SB24-033

Summary

Bill 24-033 establishes that, for property tax years commencing on or after January 1, 2026, “short-term rental units” may be classified as either residential real property or lodging property. If, during the previous property tax year, a short-term rental unit was leased for “short-term stays” for more than 90 days, then it is classified as lodging property. The market approach shall be the sole method for determining the actual value of a short-term rental unit that is classified as lodging property. Notably, the property tax assessment rate in 2023 for residential properties was 6.765% and, in 2024, the assessment rate for lodging properties is 29%.

Legislative Updates

• 2024-04-16 / Failed
  Senate Committee on Finance Postpone Indefinitely
• 2024-01-10
  Introduced in Senate – Assigned to Finance

This content is updated every Thursday, but is not a comprehensive list of updates. If you have questions regarding a specific piece of legislation, please contact Davis Graham partner, Sarah Kellner.

SB24-024

Summary

Bill 24-024 requires local taxing jurisdictions for which the department of revenue does not administer local lodging taxes to apply the same local lodging tax standards or requirements to accommodations’ intermediaries and marketplace facilitators who are required to collect and remit local lodging taxes. The bill prohibits local taxing jurisdictions from requiring additional reporting information from an accommodation’s intermediary for purposes of local taxes, but, notably, does not prohibit local taxing jurisdictions from obtaining this information on a voluntary basis, and home rule municipalities may pass ordinances regulating these entities (including an ordinance governing the issuance of information or data) for purposes unrelated to local taxes. The bill declares that it is a matter of statewide concern to have uniform collection and remittance of local lodging taxes across local taxing jurisdictions, and to standardize reporting requirements.

Legislative Updates

• 2024-04-19 / Passed
  Governor Signed
• 2024-04-12
  Sent to the Governor
  Signed by the Speaker of the House
  Signed by the President of the Senate
• 2024-04-09
  Senate Considered House Amendments – Result was to Concur – Repass
• 2024-04-08
  House Third Reading Passed – No Amendments
• 2024-04-05
  House Second Reading Special Order – Passed with Amendments – Committee
• 2024-04-04
  House Committee on Finance Refer Amended to House Committee of the Whole
• 2024-02-22
  Introduced In House – Assigned to Finance
  Senate Third Reading Passed – No Amendments
• 2024-02-21
  Senate Second Reading Passed – No Amendments
• 2024-02-15
  Senate Committee on Finance Refer Amended – Consent Calendar to Senate Committee of the Whole
• 2024-02-08
  Senate Committee on Finance Witness Testimony and/or Committee Discussion Only
• 2024-01-30
  Senate Committee on Finance Witness Testimony and/or Committee Discussion Only
• 2024-01-10
  Introduced in Senate – Assigned to Finance

This content is updated every Thursday, but is not a comprehensive list of updates. If you have questions regarding a specific piece of legislation, please contact Davis Graham partner, Sarah Kellner.

Summary

SB24-021

Under current law, certain small communities are exempt from various requirements of the Colorado Common Interest Ownership Act (CCIOA), which governs the conduct of homeowners’ associations. SB24-021 would consolidate and amend the current exemptions, to state that a cooperative or planned community may avail itself of the exemption if: (1) a cooperative or planned community was created on or after July 1, 1992, and it either (i) contains only units restricted to nonresidential use or (ii) contains no more than 20 units and is not subject to any development rights; or (2) a planned community provides in its declaration that the annual average common expense liability of each unit restricted to residential purposes must not exceed $400, as adjusted annually since July 1, 1999, for changes in the Consumer Price Index. A cooperative or planned community that is eligible for the exemption may elect instead to be subject to CCIOA by adopting an amendment to its declaration evidencing such election.

Legislative Updates

• 2024-04-11 / Passed
  Governor Signed
• 2024-04-04
  Sent to the Governor
  Signed by the Speaker of the House
  Signed by the President of the Senate
• 2024-03-25
  House Third Reading Passed – No Amendments
• 2024-03-22
  House Second Reading Special Order – Passed – No Amendments
• 2024-03-19
  House Committee on Transportation, Housing & Local Government Refer Unamended to House Committee of the Whole
• 2024-02-08
  Introduced In House – Assigned to Transportation, Housing & Local Government
• 2024-02-05
  Senate Third Reading Passed – No Amendments
• 2024-02-02
  Senate Second Reading Passed with Amendments – Committee
• 2024-01-30
  Senate Committee on Local Government & Housing Refer Amended – Consent Calendar to Senate Committee of the Whole
• 2024-01-10
  Introduced In Senate – Assigned to Local Government & Housing

This content is updated every Thursday, but is not a comprehensive list of updates. If you have questions regarding a specific piece of legislation, please contact Davis Graham partner, Sarah Kellner.

On Monday, November 20, 2023, the Colorado Supreme Court issued a decision in which it declined to adopt a universal definition of “production” in Colorado oil and gas leases, instead holding that Colorado courts should interpret each oil and gas lease pursuant to its own terms.

In Bd. of County Comm’rs of Boulder County v. Crestone Peak Res. Operating LLC, 2023 Colo. LEXIS 1086 (Colo. Nov. 20, 2023), the Board of County Commissioners of Boulder County (“Boulder”) sought to invalidate two oil and gas leases with Crestone Peak Resources Operating LLC (“Crestone”). The leases contained a habendum clause that provided for a primary term of two years, and a secondary term for “as long thereafter as oil or gas, or either of them, is produced from said land . . . or the premises are being developed or operated.” Id. at 3-4, 6-7. In 2014, during the secondary term of the leases, a third party’s pipeline maintenance forced lessee to shut-in otherwise commercially viable wells for approximately four months. Boulder did not claim the leases had been terminated during the shut-in and continued to accept royalty payments, even throughout the course of the lawsuit. Id. at 10. In 2018, Boulder filed suit claiming that the 2014 shut-in constituted a cease in production which terminated the leases under the cessation-of-production clauses. Such clauses provide that if production “shall cease from any cause, [the] lease shall not terminate provided lessee resumes operations for reworking or drilling a well within [60 or 90] days from the cessation . . . .” Id.
at 7.

