2023 Colorado Revised Statutes › Title 25 - PUBLIC HEALTH AND ENVIRONMENT (§§ 25-1-101 — 25-59-106) › ENVIRONMENTAL CONTROL (§§ 25-6.5-101 — 25-18.9-105) › Article 7 - AIR QUALITY CONTROL (§§ 25-7-101 — 25-7-1604) › Part 1 - AIR QUALITY CONTROL PROGRAM (§§ 25-7-101 — 25-7-147) › Section 25-7-105 - Duties of commission - technical secretary - rules - report - legislative declaration - definitions - repeal

(1)
Except as provided in sections
25-7-130
and
25-7-131
, the commission shall promulgate rules that are consistent with the legislative declaration set forth in section
25-7-102
and necessary for the proper implementation and administration of this article 7, including:
(a)
(I)
A comprehensive state implementation plan which will assure attainment and maintenance of national ambient air quality standards and which will prevent significant deterioration of air quality, all in conformity with the provisions of this article. The comprehensive plan shall meet all requirements of the federal act and shall be revised whenever necessary or appropriate.
(II)
The comprehensive state implementation plan of the commission shall, wherever feasible, include local or regional air pollution plans and programs adopted or enforceable by municipal or county governments. Before making any changes to those portions of the state implementation plan which include such air pollution plans and programs or to such plans and programs which are suggested for inclusion in the state implementation plan, the commission shall give thirty days' notice of the proposed changes to the affected municipal or county government to allow a reasonable opportunity to prepare comments on the proposed changes. The commission shall consider such comments in its action on the state implementation plan and shall document in the record of the hearing its reasons for any changes to such plans and programs. Any such plans and programs which are approved by the commission and formally submitted as a part of the state implementation plan shall be deemed a part of the comprehensive program of the commission and shall be enforced as such.
(III)
The revisions to the Denver element of the PM-10 state implementation plan adopted by the commission on February 16, 1995, which contain a sixty tons-per-day PM-10 mobile source emissions budget which expires January 1, 1998, and reverts to a forty-four tons-per-day budget, are amended to provide that such forty-four tons-per-day reversion shall not be a part of the state implementation plan and shall only apply as a regulation adopted exclusively under reserved state authority pursuant to the provisions of section
25-7-105.1
. The sixty tons-per-day emissions budget shall, unless modified by the commission through rule-making, apply for federal transportation conformity and is included in the state implementation plan only as required by the federal act. Any entity with authority to adopt a transportation plan required under section
43-1-1103
, C.R.S., shall consider any mobile source emissions budgets in effect under this article in the development of transportation improvement programs for federal purposes.
(IV)
Notwithstanding the provisions of section
25-7-133
, the expiration of the state implementation plan for ozone maintenance and related rules of the air quality control commission, and the amendments to commission regulations numbers 3 and 7, which state implementation plan and rules, and amendments to regulations numbers 3 and 7, were adopted or amended by the commission on March 21, 1996, and which are therefore scheduled for expiration May 15, 1997, is postponed until December 31, 2005.
(b)
Emission control regulations in conformity with section
25-7-109
;
(c)
A prevention of significant deterioration program in conformity with part 2 of this article and federal requirements; except that definitions used in the program shall not differ from any definitions pertaining to the prevention of significant deterioration program which appear in section 169 of the federal act or in federal regulations promulgated thereunder, and an attainment program in conformity with part 3 of this article;
(d)
A satisfactory process of consultation with general purpose local governments and any federal land manager having authority over federal land to which the state implementation plan applies, effective with respect to measures adopted after August 7, 1978, pertaining to transportation controls, air quality maintenance plan requirements, preconstruction review of stationary sources of air pollution, or any measure referred to in the prevention of significant deterioration program established pursuant to part 2 of this article or the attainment program established pursuant to part 3 of this article, or granting delayed compliance orders pursuant to section
25-7-118
.
(d.5)
Additional permitting requirements for sources that affect disproportionately impacted communities in conformity with section
25-7-114.4 (5)
.
(e)
(I)
Statewide greenhouse gas pollution abatement. As the commission adopts rules pursuant to this subsection (1)(e), it shall pursue near-term reductions in greenhouse gas emissions as part of the effort to reduce total cumulative emissions over time.
(II)
Consistent with section
25-7-102 (2)(g)
, the commission shall timely promulgate implementing rules and regulations. The implementing rules may take into account other relevant laws and rules, as well as voluntary actions taken by local communities and the private sector, to enhance efficiency and cost-effectiveness, and shall be revised as necessary over time to ensure timely progress toward the 2025, 2030, 2035, 2040, 2045, and 2050 goals. The implementing rules must provide for ongoing tracking of emission sources that adversely affect disproportionately impacted communities and are subject to rules implemented pursuant to this subsection (1)(e) and must include strategies designed to achieve reductions in harmful air pollution affecting those communities.
(III)
The commission will identify and engage with disproportionately impacted communities as specified in section
24-4-109
.
(IV)
The division, at the direction of the commission, shall solicit input from other state agencies, stakeholders, and the public on the advantages of different statewide greenhouse gas pollution mitigation measures, specifically soliciting input from those most impacted by climate change, including disproportionately impacted communities; large emission sources; workers in relevant industries, including advanced energy and fuel delivery; and communities that are currently economically dependent on industries with high levels of greenhouse gas emissions.
(V)
The implementing rules and policies may include, in addition to renewable energy development strategies, regulatory strategies that have been deployed by another jurisdiction to reduce multi-sector greenhouse gas emissions, that facilitate adoption of technologies that have very low or zero emissions, and that enhance cost-effectiveness, compliance flexibility, and transparency around compliance costs, among other regulatory strategies. The commission may coordinate with other jurisdictions in securing emission reductions, including in satisfying future federal regulations. The commission may account for reductions in net greenhouse gas emissions that occur under coordinated jurisdictions' programs if the commission finds that the implementing regulations of each coordinated jurisdiction are of sufficient rigor to ensure the integrity of the reductions in greenhouse gas emissions to the atmosphere and may account for carbon dioxide that electricity consumption in this state causes to be emitted elsewhere.
(VI)
In carrying out its responsibilities under this subsection (1)(e), the commission shall consider: The benefits of compliance, including health, environmental, and air quality; the costs of compliance; economic and job impacts and opportunities; the time necessary for compliance; the relative contribution of each source or source category to statewide greenhouse gas pollution based on current data updated at reasonable intervals as determined by the commission; harmonizing emission reporting requirements with existing federal requirements, where the commission deems appropriate; the importance of striving to equitably distribute the benefits of compliance, opportunities to incentivize renewable energy resources and pollution abatement opportunities in disproportionately impacted communities, opportunities to encourage clean energy in transitioning communities; issues related to the beneficial use of electricity to reduce greenhouse gas emissions; whether program design could enhance the reliability of electric service; the potential to enhance the resilience of Colorado's communities and natural resources to climate impacts; and whether greater or more cost-effective emission reductions are available through program design.
(VII)
Notwithstanding section
24-1-136 (11)(a)(I)
, the division, at the direction of the commission, shall report to the general assembly every odd-numbered year after May 30, 2019, regarding: Progress toward the goals set forth in section
25-7-102 (2)(g)
; any newly available, final cost-benefit or regulatory analysis, developed under section
24-4-103
(2.5) or (4.5), for rules adopted to attain the goals; recommendations on future commission rules or policies to reduce greenhouse gas emissions sufficient to achieve the goals set forth in section
25-7-102 (2)(g)
; and any recommendations on future legislative action to address climate change, including implementation of climate adaptation policies or accelerating deployment of cleaner technologies. The division shall make its proposed report available for public review prior to presentation to the general assembly. Beginning with the report in 2023, if the report indicates that emission reductions required by subsections (1)(e)(XII) and (1)(e)(XIII) of this section are not being met, the division shall develop and propose additional requirements to the commission, no later than six months from the submission of the report to the general assembly, which requirements must address any shortfall between the emission reductions achieved and the emission reductions necessary to meet the requirements of subsections (1)(e)(XII) and (1)(e)(XIII) of this section. In even-numbered years when a report is not made pursuant to this subsection (1)(e)(VII), the division shall provide an update to the commission on progress toward the emission reduction requirements in subsections (1)(e)(XII) and (1)(e)(XIII) of this section based on annual data reported to the division.
