5 Colo. Code Regs. § 1001-26-E-VI
Revisions to Regulation Number 22, Part C.
This Statement of Basis, Specific Statutory Authority, and Purpose complies with the requirements of the State Administrative Procedure Act, § 24-4-101, C.R.S., et seq., the Colorado Air Pollution Prevention and Control Act, § 25-7-101, C.R.S., et seq., and the Air Quality Control Commission's (Commission) Procedural Rules, 5 C.C.R. §1001-1.
Basis
During the 2021 legislative session, Colorado's General Assembly adopted revisions to several Colorado Revised Statutes through Senate Bill 21-264 (SB 21-264) (Concerning the adoption of programs by gas utilities to reduce greenhouse gas emissions, and, in connection therewith, making an appropriation) that directed, among other things, the Commission to adopt rules establishing recovered methane protocols for coal mines, biomethane, and gas system leaks. §§ 25-7-105(1)(e) (X.4)-(X.8), C.R.S.; see also § 40-3.2-108, C.R.S.
Specific Statutory Authority
The Colorado Air Pollution Prevention and Control Act, § 25-7-101, C.R.S., et seq. (the State Air Act or the Act), specifically § 25-7-105(1), directs the Commission to promulgate such rules and regulations as are consistent with the legislative declaration set forth in § 25-7-102 and that are necessary for the proper implementation and administration of Article 7. The Act provides the Commission broad authority to regulate air pollutants, including GHG and its constituent gasses (particularly carbon dioxide, methane, and nitrous oxide).
Pursuant to § 25-7-105(1)(e) (X.4), the Commission must, by February 1, 2023, adopt rules establishing recovered methane protocols for coal mines, biomethane, and gas system leaks and a crediting and tracking system for recovered methane.
Purpose
In response to SB 21-264, the Commission adopted recovered methane protocols for biomethane, coal mine methane, and gas system leaks. These protocols must be used for gas distribution utilities to take credit for the greenhouse gas emission reductions from the recovered methane projects in the utility's clean heat plan. Accordingly, the Commission also adopted a crediting and tracking system for recovered methane.
The revisions also correct typographical, grammatical, and formatting errors found through the regulation.
Clean Heat Plans
Through SB 21-264, the Colorado General Assembly required gas distribution utilities and municipal gas utilities to develop and implement clean heat plans that demonstrate projected reductions in methane and carbon dioxide emissions at the lowest reasonable cost. § 40-3.2-108(2)(b), C.R.S. Requirements for submission of clean heat plans differ between gas distribution utilities with more than ninety thousand retail customers, small gas distribution utilities with ninety thousand or fewer retail customers, and municipal gas distribution utilities with ninety thousand or more retail customers. See § 40-3.2-108, C.R.S.; and see § 25-7-105(1)(e) (X.8), C.R.S.
Gas distribution utilities with ninety thousand or more retail customers must file with the Public Utilities Commission (PUC) clean heat plans that will reduce carbon dioxide and methane emissions from the distribution and end-use combustion of gas to meet specified clean heat targets relative to a 2015 baseline. In 2025, the clean heat plans must reduce emissions at least four percent in 2025, of which no more than one percent can be from recovered methane, and twenty-two percent in 2030, of which no more than five percent can be from recovered methane. § 40-3.2-108(3)(b)(II), C.R.S. The largest gas distribution utility in the state, Xcel Energy, must file its clean heat plan with the PUC no later than August 1, 2023 and all other gas distribution utilities must file clean heat plans with the PUC no later than January 1, 2024. These first plans must demonstrate that the clean heat plan will accomplish the 2025 clean heat targets.
Small gas distribution utilities, those with ninety thousand or fewer retail customers, may elect to file with the PUC clean heat plans accomplishing the same clean heat targets as the larger gas distribution utilities or, alternatively, may submit a small utility emission reduction plan. See § 40-3.2-108(9), C.R.S. These clean heat plans would be subject to the same clean heat targets as those for larger gas distribution utilities. Id. In a small utility emission reduction plan, the utility can set its own emission reduction targets. Id.
The PUC has opened a rulemaking proceeding, No. 21R-0449G, to adopt rules governing clean heatplans gas distribution and small gas distribution utilities no later than December 1, 2022. § 40-3.2-108(5)(b), C.R.S.
A municipal gas distribution utility, being a municipally owned utility that provides gas service to more thanninety thousand customers, must submit its clean heat plan to the Division no later than August 1, 2023. § 25-7-105(1)(e) (X.8)(C), C.R.S. Like the other utilities, a municipal gas distribution utility's clean heat planmust reduce emissions at least four percent in 2025, of which no more than one percent can be fromrecovered methane, and twenty-two percent in 2030, of which no more than five percent can be fromrecovered methane. Id.
