2023 Colorado Revised Statutes › Title 40 - UTILITIES (§§ 40-1-101 — 40-43-104) › PUBLIC UTILITIES (§§ 40-1-101 — 40-17.5-105) › GENERAL AND ADMINISTRATIVE (§§ 40-1-101 — 40-9.8-104) › Article 3.2 - AIR QUALITY IMPROVEMENT COSTS (§§ 40-3.2-101 — 40-3.2-210) › Part 1 - GENERAL PROVISIONS (§§ 40-3.2-101 — 40-3.2-110) › Section 40-3.2-108 - Clean heat targets - legislative declaration - definitions - plans - rules - reports

(1)
Legislative declaration.
The general assembly hereby:
(a)
Finds that:
(I)
In order to achieve Colorado's science-based greenhouse gas emission reduction goals and maintain a healthy, livable climate for Coloradans, Colorado must reduce greenhouse gas pollution from all sectors of the economy, including the built environment;
(II)
A significant source of greenhouse gas pollution from the built environment comes from the use of gas to heat Colorado's homes and businesses and to heat water in those buildings, from the use of gas in commercial and industrial processes, and from gas leaks in the supply chain;
(III)
Improving the energy efficiency of Colorado's buildings will reduce pollution, improve comfort and safety, provide more resilience during weather extremes, and reduce consumer costs for heating and cooling homes and businesses; and
(IV)
Reducing the carbon intensity of gas delivered by utilities and switching from gas space and water heating to high-efficiency electric heating will reduce greenhouse gas pollution and lead to improved indoor air quality;
(b)
Determines that:
(I)
There is significant potential to reduce emissions of methane from active and inactive coal mines, landfills, wastewater treatment plants, agricultural operations, and other sources of methane pollution through development of methane recovery and biomethane projects, and there are also significant economic development opportunities, especially in rural Colorado, from development of this resource;
(II)
Green and blue hydrogen have the potential to be zero- or very low-carbon sources of energy for use in a variety of sectors, including high-heat industrial applications, zero-carbon electricity generation, and the gas distribution system; and
(III)
The development of hydrogen projects in Colorado has the potential to lower costs, contribute to economies of scale, and bring economic development opportunities; and
(c)
Declares that:
(I)
The general assembly's intent in enacting this section is to implement a performance standard that will allow Colorado gas utilities to use available tools, including energy efficiency, biomethane, hydrogen, recovered methane, beneficial electrification of customer end uses, cost-effective leak reductions on the utility's distribution system as determined by the commission that exceed state and federal requirements, and other measures to achieve greenhouse gas emission reductions, cost-effectiveness, and equity;
(II)
Colorado is focused on a transition to a decarbonized economy that recognizes the historic injustices that impact lower-income Coloradans and Black, Indigenous, and other people of color who have borne a disproportionate share of environmental risks while also enjoying fewer environmental benefits;
(III)
The commission must maximize greenhouse gas emission reductions and benefits to customers, with particular attention to residential customers who participate in income-qualified programs, while managing costs and risks to customers, including stranded-asset cost risks, and in a manner that supports family-sustaining jobs; and
(IV)
Decarbonizing Colorado's homes and businesses will require investments in building and equipment upgrades, clean fuel projects, and infrastructure upgrades.
(2)
Definitions.
As used in this section, unless the context otherwise requires:
(a)
"Biomethane":
(I)
Means a mixture of carbon dioxide and hydrocarbons released from the biological decomposition of organic materials that is primarily methane and provides a net reduction in greenhouse gas emissions; and
(II)
Includes biomethane recovered from manure management systems or anaerobic digesters, including from operations for dairy cows, beef cattle, poultry, swine, or sheep, that has been processed to meet pipeline quality.
(b)
"Clean heat plan" means a comprehensive plan submitted by a gas distribution utility or municipal gas distribution utility that demonstrates projected reductions in methane and carbon dioxide emissions that, together, meet the reductions required in this section at the lowest reasonable cost.