(VIII)
(A)
In carrying out its responsibilities under this subsection (1)(e), the commission shall consult with the public utilities commission, including on issues of cost of electricity, reliability of electric service, technology developments in electricity production, and beneficial electrification, and keep a record of its consultation.
(B)
The general assembly hereby finds, determines, and declares that it is beneficial to encourage the development of clean energy plans that will require greenhouse gas emissions caused by Colorado retail electricity sales to decrease eighty percent by 2030 relative to 2005 levels to provide for the cost-effective and proactive deployment of clean energy resources.
(C)
In designing, implementing, and enforcing programs and requirements under this subsection (1)(e), the commission and the division shall take into consideration any clean energy plan at the public utilities commission that, as filed, will achieve at least an eighty percent reduction in greenhouse gas emissions caused by the utility's Colorado retail electricity sales by 2030 relative to 2005 levels, as verified by the division. When including public utilities in its programs or requirements under this subsection (1)(e), the commission shall not mandate that a public utility reduce greenhouse gas emissions caused by the utility's Colorado retail electricity sales by 2030 more than is required under such an approved clean energy plan or impose any direct, nonadministrative cost on the public utility directly associated with quantities of greenhouse gas emissions caused by the utility's Colorado retail electricity sales that remain after the reductions required by such a clean energy plan through 2030 if those reductions are achieved and the division has verified that the approved clean energy plan will achieve at least a seventy-five percent reduction in greenhouse gas emissions caused by the utility's Colorado retail electricity sales by 2030 relative to 2005 levels. This subsection (1)(e)(VIII)(C) applies to any clean energy plan that is voluntarily submitted or is required to be submitted pursuant to law.
(D)
Implementing rules developed by the commission must not include any requirements dictating the mix of electric generating resources that any public utility shall use to meet applicable pollution limits.
(E)
Implementing rules developed by the commission must consider issues relating to joint ownership of electric generating resources as between multiple parties and the extent to which the public utility is relying on power purchased from third parties in meeting its obligations under such a clean energy plan.
(F)
A clean energy plan voluntarily filed by a cooperative electric association that has voted to exempt itself from regulation by the public utilities commission pursuant to article
9.5
of title
40
or by a municipal utility shall be deemed approved by the public utilities commission as filed if: The division, in consultation with the public utilities commission, publicly verifies that the plan demonstrates that, by 2030, the cooperative electric association or municipal utility will achieve at least an eighty percent reduction in greenhouse gas emissions caused by the entity's Colorado retail electricity sales relative to 2005 levels; and the clean energy plan has previously been approved by a vote of the entity's governing body. Voluntary submission of a clean energy plan by a cooperative electric association or municipal utility does not alter the entity's regulatory status with respect to the public utilities commission, including under article
9.5
of title
40
.
(G)
The commission is encouraged to pursue programs and policies that are consistent with this subsection (1)(e)(VIII) and that incentivize voluntary additional near-term greenhouse gas reductions from electric utilities with the aim of reducing greenhouse gas emissions from electric utilities by at least forty-eight percent by 2025 and eighty percent by 2030, including emissions associated with imported electricity, as compared to a 2005 baseline and accelerating near-term reductions in greenhouse gas emissions to increase cumulative reductions from electric utilities. Nothing in this subsection (1)(e)(VIII)(G) limits the authority of the public utilities commission.
(H)
In verifying clean energy plans or a wholesale generation and transmission cooperative electric resource plan submitted in accordance with subsection (1)(e)(VIII)(I) of this section, the division shall prevent double counting of emission reductions among utilities and shall consider electricity generated by renewable energy resources as having zero greenhouse gas emissions only if: The electricity is accompanied by any associated renewable energy credit, and the renewable energy credit is retired on behalf of the utility's customers in the year generated; or the electricity is generated by retail distributed generation, as defined in sections
40-2-124 (1)(a)(VIII)
,
40-2-127 (2)(b)(I)(A) and (2)(b)(I)(B)
, and
40-2-127.5 (2)(a)(I) and (2)(a)(II)
, and the retail customer retains the renewable energy credit as part of a voluntary renewable energy program.
(I)
Each wholesale generation and transmission electric cooperative shall file with the public utilities commission and the division an electric resource plan that will achieve at least an eighty percent reduction of greenhouse gas emissions associated with the cooperative's sales of electricity to customers within Colorado by 2030, relative to 2005 levels.
(J)
An electric utility that is not a qualifying retail utility as defined in section
40-2-125.5 (2)(c)(I)
that is required to submit a clean energy plan or a wholesale generation and transmission cooperative that is required to file an electric resource plan pursuant to this subsection (1)(e) shall provide written notice to the division of intent to file a clean energy plan by August 1, 2021. An investor-owned utility that has not already filed a clean energy plan and that indicates an intent to file a clean energy plan shall file a clean energy plan with the public utilities commission with its next resource plan filing. The division shall verify emission reductions as part of the public utilities commission proceeding that reviews the resource plan. A utility other than an investor-owned utility or a wholesale generation and transmission cooperative utility that provided written notice of intent to file a voluntary clean energy plan pursuant to this subsection (1)(e)(VIII)(J) shall provide all information the division deems necessary to evaluate and verify the emission reductions claimed as part of a clean energy plan no later than December 31, 2021. The division shall, in consultation with the public utilities commission, fully evaluate and verify the clean energy plan. The utility must submit the verified clean energy plan to the public utilities commission in accordance with section
40-2-125.5 (5)(g)(I)
no later than July 1, 2022. The division may approve alternate data submission and filing deadlines, to be no later than December 31, 2023, upon reviewing information supplied by a utility in conjunction with the utility's written intention to file if the emission reduction calculations are dependent on decisions of another utility subject to resource planning requirements of the public utilities commission.
(VIII.1)
This subsection (1)(e)(VIII.1) applies to any clean energy plan submitted to the division on or after July 1, 2023, and does not apply to a clean energy plan submitted by a qualifying retail utility pursuant to section
40-2-125.5 (4)(a)
prior to July 1, 2023. Any entity required to submit a clean energy plan pursuant to this section shall base the calculations of the entity's 2005 baseline greenhouse gas emissions, estimated 2027 greenhouse gas emissions, and estimated 2030 greenhouse gas emissions on:
(A)
The greenhouse gas emissions from each resource that is used to supply electricity to the entity's retail customers; and
(B)
The greenhouse gas emissions from each resource that generates electricity and is owned in whole or in part by the entity if the greenhouse gas emissions from that resource are not otherwise required to be included in any other entity's clean energy plan or a plan submitted pursuant to subsection (1)(e)(VIII)(I) of this section.
(VIII.2)
As used in this subsection (1)(e)(VIII.2), "independently determined" means that, in verifying a clean energy plan, the division makes independent judgment of the emissions impact of the clean energy plan based on the information presented to the division by the applicable entity, the public utilities commission, and any stakeholders. This subsection (1)(e)(VIII.2) applies to verification by the division of any clean energy plan submitted to the division on or after July 1, 2023. In verifying a clean energy plan, the division shall, in consultation with the public utilities commission, independently confirm the accuracy of any data supplied by an entity that has adopted a clean energy plan. The division, in consultation with the public utilities commission, shall not verify a clean energy plan pursuant to this section unless it has independently determined that the data used to verify the clean energy plan is accurate and consistent with the clean energy plan adopted by the entity's governing body. In making this independent determination, the division is not required to conduct its own modeling. Prior to verifying a clean energy plan, the division shall:
(A)
Subject to section
25-7-111 (4)
, make publicly available a copy of the clean energy plan, any draft verification workbooks associated with the clean energy plan, and any other materials the division relies upon in making its proposed verification of the clean energy plan;
(B)
Unless the clean energy plan is submitted by a utility that has its resource planning process regulated by the public utilities commission, including a clean energy plan submitted by a qualifying retail utility pursuant to section
40-2-125.5 (4)(a)
: Hold at least one stakeholder meeting regarding the proposed verification of the clean energy plan; accept written comments from the public on the proposed verification of the clean energy plan; and draft and make publicly available a written response to any written comments;
(C)
In consultation with the public utilities commission, independently verify that the entity has provided an accurate calculation of the entity's 2005 baseline greenhouse gas emissions or independently calculate the entity's 2005 baseline greenhouse gas emissions; and
(D)
In consultation with the public utilities commission, independently verify that the entity has provided a reasonably accurate estimate of the entity's 2027 and 2030 greenhouse gas emissions or independently calculate the entity's 2027 and 2030 greenhouse gas emissions.