All clean heat plans, whether submitted to the PUC or Division and whether mandatory or voluntary, mayincorporate clean heat resources that can include recovered methane in order to accomplish theemissions reductions needed for the pertinent clean heat target. See § 40-3.2-108(2)(c), C.R.S. (defining"clean heat resource" to include recovered methane); see also § 40-3.2-108(4)(c), C.R.S. (describingclean heat portfolio requirements). The use of recovered methane in these portfolios is a limited, butpotentially critical aspect of utilities successfully accomplishing clean heat targets. Accordingly, theCommission through these regulations is adopting robust recovered methane protocols that will rigorouslyevaluate any recovered methane projects before awarding credits that can be used towards clean heatplan compliance and is establishing a crediting and tracking system that will enable efficient and effectiveaccounting and exchange of recovered methane credits.
Recovered Methane Protocol Selection
The proposed recovered methane protocols were selected with input from the public as well as members of the recovered methane technical work group. The technical work group members were selected based on technical expertise for the specific subgroups (gas distribution system leaks, coal mine methane, and biomethane) and environmental justice expertise. Subgroups included representation from academia, industry, utilities, environmental groups, and local governments. Members of the public could also attend the technical work group meetings and provide written comments throughout the process. Technical workgroup meetings were held on ten occasions between January and July 2022. The technical work groups considered various project types and protocols to satisfy the statutory directives set forth in SB21-264, including international Clean Development Mechanism protocols, California Air Resource Board (CARB) protocols and American Carbon Registry (ACR) protocols, among others, before making recommendations on those to be proposed to this Commission. Public stakeholder meetings regarding the recovered methane protocols were also held on three occasions in June of 2022 along with a presentation to the Climate Equity Advisory Council.
The gas distribution system leaks subgroup consisted of representatives from Colorado State University, Geosyntec, Xcel Energy, Black Hills Energy, Atmos Energy, Colorado Springs Utilities, Summit Utilities, Radicle, Western Resource Advocates, Southwest Energy Efficiency Project, International Brotherhood of Electrical Workers, and the City and County of Denver.
The coal mine methane capture subgroup consisted of representatives from Geosyntec, Delta Brick, Environmental Commodities Corporation, Energy Smart Solutions, Radicle, Environmental Defense Fund, Colorado Springs Utilities, Colorado Mining Association, Peabody Energy, Colorado State University, Xcel Energy, and the City and County of Denver.
The biomethane subgroup consisted of representatives from Western Resource Advocates, Radicle, Natural Resource Defense Council, Colorado Dept of Agriculture, Sheldon Kye Energy, Metro Water Recovery, Black Hills Energy, Colorado Springs Utilities, Ramboll, Renewable Natural Gas Coalition, Camco International, Xcel Energy, City and County of Denver, and Summit Utilities.
Pursuant to § 40-3.2-108(2)(p), C.R.S., recovered methane protocols must: specify relevant data collection and monitoring procedures and emission factors; account for uncertainty, activity-shifting leakage risks, and market-shifting leakage risks associated with a type of recovered methane project; determine data verification requirements; and specify procedures for approving entities accredited for verification of ongoing greenhouse gas emission reductions or greenhouse gas removal enhancements. In satisfaction of these requirements, the Commission has adopted the following recovered methane protocols:
Biomethane from manure management systems - The Commission has selected the "Compliance Offset Protocol Livestock Projects" adopted by CARB on November 14, 2014 to quantify GHG emission reductions or GHG removal enhancements for biomethane recovered from manure management systems. This protocol meets the requirements in the statutory definition of "recovered methane protocol" by clearly identifying data collection and monitoring procedures, emission factors, and data verification requirements for projects that capture methane from manure management systems. Chapter 5 of the protocol lays out methods and equations to quantify greenhouse gas emission reductions from a project, including establishing the project baseline, and Appendix A has the emission factors to be used in the quantification methodology. Chapter 6 specifies the data collection and monitoring procedures of the protocol. The protocol also includes an additionality evaluation component found in Chapter 3 (Eligibility). The protocol addresses uncertainty by having rigorous data collection and monitoring procedures and includes a methodology for data substitution if necessary as found in Appendix B. The protocol also has a verification requirement in Chapter 8 that requires a CARB accredited offset verification body to verify all GHG reductions or GHG removal enhancements from a livestock manure management systems project.