Crestone moved for summary judgment, arguing that under the cessation-in-production clauses, Crestone merely ceased marketing – not production – during the shut-in, such that the leases were never terminated. The District Court granted summary judgment and Boulder appealed. Relying on Davis v. Cramer, 837 P.2d 218 (Colo. App. 1992), the Court of Appeals adopted the “commercial discovery rule” which provides that the term “production” means “capable of producing oil or gas in commercial quantities.” Id. at 11. The Appeals Court determined that the leases had not terminated because “at all times relevant to the dispute, there remained a commercially viable discovery of oil and gas at the wells.” Id.
at 12.

The Colorado Supreme Court granted certiorari review of one issue: whether the Court of Appeals erred in adopting the “commercial discovery rule” in interpreting oil and gas leases. Id. at 12 n. 3. Boulder argued that the Court should instead apply an “actual production” rule and find that “production” requires “extraction.” Id.
at 20 n. 5. The Supreme Court rejected that argument, reasoning that the term “must be given meaning that is consistent with reality in the light of the circumstances which are commonly incident to oil and gas operations and which the parties must have contemplated.” Id. at 18 (citing 2 Eugene Kuntz, A Treatise of Oil and Gas § 26.6 (2022)). While the “commercial discovery rule” set forth in Davis v. Cramer is most applicable in determining whether there was sufficient production within the primary term to extend to the secondary term, once in the secondary term, the lessee has fulfilled its obligation and achieved the primary objective of the lease. Id. Courts should then exercise greater caution in terminating a lease to avoid depriving the lessee of its investment. Id. at 19-20. In considering whether the shut-in triggered termination under the cessation-of-production clauses, the Court held that the leases make clear that these clauses are triggered only when a cessation of production occurs that would be permanent without reworking or drilling. Id.
at 22. To require the lessee to engage in reworking or drilling operations under these circumstances would result in economic and environmental waste. Id. at 24. Accordingly, the 2014 shut-in did not trigger termination of the leases under the cessation of production clauses. Id. at 23-24. Thus, the Colorado Supreme Court upheld the judgment of the Court of Appeals under different reasoning.

Should you have questions about the content of this Legal Alert, please contact Stephanie Morr or Sam Niebrugge.

In the 2019 legislative session Colorado passed House Bill 19-1261, the Climate Action Plan to Reduce Pollution (“Climate Action Plan”), which includes targets for reducing statewide greenhouse gas pollution 26% by 2025, 50% by 2030, and 90% by 2050 from 2005 levels.[1]
To ensure that Colorado continues to make progress toward these targets, Governor Polis directed state agencies to develop a comprehensive Greenhouse Gas Pollution Reduction Roadmap (“GHG Roadmap”). The GHG Roadmap delivers a list of near-term actions the state will pursue over the next one to two years to make significant progress toward the 2025 and 2030 Climate Action Plan goals. The GHG Roadmap also analyzes further actions that can help put the state on a solid path to meeting the 2050 goal. A Version 2.0 of the GHG Roadmap is currently being prepared for release in draft in early 2024.

GHG Roadmap Ver. 1.0

The first GHG Emission Reduction Roadmap (Version 1.0) was prepared in draft in September of 2019 and finalized in January of 2020. Though primarily authored by Will Toor of the Colorado Energy Office and John Putnam of the Colorado Department of Public Health and Environment (“CDPHE”), it represents the work of many state agencies also including the Colorado Departments of Agriculture, Natural Resources, and Transportation. Additional support for the GHG Roadmap Ver. 1.0 was provided by the Department of Local Affairs, the Colorado Resiliency Office, and the Office of Just Transition. Colorado hired Energy + Environmental Economics (“E3”), a leading national consulting firm with expertise in GHG modeling, to develop a model of the state’s economy-wide emissions by sector. Technical staff from the Climate Change Unit at the CDPHE provided additional analysis of projected emissions reductions from near term policy recommendations.

The GHG Roadmap team constructed a Reference Case, which represents a projection of the state’s GHG emissions based on policies that were in place prior to 2019. The Reference Case assumes no new policies or actions to reduce emissions. That assessment found that the four largest emitting sectors were the same in 2020 as 2005. In 2020, transportation displaced electricity generation as the largest source of pollution. Electricity generation, oil and gas production, and fossil methane use in the residential, commercial, and industrial sectors remain the other three largest emitters.

While the state has made significant progress toward meeting the 2025 and 2030 goals, the analysis showed that additional actions are needed to reach the targets. E3 modeled an illustrative scenario, the HB 1261 Targets Scenario, to represent one approach Colorado could take to meet the Climate Action Plan targets through 2050. Based on these analyses, the GHG Roadmap proposes administrative, regulatory, legislative, procurement, incentive-based, and other measures to reduce emissions in different sectors of the state’s economy to achieve GHG pollution reductions in a cost effective and equitable way. The GHG Roadmap describes actions Colorado has taken to address climate change, analyzes the current trajectory for GHG emissions, and presents a suite of actions the state can pursue in the near term to make progress toward the Climate Action Plan goals.

The GHG Roadmap’s key findings for the state’s 2050 goals include:

• All sectors of Colorado’s economy will need to achieve reductions of 90-100%;
• The state’s 2 largest utilities will need to meet demand with zero-carbon electricity by 2050, with smaller utilities reducing GHG emissions by 80%;
• The transportation sector will need to be close to 100% electric vehicles (EVs) on the road by 2050;
• Achieving the 2050 goal will require further technical innovation such as green hydrogen, long duration energy storage, carbon capture and storage, and advanced biofuels;
• In the buildings sector full decarbonization by 2050 is based on a large-scale shift to the use of electric heat pumps, powered by zero carbon electricity, for space and water heating;
• Land conservation, restoration, and climate-adaptive ecosystem management will be critical
• for maintaining and enhancing resilient carbon sequestration on natural and working lands; and
• In agriculture, the development of markets that pay producers for ecosystem services may be an increasingly important tool.

Concerns of various commenters on GHG Roadmap 1.0 included that:

• It endorses large scale electrification and prescribes solutions 30 years into the future based on uncertain or non-existent technologies;
• It is aspirational, prescriptive, and inflexible rather than pursuing cost-effective measures in an iterative process;
• As a result, it vests greater power in electric utilities which simply pass costs on to consumers and stifle lower-cost outcomes that competition would encourage;
• It employs an accounting scheme that is fundamentally flawed;
• It relies on proprietary models of the State’s contractor, E3, the algorithms for which were not disclosed publicly; and
• It did not pursue a robust stakeholder and public participation process for such a transformational energy policy document.