(VIII.3)
(A)
No later than June 1, 2028, the division shall make the following calculation and determination for each entity, including a wholesale power marketer, as defined in subsection (1)(e)(VIII.7)(A) of this section, that is required to submit a clean energy plan and does not have its electric resource planning process regulated by the public utilities commission: Calculate the percentage of reduction in greenhouse gas emissions caused by each entity's Colorado electricity sales that the entity has achieved by December 31, 2027, relative to 2005 levels; and determine whether the entity has, by December 31, 2027, contracted for, acquired, or commenced construction of the resources identified in the entity's clean energy plan necessary to achieve at least an eighty percent reduction in greenhouse gas emissions caused by the entity's Colorado electricity sales by 2030 relative to 2005 levels. The division shall promptly inform each entity that has submitted a clean energy plan of its final calculations and determination and make the final calculations and determinations for each entity publicly available.
(B)
Prior to making the calculations and determinations required by subsections (1)(e)(VIII.3)(A) and (1)(e)(VIII.3)(D) of this section, the division shall: Subject to section
25-7-111 (4)
, make the calculations and determinations and any data that the division relied on to make the determinations and calculations publicly available; hold at least one stakeholder meeting regarding the calculations and determinations; accept written comments from the public regarding the calculations and determinations; and draft and make publicly available a written response to any written comments.
(C)
If the division determines that the entity has not contracted for, acquired, or commenced construction of the resources described in subsection (1)(e)(VIII.3)(A) of this section by December 31, 2027, no later than December 31, 2028, the entity shall submit a report to the division identifying a specific mix of supply-side and demand-side resources that the entity has procured or is in the process of procuring to enable the entity to achieve at least an eighty percent reduction in greenhouse gas emissions caused by the entity's Colorado electricity sales by 2030 relative to 2005 levels.
(D)
No later than April 30, 2029, if a report was submitted in accordance with subsection (1)(e)(VIII.3)(C) of this section, the division shall review the report and make a determination whether the entity has contracted for, acquired, or commenced construction of a sufficient mix of supply-side and demand-side resources to enable the entity to achieve at least an eighty percent reduction in greenhouse gas emissions caused by the entity's Colorado electricity sales by 2030 relative to 2005 levels. The division shall promptly inform each entity that has submitted a clean energy plan of its determination and make the final determination for each entity publicly available.
(E)
If the entity does not submit the report required pursuant to subsection (1)(e)(VIII.3)(C) of this section on or before December 31, 2028, or if the division determines from the report that the entity has not contracted for, acquired, or commenced construction of a sufficient mix of supply-side and demand-side resources to enable the entity to achieve at least an eighty percent reduction in greenhouse gas emissions caused by the entity's Colorado electricity sales by 2030 relative to 2005 levels: The commission shall adopt rules that limit the greenhouse gas emissions by the generating resources that supply electricity to the entity to ensure that the entity achieves at least an eighty percent reduction in greenhouse gas emissions caused by the entity's Colorado electricity sales by 2030 relative to 2005 levels; and the division shall amend any operating permits for sources of greenhouse gas emissions as necessary to ensure that the entity achieves at least an eighty percent reduction in greenhouse gas emissions caused by the entity's Colorado electricity sales by 2030 relative to 2005 levels.
(F)
The commission and division shall take all actions required pursuant to this subsection (1)(e)(VIII.3) no later than December 31, 2029.
(VIII.4)
(A)
This subsection (1)(e)(VIII.4) applies to all entities that are not otherwise required to submit a clean energy plan pursuant to this section or to submit a plan pursuant to subsection (1)(e)(VIII)(I) of this section.
(B)
Notwithstanding subsection (1)(e)(VIII.5)(A) of this section, if a utility's Colorado electricity sales between January 1, 2022, and December 31, 2022, are equal to or greater than three hundred thousand megawatt-hours, the utility shall submit a clean energy plan to the division for verification in consultation with the public utilities commission.
(C)
The owner of an electric generating unit that has a nameplate capacity equal to or larger than fifty megawatts and emits greenhouse gases directly into the atmosphere shall submit a clean energy plan to the division that covers all greenhouse gas emissions from the electric generating unit that are not otherwise required to be included in the clean energy plan of any entity or a plan submitted pursuant to subsection (1)(e)(VIII)(I) of this section that receives electricity from the electric generating unit.
(D)
Any entity that is required to submit a clean energy plan pursuant to this subsection (1)(e)(VIII.4) shall submit a clean energy plan: To the division no later than December 31, 2024; and to the public utilities commission no later than December 31, 2025. The division, in consultation with the public utilities commission, shall verify that a clean energy plan submitted to the division pursuant to this subsection (1)(e)(VIII.4)(D) meets the requirements of this section and any other applicable requirements no later than September 1, 2025. Any clean energy plan submitted to the division pursuant to this subsection (1)(e)(VIII.4)(D) is deemed approved by the public utilities commission as submitted if the division, in consultation with the public utilities commission, has verified that the clean energy plan complies with the applicable requirements of this section.
(VIII.5)
(A)
This subsection (1)(e)(VIII.5)(A) and subsections (1)(e)(VIII.5)(B) and (1)(e)(VIII.5)(C) of this section apply only to an electric utility that serves at least fifty thousand Colorado retail customers and obtains less than eighty percent of the load necessary to serve Colorado retail customers from an electric utility that has filed a clean energy plan and owns or plans to invest in, in whole or in part, an electric generating unit with a nameplate capacity larger than fifty megawatts that directly emits greenhouse gases into the atmosphere, including generating units that burn oil, gas, or coal. The requirements of subsections (1)(e)(VIII.5)(B) and (1)(e)(VIII.5)(C) of this section become applicable if an electric utility satisfies the criteria specified in this subsection (1)(e)(VIII.5)(A) upon leaving a provider who has filed a clean energy plan. The electric utility shall provide notice of intent to file a clean energy plan to the division within six months after becoming subject to this subsection (1)(e)(VIII.5). The electric utility shall file a clean energy plan pursuant to subsection (1)(e)(VIII) of this section within one year after becoming subject to this subsection (1)(e)(VIII.5).
(B)
If an electric utility does not provide written notice of intent to file a clean energy plan with the division or does not submit a clean energy plan after expressing written intent to file a plan, the commission shall, within fifteen months after the electric utility's failure to provide written notice or submit a plan, adopt a rule to reduce greenhouse gas emissions caused by the electric utility's Colorado retail electricity sales of at least forty-eight percent by 2025 and eighty percent by 2030, including emissions associated with imported electricity, as compared to a 2005 baseline. The commission shall design the rules to accelerate near-term reductions in greenhouse gas emissions in order to reduce total cumulative emissions between the date of adoption and 2030.
(C)
Clean energy plan filings must include projected emissions for each calendar year through 2030 to inform the statewide greenhouse gas planning process. The division shall evaluate the reported emissions and supplemental information in an electric utility's annual greenhouse gas reporting data submission made pursuant to the commission's rules to determine whether an electric utility is progressing consistent with the annual emissions projected by the plan and remains on track to achieve the reductions of the clean energy plan by 2030. If the division determines that the electric utility is not progressing as planned, the electric utility's annual greenhouse gas emissions exceed annual emissions projected as part of an approved clean energy plan for two consecutive years, or the electric utility's annual greenhouse gas emission reductions are not on track to achieve at least an eighty percent reduction below 2005 levels in greenhouse gas emissions by 2030, the division shall include this information in the next greenhouse gas progress briefing to the commission and the commission shall, within nine months after receiving the briefing from the division, adopt rules that require an updated clean energy plan to be filed that demonstrates achievement of the 2030 targets and the cumulative emission reductions that were projected in the initial clean energy plan. The updated clean energy plan, once verified by the division, becomes the operative plan for purposes of subsection (1)(e)(VIII) of this section regarding the commission's regulatory requirements.