Methane derived from municipal solid waste - The Commission has selected Version 2.0 of the "Landfill Gas Destruction and Beneficial Use Projects" methodology (April 2021; Errata & Clarification October 25,2022) issued by ACR to quantify GHG emission reductions or GHG removal enhancements for methane derived from municipal solid waste. This protocol meets the requirements in the statutory definition of "recovered methane protocol" by clearly identifying data collection and monitoring procedures, emission factors, and data verification requirements for projects that capture methane from municipal solid waste. Chapter 3 of the protocol summarizes how to make a baseline determination and perform an additionality assessment for the project. Chapter 4 lays out methods and equations to quantify greenhouse gas emission reductions from the project and addresses leakage issues, which the protocol indicates does not apply to landfill gas projects.
Appendix B has the emission factors to be used in the application of the protocol. Chapter 5 specifies the data collection and monitoring procedures of the protocol. The protocol addresses uncertainty by having rigorous data collection and monitoring procedures. Validation and verification requirements for use of the protocol and confirming the GHG reductions or GHG removal enhancements from a municipal solid waste methane recovery project will be met by a body or organization accredited under the Accreditation Program for Greenhouse Gas Validation/Verification Bodies (GHGVVB) of the ANSI National Accreditation Board (ANAB) as required under Part C, Section I.C.7.a. All bodies accredited under GHGVVB to perform verification services for a specific project type utilizing an ACR protocol or methodology are acceptable to ACR so long as ACR's requirements and approval to conduct verification for the specific project type have also been met (see exhibit "ACR VV Standard_V1.1_May 31 2018" and ACR Validation and Verification requirements at https://americancarbonregistry.org/carbon-accounting/verification/verification).
Methane derived from wastewater treatment - The Commission has selected Version 2.1 of the "Organic Waste Digestion Protocol" (January 16, 2014; Errata and Clarifications November 1, 2018) issued by the Climate Action Reserve (CAR) to quantify GHG emission reductions or GHG removal enhancements for methane derived from wastewater treatment. This protocol meets the requirements in the statutory definition of "recovered methane protocol" by clearly identifying data collection and monitoring procedures, emission factors, and data verification requirements for projects that capture methane from waste water treatment. Chapter 5 of the protocol lays out methods and equations to be used in order to quantify greenhouse gas emission reductions from a project, including establishing the project baseline, and Appendix B has emission factors to be used in the quantification methodology. Chapter 6 specifies the data collection and monitoring procedures of the protocol. The protocol addresses uncertainty by incorporating baseline and project uncertainty factors into its calculation methodologies. The protocol also includes an additionality evaluation component found in Chapter 3 (Eligibility Rules) and a verification requirement in Chapter 8. Verification requirements for use of the CAR protocol and confirming the GHG reductions or GHG removal enhancements from a wastewater treatment methane recovery project will be met by a body or organization accredited under the Accreditation Program for GHGVVB of the ANAB as required under Part C, Section I.C.7.a.
All bodies accredited under GHGVVB to perform verification services for a specific project type utilizing a CAR protocol are acceptable to CAR so long as CAR's requirements to conduct verification for the specific project type have also been met. CAR will conduct validation of projects that use its protocols. As the CAR protocol applies only to certain wastewater treatment facilities, Section I.C.4.a., also provides that Facilities or operations that exclusively accept or rely on livestock manure must use CARB's "Compliance Offset Protocol finalized on November 14, 2014 because this protocol is specific to that type of operation. Per Part C, Section I.C.7.b., verification under the CARB protocol must be completed by an entity accredited by CARB for this type of project.
The Commission also adopted a novel protocol for domestic wastewater treatment facilities using anaerobic digesters at Section I.C.4.b. This protocol is necessary because it is the practice and regulatory expectation in Colorado that such facilities capture and either control or use methane from anaerobic digesters, irrespective of any recovered methane program. However, to the extent that a facility elects to deliver methane it captures for use instead of on-site destruction, the Commission recognizes that there is an additional GHG emission reduction benefit that should qualify for a recovered methane credit based on the recovered methane not being destroyed on-site through flaring and instead displacing use of geological gas supplied by a gas utility. The protocol established in Section I.C.4.b. meets the requirements in the statutory definition of "recovered methane protocol" by clearly identifying data collection and monitoring procedures, emission factors, and data verification requirements for projects that capture methane from domestic wastewater treatment facilities using anaerobic digesters. The protocol clearly establishes the project baseline, identifies data collection and monitoring procedures, emission factors, and data verification requirements for projects that capture methane from domestic waste water treatment facilities using anaerobic digesters. Project baselines are determined pursuant to Section I.C.4.b.(i) and Section I.C.4.b.(ii) sets out the means of assuring emissions reductions are additional. Data collection, monitoring procedures, and emission factors are addressed in Section I.C.4.b.(iii) through I.C.4.b.(vi). As the emissions savings from this type of project are based entirely on combusting recovered methane instead of geological gas in an end-use and therefore focused on methane combustion, the procedures and methodologies set forth in Subpart NN of 40 CFR Part 98, governing GHG emissions reporting from suppliers of natural gas and natural gas liquids, are sufficiently analogous to use for this protocol.