(c)
"Clean heat resource" means any one or a combination of:
(I)
Gas demand-side management programs as defined in section
40-1-102(6)
;
(II)
Recovered methane;
(III)
Green hydrogen;
(IV)
Beneficial electrification as defined in section
40-1-102
(1.2);
(V)
Pyrolysis of tires if the pyrolysis meets a recovered methane protocol;
(V.5)
Thermal energy; and
(V.8)
Wastewater thermal energy; and
(VI)
Any technology that the commission finds is cost-effective and that the division finds results in a reduction in carbon emissions from the combustion of gas in customer end uses or meets a recovered methane protocol approved by the air quality control commission. To qualify as a clean heat resource, all credits or severable, tradable mechanisms representing the emission reduction attributes of the clean heat resource must be retired in the year generated and may not be sold.
(d)
"Cost cap" means a maximum cost impact established pursuant to subsection (6)(a)(I) of this section for compliance with a clean heat target.
(e)
"Division" means the division of administration created by section
25-1-102(2)(a)
in the department of public health and environment.
(f)
"Gas" means geological gas, hydrogen, and recovered methane.
(g)
"Gas distribution utility" means a public utility providing gas service to more than ninety thousand retail customers. "Gas distribution utility" does not include a municipal gas distribution utility.
(h)
"Geological gas" means methane and other hydrocarbons that occur underground without human intervention and are used as fuel.
(h.5)
"Geothermal fluid" has the meaning set forth in section 37-90.5-103 (2).
(i)
"Greenhouse gas" has the meaning set forth in section
25-7-140(6)
, measured in terms of carbon dioxide equivalent.
(j)
"Green hydrogen" means hydrogen derived from a clean energy resource as defined in section
40-2-125.5(2)(b)
that uses water as the source of the hydrogen. For purposes of a clean heat plan, a green hydrogen project may include associated clean energy generation, transmission, and other infrastructure, subject to commission approval.
(k)
"Lowest reasonable cost" means a reasonable-cost mix of clean heat resources that meet clean heat targets established pursuant to this section as determined through a detailed analysis of available technologies and includes resource costs, market volatility risks, risks to ratepayers, systems operations costs, infrastructure costs, environmental justice goals, the social cost of carbon, and the social cost of methane in comparing the costs and benefits of alternatives, and other costs and benefits as determined by the commission.
(l)
"Municipal gas distribution utility" means a municipally owned utility that provides gas service to more than ninety thousand customers.
(m)
"Pyrolysis" has the meaning set forth in section
40-2-124(1)(a)(V)
.
(n)
"Recovered methane" means any of the following that are located in Colorado and meet a recovered methane protocol approved by the air quality control commission:
(I)
Biomethane; and
(II)
Methane derived from:
(A)
Municipal solid waste;
(B)
The pyrolysis of municipal solid waste;
(C)
Biomass pyrolysis or enzymatic biomass; or
(D)
Wastewater treatment;
(III)
Coal mine methane, as defined in section
40-2-124(1)(a)(II)
, the capture of which is not otherwise required by state or federal law; or
(IV)
Methane that would have leaked without repairs of the gas distribution and service pipelines from the city gate to customer end use.
(o)
"Recovered methane credit" means a tradable instrument that represents a greenhouse gas emission reduction or greenhouse gas removal enhancement of one metric ton of carbon dioxide equivalent. The greenhouse gas emission reduction or greenhouse gas removal enhancement must be real, additional, quantifiable, permanent, verifiable, and enforceable. No recovered methane credit may be issued if the greenhouse gas emission reduction or greenhouse gas removal enhancement that the credit would represent is required or accounted for by a proposed or final federal, state, or local rule or regulation.
(p)
"Recovered methane protocol" means a documented set of procedures and requirements established by the air quality control commission to quantify ongoing greenhouse gas emission reductions or greenhouse gas removal enhancements achieved by a recovered methane project and to calculate the project baseline. a recovered methane protocol that the air quality control commission adopts for biomethane from manure management systems must allow for the use of manure from beef cattle operations. The air quality control commission may also adopt a recovered methane protocol that is specific to manure management from beef cattle operations. A recovered methane protocol must:
(I)
Specify relevant data collection and monitoring procedures and emission factors;
(II)
Conservatively account for uncertainty, activity-shifting leakage risks, and market-shifting leakage risks associated with a type of recovered methane project;
(III)
Determine data verification requirements; and
(IV)
Specify procedures pursuant to which the air quality control commission must approve an entity that the division proposes to accredit for verification of ongoing greenhouse gas emission reductions or greenhouse gas removal enhancements.