(D)
Notwithstanding subsections (1)(e)(VIII.5)(A) to (1)(e)(VIII.5)(C) of this section, a qualifying retail utility with a clean energy plan that has been approved and verified in accordance with section
40-2-125.5
and subsection (1)(e)(VIII)(C) of this section and a wholesale generation and transmission cooperative with an electric resource plan that has been filed in accordance with subsection (1)(e)(VIII)(I) of this section and that has been approved are not subject to subsections (1)(e)(VIII.5)(A) to (1)(e)(VIII.5)(C) of this section. Progress of emission reductions for an electric utility that is an investor-owned retail utility with a clean energy plan that has been approved and verified in accordance with section
40-2-125.5
and subsection (1)(e)(VIII)(C) of this section or a wholesale generation and transmission cooperative with an electric resource plan that has been filed in accordance with subsection (1)(e)(VIII)(I) of this section and that has been approved shall be assessed through the recurring resource planning process at the public utilities commission.
(E)
Any entity required to submit a clean energy plan to the division may designate another entity to submit a clean energy plan on its behalf if the designated entity agrees to submit a clean energy plan on its behalf. In this case, the designated entity shall submit a clean energy plan that meets all of the requirements that apply to the entity and its clean energy plan, including all of the substantive and procedural requirements and the applicable deadlines for submitting the clean energy plan to the division and the public utilities commission. Two or more entities required under this section to submit a clean energy plan may submit a joint clean energy plan if the joint clean energy plan meets all of the requirements that apply to each of the entities and their respective clean energy plans, including all of the substantive and procedural requirements and the applicable deadlines for submitting the clean energy plans to the division and the public utilities commission. If an entity intends to designate another entity to submit a clean energy plan on its behalf, or if two or more entities intend to submit a joint clean energy plan, the entity or entities shall notify the division of their intent prior to the applicable deadline to submit the clean energy plan to the division.
(F)
No later than October 1, 2024, the division shall submit a report to the general assembly that: Identifies all electric utilities that serve retail electricity customers in the state; identifies which electric utilities have submitted a clean energy plan or a plan submitted in accordance with subsection (1)(e)(VIII)(I) of this section with the division, including the verification status of each clean energy plan or plan submitted in accordance with subsection (1)(e)(VIII)(I) of this section, have not submitted a clean energy plan to the division but are required by this section to submit a clean energy plan to the division, or are not required by this section to submit a clean energy plan; calculates the percentage of retail electricity sales in the state from January 1, 2022, to December 31, 2022, that are covered by a clean energy plan or plan submitted in accordance with subsection (1)(e)(VIII)(I) of this section that has been submitted to the division or is required to be submitted to the division but has not been submitted to the division; identifies all greenhouse gas emissions from a power plant unit with a nameplate capacity equal to or larger than fifty megawatts that are not included in a clean energy plan that has been verified and approved by the division, that are not included in a clean energy plan that is required to be submitted to the division but has not been submitted, or that are not covered by any clean energy plan; and presents a map of all electricity generation resources responsible for greenhouse gas emissions in the state that is overlaid on top of the territories of each utility and disproportionately impacted communities.
(G)
No later than December 31, 2024, the division shall issue guidance specifying the manner in which the division will track and account for greenhouse gas emissions associated with electric utility transactions in organized markets, including energy imbalance markets, extended day-ahead markets, independent system operators, and regional transmission organizations, for the purposes of monitoring progress and compliance with clean energy plans that have been verified by the division. The guidance must address, at a minimum, appropriate platforms or platform capabilities to host greenhouse gas emissions data in a transparent and efficient manner for ease of access to the data for utilities, energy customers, and the public. In adopting the guidance, the division shall consult with the public utilities commission.
(H)
No later than March 31, 2026, any entity required to submit a clean energy plan or a plan pursuant to subsection (1)(e)(VIII)(I) of this section to the division may inform the division in writing of any challenges the entity is encountering or expects to encounter in achieving at least an eighty percent reduction of greenhouse gas emissions caused by the entity's Colorado electricity sales by 2030 relative to 2005 levels. If an entity informs the division of any challenges in achieving the greenhouse gas emissions reduction percentage, the division, in coordination with the Colorado energy office created in section
24-38.5-101 (1)
, shall hold at least one public stakeholder meeting in 2026 to discuss the challenges raised by the entity and strategies for the entity to achieve the greenhouse gas emissions reduction percentage. If, after the public stakeholder meeting, an entity informs the division in writing that the entity is still encountering or expects to encounter challenges in achieving the greenhouse gas emissions reduction percentage, no later than December 31, 2026, the division shall submit a concise report to the general assembly summarizing the challenges the entity is encountering or expects to encounter and describing any potential solutions to the challenges. This subsection (1)(e)(VIII.5)(H) is repealed, effective July 1, 2027.
(VIII.6)
(A)
As used in this subsection (1)(e)(VIII.6), "cooperative retail electric utility" means any retail electric utility that, as of January 1, 2021, was a member of a wholesale generation and transmission cooperative that has either indicated an intent to submit or, on or after December 1, 2020, has submitted a clean energy plan or plan in accordance with subsection (1)(e)(VIII)(I) of this section and that either: Provided or provides a nonconditional notice that it is withdrawing from the wholesale generation and transmission cooperative after January 1, 2021; or, after January 1, 2021, obtains more than five percent of its firm capacity supply from a greenhouse-gas-emitting generation source other than the cooperative retail electric utility's wholesale generation and transmission cooperative provider.
(B)
A cooperative retail electric utility shall submit a clean energy plan to the division no later than twenty-four months after ceasing to be a member of a wholesale generation and transmission cooperative or no later than twenty-four months after the date that an applicable partial requirements contract, as described in subsection (1)(e)(VIII.6)(A) of this section, begins. If a cooperative retail electric utility enters into an applicable partial requirements contract before terminating its membership in a wholesale generation and transmission cooperative, the cooperative retail electric utility shall submit its clean energy plan within twenty-four months after ceasing to be a member of the wholesale generation and transmission cooperative.
(C)
In the case of a cooperative retail electric utility that has provided or provides a nonconditional notice that it is withdrawing from a wholesale generation and transmission cooperative, no later than twelve months after the cooperative retail electric utility is required to submit a clean energy plan to the division pursuant to this subsection (1)(e)(VIII.6), the division, in consultation with the public utilities commission, shall verify that the clean energy plan demonstrates that the cooperative retail electric utility will meet the requirements of subsection (1)(e)(VIII.9) of this section and that the cooperative retail electric utility will achieve at least an eighty percent reduction in greenhouse gas emissions caused by the utility's Colorado electricity sales by 2030 relative to 2005 levels.
(D)
In the case of a cooperative retail electric utility that has entered a partial requirements contract, as described in subsection (1)(e)(VIII.6)(A) of this section, no later than twelve months after the cooperative retail electric utility is required to submit a clean energy plan to the division pursuant to this subsection (1)(e)(VIII.6), the division, in consultation with the public utilities commission, shall verify that the clean energy plan demonstrates that the cooperative retail electric utility will meet the requirements of subsection (1)(e)(VIII.9) of this section and that the cooperative retail electric utility will achieve at least an eighty percent reduction in greenhouse gas emissions caused by the utility's Colorado electricity sales by 2030 relative to 2005 levels. The cooperative retail electric utility shall calculate its 2005 baseline emissions for a clean energy plan required pursuant to this subsection (1)(e)(VIII.6) by the percentage of the utility's sales that it self-supplies under its partial requirements contract.
(E)
A cooperative retail electric utility shall submit a clean energy plan to the public utilities commission no later than twelve months after the deadline to submit the clean energy plan to the division. Any clean energy plan submitted to the division pursuant to this subsection (1)(e)(VIII.6) is deemed approved by the public utilities commission as submitted if the division, in consultation with the public utilities commission, has verified that the clean energy plan complies with the applicable requirements of this section.
(F)
Submission of a clean energy plan by a cooperative retail electric utility pursuant to this subsection (1)(e)(VIII.6) does not alter the cooperative retail electric utility's regulatory status with respect to the public utilities commission.
(G)
Upon the request of a cooperative retail electric utility, a wholesale power marketer, as defined in subsection (1)(e)(VIII.7)(A) of this section, public utility, or owner of an electric-generating resource that supplies electricity to the cooperative retail electric utility shall provide any emissions data in its possession relating to the cooperative retail electric utility that is necessary for the cooperative retail electric utility to develop and submit a clean energy plan to the division. In complying with this subsection (1)(e)(VIII.6)(G), a person may withhold any proprietary or confidential information or trade secrets.