Thus, the Commission incorporates by reference the applicable provisions of Subpart NN for this protocol. Data verification requirements and minimizing uncertainty in the emission reductions are addressed in Section I.C.4.b.(vi). There, the Division recommends incorporating the existing monitoring, quality assurance and quality control requirements, and data reporting in 40 CFR §§ 98.404-406 as appropriate means of quantifying emissions reductions from these facilities insofar as they are applicable to the emissions calculation provisions of 40 CFR § 98.403. The third-party verification process will confirm that the protocol requirements were followed to establish emission reductions. The Division will work with ANAB to establish validation standards to be followed for the protocol.
Coal mine methane - The Commission has selected Version 1.1 of the "Capturing and Destroying Methane from Coal and Trona Mines in North America" methodology (August 2022) issued by the American Carbon Registry (ACR) to quantify GHG emission reductions or GHG removal enhancements for coal mine methane. This protocol meets the requirements in the statutory definition of "recovered methane protocol" by clearly identifying data collection and monitoring procedures, emission factors, and data verification requirements for projects that capture coal mine methane. Chapter 5 of the protocol lays out methods and equations to quantify greenhouse gas emission reductions from a project, including establishing the project baseline, and Appendix A has the emission factors to be used in the quantification methodology. Chapter 6 specifies the data collection and monitoring procedures of the protocol. The protocol addresses uncertainty by having rigorous data collection and monitoring procedures. The protocol also includes an additionality evaluation component found in Chapter 3 (Eligibility) and has a verification requirement in Chapter 7.
Verification requirements for use of the protocol and confirming the GHG reductions or GHG removal enhancements from a coal mine methane project will be met by a body or organization accredited under the Accreditation Program for GHGVVB of the ANAB as required under Part C, Section I.C.7.a. All bodies accredited under GHGVVB to perform verification services for a specific project type utilizing an ACR protocol or methodology are acceptable to ACR so long as ACR's requirements and approval to conduct verification for the specific project type have also been met.
Gas distribution system leaks - The Division's review of available gas distribution system leak accounting approaches did not identify any published protocols that quantified system leakage for purposes of creating recovered methane credits as described in §§ 40-3.2-108 and 25-7-105(1)(e) (X.4), C.R.S. Hence, the Division proposes a novel protocol in Section I.C.6. In order to verify additionality and for recovered methane credits to be issued, individual repaired leaks must not be part of the utility's required leak detection and repair procedures and emissions reduced must be quantified following written procedures in Part C, Section I.C.6. The written procedures must identify the measurements and other data required to be collected in order to quantify the mass emissions of methane, the processes and instrumentation used to collect the data, and the quality assurance requirements necessary to ensure accurate measurements from the instrumentation for each leak. Section I.C.6.a.(ii)(C) sets out the requirements for confirming that a leak is repaired and no longer emitting gas. Section I.C.6.a.(ii)(C)(1) provides the parameters that an applicant's procedure must satisfy to confirm leak repairs and is intended to allow reasonable flexibility while ensuring certainty that emissions reductions from repaired leaks are real and verified. As used in Section I.C.6.a.(ii)(C)(2), the detection sensitivity of equipment or techniques used for post-repair verification must be at least as capable of detecting emissions from the repaired equipment as that which was used for initial measurement. As recognized in Section I.C.6.a.(ii)(C)(3),certain leaks may be mitigated by removing the equipment or component permanently from the gas distribution system, in which case a post mitigation measurement is not possible. The Division will review and approve the proposed methodologies in the written procedures submitted by the company and the third-party verification process will confirm that the written procedures were followed and that all data required in the procedures was collected. The Division will work with ANAB to establish validation standards to be followed for the protocol.