(q)
"Small gas distribution utility" means a public utility providing gas service to ninety thousand retail customers or fewer. "Small gas distribution utility" does not include a municipal gas distribution utility.
(r)
(I)
"Thermal energy" means piped, noncombustible fluids used for adding or removing heat from buildings for the purpose of efficient building temperature control and domestic hot water, including space heating and cooling and refrigeration.
(II)
"Thermal energy" includes methods of exchanging the piped, noncombustible fluids through the ground, wastewater treatment facilities, or other sources that achieve desired fluid temperatures; except that any source of thermal energy for this purpose must:
(A)
Not cause incremental greenhouse gas emissions or rely on increased, long-term combustion of fossil fuels; and
(B)
Be evaluated by the commission to protect against increased emissions of harmful co-pollutants, negative impacts to communities including to disproportionately impacted communities, as defined in section 24-4-109 (2)(b)(II), and the risk of stranded assets, if the thermal energy is from any industrial source including a system for which the primary purpose is to generate electricity, including any process involving engine-driven generation.
(s)
"Thermal energy network":
(I)
Means all real estate, fixtures, and personal property that are operated, owned, used, or intended to be used for, in connection with, or to facilitate a distribution infrastructure project that supplies thermal energy to two or more buildings that are not a campus, as defined in section 40-4-121 (1)(a), and that assists in reducing greenhouse gas emissions in the state;
(II)
Consists of pipe loops between multiple buildings and energy sources carrying piped, noncombustible fluids at the desired thermal temperature;
(III)
Includes a network that can be used for heating, cooling, and other building services; and
(IV)
May also be known as a geothermal exchange district, networked geothermal system, geoexchange system, geogrid system, community geothermal heating and cooling district, or a geothermal heating district.
(t)
"Thermal energy system" includes a geothermal system or other method of exchanging the piped, noncombustible fluids through the ground, wastewater treatment facilities, or other sources of thermal energy that achieve desired fluid temperatures.
(u)
"Wastewater thermal energy" means a system that uses thermal energy in wastewater, to heat or cool a space, or for any other useful thermal purpose that reduces greenhouse gas emissions from the combustion of gas in customer end uses.
(3)
Clean heat targets.
(a)
The purpose of a clean heat plan is to achieve clean heat targets by reducing carbon dioxide and methane emissions from gas distribution utilities.
(b)
(I)
A clean heat plan under this section must demonstrate that the gas distribution utility submitting the clean heat plan will achieve a reduction of carbon dioxide and methane emissions from the distribution and end-use combustion of gas.
(II)
A gas distribution utility shall demonstrate compliance with subsection (3)(b)(I) of this section by filing and obtaining commission approval of clean heat plans that meet clean heat targets calculated as follows: Consistent with subsection (3)(c) of this section and as compared to a 2015 baseline, a four percent reduction in greenhouse gas emissions in 2025, of which not more than one percent can be from recovered methane; and a twenty-two percent reduction in greenhouse gas emissions in 2030, of which not more than five percent can be from recovered methane.
(c)
(I)
In calculating the baseline and projected emissions covered under a clean heat plan, a gas distribution utility must include the following:
(A)
Methane leaked from the transportation and delivery of gas from the gas distribution and service pipelines from the city gate to customer end use;
(B)
Carbon dioxide emissions resulting from the combustion of gas by residential, commercial, and industrial customers not otherwise subject to federal greenhouse gas emission reporting and excluding all transport customers; and
(C)
Emissions of methane resulting from leakage from delivery of gas to other local distribution companies.
(II)
All emissions are metric tons of carbon dioxide equivalent as reported to the federal environmental protection agency pursuant to 40 CFR 98, either subpart W (methane) or subpart NN (carbon dioxide), or successor reporting requirements; except that the division shall use the AR-4 one-hundred-year global warming potential or any greater successor value determined by the federal environmental protection agency.
(d)
In calculating its clean heat target, a utility must show its baseline carbon dioxide emissions and methane emissions separately and must show that the total emission reductions are projected to achieve the clean heat target. The final calculation demonstrating that the plan meets the clean heat target must be presented on a carbon dioxide equivalent basis.