(VIII.7)
(A)
As used in this subsection (1)(e)(VIII.7), "wholesale power marketer" means an entity operating in the state that supplies wholesale capacity or energy to a retail electric utility located in the state and that supplies three hundred thousand megawatt-hours or more of electricity to entities in the state annually. "Wholesale power marketer" does not include a wholesale generation and transmission cooperative, a retail electric utility, a federal power marketing administration, an independent power producer, any entity for which all of its greenhouse gas emissions are included in another entity's clean energy plan or plan pursuant to subsection (1)(e)(VIII)(I) of this section, any entity that supplies capacity or energy to electric utilities located in the state solely through an organized market that electric utilities in the state can participate in, and any entity that is required by another provision of this section to file a clean energy plan or has voluntarily filed a clean energy plan.
(B)
A wholesale power marketer shall submit a clean energy plan to the division if, on or after July 1, 2023: The wholesale power marketer sells, provides, arranges for, or contracts for the delivery of capacity or energy to a retail electric utility located in the state or has contracted to sell, provide, arrange, or contract for the delivery of capacity or energy to a retail electric utility located in the state; and the greenhouse gas emissions associated with the operations described in this subsection (1)(e)(VIII.7)(B) are not otherwise required to be included in another entity's clean energy plan or a plan submitted pursuant to subsection (1)(e)(VIII)(I) of this section.
(C)
The division shall, in consultation with the public utilities commission, verify that the wholesale power marketer's clean energy plan: Meets the requirements of subsection (1)(e)(VIII.9) of this section and achieves at least an eighty percent reduction in greenhouse gas emissions caused by the wholesale power marketer's Colorado electricity sales by 2030 relative to 2005 levels; and addresses all greenhouse gas emissions associated with the operations described in subsection (1)(e)(VIII.7)(B) of this section.
(D)
A wholesale power marketer shall submit a clean energy plan: With the division no later than one year after becoming subject to the requirements of this subsection (1)(e)(VIII.7); and with the public utilities commission no later than one year after the date that the wholesale power marketer must submit the clean energy plan with the division. The division, in consultation with the public utilities commission, shall verify the clean energy plan within nine months after the date that the wholesale power marketer must submit the clean energy plan with the division.
(E)
If a wholesale power marketer does not submit a clean energy plan to the division by the deadline to submit a clean energy plan to the division pursuant to subsection (1)(e)(VIII.7)(D) of this section, no later than two years after the deadline to submit a clean energy plan to the division pursuant to subsection (1)(e)(VIII.7)(D) of this section, the commission shall adopt rules that reduce the greenhouse gas emissions by the wholesale power marketer to ensure that the wholesale power marketer meets the requirements of subsection (1)(e)(VIII.9) of this section and achieves at least an eighty percent reduction in greenhouse gas emissions caused by the wholesale power marketer's Colorado electricity sales by 2030 relative to 2005 levels.
(F)
Submission of a clean energy plan by a wholesale power marketer pursuant to this subsection (1)(e)(VIII.7) does not alter the wholesale power marketer's regulatory status with respect to the public utilities commission.
(G)
A wholesale power marketer that supplies electricity to any entity shall, upon the request of the entity, provide any emissions data in its possession relating to the entity that is necessary for the entity to develop and submit a clean energy plan to the division. In complying with this subsection (1)(e)(VIII.7)(G), a person may withhold any proprietary or confidential information or trade secrets. If the wholesale power marketer does not possess the emissions data, the entity shall disclose in its clean energy plan that the entity does not possess the emissions data and shall not be penalized for the unavailability of the emissions data. If the emissions data is unavailable, the entity filing the clean energy plan shall make a reasonable estimate of emissions.
(VIII.8)
(A)
As used in this subsection (1)(e)(VIII.8), "new electric utility" means any new electric utility, of any type, that is incorporated, created, or otherwise formed on or after July 1, 2023, that serves retail customers in the state and sells three hundred thousand megawatt-hours or more of electricity in its first year of operation.
(B)
A new electric utility shall submit a clean energy plan: With the division no later than two years after the date that the new electric utility is incorporated, created, or otherwise formed; and with the public utilities commission no later than one year after the date that the new electric utility must submit the clean energy plan with the division. The division, in consultation with the public utilities commission, shall, no later than nine months after the date that the new electric utility must submit the clean energy plan with the division, verify that the clean energy plan demonstrates that the new electric utility will meet the requirements of subsection (1)(e)(VIII.9) of this section and that the new electric utility will achieve at least an eighty percent reduction in greenhouse gas emissions caused by the utility's Colorado electricity sales by 2030 relative to the new electric utility's annual greenhouse gas emissions during its first year of operations.
(C)
If the new electric utility does not submit a clean energy plan to the division no later than two years after being incorporated, created, or otherwise formed, the commission, within three years after the new electric utility is incorporated, created, or otherwise formed, shall adopt rules to reduce the greenhouse gas emissions by the new electric utility to ensure that the new electric utility: Meets the requirements of subsection (1)(e)(VIII.9) of this section; and achieves at least an eighty percent reduction in greenhouse gas emissions caused by the new electric utility's Colorado electricity sales by 2030 relative to the new electric utility's annual greenhouse gas emissions during its first year of operations.
(VIII.9)
(A)
In addition to meeting the clean energy targets described in section
40-2-125.5 (3)
, any clean energy plan or any plan submitted pursuant to subsection (1)(e)(VIII)(I) of this section that is submitted to the division on or after January 1, 2024, must achieve at least a forty-six percent reduction in greenhouse gas emissions caused by the entity's Colorado electricity sales by 2027 relative to 2005 levels, if the achievement of the forty-six percent reduction in greenhouse gas emissions will maintain reliability and result in an incremental average annual cost to the entity of no more than two and one-half percent of the entity's total system costs.
(B)
Subsections (1)(e)(VIII.9)(C) and (1)(e)(VIII.9)(D) of this section apply to any entity that, before January 1, 2024, submits a clean energy plan or a plan pursuant to subsection (1)(e)(VIII)(I) of this section to the division and the verification workbook for the plan projects that the plan will not achieve the reduction in greenhouse gas emissions described in subsection (1)(e)(VIII.9)(A) of this section.
(C)
Any entity described in subsection (1)(e)(VIII.9)(B) of this section is encouraged to achieve the reduction in greenhouse gas emissions described in subsection (1)(e)(VIII.9)(A) of this section. As a part of any electric resource plan developed, finalized, or submitted on or after July 1, 2023, any entity described in subsection (1)(e)(VIII.9)(B) of this section shall model: At least one portfolio that achieves the reduction in greenhouse gas emissions described in subsection (1)(e)(VIII.9)(A) of this section and achieves at least an eighty percent reduction in greenhouse gas emissions caused by the entity's Colorado electricity sales by 2030 relative to 2005 levels; and at least one portfolio that achieves greater greenhouse gas emissions reductions than the reductions that the clean energy plan submitted before January 1, 2024, is projected to achieve by 2027 and achieves at least an eighty percent reduction in greenhouse gas emissions caused by the entity's Colorado electricity sales by 2030 relative to 2005 levels. The entity's governing body shall consider these two portfolios as part of the electric resource planning process.
(D)
To assist entities that have submitted a clean energy plan or a plan pursuant to subsection (1)(e)(VIII)(I) of this section to cost-effectively maximize reduction in greenhouse gas emissions as part of the electric resource planning process and to otherwise accelerate greenhouse gas emissions reductions, at the request of an entity that has submitted a clean energy plan or a plan submitted pursuant to subsection (1)(e)(VIII)(I) of this section that has been verified by the division in consultation with the public utilities commission, the Colorado energy office, created in section
24-38.5-101 (1)
, shall provide the entity with information regarding federal funding opportunities for accelerating reductions in greenhouse gas emissions.
(IX)
(A)
In addressing greenhouse gas emissions from an energy-intensive, trade-exposed manufacturing source, the commission shall require the source to execute an energy and emission control audit, according to criteria established by the commission, of the source's operations every five years through at least 2035. A qualified third party, as determined by the commission, shall conduct the audit and submit the results to the commission. If the commission determines that the source currently employs best available emission control technologies for greenhouse gas emissions and best available energy efficiency practices, the commission shall not impose a direct nonadministrative cost on the source directly associated with at least ninety-five percent of the source's greenhouse gas emissions attributable to manufacturing a good in this state for a period of five years, if the source's emissions are not greater than the emissions associated with use of the best available emission control technologies as determined by the commission. The commission shall consider how program design as relevant to those sources can further mitigate the cost of reducing emissions for such manufacturers while providing an incentive to improve efficiency and reduce emissions. Specifically, the commission shall design the program as relevant to those sources such that as the sources are subject to emission reduction requirements, those sources will have, under the program, a pathway to obtain equivalent lower-cost emission reductions at other regulated sources to satisfy their compliance obligations.