Double-counting of emissions reductions in a Clean Heat Plan filing is avoided because any referenced methods utilized in a gas utility's projected future emissions cannot also generate recovered methane credits under this program. Any utility applying for credits under Section I.C.6. must certify that any leak repairs for which credits are sought are not included as part of the system planning baseline and projected emissions in a proposed or approved Clean Heat Plan. The Division may confirm this by reviewing the applicant's Clean Heat Plan. Conversely, it is the Commission's understanding of the Public Utilities Commission's rules in 4 Colo. Code. Regs. 723-4 that emissions changes in a proposed or approved Clean Heat Plan resulting from revised federal reporting requirements or advanced leak detection and repair obligations enacted by the Colorado Public Utilities Commission or other regulatory agency are included as part of the Clean Heat Plan baseline and projected emissions and not as a clean heat resource for which recovered methane credits are required to be utilized. Finally, this recovered methane protocol does not have activity- or market-shifting leakage risks as the methane is already in the distribution pipeline.
Under Sections I.C.2.b., I.C.3.b., I.C.4.c., and I.C.5.b., project developers or operators are required to account for any vehicular emissions from the delivery of recovered methane to a dedicated pipeline, common carrier pipeline, or directly to an end user in Colorado. Vehicle fuel use attributable to delivery under these provisions is to include any vehicle fuel consumed for travel to or from the project site to retrieve or gather the recovered methane, for any gathering or collection activities, and travel to or from a project site for delivery of recovered methane to a dedicated pipeline, common carrier pipeline, or directly to an end user in Colorado.
The Commission has determined the protocols selected will not have activity- or market-shifting leak age risks as the recovered methane protocols are intended to spur and assist in the development of projects that reduce greenhouse gas emissions in Colorado but do not create an incentive for those utilizing the protocols to then undertake activities that increase greenhouse gas emissions outside Colorado.
As the Commission is incorporating by reference a number of existing protocols, the Commission is cognizant that future rulemakings will be necessary to update these incorporations. Likewise, the Commission recognizes that the landscape of greenhouse gas accounting, including recovered methane protocols, is ever-evolving and that additional protocols for additional recovered methane project types may be appropriate for future amendments to this Part C. As such, the Commission encourages the Division and stakeholders alike to monitor and evaluate developments in this field to ensure Colorado continues to employ best practices for assessing emissions reductions and assigning corresponding recovered methane credits, and to incorporate these new or updated protocols into these rules by written comment only rulemaking as appropriate.
One area of particular interest expressed by stakeholders is the possibility of Colorado adopting a single recovered methane protocol for all project types and the possibility to use a "life-cycle analysis" approach for assessing emissions reductions. Hence, any person or entity may submit to the Division an assessment of the benefits and costs associated with development and implementation of a single combined recovered methane protocol for determining credits for recovered methane projects from manure management systems, municipal solid waste, wastewater treatment, coal mine methane, and any other projects contemplated in SB 21-264 as applicable. Such assessment should include, but is not necessarily limited to, an assessment of a single combined recovered protocol that considers the life-cycle emission impacts of the project to recover methane from manure management systems, municipal solid waste, wastewater treatment, coal methane, and any other projects contemplated in SB 21-264 as applicable, as well as a life-cycle emission evaluation or methodology for the geological gas the recovered methane would be replacing. Any assessment shall evaluate the anticipated costs to the Division for implementing such a protocol instead of those adopted in this proceeding, as well address all requirements that apply to recovered methane protocols in SB 21-264.
In order to facilitate a full evaluation of any such assessment, the entity should provide the Division a proposed framework for the assessment, including an outline of the evaluation of the benefits and costs that will be conducted as part of the assessment. The Division will evaluate any such framework within a reasonable time (with a goal of completing such evaluation within 90 days of receipt) and work with the person or entity developing the assessment. The Division will also ensure that any calculation methodologies for emissions intensity are consistent with all relevant calculation methodologies under air quality regulations, guidance, or policy. The entity may also provide the Division a draft of the assessment prior to finalization and the Division will provide feedback on the proposed draft within a reasonable time (with a goal of responding within 90 days of receipt). The Division may elect to submit such a proposal for a single recovered methane protocol to the Commission for adoption. Within 180 days of receiving the final assessment, the Division must notify the entity of whether it will submit a proposal to the Commission.
Procedures for Approving Entities Verifying GHG Reductions or Removal Enhancements
Consistent with § 40-3.2-108(2)(p), C.R.S., recovered methane protocols must "[s]pecify 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." The Commission has therefore required that all greenhouse gas reduction or removal enhancements be verified by an accredited third-party. See Part C, Section I.C.7.
The Commission has determined that any entity engaged to verify ongoing GHG emission reductions must, itself, be accredited to conduct such verification through the Accreditation Program for Green house Gas Validation/Verification Bodies of the ANSI National Accreditation Board (ANAB), or for manure management system projects, be accredited by CARB for that project type.
