential application of geothermal energy to nonproductive oil and gas wells.[3] Prairie Public Broadcasting later reported that the University of North Dakota’s Energy and Environmental Research Center has been engaged to study the possibility of generating up to 600 megawatts of power from geothermal energy coupled with oil production or CO2 storage.[4]

Proponents of co-locating geothermal and hydrocarbon production see potential synergies in leveraging the deep expertise in subsurface drilling developed for oil and gas industries to better access and produce from deeper – and hotter – energy sources. All while reducing drilling costs to make geothermal power economically competitive compared to both traditional and renewable energy sources. Meanwhile, legislatures are hoping these solutions can alleviate their states’ concerns regarding orphaned well liabilities while pushing the energy transition forward.

[1] New Mexico House Bill 361

[2] New Mexico House Democrats, “House Passes Environmental Protection and Clean Energy Bills”, March 14, 2025

[3]: North Dakota Senate Bill 2360

[4] Dave Thompson, “EERC to undertake a study of geothermal energy (audio)”, Prairie Public Broadcasting, July 2, 2025

In July 2025, President Trump issued an executive order setting forth a presidential priority “to facilitate the rapid and efficient buildout” of data centers and associated infrastructure, including power generation sources and associated transmission lines. To further this goal, the order directs the utilization of “federally owned land and resources for the expeditious and orderly development of data centers.” Additionally, the order calls for the identification of Brownfield and Superfund sites for data center development.

Federal agencies’ implementation of these directives to date is mixed. The Department of Energy (DOE) and U.S. Air Force are already accepting proposals for projects at certain sites within their jurisdiction. Despite its vast land holdings, however, the Department of the Interior (DOI) has not yet identified any sites on public lands for data center development. Agencies’ progress is detailed below, with an analysis of the potential impacts of delays.

Overview of the Executive Order.

The executive order applies to “data center projects” that require more than 100 megawatts of new load dedicated to artificial intelligence (AI) and certain “components” of these projects—namely, the materials, products, and infrastructure necessary to build data center projects, including energy infrastructure, transmission, and natural gas, coal, nuclear, and geothermal power sources. To be considered a “qualifying project” under the order, a data center project or its components must involve commitments of at least $500 million in capital expenditures, incrementally add more than 100 megawatts of electric load, protect national security, or otherwise be designated a qualifying project by one of several federal agencies.

Relevant to this update, the order calls for the Department of Defense (now known as the Department of War) (DoD), DOE, and DOI to identify sites for projects on lands within their jurisdiction. Additionally, the order directs the Environmental Protection Agency (EPA) to identify Brownfield sites and Superfund sites suitable for the development of qualifying data center projects.

Finally, the order sets forth numerous paths to streamline federal agencies’ permitting of data center projects.

Although Federal Lands Are Targeted for Data Center Projects, No Sites Have Been Identified on Public Lands.

DOE and DoD are implementing the order’s directive to identify sites for data center projects, but DOI has not yet publicly taken any steps to implement the order to promote the development of data center projects on federal public lands.

DOE Lands. The day after the President issued the order, DOE announced it had selected four sites—the Idaho National Laboratory, Oak Ridge Reservation in Tennessee, Paducah Gaseous Diffusion Plant in Kentucky, and the Savannah River Site in South Carolina—for data center development and energy generation projects. Then, in the fall of 2025, offices within DOE issued requests for application or proposal for projects at three of these sites; the National Nuclear Security Administration issued a request for offer for a project at the Paducah Gaseous Diffusion Plant. These application periods are either open or have recently closed. DOE has not identified a timeframe as to when it will announce which projects it will select.

DoD Lands. In October 2025, the U.S. Air Force issued a solicitation for proposals to develop “underutilized” lands at Arnold Air Force Base in Tennessee, Edwards Air Force Base in California, Joint Base McGuire-Dix-Lakehurst in New Jersey, Davis-Monthan Air Force Base in Arizona, and Robins Air Force Base in Georgia. Offers were due on November 14, 2025. The Air Force has not indicated when it will make decisions on proposals.

DOI Lands. DOI has not identified any sites for data center projects or sought public input on potential sites on federal public lands. Federal public lands include the vast expanse of lands the Bureau of Land Management (BLM) manages in western states for multiple uses, including energy development.

DOI’s inaction is notable for several reasons. First, the agency is the nation’s largest landholder; DOI manages more than 530 million acres of onshore surface lands and, of these, BLM manages approximately 245 million acres. Second, presidential administrations historically have used public lands to advance national objectives; for example, President Biden relied on public lands to increase large-scale renewable energy production. Finally, because many BLM lands can also be used for energy production, data centers can be co-located with energy sources.