(e)
It is the policy of the state of Colorado to reduce the state's greenhouse gas emissions, and therefore to count toward a gas distribution utility's compliance with the emission reduction goals, recovered methane under a clean heat plan must be represented by a recovered methane credit, issued subject to an approved recovered methane protocol, and delivered:
(I)
To or within Colorado through a dedicated pipeline; or
(II)
Through a common carrier pipeline if the source of the recovered methane injects the recovered methane into a common carrier pipeline that physically flows within Colorado or toward the end user in Colorado for which the recovered methane was produced.
(f)
To count toward a gas distribution utility's compliance with the clean heat targets, the utility must quantify the actual methane reductions achieved by any leak repairs and the commission must find that the leak reductions are cost-effective. The commission may require the utility to evaluate nonpipeline alternatives.
(4)
Submission of clean heat plans.
(a)
No later than August 1, 2023, the largest gas distribution utility in Colorado, as determined by the volume of gas sold in Colorado, shall file with the commission an application for approval of a clean heat plan that demonstrates that the gas distribution utility will achieve the clean heat target established for 2025 in subsection (3)(b)(II) of this section by 2025. All other gas distribution utilities shall file applications for approval of clean heat plans no later than January 1, 2024, that demonstrate, for each such gas distribution utility, that it will achieve the clean heat target established for 2025 in subsection (3)(b)(II) of this section by 2025.
(b)
After complying with subsection (4)(a) of this section, each gas distribution utility shall, as directed by the commission but not less often than every four years, file an additional clean heat plan that covers, at minimum, five years after the date of the filing.
(c)
A clean heat plan filed pursuant to this subsection (4) must:
(I)
Demonstrate that the gas distribution utility will meet the applicable clean heat targets specified in this section for the applicable plan period;
(II)
Set forth portfolios that the gas distribution utility will use to demonstrate alternative compliance approaches for reducing carbon dioxide and methane emissions to meet the clean heat target in the applicable plan period, including its preferred option. The utility shall present:
(A)
A portfolio of resources that uses clean heat resources to the maximum practicable extent, that complies with the cost cap, that may include leak reductions approved by the commission, and that may or may not meet the clean heat target in the applicable plan period but that demonstrates reductions in methane emissions;
(B)
A portfolio that meets the clean heat targets in the applicable plan period using only clean heat resources but that need not meet the cost cap;
(C)
Other portfolios at the utility's discretion; and
(D)
Other portfolios as directed by the commission.
(III)
Quantify annual projected greenhouse gas emission reductions during the applicable plan period resulting from each portfolio;
(IV)
Propose program budgets to meet the emission reduction targets;
(V)
Prioritize investments that ensure that disproportionately impacted communities or customers who meet requirements for income-qualified programs benefit from the investments made to implement the clean heat plan;
(VI)
Project annual greenhouse gas emission reductions that would result if each proposed portfolio were extended through 2050;
(VII)
Forecast carbon dioxide and methane emission reductions that are consistent with the recovered methane protocol rules adopted by the air quality control commission pursuant to section
25-7-105(1)(e)
(X.4);
(VIII)
Quantify additional air quality, environmental, and health benefits of the plan in addition to the greenhouse gas emission reductions;
(IX)
Include a forecast of potential new customers and system growth or expansion of the gas system for the applicable plan period, including projected greenhouse gas emissions related to that growth;
(X)
Describe the effects of the actions and investments in the clean heat plan on the safety, reliability, and resilience of the gas distribution utility's gas service;
(XI)
Quantify the cost of implementing the preferred portfolio of clean heat resources used to meet the clean heat targets through the clean heat plan, net of the avoided cost of any new delivery infrastructure avoided through implementing the plan;
(XII)
Identify potential changes to depreciation schedules or other actions to align the gas distribution utility's cost recovery with statewide policy goals, including reducing carbon dioxide and methane emissions, minimizing costs, and minimizing risks to customers;
(XIII)
Explain the gas distribution utility's analysis of the costs and benefits of an array of compliance alternatives, including the social cost of carbon and the social cost of methane in the cost-benefit calculations;
(XIV)
Describe the monitoring and verification methodology to be used in annual reporting;
(XIV.5)
Demonstrate that, with respect to any thermal energy network that will be used as a clean heat resource, any geothermal fluid associated with the thermal energy system or thermal energy network is used in compliance with the permitting requirements for production of geothermal fluid set forth in article 90.5 of title 37; and
(XV)
Include any other information required by the commission.