ANAB accreditation for Greenhouse Gas Validation/Verification is a rigorous and extensive process in which applying bodies must demonstrate technical competency and implementation of applicable verification standards specific to greenhouse gas emissions. Namely, ANAB requires a verifying body to faithfully implement the most current version(s) of ISO 14065 required by ANAB for accreditation and to conduct verification. Currently, this includes ISO 14065:2013, Greenhouse gases - Requirements for green house gas validation and verification bodies for use in accreditation or other forms of recognition, and ISO 14065:2020, General principles and requirements for bodies validating and verifying environmental information. ANAB is requiring that verification bodies or entities transition accreditation to ISO 14065:2020 before the end of June 2024. ANAB also requires technical competency and implementation of ISO 14064-3:2019, Greenhouse gases - Part 3: Specification with guidance for the validation and verification of greenhouse gas assertions, and ISO 14066:2011, Greenhouse gases -Competence requirements for greenhouse gas validation teams and verification teams, for validation bodies or entities, with ISO 14064-3: 2019 and 14066 being incorporated into ISO 14065 as normative references.
The application and accreditation process is explained here https://anab.ansi.org/greenhouse-gas-validation-verification/how-to-apply.
Once accredited, ANAB further requires ongoing surveillance of accredited entities and reassessment every three years. ANAB maintains a current list of accredited entities, which can be found here: https://anabpd.ansi.org/Accreditation/environmental/greenhouse-gas-validation-verification/AllDirectoryListing?prgID=200&statusID=4.
Requiring that recovered methane projects be verified by entities accredited through this robust, pre-existing program, the Commission intends to guarantee that recovered methane credits generated and used for clean heat plan compliance are real, additional, quantifiable, and verifiable. As of July 2022, there are 20 verifying bodies accredited under this program.
For projects for biomethane from manure management systems, which must use the "Compliance Offset Protocol Livestock Projects" adopted by CARB on November 14, 2014, the verifying body must be accredited through CARB for that project type. CARB's accreditation program for greenhouse gas emissions is found at California Code of Regulations, Title 17, § 95132, and the provisions specific to its offset protocols that are relevant here are at California Code of Regulations, Title 17, § 95978.
A list of CARB-accredited verification bodies is available at: https://ww2.arb.ca.gov/resources/documents/accredited-offset-verification-bodies.
Should the Division or other stakeholders identify accreditation bodies or third-party verification programs that are deemed sufficiently rigorous in addition to those identified in this proceeding, the Division or any person or entity may petition the Commission to amend these rules accordingly.
Crediting and Tracking System
In conjunction with the protocols in Part C, Section I.C., the Commission established in Part C, Section 1.D.a. crediting and tracking system for recovered methane credits consistent with § 25-7-105(1)(e) (X.4), C.R.S. This system is currently limited in scope to recovered methane credits and their limited use in clean heat plan compliance under § 40-3.2-108(3), C.R.S., for gas distribution utilities and small gas distribution utilities, and § 25-7-105(1)(e) (X.4), C.R.S., for municipal gas distribution utilities. Recovered methane credits are not general purpose "GHG credits" that can be traded or used to meet GHG compliance obligations by "regulated sources," as that term is defined in § 25-7-105(1)(f)(B), C.R.S. The recovered methane crediting and tracking system established in Part C, Section I.D. provides the exclusive forum for the trading of recovered methane credits generated through qualifying projects, verified through approved protocols, and used by utilities for clean heat plan compliance.
It is critical that credits are rigorously tracked to ensure the environmental attributes are not double-counted since once credits are issued, they become fully tradable until they are retired or otherwise expire.
Accordingly, the system functions in four phases:
Registration - Under Part C, Section I.D.1.a., entities wishing to participate in the recovered methane crediting and tracking system must register with the Division and identify authorized users. Through the registration process, it is necessary that authorized users bind the entities they represent as they will be able to request the transfer of credits in the system.
Project Submission - Under Part C, Sections I.D.1.b. through I.D.1.i., I.D.3., and I.D.4., prior to the generation of any recovered methane credits, the Division must receive information sufficient to demonstrate that the applicant's project satisfied all statutory requirements and guarantee all emissions reductions or removal enhancements are real, additional, quantifiable, permanent, verifiable, and enforceable.
As set forth in Part C, Sections I.D.1.g. and I.D.3, applicants seeking credits for recovered methane projects for municipal solid waste and coal methane must first register with the ACR and establish credits in that system for the project. Then, in order for ACR credits to be used in Colorado's recovered methane tracking system, the applicant must cancel the ACR credits without using them and provide such evidence to the Division as part of its project submission. Pursuant to American Carbon Registry, Requirements and Specifications for the Quantifications, Monitoring, Reporting, Verification, and Registration of Project-Based GHG Emissions Reductions and Removals (Dec. 2020), to be eligible under ACR, new projects must be validated within two years of the project Start Date, with limited exceptions defined in the Standard.