And, timing compounds DOI’s inaction to date. BLM may be unable to move as nimbly as other federal agencies to authorize data center projects. BLM manages its lands in accordance with resource management plans, which are often developed through a multi-year public process. To accommodate data center development, BLM may need to amend or revise governing plans. Thus, data center development on BLM lands may require more process, and thus more time, than lands managed by other federal agencies.

Action on Brownfield Sites and Superfund Sites Is Forthcoming.

EPA has not yet identified Brownfield and Superfund sites for data center projects covered by the order. In November 2025, Inside EPA reported that EPA is developing criteria to identify suitable data center sites.

The order also calls for EPA, within 180 days of the order (i.e., by January 19, 2026), to develop guidance to expedite environmental reviews for qualified reuse of Brownfield and Superfund sites and to assist state governments and private parties to expeditiously return these sites to productive use. Presumably, this guidance will follow in a timely manner.

Conclusion

Much work remains before federal agencies can authorize the construction of data center projects on federal lands. 2026 will be a pivotal year for federal agencies to secure agreements for these projects so that they can be timely constructed.

• 2026 Renewable Energy Outlook: The renewable energy industry has faced significant challenges in 2025, particularly with the passage of the One Big Beautiful Bill Act (OBBBA), which rolled back key tax credits and imposed new restrictions.  And although wind and solar investments have fallen in 2025, renewables still dominated U.S. capacity growth, accounting for 93% of additions (30.2 GW) through September 2025, with solar and storage making up 83%.  Last month, Deloitte released its 2026 Renewable Energy Industry Outlook, which outlines five key trends that could shape the industry in 2026.  The outlook is a mixed bag.  2026 could be a good year for renewables, particularly for developers that can move quickly to take advantage of safe-harbor deadlines and build resilient and innovative operations, but any optimism is tempered by policy and supply chain risks.

• Potential New FERC Regulations on Interconnection of AI Data Centers: The Department of Energy (DOE) has directed FERC to initiate a rulemaking to “rapidly accelerate the interconnection of large loads,” including AI data centers.  DOE’s letter and attached Advanced Notice of Proposed Rulemaking (ANOPR), dated October 23, 2025, were issued pursuant to Section 403 of the Department of Energy Organization Act.  If implemented as directed by DOE, the new rule would expand FERC’s jurisdiction over interstate transmission to provide for expedited grid access for data centers and other advanced manufacturing facilities.  FERC received comments on the ANOPR through November 14, 2025, and is accepting reply comments through November 28, 2025.  DOE has directed FERC to issue a final rule by April 30, 2026.

• Litigation Update—Trump Attacks on Wind Industry: On his first day in office, President Trump issued a memorandum titled “Temporary Withdrawal of All Areas on the Outer Continental Shelf from Offshore Wind Leasing and Review of the Federal Government’s Leasing and Permitting Practices for Wind Projects.”  The memo directs federal agencies to temporarily cease issuing new or renewed approvals, permits, or leases for onshore or offshore wind projects, pending a comprehensive review of federal wind-leasing and permitting practices, and directs the Secretary of Interior to review existing approvals, permits, and leases to identify legal bases for revocation.  The memo and the administration’s subsequent actions have spurred a litany of lawsuits.  In May 2025, the District of Columbia and 17 states filed suit challenging the administration’s authority to issue the memo (New York et al v. Trump, No. 1:25-cv-11221 (D. Mass.)); hearings were held this week in that suit.  Litigation also has ensued over several stop-work orders issued pursuant to the memo, including those related to the high-profile Revolution Wind project—a 704 MW project that would be the first multi-state offshore wind farm in the U.S.  In August 2025, the Department of Interior ordered Revolution Wind to stop work on construction (which was 80% complete) citing vague “national security concerns,” and both the developer and the States of Rhode Island and Connecticut filed suit (Revolution Wind, LLC v. Doug Burgum et al., No. 1:25-cv-02999 (D.D.C.); Rhode Island & Connecticut v. U.S. DOI, No. 1:25-cv-00439 (D.R.I.)).  In September 2025, the D.C. District Court in Revolution Wind issued a preliminary injunction that temporarily blocked the stop-work order, allowing construction to resume for now.  These lawsuits, among several others, are ongoing.