GHG Roadmap Ver. 2.0

The state is now working to update the Greenhouse Gas Pollution Reduction Roadmap (“Roadmap 2.0”), including an updated inventory of emissions and a new set of Near-Term Actions that will guide implementation in the state. The State is soliciting written comments, holding open meetings and conducting sector roundtables in connection with the GHG Roadmap 2.0 update. The sector-specific roundtables concern topics including major sources of emissions in the transportation, electricity generation, oil and gas, industry, building energy use, land use and agriculture sectors. More information is available on the Colorado Energy Office website at: https://energyoffice.colorado.gov/climate-energy/ghg-pollution-reduction-roadmap-20.

Initial written comment on the planned GHG Roadmap Ver. 2.0 update was due by September 15, 2023. Among the concerns raise in initial public comment are:

• The need to prioritize feasibility and resource availability in Colorado’s Clean Energy Planning for 2040;
• The need to decarbonize Colorado’s electric grid before requiring or incentivizing widespread electrification of various sectors of the Colorado economy so as to avoid leakage and increased scope 2 emissions;
• Promoting the robust yet streamlined processes necessary to modernize permitting and siting of renewable energy generation and transmission projects on State lands;
• Including renewable natural gas (“RNG”) in the development of a circular clean energy economy in Colorado, in addition to proposed clean energy/battery recycling and waste stream measures identified;
• Facilitating the implementation of carbon dioxide removal (“CDR”) strategies including carbon capture, utilization and sequestration (“CCUS”) is essential for industry to reduce GHG emissions efficiently and cost-effectively, especially while awaiting the development of more renewables powering the grid;
• Rethinking proposed oil & gas sector strategies to avoid technology preferences being established in policy and regulations, and to also avoid unnecessarily combining GHG reduction and conventional air pollutant emissions mitigation strategies, as these are fundamentally different (global vs. local) and difficult to regulate together in a balanced way as recognized recently by the Colorado Air Quality Control Commission in the adoption of GEMM 2 rules last month;
• Developing a strategy for Urban Freight that is not exclusively based on electrification, especially for heavy-duty and long-haul vehicles; and
• Considering the unique needs of rural communities alongside actions that will benefit urban areas when developing Roadmap 2.0, especially with respect to possible strategies like expanded fare-free transit, since rural communities typically lack robust transit systems.

Preparation of GHG Roadmap 2.0 in draft for public comment is expected to occur by January of 2024. This policy document is crucial to the State’s approach to reducing emissions from all sectors of the state’s economy. As such, it is incumbent on industry, community and civic leaders and other stakeholders for each sector to be aware of the very significant likely consequences of the strategies to be adopted in GHG Roadmap 2.0. Once again, there is a lot of relevant information available on the Colorado Energy Office website at: https://energyoffice.colorado.gov/climate-energy/ghg-pollution-reduction-roadmap-20
, and may also be addressed and updated on the websites of other involved state agencies including CDPHE, CDOT (https://www.codot.gov/programs/research/pdfs/other-reports/colorado-greenhouse-gas-pollution-reduction-roadmap
), DNR and DOA.

[1] The 2050 target in the Climate Action Plan has since been modified from 90% to 100% by subsequent legislation, S.B. 23-016, concerning Greenhouse Gas Emission Reduction Measures, codified at C.R.S. § 25-7-102(g)(I)(F).

On Friday, October 20, 2023, the Colorado Department of Public Health & Environment (“CDPHE”), Air Quality Control Commission (“AQCC”) voted to adopt the Greenhouse Gas Emissions and Energy Management for Manufacturing Phase 2 Rule (“GEMM 2 Rule”) that implements key provisions of Colorado’s Environmental Justice Act (“EJ Act”)—HB 21-1266. The Colorado Legislature passed the EJ Act in July 2021 and one of its main provisions required that the state’s industrial and manufacturing sector reduce its greenhouse gas (“GHG”) emissions by 20% by the year 2030, as compared to the sector’s 2015 emissions. The final GEMM 2 Rule helps accomplish this goal by imposing strict mass based GHG reduction requirements on 18 industrial and manufacturing facilities within the state and imposing additional reduction requirements of harmful air pollutants for those facilities that are located within or less than one mile from a Disproportionately Impacted Community (“DIC”) and within 15 miles of a residential community.

A high-level summary of the GEMM 2 Rule and its most significant provisions is provided below.

Who is Affected by the GEMM 2 Rule?

The GEMM 2 Rule affects stationary sources in the industrial and manufacturing sector that emit greater than or equal to 25,000 metric tons (“mt”) of CO2 equivalent (“CO2e”) emissions per year. The rule also applies to any other manufacturing facilities that exist within Colorado as of the effective date of the rule and emit equal to or greater than 25,000 mt of CO2e in any year following the rule’s effective date.

While the GEMM 1 Rule passed in October 2021 limited GHG emissions from the state’s largest energy intensive and trade exposed industries in the industrial and manufacturing sector—namely four facilities in the cement and steel industries—the GEMM 2 Rule specifically identified 18 industrial and manufacturing facilities (“GEMM 2 Facilities”) as subject to the rule: American Gypsum Company LLC, Anheuser Busch Inc., Avago Technologies, Carestream Health, Inc., Cargill Meat Solutions, Front Range Energy, LLC, Golden Aluminum Inc., JBS Swift Beef Company, Leprino Foods, Microchip Technology, Molson Coors USA LLC, Natural Soda, LLC, Owen-Brockway Glass, Rocky Mountain Bottle Company, Sterling Ethanol, LLC, Suncor Energy USA, Western Sugar Cooperative, and Yuma Ethanol, LLC.

What Does the GEMM 2 Rule Require?

GEMM 2 Facilities are required to achieve facility-specific, onsite GHG reductions from their baseline emissions by implementing a portfolio of technically feasible and cost effective GHG reduction measures at their facilities. The GEMM 2 Rule’s cost effectiveness threshold was set at the 2030 social cost of GHGs—currently set at $89/ton. Such reduction measures may include equipment upgrades, efficiency improvements, the installation of additional controls, or onsite carbon capture, utilization and storage, among others.