(d)
(I)
To demonstrate compliance with the applicable clean heat target in a clean heat plan, a gas distribution utility must utilize clean heat resources to the maximum extent practicable and count greenhouse gas emission reductions resulting from its use of those resources. For compliance with the 2030 target, a utility shall not propose and the commission shall not approve recovered methane resources achieving more than five percent of the target of twenty-two percent.
(II)
Notwithstanding any other provision of this section, and unless the commission finds that a clean heat plan is not cost-effective in meeting the following targets, of the emission reductions required in a clean heat plan that a gas distribution utility must achieve, reductions from recovered methane projects may be in the following maximum amounts:
(A)
Five percent of the total reduction for the period 2026 through 2030; and
(B)
An amount specified by the commission by rule for clean heat plans covering years after 2030 if the commission determines that the requirements further investment in Colorado communities, reduce greenhouse gas emissions, are cost-effective, and are in the public interest.
(e)
A clean heat plan may be filed as part of a demand-side management plan or any other plan as determined by the commission.
(f)
A gas distribution utility may include proposals to make investments in green or blue hydrogen projects that will reduce greenhouse gas emissions. If a gas distribution utility proposes to make an investment pursuant to this subsection (4)(f), it must also include a proposal for competitive solicitation.
(g)
(I)
The commission shall consult with the division to estimate reductions of emissions of greenhouse gases and other air pollutants under the portfolios.
(II)
The division may participate as a party in any proceeding before the commission in which a gas distribution utility is seeking approval of a clean heat plan the gas distribution utility developed pursuant to this section.
(h)
A gas distribution utility's first clean heat plan must use a planning period that extends through 2025. The second clean heat plan must use a planning period that extends through 2030. Subsequent clean heat plans must use a planning period as determined by the commission.
(5)
Commission rules.
(a)
No later than October 1, 2021, the commission shall undertake a rule-making proceeding to update electric and gas demand-side management rules consistent with the clean heat targets established in this section. In the rule-making, the commission shall remove any prohibition on customer incentives to help customers replace gas appliances with highly efficient electric alternatives. As part of this rule-making process, the commission shall convene at least four workshops or public meetings to solicit input on the contents and evaluation of gas distribution utilities' clean heat plans, two of which must be located in disproportionately impacted communities served by the utility that is required to submit a clean heat plan. Participation must be open to the public and shall not be limited to parties represented by an attorney.
(b)
The commission shall adopt rules necessary for gas distribution utilities to implement clean heat plans by December 1, 2022.
(6)
Approval of clean heat plans - recovery.
(a)
(I)
For each gas distribution utility, the commission shall establish a cost cap that is two and one-half percent of annual gas bills for all full-service customers as a whole.
(II)
The commission shall calculate the annual retail cost impact net of the utility's approved gas demand-side management program budgets but shall include any incentive adopted or approved by the commission. If a gas distribution utility includes a beneficial electrification plan as part of a filing with a clean heat plan, the commission shall calculate the retail cost impact cap net of the utility's approved beneficial electrification plan program budget.
(b)
The commission shall consider allowing current recovery for clean heat plan costs through a rate adjustment clause or structure that allows for current recovery, and a gas distribution utility may recover the prudently incurred costs associated with actions under an approved clean heat plan or actions to meet any additional emission reduction requirements imposed pursuant to section
25-7-105(1)(e)
(X.7).
(c)
(I)
In approving a clean heat plan, the commission shall consider a cost test that includes both the social cost of carbon and the social cost of methane.
(II)
In evaluating a clean heat plan, the commission shall consider whether the plan will achieve the applicable clean heat targets.
(d)
(I)
The commission shall approve a clean heat plan if the commission finds it to be in the public interest. The commission may modify the plan if the modifications are necessary to ensure that the plan is in the public interest. In evaluating whether the clean heat plan submitted to the commission is in the public interest, the commission shall take into account the following factors:
(A)
Whether the clean heat plan achieves the clean heat targets through maximizing the use of clean heat resources;
(B)
The additional air quality, environmental, and health benefits of the plan in addition to the greenhouse gas emission reductions;
(C)
Whether investments in a clean heat plan prioritize serving customers participating in income-qualified programs and communities historically impacted by air pollution and other energy-related pollution;
(D)
Whether the clean heat plan results in a reasonable cost to customers, including savings to customer bills resulting from investments made pursuant to the plan; and
(E)
Whether the clean heat plan ensures system reliability.