• EPA Seeks to Dismantle “Solar for All,” Litigation Ensues: On August 7, 2025, the U.S. Environmental Protection Agency (EPA) terminated the $7 billion Solar for All program, a Biden-era fund established under the 2022 Inflation Reduction Act designed to help low-income households, multi-family buildings, community solar, and underserved communities deploy solar energy.  Announced on X (formerly Twitter) by EPA Administrator Lee Zeldin, the agency cited a lack of statutory authority to administer the program in light of the OBBBA.  In October 2025, four separate lawsuits were filed challenging the termination of Solar for All.  One of those suits—State of Arizona v. EPA—was filed by 22 states (including Colorado), the District of Columbia, and other stakeholders, and asserts violations of the Administrative Procedure Act and the Constitution, among other claims.  A detailed summary of congressional and administrative developments surrounding Solar for All and the litigation that has ensued can be found on the Columbia Law School Sabin Center’s Climate Law Blog.

Table of Contents

• SEC Issues New Guidance for Registered Closed-End Funds Investing in Private Funds
• NYSE Proposes to Remove Annual Shareholder Meeting Requirements for Closed-End Funds
• RIA Charged with Custody Rule Violations
• SEC Further Extends Compliance Deadline for Form PF
• SEC Approves TXSE
• Leaked SEC Regulatory Agenda
• SEC Staffing Updates

SEC ISSUES NEW GUIDANCE FOR REGISTERED CLOSED-END FUNDS INVESTING IN PRIVATE FUNDS

In August 2025, the Division of Investment Management (the “Division”) of the U.S. Securities and Exchange Commission (the “SEC” or the “Commission”) published Accounting and Disclosure Information 2025-16 (the “ADI”) providing updated guidance for registered closed-end funds that invest in private funds (“CE‑FOPFs”). The staff guidance in the ADI formalizes statements made by senior members of the SEC staff earlier this year that had reversed prior SEC staff guidance.

As noted in our Second Quarter 2025 Update, this new guidance is part of a shift from informal staff positions taken before May, which were implemented as part of the Division’s comment process. Previously, SEC staff took the position that a CE-FOPF 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, as amended (the “1940 Act”).

The SEC’s new ADI confirms CE-FOPFs can now invest in private funds without caps on investor eligibility, minimum investments, or exposure limits. The ADI explains that existing regulatory protections under federal securities laws provide adequate protection of investors in CE-FOPFs that indirectly invest in private funds.

The ADI guidance focuses on two key areas: registration statement disclosure and filing requirements. It also encourages registrants to consult with Division staff for clarity on these matters.

With respect to disclosures, the ADI highlights the following areas that the SEC staff will continue to focus on:

• Plain English and Material Information: Registration statements must be clear, concise, and comply with the “plain English” rule.
• Costs, Strategies, and Risks: CE‑FOPFs should provide full disclosure of its costs, strategies, and risks, as well as the investment process-related due diligence practices conducted by the adviser when evaluating private fund investment opportunities (including investment, operational, legal, and, as applicable, tax considerations). The liquidity terms of the CE-FOPF should also be disclosed clearly and prominently.
• Fee Structures and Performance Impact: CE-FOPFs should describe the various fee structures imposed by the underlying private funds, including any performance-related compensation, as well as how those fees could affect the underlying private funds’ returns and the CE-FOPF’s performance. A CE-FOPF should also disclose how multiple layers of direct and indirect costs will impact the returns realized by an investor in the CE-FOPF, including the possibility that certain of the underlying private funds may receive performance fees, while other underlying private funds, or the overall performance of the CE-FOPF itself, is negative.
• Underlying Private Fund Strategies: CE-FOPFs should consider disclosures about the types of underlying private funds in which it proposes to invest and the associated risks and considerations, including (to the extent material) the private funds’ investment strategies, risks associated with more volatile or speculative investments, conflicts of interest, and the liquidity of the private funds’ underlying investments.
• Regulatory Differences: CE-FOPFs should clarify that the underlying private funds in which they invest are not subject to protections under the 1940 Act (e.g., leverage and transactions with affiliates), which may impact the CE-FOPF’s strategies, risks, and costs. The CE‑FOPF should also disclose that shareholders may have limited information about the underlying private funds in which the CE-FOPF is investing, including with respect to the underlying private funds’ holdings, liquidity, and valuation.
• Material Risks: Where material, a CE-FOPF should consider disclosing the risks and impacts related to legal jurisdictions of the underlying private funds, liquidity terms (such as mandatory minimum holding periods, limitations or suspensions of redemptions, and the possibility of “payment in kind” distributions in response to a redemption request), and tax considerations when investing in private funds that produce non-qualifying income and that could impact the CE-FOPF’s pass-through status as a “regulated investment company” as defined under Subchapter M of the Internal Revenue Code.