CDPHE’s Air Pollution Control Division (“APCD”) first established each facility’s baseline emissions by using the higher of the facility’s reported 2021 or 2022 GHG emissions. In addition, facilities that demonstrated to the APCD that they had invested in capital projects that increased the facility’s production capacity between 2015 and 2030, but had not yet realized the additional production capacity, were eligible for a baseline adjustment equal to 75% of the facility’s increased production capacity, or 100% of the facility’s increased production capacity if the facility had already reduced its GHG emissions by 20% or greater.

The APCD then assigned tiered reduction requirements to the GEMM 2 Facilities based on the facilities’ GHG reductions since 2015 and their overall contribution to the group’s cumulative GHG emissions. Therefore, facilities that achieved significant GHG reductions since 2015 were assigned a lower 2030 reduction obligation than those facilities that achieved fewer GHG reductions, or increased their GHG emissions, since 2015. In addition, facilities with a high quantity of GHG emissions were assigned a greater 2030 reduction obligation than those facilities that emit a smaller quantity of GHGs. By considering these factors, the APCD sought to equitably distribute the GHG reduction requirements among the 18 GEMM 2 Facilities.

Depending on the facility’s assigned reduction requirement, the GEMM 2 Facilities must achieve an interim GHG reduction requirement of between 0 to 1.75% less than the facility’s baseline emissions beginning in 2024, and a final GHG reduction requirement of between 1 to 12.5% less than the facility’s baseline emissions by 2030. An additional GHG reduction of between 3 to 6% was assigned to certain facilities based on their percent contribution to the GEMM 2 Facilities’ cumulative total GHG emissions.

Finally, the GEMM 2 Rule requires facilities located within, or within one mile of, a DIC and within 15 miles of a residential community to prioritize onsite reductions of harmful air pollutants. As explained below, the amount of harmful air pollutant reductions is determined by the facility’s GHG Reduction Plan that must be submitted to the APCD by September 2025.

How does the Rule Work?

Beginning in 2024, GEMM 2 Facilities must secure their interim reduction requirement of between 0 to 1.75% and sustain this reduction through 2029.

Next, no later than September 20, 2025, GEMM 2 Facilities must develop and submit a GHG Reduction Plan to the APCD. The GHG Reduction Plan must include information on the facility’s emissions, a list of all GHG reduction measures that are technically feasible for implementation at the facility, and a portfolio of GHG reduction measures, the average cost of which is equivalent to the 2030 social cost of GHGs, that the facility is required to implement by 2030 to help the facility achieve its 2030 final GHG reduction requirement. The GHG Reduction Plan must also identify the estimated reduction of harmful air pollutants associated with the GHG reduction measures identified in the plan.

If a facility proposes to implement a technically feasible and cost-effective portfolio of GHG reduction measures, but the proposed measures do not achieve the facility’s 2030 GHG reduction requirement, the facility may purchase GHG credits for compliance. However, if the facility is located within one mile of a DIC and within 15 miles of a residential community, the facility must first identify the harmful air pollutant reductions associated with the GHG measures in its GHG Reduction Plan, up to 50% above the 2030 social cost of GHGs, and secure the harmful air pollutant reductions associated with these measures at the facility before they can participate in the GHG credit trading market.

To generate GHG credits, GEMM 2 Facilities must reduce their GHG emissions beyond their 2030 GHG reduction requirement. These GHG credits, which expire after 3 years, can then be traded among the GEMM 2 Facilities to help the facilities with few available onsite GHG reduction measures to comply with their 2024 and 2030 reduction requirements. No facility is required to place their GHG credits into the market, and individual GEMM 2 Facilities may enter into private GHG credit transactions at any time. Furthermore, the APCD will host an annual GHG credit auction whereby GEMM 2 Facilities can submit offers for sale and bids for GHG credits to the APCD.

Finally, if a facility cannot achieve its interim or 2030 GHG reduction requirement by implementing onsite GHG reduction measures, and there are not enough credits available in the GHG credit market to allow the facility to purchase credits to achieve its reduction requirement, the GEMM 2 Facility can pay into a state-managed GHG reduction fund, on a per metric ton of CO2e basis, up to the amount required to achieve the facility’s GHG reduction requirement for that year. The GHG reduction fund will then be used by the state to finance GHG reduction projects at other industrial and manufacturing sites, or finance otherwise cost-prohibitive onsite reduction measures at GEMM 2 Facilities. While the GHG reduction fund is not currently available, the APCD must propose establishment of the fund by September 2025, and implement the fund via rulemaking by the end of 2025.

By 2030, GEMM 2 Facilities must achieve their remaining GHG reduction requirement and sustain that reduction in perpetuity.

Compliance and Enforcement

GEMM 2 Facilities must demonstrate compliance with their annual GHG reduction requirements during two separate compliance periods. GEMM 2 Facilities must demonstrate compliance for the first compliance period—2024, 2025, and 2026—in 2027 by aggregating the facility’s annual GHG reduction requirement in each of those years and demonstrating to the APCD that the facility secured the reductions by the end of 2026. Next, GEMM 2 Facilities must demonstrate compliance for the second compliance period—2027, 2028, and 2029—in 2030 by the same method. Finally, beginning in September 2031, GEMM 2 Facilities must submit an annual report to the APCD that demonstrates compliance with the facility’s 2030 reduction requirement every year thereafter.

If a facility fails to demonstrate compliance in any compliance period, the facility’s annual GHG reduction requirement will be adjusted downwards by at least two times the amount, in mt of CO2e, by which the facility exceeded its aggregated GHG emission reduction requirement in either compliance period, or in any year after 2029. The GEMM 2 Facility must secure this additional “mitigation” reduction no later than three years after the compliance period or year of noncompliance.

In addition, the APCD maintains all the enforcement mechanisms available to it under the Colorado Air Pollution Prevention and Control Act, including the assessment of daily civil penalties.

Conclusion

The GEMM 2 Rule is the first regulation of its kind in the United States. While it is complex, the APCD anticipates that the GEMM 2 Rule’s 2024 interim reduction requirements will result in a 12% reduction in GHG emissions from the GEMM 2 Facilities by 2024. In addition, the APCD anticipates that the remaining reduction requirements will reduce the GEMM 2 Facilities’ GHG emissions by 20% by 2030. Accordingly, the GEMM 2 Rule will assist the state in achieving the EJ Act’s goal of reducing the state’s industrial and manufacturing sector GHG emissions by 20% by the year 2030 and help Colorado to cement itself as a national leader in climate and sustainability regulations.