(B)
As used in this subsection (1)(e)(IX), "energy-intensive, trade-exposed manufacturing source" means an entity that principally manufactures iron, steel, aluminum, pulp, paper, or cement and that is engaged in the manufacture of goods through one or more emissions-intensive, trade-exposed processes, as determined by the commission.
(X)
Nothing in this subsection (1)(e) diminishes the existing authority of the commission or the division. Nothing in this subsection (1)(e) alters the regulatory exemptions provided in section
25-7-109 (8)(a)
. Nothing authorized in this subsection (1)(e), including the assignment of emission reduction obligations or emission authorizations and excluding program development and administrative costs, implicates state fiscal year spending as defined in section
24-77-102
. Nothing in this subsection (1)(e) alters any requirement to prepare a cost-benefit analysis under section
24-4-103
(2.5) or any requirement to issue a regulatory analysis under section
24-4-103
(4.5). Nothing in this subsection (1)(e) diminishes the authority of the public utilities commission under the public utilities law, including sections
40-3-101
and
40-3-102
.
(X.4)
No later than September 1, 2022, the commission shall propose rules establishing recovered methane protocols, as that term is defined in section
40-3.2-108 (2)(p)
, for at least inactive coal mines, biomethane, as that term is defined in section
40-3.2-108 (2)(a)
, and gas system leaks, and a crediting and tracking system for recovered methane, as that term is defined in section
40-3.2-108 (2)(n)
. The commission shall adopt the rules no later than February 1, 2023. The rule-making proceeding is subject to the procedural requirements of this subsection (1)(e).
(X.7)
In designing greenhouse gas emission reduction rules that apply to gas distribution utilities with clean heat plans approved by the public utilities commission, the commission shall harmonize its regulatory requirements with the activities contemplated under an approved clean heat plan. In adopting any additional emission reduction requirements on gas distribution utilities subject to a clean heat plan different from the requirements of an approved clean heat plan, the commission shall:
(A)
Consult with the public utilities commission regarding the emission reductions under any approved clean heat plan, the clean heat targets, and the cost-effectiveness of any additional emission reduction requirements and their impact on customer costs; and
(B)
Design rules to maximize cost-effectiveness of additional emission reduction requirements to protect low-income customers.
(X.8)
(A)
The definitions in section
40-3.2-108 (2)
apply to this subsection (1)(e)(X.8) and subsection (1)(e)(X.7) of this section.
(B)
A municipal gas distribution utility shall implement a clean heat plan program. The purpose of a clean heat plan is to reduce carbon dioxide and methane emissions to meet the state's greenhouse gas pollution reduction goals in section
25-7-102 (2)(g)
. The clean heat plan must include a projection of the utility's greenhouse gas emissions through 2050.
(C)
A municipal gas distribution utility shall submit its clean heat plan to the division no later than August 1, 2023, for the division to verify that the plan demonstrates that, by 2025, the utility will achieve at least a four percent total reduction in greenhouse gas emissions caused by the utility's retail gas sales below 2015 levels, of which not more than one percent can come from recovered methane. The utility may propose a cost cap of two percent of total annual revenue from full-service gas customers in achieving the 2025 target. The plan submitted to the division must also show that, by 2030, the utility will achieve at least a twenty-two percent reduction in greenhouse gas emissions caused by the utility's retail gas sales below 2015 levels by 2030, of which not more than five percent can be from recovered methane. The utility may propose a cost cap of two and one-half percent of total annual revenue from full-service gas customers in achieving the 2030 target. If the division's calculations show that a clean heat plan submitted by a municipal gas distribution utility does not achieve the relevant clean heat targets, the utility shall revise its plan to strive to maximize emission reductions without exceeding the cost cap.
(D)
The utility shall provide to the division an annual report of carbon dioxide emissions associated with customer end-uses and, separately, methane emissions associated with the utility's distribution system.
(XI)
As used in this subsection (1)(e):
(A)
"Cost-effective" or "cost-effectiveness" means the cost per unit of reduced emissions of greenhouse gases expressed as carbon dioxide equivalent.
(B)
"Greenhouse gas" includes carbon dioxide, methane, nitrous oxide, hydrofluorocarbons, perfluorocarbons, nitrogen trifluoride, and sulfur hexafluoride, expressed as carbon dioxide equivalent.
(B.5)
"Industrial and manufacturing sector" means energy combustion and energy use by industry, including: Combustion from coal, diesel, gasoline, heat, liquified petroleum gas, natural gas, refinery feedstocks, and residual fuel oil; and industrial processes, including cement manufacture, electric transmission and distribution equipment, iron and steel production, lime manufacture, limestone and dolomite use, ozone depleting substances substitutes, semiconductor manufacture, soda ash, and urea consumption. The term does not include oil and gas exploration, production, processing, transmission, and storage operations other than energy combustion emissions that are included in the industrial and manufacturing sector.
(C)
"Retail electricity sales" means electric energy sold to retail end-use electric consumers.
(XII)
No later than January 1, 2022, the commission shall adopt, and the division shall begin implementing, comprehensive rules that will reduce statewide greenhouse gas emissions from oil and gas exploration, production, processing, transmission, and storage operations in the state below the 2005 baseline established for the oil and gas emissions covered by the "oil and gas fugitive emissions" category in the initial inventory developed by the division pursuant to section
25-7-140 (2)(a)(II)
, taking into account subsections (1)(e)(II) to (1)(e)(VI) of this section, by at least thirty-six percent by 2025 and sixty percent by 2030. The commission shall design the rules to prioritize near-term reductions in greenhouse gas emissions. The rules must include:
(A)
Protections for disproportionately impacted communities, achieving reduction of greenhouse gases and co-pollutants; and
(B)
More robust monitoring, leak detection, and repair requirements, reporting, and record-keeping requirements to ensure that the division can accurately quantify greenhouse gas emissions during all operating conditions, including equipment malfunctions; and
(C)
Additional direct emission reduction controls.
(XIII)
In implementing this subsection (1)(e), the commission shall adopt rules to reduce statewide greenhouse gas emissions from the industrial and manufacturing sector in the state by at least twenty percent by 2030 below the 2015 baseline established pursuant to section
25-7-140 (2)(a)(II)
, taking into account the factors set out in subsections (1)(e)(II) to (1)(e)(VI) of this section. The rules must include protections for disproportionately impacted communities and prioritize emission reductions that will reduce emissions of co-pollutants that adversely affect disproportionately impacted communities, be designed to accelerate near-term reductions, and secure meaningful emission reductions from this sector to be realized beginning no later than September 30, 2024. The rules must:
(A)
Be consistent with the requirements of subsection (1)(e)(IX) of this section; and
(B)
Require a five percent reduction in the greenhouse gas emissions associated with energy-intensive, trade-exposed manufacturing sources that currently employ best available emission control technologies for greenhouse gas emissions and best available energy efficiency practices, as determined by the commission, pursuant to subsection (1)(e)(IX)(A) of this section.
(f)
(I)
Definitions.
The definitions in subsection (1)(e)(XI) of this section apply to this subsection (1)(f). As used in this subsection (1)(f), unless the context requires otherwise:
(A)
"GHG credit" means a tradeable compliance instrument in a physical or electronic format, the use of which is authorized pursuant to a regulatory program adopted by the commission that represents the reduction of one metric ton of carbon dioxide equivalent of greenhouse gas by a regulated source.
(B)
"Regulated source" means a source of greenhouse gas that is subject to a rule adopted by the commission under subsection (1)(e) of this section that imposes specific and quantifiable greenhouse gas reduction obligations upon that source or group of sources.
(C)
"Trading program" means a commission-adopted regulatory program that allows for regulated sources to meet their greenhouse gas compliance obligations under subsection (1)(e) of this section through the creation, purchase, acquisition, or exchange of, or other commercial-type transaction involving, a GHG credit with other regulated sources.
(II)
Greenhouse gas accounting system.