With respect to filing requirements, the ADI details the appropriate filing process for existing CE-FOPFs seeking to adjust investor limits or asset exposure thresholds.

The ADI states that CE-FOPFs currently operating, which have invested or plan to invest more than 15% of their assets in private funds and have removed or intend to remove limitations on accredited investors and/or investment minimums, are required to file either (i) amendments to their registration statements in accordance with Rule 486(a) or Rule 486(b) of the 1933 Act, or (ii) updates to their prospectus supplements under Rule 424 of the 1933 Act, as applicable. CE-FOPFs should evaluate whether these cumulative changes are considered material, as this would necessitate a review by Division staff of a post-effective amendment to the CE-FOPF’s registration statement under Rule 486(a).

Registrants that currently limit private fund exposure to 15% of assets and never imposed accredited investor and/or investment minimum shareholder limitations on their registration statements and now seek to remove the 15% limitation should file a post‑effective amendment filing pursuant to Rule 486(a), subject to Division staff review.

NYSE PROPOSES TO REMOVE ANNUAL SHAREHOLDER MEETING REQUIREMENTS FOR CLOSED-END FUNDS

In June 2025, the New York Stock Exchange LLC (“NYSE”) proposed amendments to Section 302.00 (“Section 302.00”) of the NYSE Listed Company Manual, which would exempt certain 1940 Act registered closed-end funds (“CEFs”) from the requirement to hold annual shareholder meetings (the “NYSE Proposal”).

Under Section 302.00, companies listing common stock or voting preferred stock and their equivalents are required to hold annual shareholder meetings. Section 302.00 includes a list of the types of companies to which Section 302.00 does not apply – for example, companies whose only securities listed on NYSE are non-voting preferred and debt securities, passive business organizations, or issuers of securities listed pursuant to certain NYSE rules are not currently required to hold annual shareholder meetings. The NYSE Proposal would amend Section 302.00 to state that newly listed CEFs would also be exempt from the annual shareholder meeting requirements. Any CEF listed prior to the approval of the NYSE Proposal would remain subject to the annual shareholder meeting requirement. However, business development companies would still be required to comply with the shareholder meeting requirements.

In July 2024, the NYSE previously proposed to amend Section 302.00 to exempt all CEFs from the annual shareholder meeting requirement. The July 2024 proposal was later withdrawn by NYSE.

RIA CHARGED WITH CUSTODY RULE VIOLATIONS

In August 2025, the SEC announced that it had issued a cease-and-desist order against a registered investment adviser (the “RIA”), for violating Rule 206(4)-2 (the “Custody Rule”) under the Investment Advisers Act of 1940.

Under the Custody Rule, “it is a fraudulent, deceptive, or manipulative act, practice or course of business . . . for [a registered investment adviser] to have custody of client funds or securities unless” the adviser implements an enumerated set of requirements to prevent loss, misuse, or misappropriation of those funds and securities, including the following:

• Qualified Custodian: Client funds and securities must be maintained with a qualified custodian.
• Notice to Clients and Account Statements: RIAs must provide written notice to clients when an account has been opened on their behalf and have an articulable reasonable basis to believe the custodian sends quarterly account statements.
• Independent Verification: If an RIA has custody, client assets must be verified annually by an independent public accountant via a surprise examination conducted under a written agreement.

The SEC found that, while acting in his capacity as co-trustee of two trusts that were advisory clients, the RIA’s President had (i) access and authority to obtain possession of trust funds and securities without the consent of the respective co-trustees, (ii) signatory authority to the same degree as a beneficial owner on four clients’ accounts, and (iii) acted as an authorized agent with power of attorney on five clients’ accounts where he had the ability to place orders, request disbursements, and make inquiries concerning account balances.

Because of these actions and the level of access to client accounts, the RIA was required to obtain surprise examinations in accordance with the Custody Rule. However, it failed to do so. Without admitting or denying the findings, the RIA settled the action with the SEC and was required to pay a civil penalty of $50,000.

SEC FURTHER EXTENDS COMPLIANCE DEADLINE FOR FORM PF

In September 2025, the SEC and the Commodity Futures Trading Commission (“CFTC”) announced that the compliance date for the February 2024 amendments to Form PF would be once more pushed back.