(II)
In approving a clean heat plan:
(A)
If the commission determines that it is possible to achieve larger greenhouse gas emission reductions than the required clean heat targets using clean heat resources at or below the cost cap, the commission shall require the maximum level of emission reductions above the clean heat targets that can be achieved at or below the cost cap using clean heat resources, with the proportion of greenhouse gas emission reductions from recovered methane not exceeding the proportion allowed in meeting the clean heat target for the applicable plan period.
(B)
The commission must require the gas distribution utility to achieve the maximum level of greenhouse gas emission reductions practicable using clean heat resources at or below the cost cap, with the proportion of greenhouse gas emission reductions from recovered methane not exceeding the proportion allowed in meeting the clean heat target for the applicable plan period.
(III)
The commission may approve, or amend and approve, a clean heat plan with costs greater than the cost cap only if it finds that the plan is in the public interest, costs to customers are reasonable, the plan includes mitigation of rate increases for income-qualified customers, and the benefits of the plan, including the social costs of methane and carbon dioxide, exceed the costs.
(IV)
Notwithstanding subsection (6)(a)(I) of this section, the commission shall not require a utility with fewer than two hundred fifty thousand meters to spend more than an amount equal to two percent of the utility's total annual revenues from full-service customers to comply with the 2025 emission reductions requirements of subsection (3)(b)(II) of this section, net of costs associated with a commission-approved demand-side management plan, avoided fuel costs, and avoided capital infrastructure costs. Notwithstanding subsection (6)(d)(III) of this section, a utility subject to this subsection (6)(d)(IV) may voluntarily request to spend a higher amount to comply with the 2025 clean heat targets, and the commission may approve the requested amount if the commission finds that the spending comes at a reasonable cost and rate impact and is in the public interest.
(7)
Annual reporting.
(a)
Each gas distribution utility shall submit to the commission an annual report that shows the amount of money that it has spent under each program in the clean heat plan, the amount spent on income-qualified programs or programs that serve communities historically impacted by air pollution and other energy-related pollution, a calculation of emissions reduced or avoided pursuant to its approved clean heat plan, and any other information required by the commission.
(b)
In addition to any other greenhouse gas reporting requirements, each gas distribution utility shall submit an annual report to the commission providing a calculation of emissions reduced or avoided pursuant to its approved clean heat plan. The report must include separate quantifications of the reductions in carbon dioxide and methane emissions. Carbon dioxide emission reductions must be calculated based on emissions reported pursuant to the air quality control commission's rules. If a utility includes recovered methane, the utility shall quantify actual emission reductions achieved on a project basis for each project for which it claims reductions in that year, based on any recovered methane credits generated.
(8)
Employment and utility workforce.
(a)
For any utility-owned project that is part of a clean heat plan, the gas distribution utility shall, where practicable, use its own employees to complete the work.
(b)
For a utility project that is part of a competitive solicitation and with a cost of more than one million dollars, the gas distribution utility shall require all bidders to provide detailed information about the use of Colorado-based labor and out-of-state labor. The utility shall provide this information to the commission.
(c)
If a clean heat plan includes gas demand-side management programs as defined in section
40-1-102(6)
, all requirements specified in this article 3.2 relating to labor standards for gas demand-side management programs or projects apply. If a clean heat plan includes beneficial electrification, all requirements specified in this article 3.2 relating to beneficial electrification labor standards, beneficial electrification plans, recovery of costs, and reporting apply.
(d)
In all decisions approving clean heat resources to be acquired as part of a clean heat plan, the commission shall consider the long-term impacts on Colorado's utility workforce as part of a just transition and shall give additional weight to a project that includes:
(I)
Training programs, including training through the division of employment and training in the department of labor and employment created in section
8-83-102
, or apprenticeship programs registered with the United States department of labor's office of apprenticeship or a state apprenticeship agency recognized by the United States department of labor;
(II)
Employment of Colorado-based labor; and
(III)
Long-term career opportunities and industry-standard wages, health care, and pension benefits.