Under Part C, Sections I.D.1.g. and I.D.4., the same process applies for applicants seeking credits for recovered methane projects for wastewater treatment for which credits must first be established at the Climate Action Reserve (CAR) Reserve Offset Program. Pursuant to the Version 2.1 of the "Organic Waste Digestion Protocol" (January 16, 2014; Errata and Clarifications November 1, 2018) at Section 3.2, to be eligible for registration with CAR, projects must be submitted to CAR no more than six months after the project start date.
And, under Part C, Sections I.D.1.g. and I.D.5. the same process also applies for applicants seeking credits for recovered methane projects for manure management systems if those projects are first registered in a registry outside of the recovered methane system.
For all projects, the recovered methane credit in the Colorado system must represent the attribute of onemetric ton of carbon dioxide equivalent reduced using the 100-yr value from the IPCC's Fourth Assessment Report (AR). In addition to the requirements of the protocols specified under Section I.C., applicants must provide information sufficient to demonstrate that any project for which credits are sought meet the particular requirements of SB21-264 and this Part C.
One such requirement is a demonstration that the recovered methane project where emissions reductions are credited be physically located in Colorado. Though the Commission is aware that certain parties to this proceeding have advocated for allowing recovered methane credits to be generated from projects located outside of Colorado, the Commission has determined that only projects located inside Colorado are eligible for generating recovered methane credits. The Commission makes this determination to remain consistent with the General Assembly's direction that recovered methane means biomethane and methane derived from specified sources "that are located in Colorado and meet a recovered methane protocol approved by [this Commission]." § 40-3.2-108(2)(n), C.R.S.
Further, requiring that recovered methane projects be in Colorado is necessary to ensure that the emissions reductions realized through such projects and that the credits then utilized by gas utilities for clean heat plan compliance reflect reductions in statewide greenhouse gas emissions. While it is possible that SB21-264 could be interpreted differently and that reductions in greenhouse gas emissions outside of Colorado will also have the effect of slowing climate change, such a reading would fail to further Colorado's interests in reducing statewide greenhouse gas pollution towards the goals established by the General Assembly in § 25-7-102(2), C.R.S. and would therefore be contrary to the clearly stated legislative intent of SB 21-264. See § 40-3.2-108(1)(a), C.R.S. (citing the need to reduce greenhouse gas emissions from the built environment "in order to achieve Colorado's science-based greenhouse gas emission reduction goals and maintain a healthy, livable climate for Coloradoans").
Section I.D.1.e. requires an applicant to provide proof that recovered methane has been delivered to or within Colorado through a "dedicated pipeline" or "common carrier pipeline." SB 21-264 does not define "dedicated pipeline." Pursuant to feedback from parties to this proceeding, the Commission adopted a definition of "dedicated pipeline" at Section I.B.7. that aligns with the legislative intent to reduce GHG emissions in Colorado by replacing geological gas with recovered methane while broadly accounting for the practical realities of potential recovered methane projects in Colorado. This approach, sometimes referred to as a "virtual pipeline" allows for recovered methane to be transported in point-to-point pipelines, but also through other conveyances such as trucks. It would also allow direct delivery of the gas from the recovered methane project to the end user, without requiring that it be injected into a utility's distribution system so long as the project developer can demonstrate that but for the recovered methane, the end-user would be consuming geologic gas from a utility. To this end, the proof that recovered methane is replacing geological gas required under Section I.D.1.e.(i) is not intended to be an engineering or technical showing but rather a demonstration that recovered methane is serving a demand that would otherwise be fulfilled with geological gas. This could be satisfied with proof of delivery of the recovered methane to its end use, gas utility bills showing that the end use was formerly served by a gas utility, or similar showings.
Division Review and Credit Generation- upon receipt and verification of a complete submission under Part C, Section I.D.1., the Division will generate recovered methane credits for the project in the system. Sections I.D.1.e. through I.D.1.i. detail how the credits will be entered and tracked in the system in a manner that will avoid double-counting of credits. Further, these sections provide for a system that requires that recovered methane credits generated and used in the system are directly traceable to the specific project from which they were created. The Division will retain the ability to audit and evaluate all credit balances and generate reports that will be made publicly available.