As noted in our Second Quarter 2025 Update, the CFTC and SEC last extended the compliance date to October 1, 2025. The announcement further extended the compliance date to October 1, 2026 in an effort to allow time for the SEC to complete a substantive review of the amendments to Form PF in accordance with a Presidential Memorandum sent to federal agencies by the Trump administration.

Form PF is the confidential reporting form used by certain SEC-registered investment advisers to private funds, including those that also are registered with the CFTC as commodity pool operators or commodity trading advisers. According to the SEC, the amendments to are intended to enhance the quality and usefulness of Form PF data for both the SEC and the Financial Stability Oversight Council by improving data accuracy, more completely capturing information on fund ownership, size, strategies, and exposures, and streamlining certain reporting elements without compromising investor protection or systemic risk analysis.

The SEC has stated that the extension would allow for sufficient time to review the amendments and should implement any additional amendments to Form PF.

SEC APPROVES TXSE

On September 30, 2025, the SEC approved the Texas Stock Exchange (“TXSE”) as a national securities exchange, making TXSE the first fully integrated stock exchange to receive SEC approval in decades. TXSE is headquartered in Dallas, Texas and intends to launch trading, exchange traded products and corporate listings in 2026, with the stated goal of being a top competitor of the New York Stock Exchange and Nasdaq.

In June of 2024, TXSE Group Inc., the parent company of TXSE, announced that the exchange planned to launch with $120 million in backing from investment firms including BlackRock and Citadel. Support for the exchange follows opinions that Texas was a prime location for a new exchange given the favorable regulatory and taxation policies in the state.^[1] 

LEAKED SEC REGULATORY AGENDA

In August 2025, the Office of Information and Regulatory Affairs, part of the Office of Management and Budget, briefly published, and then removed, several agency regulatory agendas, including the SEC’s semiannual Regulatory Flexibility Agenda detailing the Commission’s rulemaking priorities for the upcoming six months. The inadvertent draft publication, that was later confirmed by a source as authentic, offers insight into the rulemaking priorities under the SEC’s new leadership. While agendas are nonbinding and SEC priorities may change, prioritization suggests a regulatory posture oriented toward burden reduction alongside targeted modernization for funds and their advisers and is notable for several items directly affecting registered funds, exchange traded funds, and private funds. Among other things, the SEC alluded to potential amendments to Form N‑PORT, revisions to Rule 17a‑7, updates to custody requirements (including for digital assets), renewed attention on transfer agents, and a reassessment of the Consolidated Audit Trail (“CAT”).  A few highlights from that agenda include:

• Amendments to Form N‑PORT: According to the release, the Commission is reviewing the upcoming change for filing frequency of Form N-PORT. In 2027, filers will be required to begin filing Form N-PORT monthly. However, this change may be amended to a quarterly cadence. Changes to data elements within N-PORT are also being considered.
• Amendments to Rule 17a‑7 under the Investment Company Act: The Commission is revisiting proposed amendments to Rule 17a-7, which grants exemptions to self-dealing transactions between registered investment companies and affiliated persons (also known as cross-trading). The hope of the industry is that this renewed interest leads to modernizations in the rule.
• Amendments to the custody rules: Although the initial publication of the SEC agenda made a vague reference to amendments to custody rules, a subsequent proposed rule by the SEC clarified that the Commission will focus on improving and modernizing the regulations around the custody of advisory client and fund assets, including crypto assets.
• Transfer agents (“TAs”): Although the agenda also signaled a renewed attention in transfer agent responsibilities as it pertains to distributed ledger technology and crypto assets, proposed rulemaking could have an effect on TAs writ-large and the funds they service.
• Consolidated Audit Trail: While in the prerule stage, the Commission is considering comprehensive reforms of CAT, including the scope of information collected, addressing ongoing cost and data security concerns, and supporting clearly defined regulatory objectives.
• Customer Identification Programs for RIAs and ERAs: In its final-rule stage, the Commission, along with the Department of the Treasury, is seeking to implement additional safeguards with respect to certain investment advisers that, among other things, requires investment advisers to implement reasonable procedures to verify the identities of their customers.

SEC STAFFING UPDATES

Margaret Ryan

Effective as of September 2, 2025, Judge Margaret Ryan was named the new Director of the Division of Enforcement of the SEC. Following the SEC’s announcement of Judge Ryan’s appointment, SEC Chairman Paul Atkins stated that “Judge Ryan will lead the Division guided by Congress’ original intent: enforcing the securities laws, particularly as they relate to fraud and manipulation.” Sam Waldon, the Acting Director of Enforcement, will return to his previous role as Chief Counsel for the Division of Enforcement.