If you would like to learn more about Colorado’s GEMM 2 Rule or discuss it in more detail, please contact John Jacus or Cole Killion.

Effective October 15, 2023, Colorado’s Air Quality Commission (the “Commission”) approved Regulation 28, titled “Building Benchmarking and Performance Standards,” which requires “covered building” owners to meet certain energy use targets or implement greenhouse gas emissions reductions to increase efficiency, as part of Colorado’s broader plan to reduce emissions by 50% prior to 2030.[1]  A ”covered building” under Regulation 28 includes any residential or commercial building over 50,000 square feet. This regulation impacts approximately 8,000 buildings in Colorado.

Regulation 28 does not apply to storage facilities, stand-alone parking garages, buildings in which over half of the gross floor area is used for manufacturing, industrial, or agricultural purposes, or single-family homes, duplexes, or triplexes.[2] The applicability of Regulation 28 to owners of public buildings, which includes those owned by a governmental entity and educational institutions, is limited.

Regulation Requirements

Covered building owners must report benchmarking data for the previous calendar year to the Colorado Energy Office (“CEO”) and pay an annual fee to the CEO of $100 per covered building, which payment does not apply to owners of public buildings.[3] The annual report must specify the owner’s plan to reduce the building’s greenhouse gas emissions in order to achieve Colorado’s 2026 target to reduce emissions by 7%.[4] In 2028, each annual report must address the owner’s plan to meet the 2030 target to reduce emissions by 20%.[5] Owners may apply to the CEO for a waiver, extension of the deadline, or an exemption from these reporting requirements.

Pathways to Compliance

In order to meet these emissions targets, owners must reduce the building’s greenhouse gas emissions through the following compliance pathways, which may be combined, providing some flexibility to owners:

1. Owners may implement energy efficiency measures and technologies to meet the property type weather-normalized site Energy Use Intensity (“EUI”) requirements set forth in Table I to Regulation 28.[6] If a covered building owner is unable to achieve the site EUI target, they may comply by maintaining a standard percent reduction in their covered building’s weather-normalized site EUI as compared to the covered building’s 2021 benchmark.[7]
2. If the owner is unable to meet the EUI targets, the owner may implement high-efficiency electric equipment and replace fossil fuel equipment to decrease the building’s greenhouse gas emissions.[8] An owner may also use customer-owned generation systems or utility subscription services to reduce their emissions.

Regulation 28 provides owners flexibility in what efficiency measures are utilized, including (1) converting natural gas equipment to electric space and water heating, (2) adding LED lighting and timer lights, (3) increasing insulation, (4) thickening walls, (5) replacing windows and doors, and (6) installing high-efficiency appliances. Owners may also enroll in utility-offered programs or purchase renewable energy credits.[9] However, if an owner is unable to meet the 2026 or 2030 building performance standards by implementing these measures, the owner should request an adjustment to the timeline for these emissions targets.

Regulation 28 further requires owners to maintain records related to the building’s compliance pathway and performance standards for seven years for the CEO to review upon request.[10]

Requests for Adjustments

If necessary, owners may request an adjustment from the CEO by demonstrating the owner’s plan to achieve the performance targets within the proposed adjusted timeline, as well as measures the owner has already taken to reach that goal (including submitting purchase orders for new equipment, documentation demonstrating supply chain delays, or documentation demonstrating collaboration with the building’s utilities to update the infrastructure).[11]

Owners of under-resourced buildings may also apply for an adjusted timeline from the CEO. The application must include (1) each year of benchmarking data up to the current date, (2) a narrative detailing the building characteristic or functional variations that qualify it for the adjustment, such as age of construction or historical status, (3) an inventory of the natural gas equipment in the building, (4) documentation of operation and maintenance improvements, and (5) documentation of collaboration with the building’s utilities to determine the feasibility of electrification.[12]

All requests for an adjusted timeline are due by December 31, 2025, for the 2026 target and December 31, 2029, for the 2030 target.

Penalties for Non-Compliance

Beginning June 1, 2024, penalties for failure to submit the benchmarking report include a fine of up to $500 for the first violation and $2,000 for each subsequent violation. An owner whose building fails to meet the performance standards is subject to a civil penalty of up to $2,000 for the first violation and up to $5,000 for each subsequent violation.[13] Each month that an owner fails to demonstrate compliance with the building performance standards or fails to demonstrate progress towards meeting the standards constitutes an independent violation.

Real Estate Industry Opposition.

Commercial real estate owners vehemently opposed Regulation 28, objecting to the unfair burden the retroactive application of these standards will have on existing buildings and further arguing that they are already experiencing significant financial stress due to high vacancy rates, rising foreclosures, stagnant demand, declining lease rates, rising interest rates, and ongoing supply chain problems.[14] BOMA estimates that the cost of compliance with Regulation 28 will exceed $3.1 billion.

[1] GHG Pollution Reduction Roadmap 2.0., https://energyoffice.colorado.gov/climate-energy/ghg-pollution-reduction-roadmap-20

[2] Section A.III.O.

[3] Sections A.IV.A, B.I.

[4] Section B.I.A.1.

[5] Section B.I.A.2.

[6] Section C.I.A.1.

[7] Section C.I.A.3.a.

[8] Section C.I.B.1.

[9] Section C.I.B.1.e.

[10] Section D.I.

[11] Section C.II.A.

[12] Section C.II.C.1.

[13] Sections E.1 and E.2.

[14] Colorado Real Estate Alliance & Regulation 28, Fact Sheet.

On November 3, 2023, the United States Forest Service announced a proposed amendment to its special use regulations at 36 C.F.R. part 251 to allow the Forest Service to review and process applications for carbon capture and storage beneath National Forest System Lands.

The Forest Service’s special use regulations set forth screening criteria that a proponent for a special use permit must meet. An existing screening criterion at 36 C.F.R. § 251.54(e)(1)(iv) does not allow the Forest Service to authorize exclusive and perpetual use and occupancy of National Forest System lands for any purpose. The proposed rule would create an express exception to this prohibition by stating that “the Forest Service may authorize exclusive and perpetual use and occupancy for carbon capture and storage in subsurface pore spaces.”