Credit Trading and Use/Retirement and Expiration - As indicated in Part C, Section I.D.2.c., recovered methane credits are active and tradable for twelve months after they are generated. This is consistent with treatment of these credits as a clean heat resource in clean heat plans. See § 40-3.2-108(2)(c), C.R.S. ("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."); see also § 40-3.2-108(7)(b) ("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."). During this period, the credits in the system are fully tradable between and amongst registered entities. Within twelve months from generation recovered methane credits must be used and retired as a clean heat resource for clean heat compliance, see § 40-3.2-108(2)(c), C.R.S., otherwise they will expire and can no longer be used or traded.
Incorporation by Reference
Section 24-4-103(12.5) of the State Administrative Procedure Act allows the Commission to incorporate by reference a code, standard, guideline, or rule that has been adopted by an agency of the United States, this state, or another state, or adopted or published by a nationally recognized organization or association. The criteria of § 24-4-103 (12.5), C.R.S., are met by including specific information and making the regulations available because repeating the full text of each of the federal regulations incorporated would be unduly cumbersome and inexpedient. To fully comply with these criteria, the Commission includes reference dates to protocols, standards and reference methods incorporated in Regulation Number 22.
Additional Considerations
Section 25-7-110.5(5)(b), C.R.S.
To the extent these revisions exceed and may differ from the federal rules under the federal act, in accordance with § 25-7-110.5(5)(b), C.R.S., the Commission determines:
There are no federal requirements applicable to this situation. Furthermore, Part C establishes a fully voluntary, opt-in program therefore any part of the rule that "exceeds the requirements of the federal actor differs from the federal act or rules thereunder" would be voluntarily submitted to and not mandated by this rule.
There are no federal requirements applicable to this situation.
In SB 21-264, Colorado's General Assembly found that "a significant source of [GHG] 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 the commercial and industrial processes, and from gas leaks in the supply chain." § 40-3.2-108(a)(II), C.R.S. Further, the General Assembly determined that "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..." § 40-3.2-108(1)(b)(I), C.R.S. Hence, the General Assembly established clean heat plan requirements, while providing an option for utilities to use recovered methane as a clean heat resource to accomplish certain amounts of emissions reductions in those plans.
There are no federal requirements applicable to this situation.
The allowance for meeting clean heat targets through the use of recovered methane credits is explicitly made available to utilities as a means of more cost-effectively meeting those targets. See § 40-3.2-108(1)(b), C.R.S. The protocols identified for these recovered methane projects are already in use in other jurisdictions and therefore allow project developers to utilize existing resources, including the American Carbon Registry and Climate Action Reserve's existing registry systems. Furthermore, utilization of these protocols and the crediting and tracking system is entirely voluntary for utilities.
There are no federal requirements applicable to this situation nor any conflicting regulatory regimes that require clarification.
There are no federal requirements applicable to this situation.
The proposed regulation does not impose any mandatory requirements. Rather, it provides a system for regulatory flexibility for utilities to comply with clean heat targets through the use of recovered methane credits. The protocols and recovered methane crediting and tracking system adopted in this Part C in herently provide accommodation for uncertainty and future growth for utilities by providing a mechanism for achieving a portion of their clean heat targets irrespective of customer demand. For recovered methane project developers, there is no mandatory compliance requirement but the protocols and trading system are entirely scalable and therefore accommodate uncertainty and future growth.
The recovered methane protocols and crediting and tracking system in this voluntary, opt-in program are equitable for both project developers seeking to generate credits on the system and for utilities seeking to acquire and utilize those credits. Notably, Colorado's General Assembly determined that reducing emissions through recovered methane and biomethane projects provides "significant economic development opportunities, especially in rural Colorado[.]" § 40-3.2-108(1)(b)(I), C.R.S.
Arguably, the more stringent the requirements for recovered methane protocols or the more restrictive the crediting and tracking system would impose higher barriers to entry and potentially limit participation where it is not cost-effective. However, this itself would not increase costs but limit the cost-effectiveness of this voluntary, opt-in program.
There are no federal requirements applicable to this situation.
Yes, both the recovered methane protocols and the crediting and tracking system are based on demonstrated and available technology.
See responses to Items (III) and (IV) of this section.
While the Commission had options in which recovered methane protocols to select and how to design the crediting and tracking system, it has done so leveraging existing and tested options where available.
These rules are required under § 25-7-105(1)(e) (X.4), C.R.S., and a no-action alternative is not available.
Findings of Fact
To the extent that § 25-7-110.8, C.R.S., requirements apply to this rulemaking, and after considering all the information in the record, the Commission hereby makes the determination that:
5 CCR 1001-26-E-VI