Prior to this appointment, and since 2006, Judge Ryan has been a judge of the United States Court of Appeals for the Armed Forces, reaching senior status in 2020. Judge Ryan is also a lecturer and visiting professor at a handful of law schools, including Harvard and Notre Dame.

James Moloney

On September 10, 2025, the SEC announced that, effective in October of 2025, James Moloney will be named the Director of the Division of Corporation Finance. The Acting Director, Cicely LaMothe, will return to her role as a Deputy Director of the Division of Corporation Finance.

Moloney previously served at the SEC for six years from 1994 to 2000 as an attorney advisor and special counsel to the Office of Mergers & Acquisitions in the Division of Corporation Finance. For the last 25 years, Moloney has been at attorney at Gibson Dunn & Cutcher, making his way to equity partner. The Commission believes that Moloney’s understanding of corporate governance and disclosure, as well as his “eye toward supporting innovation and facilitating capital formation” will positively benefit the Division of Corporation Finance.

George Botic

Effective July 23, 2025, George Botic was designated to serve as the Acting Chair of the Public Company Accounting Oversight Board (“PCAOB”), following the resignation of the current PCAOB Chair, Erica Y. Williams, effective July 22, 2025. Botic is a Certified Public Accountant and has been a PCAOB board member since October of 2023. Additionally, prior to his tenue as a board member, Botic was the Director of the PCAOB’s Division of Registration and Inspections.

UPCOMING CONFERENCES

*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.

[1] See: https://www.cbsnews.com/texas/news/sec-approves-texas-stock-exchange-txse/.

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

As the end of the year approaches, investment adviser representatives (“IARs”)[1] licensed in Colorado should be aware of the continuing education requirements necessary to maintain their IAR registration ahead of the compliance deadline set for December 31, 2025.

Background

On March 30, 2023, the Colorado Division of Securities adopted continuing education requirements (“CE Requirements”) for IARs. Under the CE Requirements, all licensed IARs of either Colorado-licensed investment advisers or federally covered investment advisers must complete 12 credits of continuing education (each a “CE Credit”) per calendar year, even if the IAR’s home state has not adopted similar rules.

An IAR with a home state other than Colorado will be considered in compliance with Colorado’s continuing education requirements so long as:

• The IAR’s home state has adopted continuing education requirements that are at least as stringent as Colorado’s IAR CE Requirements, and
• The IAR is in compliance with his or her home state requirements.

Although the CE Requirements were intended to go into effect for the 2024 calendar year, the Division adjusted the initial compliance date to allow for IARs to achieve compliance for the 2024 and 2025 calendar years (by completing a total of 24 CE Credits) by December 31, 2025.

Any IAR that fails to timely complete these CE Requirements runs the risk of being ineligible to renew his or her IAR registration for the 2026 calendar year.

Continuing Education Credits

Of the 12 required CE Credits, six must be related to industry products and practice (“Products and Practice Requirement”) and six must be related to ethics and professional responsibility (“Ethics Requirement”). An IAR who is registered as an agent of a Financial Industry Regulatory Authority (“FINRA”) member broker-dealer, and who complies with FINRA’s continuing education requirements, will be considered to be in compliance with the IAR CE Products and Practice Requirement if the FINRA CE Content meets certain baseline criteria determined by North American Securities Administrators Association (“NASAA”). Otherwise, for courses to count toward the required 12 CE Credit requirement, the content must be approved by NASAA and be administered by an Authorized Provider.

IARs will be able to monitor their IAR CE through FINRA’s FinPro System, and can find out more by using this guide. A list of Authorized Providers may be found here.

For additional guidance or support, please reach out to a member of our Asset Management Group or another member of the Davis Graham Team.

[1] Under C.R.S. § 11-51-201(9.6), investment adviser representatives are defined as “individuals who have a place of business in this state; who is a partner, officer, or director of an investment adviser; who occupies a status similar to or performs functions similar to those of a partner, officer, or director for an investment adviser; or who is employed or otherwise associated with an investment adviser who: (I) Makes recommendations or otherwise renders advice to clients regarding securities; (II) Manages securities accounts or portfolios for clients; (III) Determines which recommendation or advice regarding securities should be given to clients; or (IV) Supervises employees of, or persons otherwise associated with, an investment adviser or a federal covered adviser who perform any of the duties specified in this paragraph (a).”