The proposed rule would also define “carbon capture and storage” as “the capture, transportation, injection, and storage of carbon dioxide in subsurface pore spaces in such a manner as to qualify the carbon dioxide stream for the exclusion from classification as a ‘hazardous waste’ pursuant to United States Environmental Protection Agency regulations at 40 CFR 261.4(h).” This definition would specify that carbon capture and storage does not constitute a hazardous waste and therefore is not subject to the prohibition against authorizing storage of hazardous substances on National Forest System lands at 36 C.F.R. § 251.54(e)(1)(ix).

The proposed rule would not affect the U.S. Environmental Protection Agency’s authority to regulate and permit the underground injection and storage of carbon through its Class VI Underground Injection Control program.

The Forest Service is accepting public comment on the proposed rule through January 2, 2024. Procedures for commenting are outlined in the Federal Register notice.

The Corporate Transparency Act (the “CTA”) was enacted on January 1, 2021[1] in an effort by Congress to prevent and combat money laundering, terrorist financing, tax fraud, and other illicit activities by imposing new disclosure requirements on certain companies formed or doing business in the U.S. On September 29, 2022, the U.S. Treasury Department’s Financial Crimes Enforcement Network (“FinCEN”) issued final regulations to implement Section 6403 of the CTA (the “Final CTA Rules”)[1]. Under the Final CTA Rules, certain entities—referred to as “reporting companies”—will be required to submit specified information about the reporting company, its beneficial owners and company applicants to FinCEN.

Below is a high-level overview of the key provisions and implications of the Final CTA Rules. For further details and legal counsel, please do not hesitate to contact a Davis Graham Partner.

What is a “reporting company”?

A “reporting company” includes (i) any corporation, limited liability company, and any other form of entity created by filing with a secretary of state or similar office under the laws of a state or Indian tribe (referred to as “domestic reporting companies”), and (ii) any corporation, limited liability company, and any other form of entity created under the laws of a foreign country and registered to conduct business in the U.S. or tribal jurisdiction (referred to as “foreign reporting companies”).

What entities are outside of the definition of “reporting company”?

To fall under the definition of a “reporting company,” the entity must have been created or qualified to do business by the filing of a document with a secretary of state or similar official. Accordingly, sole proprietorships, common law trusts, and general partnerships do not currently fall under the definition of “reporting company.” Trusts that are created by a filing, such as statutory or business trusts, however, will be subject to the CTA reporting requirements.

The Final CTA Rules provide 23 categories of exemptions from the “reporting company” definition, including public companies, large operating companies, subsidiaries of certain other exempt entities, inactive entities, pooled investment vehicles, and nonprofit organizations. See the Appendix attached hereto for a summary of each of the 23 exemptions.

Note that the applicability of an exemption will be an ongoing determination—if an entity no longer qualifies under an exemption, it will become a reporting company and be required to promptly file a report.

If my entity is a “reporting company,” what information is required to be submitted to FinCEN?

Each reporting company will be required to report the following for itself: (i) full legal name; (ii) trade name or DBA; (iii) street address of principal place of business or, for a foreign reporting company, its primary location in the U.S.; (iv) jurisdiction of formation and, for a foreign reporting company, the state or tribal jurisdiction in which it is registered; and (v) tax identification number or, for a foreign reporting company that doesn’t have a tax identification number, other unique tax ID number.

Reporting companies will be required to report the following for each individual that is a beneficial owner or company applicant with respect to such reporting company: (i) full legal name; (ii) date of birth; (iii) current residential or, for company applicants, business street address; (iv) unique identifying number from an acceptable identification document (e.g., a non-expired passport or driver’s license) or FinCEN identifier; and (v) an image of the document from which the identifying number was obtained.

Who qualifies as a “beneficial owner”?

A beneficial owner is any individual that, directly or indirectly, either:

• owns or controls at least 25% of the total ownership interests of the reporting company, calculated as they stand at the time of the calculation and on a fully diluted basis, or
• exercises substantial control over the reporting company.

An individual is deemed to have “substantial control” if such individual (i) serves as a senior officer of the reporting company; (ii) has authority over the appointment or removal of any senior officer or a majority of the board of directors; (iii) directs, determines or has substantial influence over, important decisions made by the reporting company; or (iv) exerts similar control.

The Final CTA Rules also describe five types of individuals that are exempt from the definition of “beneficial owner.” Note that there is no limit on the number of beneficial owners a reporting entity might have.

Who is a “company applicant”?

A company applicant is the individual directly responsible for creating or registering the reporting company, and, if different, the individual who is primarily responsible for directing or controlling the filing. Each reporting company formed after January 1, 2024 will have at least one, but not more than two, company applicants.

What are the deadlines for submitting reports?

• Existing Companies – Reporting companies created before January 1, 2024 must file their initial reports by January 1, 2025. Note that reporting companies formed prior to January 1, 2024 do not need to report information about company applicants.
• Companies formed after January 1, 2024 – Reporting companies created after January 1, 2024 must file their initial reports by the earlier of: (i) 30 calendar days[2] of the date the reporting company receives actual notice of its creation or registration, and (ii) the date on which the secretary of state or similar office provides public notice of the reporting company’s existence or registration.
• Entities that no longer qualify for an exemption – Entities that were once exempt but that no longer qualify for any exemptions must file their initial reports within 30 calendar days after the date that they no longer meet the criteria for any exemptions.
• Updates and Corrections – If there are changes or inaccuracies in previously reported information, the reporting company must file an updated report to FinCEN no later than 30 days after it becomes aware of the change or of the inaccuracy.

What are the penalties for non-compliance?

The Final CTA Rules impose penalties for willful violations by individuals and entities. Such violations include willfully reporting or attempting to report false or fraudulent information to FinCEN or willfully failing to complete or update reports to FinCEN. Each violation is subject to penalties of $500 per day up to $10,000 per violation, and possible jail time (up to two years).

How do reporting companies file reports and who will have access to the submitted reports?

Reporting companies will need to file their reports through a secure filing system on FinCEN’s website, which will be available on January 1, 2024.

FinCEN is mandated to maintain reported information confidentially, accessible only to select federal, state, or foreign agencies for investigative and enforcement purposes, as well as financial institutions requesting this information to facilitate compliance with customer due diligence regulations, with the consent of the reporting company.