Except as specified in subsection (1)(f)(III) of this section, before the commission adopts a rule or program that provides for the use of a trading program, the commission shall adopt a rule that directs the division to create a comprehensive and centralized accounting system to track emissions from, at a minimum, all regulated sources in the state covered by or that may otherwise participate in that trading program, which system must:
(A)
Enable the division and the public to track emission reductions, trades, and other transactions by sources utilizing GHG credits or otherwise participating in a trading program, and to track any transactions that take place consistent with the requirements set forth in this subsection (1)(f), including all rules promulgated pursuant to this subsection (1)(f);
(B)
Enable the division to prevent double counting of greenhouse gas emission reductions; and
(C)
Identify regulated sources that adversely affect disproportionately impacted communities through their emissions of locally harmful air pollutants.
(III)
The commission may adopt a trading program among regulated sources as necessary to timely implement subsection (1)(e)(IX) of this section if that program:
(A)
Is ultimately integrated into the comprehensive and centralized accounting system developed pursuant to subsection (1)(f)(II) of this section;
(B)
Enables the division to track the emissions of, and emission reductions, trades, and other transactions by, all regulated sources participating in the trading program;
(C)
Enables the division to prevent double counting of greenhouse gas emission reductions; and
(D)
Identifies regulated sources that adversely affect disproportionately impacted communities through their emissions of locally harmful air pollutants.
(g)
With regard to the changes made in 2021 by House Bill 21-1266:
(I)
Nothing:
(A)
Alters the greenhouse gas emission reduction goals previously established in section
25-7-102 (2)(g)
, in either amount or timing; or
(B)
Detracts from the air quality control commission's existing authority to require more than the minimum greenhouse gas emission reduction goals and deadlines previously established in section
25-7-102 (2)(g)
; and
(II)
The changes add to, but do not otherwise alter, the air quality control commission's authority and obligation to publish and promulgate rules pursuant to this section and sections
25-7-102 (2)(g)
and
25-7-140
.
(2)
The commission shall provide forms of application and shall receive all such applications for review of the classification of any attainment, nonattainment, or unclassifiable area within the state made pursuant to section
25-7-106 (1)
or
25-7-107 (2)
, all applications for designation or redesignation made pursuant to section
25-7-208
, and all applications for any revision of general application of the state implementation plan and shall set such applications for hearing and determination by the commission in accordance with the provisions of section
25-7-119
.
(3)
The commission shall employ a technical secretary and shall delegate to the secretary the duties and responsibilities as it may deem necessary; except that, notwithstanding section
24-1-105
, no authority shall be delegated to the secretary to adopt, promulgate, amend, or repeal standards or rules, or to make determinations, or to issue or countermand orders of the commission. The secretary must have appropriate practical, educational, and administrative experience related to air pollution control and must be employed pursuant to the state personnel system laws. The technical secretary is a
type 1
entity, as defined in section
24-1-105
.
(4)
(a)
The commission and the state board of health shall hold a joint public hearing during the month of October of each year in order to hear public comment on air pollution problems within the state, alleged sources of air pollution within the state, and the availability of practical remedies therefor; and at such hearing the technical secretary shall answer reasonable questions from the public concerning administration and enforcement of the various provisions of this article, as well as rules and regulations promulgated under the authority of this article.
(b)
On or before September 30, 1993, the commission shall publish and revise from time to time thereafter, as is necessary, a regulatory agenda which includes its schedule for future rule-making and its schedule for implementing section
25-7-109.3
and other air quality programs.
(5)
Prior to the hearing required under subsection (4) of this section, the commission shall prepare and make available to the public a report, which shall contain the following specific information:
(a)
A description of the pollution problem in each of the polluted areas of the state, described separately for each such area;
(b)
To the extent possible, the identification of the sources of air pollution in each separate area of the state, such as motor vehicles, industrial sources, and power-generating facilities;
(c)
A list of all alleged violations of emission control regulations showing the status of control procedures in effect with respect to each such alleged violation; and
(d)
Stationary industrial sources permitting information as follows:
(I)
The total number of permits issued;
(II)
The total number of hours billed for permitting;
(III)
The average number of hours billed per permit; and
(IV)
The number of general permits issued.
(6) and (7)
Repealed.
(8)
(Deleted by amendment, L. 92, p. 1170, § 7, effective July 1, 1992.)
(9)
The commission shall adopt exhaust emissions standards for motor vehicles purchased for state use and shall assist the executive director of the department of personnel in determining those vehicles which meet or exceed such standards.
(10)
The commission shall promulgate such rules and regulations as are necessary to implement the provisions of part 5 of this article concerning asbestos control.
(11)
The commission shall promulgate rules concerning CFC and ozone-depleting compounds as follows:
(a)
Regulations requiring the recycling or reuse of any refrigerant containing CFC which is removed from the refrigeration system of a retail store, cold storage warehouse, or commercial or industrial building by any person who installs, services, repairs, or disposes of such system as a result of service to or disposal of such system;
(b)
Regulations prohibiting the intentional venting or disposal of any refrigerant containing CFC by the owner or operator of a retail store, cold storage warehouse, or commercial or industrial building and requiring the recycling or reuse of such refrigerant;
(c)
Regulations requiring the use of approved motor vehicle refrigerant recycling equipment during the repair or servicing of a motor vehicle air conditioner, requiring that such repair or servicing be done by a person certified in accordance with federal regulations, and including requirements for reclamation of refrigerants during the disposal of a vehicle;
(d)
Repealed.
(e)
Regulations which establish requirements for recycling;
(f)
Regulations which conform with the requirements of section 608 of the federal "Clean Air Act Amendments of 1990" to establish standards and requirements regarding the use and disposal of class I and class II ozone depleting compounds during the service, repair, or disposal of appliances and industrial process refrigeration. If federal training and certification requirements are adopted under section 609 of the federal "Clean Air Act Amendments of 1990" as of January 1, 1993, no state training and certification requirements shall be adopted. If the federal regulations are not adopted, then such state regulations shall contain training and certification requirements substantially similar to those required under section 609 of the federal "Clean Air Act Amendments of 1990". Such regulations shall also include provisions for the imposition and collection of a certification fee sufficient to implement the training, certification, and enforcement requirements of this paragraph (f).
(g)
Repealed.
(h)
Rules that are necessary for the imposition and collection of a fee for registering as stationary sources refrigeration systems and other appliances that contain a minimum of one hundred pounds or use a drive system of one hundred horsepower or more and use ozone-depleting compounds. The fee set by the commission shall reflect the direct and indirect costs of registering refrigeration systems and appliances; however, such fee shall not exceed seventy-five dollars per unit and shall not exceed a maximum of three hundred dollars per facility.
(12)
The commission shall promulgate such rules and regulations as are necessary to implement the provisions of the emission notice and construction permit programs and the minimum elements of a permit program provided in Title V of the federal act.
(13)
(a)
The commission shall promulgate rules and regulations requiring motor vehicles which have manufacturer-installed diagnostic systems for emission controls to have such diagnostic systems inspected and maintained consistent with section 202 of the federal act as part of the periodic inspection of vehicle emission control systems required pursuant to this article.
(b)
This subsection (13) shall take effect July 1, 1994.
(14)
The commission shall repeal the clean vehicle fleet program mandated by section 246 of the federal act and shall replace such program if required by federal law.
(15)
The commission shall promulgate rules and regulations as are necessary to provide an emission reduction incentive permit fee credit program which provides for a permit fee reduction in the year following the year in which a permittee achieves an early reduction in emissions of hazardous air pollutants, consistent with the provisions of section 112 of the federal act and section
25-7-114.3
.
(16)
The commission shall give priority to and take expeditious action upon consideration of the following:
(a)
A request by a unit of local government to investigate and resolve air quality problems associated with a source;
(b)
A request by a unit of local government for inclusion of a locally developed air pollution control measure in a state implementation plan;
(c)
A request by a unit of local government that the commission consider local concerns respecting environmental and economic effects in the context of a proceeding where the state is targeting a source for imposition of additional air pollution controls.
(17)
(a)
Not later than December 31, 2002, and no less frequently than every five years thereafter, the commission shall conduct rule-making hearings to approve an update to the emission inventories from state and federal public land management agency activities on public lands resulting in emissions of any criteria pollutant, including surrogates or precursors for that pollutant, that affect any mandatory class I federal areas in Colorado by reducing visibility in such areas. At a minimum, such inventories shall report on emissions from the sources set forth in paragraph (d) of this subsection (17).