(e)
If a project in connection with a clean heat plan, is an energy sector public works project, as defined in section 24-92-303 (5), the project must comply with the applicable requirements of the "Colorado Energy Sector Public Works Project Craft Labor Requirements Act", part 3 of article 92 of title 24.
(9)
Small gas distribution utilities.
(a)
A small gas distribution utility may file a clean heat plan with the commission pursuant to subsections (3) to (7) of this section or it may submit a small utility emission reduction plan pursuant to this subsection (9).
(b)
The small gas distribution utility, as part of its small utility emission reduction plan:
(I)
Must propose greenhouse gas emission reduction targets for 2025 and 2030;
(II)
Is subject to the cost cap;
(III)
Must identify the clean heat resources the small gas distribution utility will use to reduce emissions on its system and quantify the annual emission reductions expected during the plan period;
(IV)
Must propose program budgets to meet the emission reduction targets proposed by the small gas distribution utility;
(V)
Must forecast carbon dioxide and methane emission reductions reasonably expected to be achieved through the actions taken in the preferred plan;
(VI)
Must quantify the cost of implementation of the preferred portfolio of resources used in the plan; and
(VII)
Must include an implementation plan of at least three years during which the small gas distribution utility proposes to acquire clean heat resources to reduce emissions.
(c)
The commission shall approve a clean heat plan filed under this subsection (9) if the commission finds it to be in the public interest. The commission may modify the clean heat plan if the modifications are necessary to ensure that the plan is in the public interest. In evaluating whether the clean heat plan submitted to the commission is in the public interest, the commission shall take into account the factors set forth in subsection (6)(d)(I) of this section. In approving a clean heat plan under this subsection (9), the commission shall carry out the duties set forth in subsection (6)(d)(II) of this section. The commission may approve a clean heat plan that exceeds the cost cap under this subsection (9) only pursuant to subsection (6)(d)(III) of this section.
(d)
Small gas distribution utilities with approved clean heat plans are subject to the reporting provisions of subsection (7) of this section.
(10)
(10)
No later than December 1, 2025, the commission, in consultation with the division, shall determine mass-based greenhouse gas emission reduction targets for clean heat plans for 2035. In establishing these targets, the commission shall:
(a)
Ensure that gas distribution utilities' greenhouse gas emissions will be in line with the residential, commercial, and industrial sectors' contribution to statewide greenhouse gas pollution; and
(b)
Determine whether recovered methane may be used to meet the mass-based greenhouse gas emissions reduction targets established pursuant to this subsection (10).
(11)
No later than December 1, 2032, the commission, in consultation with the division, shall determine the mass-based greenhouse gas emission reduction goals for clean heat plans for 2040, 2045, and 2050 using a 2015 baseline that, at minimum, ensure that gas distribution utilities' greenhouse gas emission reductions will be proportionate to the residential, commercial, and industrial sectors' contribution to the greenhouse gas emission reduction goals, excluding transportation gas service customers or customers that report their own greenhouse gas emissions to the federal environmental protection agency under applicable federal law, including 40 CFR 98, subpart NN. In determining these goals, the commission shall consider savings achieved or projected to be achieved in other sectors of the state's economy, as well as the commercial availability of technologies to achieve emission reductions in this sector.
Amended by 2024 Ch. 191,§ 22, eff. 5/17/2024.
Amended by 2023 Ch. 247,§ 9, eff. 1/1/2024, app. only to any energy sector public works project for which a public utility or cooperative electric association invitation for bids or proposals is issued on or after 1/1/2024.
Amended by 2023 Ch. 166,§ 4, eff. 8/7/2023.
Amended by 2023 Ch. 165,§ 7, eff. 8/7/2023.
Amended by 2023 Ch. 165,§ 21, eff. 8/7/2023.
Amended by 2023 Ch. 37, § 38, eff. 3/23/2023.
Added by 2021 Ch. 328, § 1, eff. 6/24/2021.
L. 2021: Entire section added, (SB 21-264), ch. 2093, p. 2093, § 1, effective June 24.
Section 5 of chapter 328 (SB 21-264), Session Laws of Colorado 2021, provides that the act adding this section applies to conduct occurring on or after June 24, 2021.
2023 Ch. 247, was passed without a safety clause. See Colo. Const. art. V, § 1(3).
2023 Ch. 166, 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).