[1] FinCEN Issues Final Rule for Beneficial Ownership Reporting to Support Law Enforcement Efforts, Counter Illicit Finance, and Increase Transparency (Adopting Release)

[2] On September 28, 2023, FinCEN issued a Notice of Proposed Rulemaking that would extend this filing deadline for reporting companies created or registered on or after January 1, 2024 but prior to January 1, 2025. Those entities would have 90 days following notice of the reporting company’s creation or registration to submit its initial report. The 30-day timeline would continue to apply to reporting companies formed on or after January 1, 2025.

APPENDIX – SUMMARY OF EXEMPTIONS FROM THE “REPORTING COMPANY” DEFINITION

1. Securities reporting issuer: Any entity that is (i) an issuer of a class of securities registered under Section 12 of the Securities Exchange Act of 1934 (the “Exchange Act”) or (ii) required to file supplementary and periodic reports under Section 15(d) of the Exchange Act.
2. Governmental authority: Any entity that (i) is established under the laws of the United States, an Indian tribe, a state, or a political subdivision of a state, or under an interstate compact between two or more states and (ii) exercises governmental authority on behalf of the US or any such Indian tribe, state, or political subdivision.
3. Bank: Any bank, as defined in Section 3 of the Federal Deposit Insurance Act, Section 2(a) of the Investment Company Act of 1940 (the “1940 Act”), or Section 202(a) of the Investment Advisers Act of 1940 (the “IAA”).
4. Credit union: Any federal credit union or state credit union, as defined in Section 101 of the Federal Credit Union Act.
5. Depository institution holding company: Any (i) bank holding company, as defined in Section 2 of the Bank Holding Company Act of 1956, or (ii) savings and loan holding company, as defined in Section 10(a) of the Home Owners’ Loan Act.
6. Money services business: Any money transmitting business or money services business registered with FinCEN under 31 U.S.C. 5330 or 31 CFR 1022.380, respectively.
7. Broker or dealer in securities: Any broker or dealer as defined Section 3 of the Exchange Act that is registered under Section 15 of the Exchange Act.
8. Securities exchange or clearing agency: Any exchange or clearing agency as defined in Section 3 of the Exchange Act that is registered under Sections 6 or 17A of the Exchange Act.
9. Other Exchange Act-registered entity: Any other entity not described in exemptions 1, 7 or 8 that is registered with the Securities and Exchange Commission (the “SEC”) under the Exchange Act.
10. Investment company or investment adviser: Any entity that is (i) an investment company as defined in Section 3 of the 1940 Act or an investment adviser as defined in Section 202 of the IAA, and (ii) registered with the SEC under the 1940 Act or the IAA.
11. Venture capital fund adviser: Any investment adviser that (i) is described in Section 203(l) of the IAA and (ii) has filed Item 10, Schedule A, and Schedule B of Part 1A of Form ADV, or any successor thereto, with the SEC.
12. Insurance company: Any insurance company, as defined in Section 2 of the 1940 Act.
13. State-licensed insurance producer: Any entity that (i) is an insurance producer that is authorized by a state and subject to supervision by the insurance commissioner or a similar official or agency of a state and (ii) has an operating presence at a physical office within the United States.
14. Commodity Exchange Act-registered entity: Any entity that is (a) a registered entity, as defined in Section 1a of the Commodity Exchange Act (the “Commodity Act”), or (b) (i) a futures commission merchant, introducing broker, swap dealer, major swap participant, commodity pool operator, or commodity trading advisor, as defined in Section 1a of the Commodity Act, or a retail foreign exchange dealer, as described in Section 2(c)(2)(B) of the Commodity Act, and (ii) registered with the Commodity Futures Trading Commission under the Commodity Act.
15. Accounting firm: Any public accounting firm registered in accordance with Section 102 of the Sarbanes-Oxley Act of 2002.
16. Public utility: Any entity that is a regulated public utility, as defined in Section 7701(a)(33)(A) of the Internal Revenue Code of 1986 (the “Code”), that provides telecommunications services, electrical power, natural gas, or water and sewer services within the United States.
17. Financial market utility: Any financial market utility designated by the Financial Stability Oversight Council under Section 804 of the Payment, Clearing, and Settlement Supervision Act of 2010.
18. Pooled investment vehicle: Any pooled investment vehicle that is operated or advised by a person described in exemptions 3, 4, 7, 10 or 11.
19. Tax-exempt entity: Any entity that is (i) an organization that is described in Section 501(c) of the Code (determined without regard to Section 508(a) of the Code) and exempt from tax under Section 501(a) of the Code (with a 180 day grace period if an organization ceases to meet the foregoing parameters), (ii) a political organization, as defined in Section 527(e)(1) of the Code, that is exempt from tax under Section 527 of the Code or (iii) a charitable trust or split-interest trust, as described in paragraph (1) or (2) of Section 4947(a) of the Code.
20. Entity assisting a tax-exempt entity: Any entity that (i) operates exclusively to provide financial assistance to, or hold governance rights over, any entity described in exemption 19, (ii) is a United States person, (iii) is beneficially owned or controlled exclusively by one or more United States persons that are United States citizens or permanent residents and (iv) derives at least a majority of its funding or revenue from one or more United States persons that are United States citizens or permanent residents.
21. Large operating company: Any entity that (i) employs more than 20 full time employees in the United States, (ii) has an operating presence at a physical office within the United States and (iii) filed a federal income tax or information return in the United States for the previous year demonstrating more than $5,000,000 in gross receipts or sales, as reported as gross receipts or sales (net of returns and allowances) on the entity’s income tax return (excluding gross receipts or sales from sources outside of the United States), which for an entity that is part of an affiliated group of corporations within the meaning of 26 U.S.C. 1504 that filed a consolidated return shall be the amount reported on the consolidated return for such group.
22. Subsidiary of certain exempt entities: Any entity whose ownership interests are controlled or wholly owned, directly or indirectly, by one or more entities described in exemptions 1 through 5, 7 through 17, 19, or 21.
23. Inactive entity: Any entity that (i) was in existence on or before January 1, 2020, (ii) is not engaged in active business, (iii) is not directly or indirectly owned in whole or in part by a foreign person, (iv) has not experienced any change in ownership in the preceding 12-month period, (v) has not sent or received any funds in an amount greater than $1,000, either directly or through any financial account in which the entity or any affiliate of the entity had an interest, in the preceding 12-month period and (vi) does not otherwise hold any kind or type of assets, whether in the United States or abroad, including any ownership interest in any corporation, LLC or other similar entity.