(b)
The commission shall ensure that the division prepares inventories for all state land management agencies with jurisdiction over state lands, including, without limitation, the state land board, the department of agriculture, and the department of natural resources, to provide an inventory of emissions from land management activities that are sources of pollutant emissions that may affect any mandatory class I federal area in Colorado by reducing visibility in such areas; except that the commission shall exempt from the inventory requirement any sources or categories of sources that it determines to be of minor significance.
(c)
The commission shall use the emission inventories provided under this subsection (17) to develop control strategies for reducing emissions within the state as a component of the visibility long-term strategies for inclusion in the state implementation plan and for inclusion in any environmental impact statement or environmental assessment required to be performed under the federal "National Environmental Policy Act of 1969",
42 U.S.C. secs. 4321
to
4347
.
(d)
The rule-making hearing held to approve the inventories provided under this subsection (17) shall require public participation and shall require the reporting of both current emissions and projected future emissions, over at least a five-year period, from the following sources on public land that affect any mandatory class I federal areas in Colorado:
(I)
Stationary source emissions, based on existing air pollution emission notices filed with the division;
(II)
Mobile sources utilizing state lands, excluding state and federal highways;
(III)
Paved and unpaved roads;
(IV)
Fires on public lands from all sources;
(V)
Biogenic sources, including emissions from flora and fauna.
(e)
Each inventory provided under this subsection (17) shall state the basis and methodology used to accumulate the data and shall be based upon data that are:
(I)
Developed no later than three years prior to the submittal; and
(II)
No more than five years old.
(18)
Upon petition by any person or on its own motion, for good cause shown, the commission may determine that the emission inventory of any criteria pollutant, including a surrogate or precursor for that pollutant, for a region of the state is inadequate for purposes of commission rule-making or adjudications in connection with development of the state implementation plan, selection of pollution control strategies, attribution of emissions to sources or categories of sources, or findings of adverse impacts. If, after conducting a public hearing in accordance with the rule-making provisions of the "State Administrative Procedure Act", article
4
of title
24
, C.R.S., the commission finds that the emission inventory should be revised to take into consideration existing credible studies or scientific data in order to reasonably attribute emissions to source categories, it shall direct that such revision be performed prior to a final rule-making or adjudication.
(19)
The commission may coordinate with the United States secretary of the interior and the United States secretary of agriculture to develop air quality management plans consistent with this article for federal lands pursuant to
16 U.S.C. sec. 530
,
16 U.S.C. sec. 1604
, and
43 U.S.C. sec. 1712
.
(20)
The commission may, within existing resources:
(a)
Analyze a range of residential, commercial, and industrial biomass equipment for air emissions standards;
(b)
Identify biomass equipment that meets the emissions standards; and
(c)
Publicly post a statement of the parameters for equipment fueled by biomass that is smaller than one million British thermal units, as defined in section
8-20-201
(1.3), C.R.S., per hour and include a list of biomass equipment that meets the emissions standards.
Amended by 2023 Ch. 303,§ 41, eff. 8/7/2023.
Amended by 2023 Ch. 165,§ 28, eff. 8/7/2023.
Amended by 2023 Ch. 352,§ 2, eff. 6/5/2023.
Amended by 2022 Ch. 469, § 50, eff. 8/10/2022.
Amended by 2022 Ch. 335, § 12, eff. 8/10/2022.
Amended by 2022 Ch. 28, § 7, eff. 8/10/2022.
Amended by 2021 Ch. 411,§ 14, eff. 7/2/2021.
Amended by 2021 Ch. 411,§ 6, eff. 7/2/2021.
Amended by 2021 Ch. 328, § 2, eff. 6/24/2021.
Amended by 2020 Ch. 216, § 57, eff. 6/30/2020.
Amended by 2019 Ch. 355, § 3, eff. 5/30/2019.
Amended by 2016 Ch. 210, § 63, eff. 6/6/2016.
Amended by 2013 Ch. 406, § 4, eff. 6/5/2013.
L. 79: Entire article R&RE, p. 1021, § 1, effective June 20; (9) added, p. 1551, § 14, effective June 20. L. 81: (9) amended, p. 1296, § 35, effective 1/1/1982. L. 84: (2) and (8) amended and (7) repealed, p. 768, §§ 3, 1, effective July 1. L. 87: (10) added, p. 1151, § 2, effective July 1. L. 89: (11) added, p. 1156, § 3, effective 1/1/1990. L. 92: (1)(c), (4), (8), and IP(11) amended and (11)(c) to (11)(g) and (12) to (16) added, pp. 1170, 1292, §§ 7, 2, effective July 1. L. 93: (11)(h) added, p. 958, § 1, effective May 28. L. 95: (1)(a)(III) added, p. 1149, § 1, effective May 31. L. 96: (1)(a)(IV) added, p. 1038, § 2, effective May 23; (9) amended, p. 1541, § 130, effective June 1; (6) repealed, p. 1257, § 149, effective August 7. L. 99: (17) and (18) added, p. 1246, § 1, effective June 2. L. 2002: (14) R&RE, p. 1066, § 1, effective August 7. L. 2003: (19) added, p. 1035, § 6, effective April 17; (11)(d) repealed, p. 724, § 3, effective July 1. L. 2005: (11)(g) repealed, p. 282, § 18, effective August 8. L. 2008: IP(11) and (11)(h) amended, p. 882, § 1, effective May 20. L. 2010: (5) amended, (HB 10-1042), ch. 908, p. 908, § 1, effective September 1. L. 2011: (14) amended, (SB 11-163), ch. 37, p. 37, § 3, effective March 9. L. 2013: (20) added, (SB 13-273), ch. 406, p. 2374, § 4, effective June 5. L. 2016: (11)(f) amended, (SB 16-189), ch. 771, p. 771, § 63, effective June 6. L. 2019: IP(1) amended and (1)(e) added, (HB 19-1261), ch. 3264, p. 3264, § 3, effective May 30. L. 2020: (14) amended, (HB 20-1402), ch. 1055, p. 1055, § 57, effective June 30. L. 2021: IP(1) amended and (1)(e)(X.4), (1)(e)(X.7), and (1)(e)(X.8) added, (SB 21-264), ch. 2106, p. 2106, § 2, effective June 24; IP(1), (1)(e)(I), (1)(e)(III), and (1)(e)(VII) amended and (1)(d.5), (1)(e)(VIII)(G), (1)(e)(VIII)(H), (1)(e)(VIII)(I), (1)(e)(VIII)(J), (1)(e)(VIII.5), (1)(e)(XI)(B.5), (1)(e)(XII), (1)(e)(XIII), (1)(f), and (1)(g) added, (HB 21-1266), ch. 411, pp. 2741, 2730, §§ 14, 6, effective July 2.
(1) Amendments to subsection IP(1) by SB 21-264 and HB 21-1266 were harmonized.
(2) Section 24 of chapter 411 (HB 21-1266), Session Laws of Colorado 2021, provides that the act changing this section applies to conduct occurring on or after July 2, 2021.
(3) Section 5 of chapter 328 (SB 21-264), Session Laws of Colorado 2021, provides that the act changing this section applies to conduct occurring on or after June 24, 2021.
2023 Ch. 303, was passed without a safety clause. See Colo. Const. art. V, § 1(3).
2023 Ch. 165, was passed without a safety clause. See Colo. Const. art. V, § 1(3).
2022 Ch. 469, was passed without a safety clause. See Colo. Const. art. V, § 1(3).
2022 Ch. 335, was passed without a safety clause. See Colo. Const. art. V, § 1(3).
2022 Ch. 28, was passed without a safety clause. See Colo. Const. art. V, § 1(3).
(1) For the legislative declaration contained in the 1996 act enacting subsection (1)(a)(IV), see section 1 of chapter 210, Session Laws of Colorado 1996. For the legislative declaration contained in the 1996 act repealing subsection (6), see section 1 of chapter 237, Session Laws of Colorado 1996. For the legislative declaration contained in the 2003 act enacting subsection (19), see section 1 of chapter 145, Session Laws of Colorado 2003. For the legislative declaration in the 2013 act adding subsection (20), see section 1 of chapter 406, Session Laws of Colorado 2013. (2) For sections 608 and 609 of the federal "Clean Air Act Amendments of 1990", see 42 U.S.C. §§7671g and 7671h , respectively. (3) For the short title ("Environmental Justice Act") and the legislative declaration in HB 21-1266, see sections 1 and 2 of chapter 411, Session Laws of Colorado 2021.