This is the third in a three-part series discussing the new and amended rules (collectively the “Rules”) adopted by the Colorado Division of Securities (“Division”) effective as of March 30, 2023 (the “Effective Date”). The series discusses the new and amended rules under the Colorado Securities Act (the “Colorado Act”) applicable to certain Colorado investment advisers and their registered representatives (“IARs”). Part 3 reviews the Division’s amendments to the requirements of advisory contracts under Rule 51-4.8(IA)(P)[1], mandatory disclosures related to Form ADV Part 2 under Rule 51-4.7(IA) (the “Mandatory Disclosure Rule”), and maintenance of books and records under Rule 51-4.6(IA) (the “Books and Records Rule”) (collectively the “Amended Rules”) and provides best practices and compliance recommendations.

Part 1 of this three-part series focused on the new Continuing Education Rule and offered practical guidance to advisers and their IARs for meeting the new requirements. Part 2 provided a comprehensive analysis of the Compliance Rule, and offered concrete recommendations to investment advisers registered with the State of Colorado (such advisers, “Colorado Licensed Advisers”) for their compliance programs.

Requirements of Advisory Contracts

Rule 51-4.8(IA)(P) was amended to clarify the information that an adviser must disclose in its advisory contracts with its clients. The amendment removes previous language embedded in the Rule that required advisory contacts or alternative disclosure documents to contain “the information required by Form ADV Part 2.” Form ADV is the uniform form used by investment advisers to register with both the U.S. Securities and Exchange Commission (the “SEC”) and state securities authorities. The form consists of three parts, Part 1, Part 2, and Part 3. Form ADV Part 2 serves as the primary disclosure document for advisers and sets forth requirements for narrative disclosures about the investment advisory firm and the business practices of its principals, fees, conflicts of interest, and disciplinary information.[2]

In its Cost-Benefit Analysis of the proposed rule changes, the Division acknowledged that Form ADV Part 2 provides more detailed information and disclosures than what is typically material in an advisory contract.[3]
The Division further explained its removal of the provision should make it clear that material terms of an advisory contract should be in contained within the contract itself and should include terms consistent with but not necessarily identical to those disclosed in Form ADV Part 2. Accordingly, under amended subsection (P) of Rule 51-4.8(IA), an advisory contract must be in writing and must disclose or address the following components: (1) the services to be provided, (2) the term of the contract, (3) the advisory fee, (4) the formula for computing the fee, 5) the amount of prepaid fees to be returned in the event of contract termination or non-performance, (6) whether the contract grants discretionary power to the adviser, and (7) a non-assignment provision in favor of the client.

Mandatory Disclosures Related To Form ADV Part 2

The Division adopted changes to Rule 51-4.7(IA) to clarify mandatory disclosures and the delivery to clients of an updated Part 2 of an adviser’s Form ADV. Form ADV Part 2 is divided into Part 2A and Part 2B and sets forth the information required in “client brochures” and “brochure supplements.” Under the “Mandatory Disclosure Rule,” an investment adviser and its investment adviser representative are obligated to furnish each advisory client and prospective advisory client with a copy of Part 2 of the investment adviser’s Form ADV. The Division’s amendments add language regarding the annual delivery of Part 2: advisers must deliver within 120 days of their fiscal year-end, an updated Form ADV Part 2 “disclosure statement” or a summary of material changes to the investment adviser’s Form ADV Part 2 that includes an offer to provide a copy of the updated Form ADV Part 2.

Amendments With Respect To Maintaining Books And Records Under Rule 51-4.6(IA)

The Division adopted changes to Rule 51-4.6(IA), the Books and Records Rule, which requires advisers to keep and maintain certain books and records relating to their investment advisory business. Rule 51-4.6(IA) subsection (3) was amended to require investment advisers to provide and keep additional information on their memorandum of trade orders (or trade blotters). Rule 51-4.6(IA) subsection (5) was amended to require firms to maintain copies of “invoices” in addition to bills and other financial statements. In addition, new recordkeeping obligations added to the Books and Records include Rule 51-4.6(IA)(7), which was amended to expand the records requirement of firms to all written communications relating to the business of the investment adviser and Rule 51-4.6(IA)(16), which was added to require advisers to maintain a written summary of all oral complaints in addition to the current requirement to maintain written communications concerning litigation and customer complaints. Advisers will thus be required to take the time to memorialize verbal complaints.

Takeaways for Amended Rules

• Consider the Scope and Applicability of the New and Amended Division Rules: Investment advisers licensed with the State of Colorado should bear in mind the scope and applicability of the Amended Rules, particularly with respect to Form ADV Part 2.

• Review and Update All Advisory Contracts: Colorado Licensed Advisers should consider providing addendums or supplements to advisory contracts that no longer meet the new requirements of Rule 51-4.8(IA)(P). Advisers should also consider reviewing their contracts on a recurring basis to seek to ensure those agreements are compliant with the Division’s regulatory requirements, reflect the adviser’s current business model, and are, most critically, consistent with the practices and fee structures disclosed in other advisory documents, such as Form ADV Part 2A and the adviser’s marketing materials.
• Review Recordkeeping Practices: Colorado Licensed Advisers should also consider whether their recordkeeping practices are consonant with the requirements of the amended Rule. As part of this determination, a Colorado Licensed Adviser should also consider whether (and to what extent) they are sufficiently positioned to promptly provide the firm’s books and records to the Division, preferably in an electronic format, if requested.

Conclusion

The topics highlighted in Parts 1 & 2 of this series (and other regulatory elements that were also part of the recent amendments) deserve attention by all investment advisers whose operations relate in some way to the state of Colorado. These new amendments will investment advisers differently.

Should you have a question about the contents of this article please contact Peter Schwartz, Martine Ventello, or any other member of the Davis Graham Asset Management team.

[1]
Section (P) falls under the larger umbrella of Division Rule 51-4.8(IA), which is a catch-all rule governing investment advisers’ dishonest or ethical conduct.

[2]
General Instructions for Part 2 of Form ADV are available at https://www.sec.gov/about/forms/formadv-part2.pdf

[3]
See the Division’s Cost-Benefit Analysis associated with these Amended Rules here: https://drive.google.com/file/d/1exIuxL_-wT4wYSKdRd6pqaikL5W80sLE/view