Colo. Rev. Stat. § 40-2-120, Rail transportation policy

In regulating rail carriers, the state of Colorado hereby adopts the rail transportation policy of 49 U.S.C. sec. 10101; except that the references therein to the United States government and its agencies shall refer to the state of Colorado and its agencies.

Source: L. 84: Entire section added, p. 1036, � 1, effective July 1. L. 2001: Entire section amended, p. 1281, � 59, effective June 5.

40-2-121. Transportation of natural gas report - legislative declaration. (Repealed)

Source: L. 96: Entire section added, p. 985, � 1, effective May 23.

Editor's note: Subsection (3) provided for the repeal of this section, effective July 1, 1998. (See L. 96, p. 985.)

40-2-122. Natural gas - deregulation of supply - voluntary separation of service offerings - consumer protection - legislative declaration - definition - rules. (1) The general assembly finds, determines, and declares that natural gas service is essential to the health and well-being of all Colorado natural gas customers. The general assembly further finds, determines, and declares that natural gas is traded in competitive markets at the wellhead and in downstream markets for sale to utilities, industrial customers, and large commercial customers and there may be the potential for natural gas also to be traded competitively for sale to all other classes of consumers. As a result, it may be predicted that competition in the natural gas supply market may increase the choices available to consumers and reduce the price of such service. Accordingly, it is the policy of the state of Colorado to encourage competition after a reasonable transition period during which consumers are educated about choices in natural gas supply that are now available or will be available in the future. The commission is authorized to approve voluntary plans consistent with this section that separate the sale of natural gas to retail customers into natural gas delivery and natural gas supply and, after a transition period, deregulate the charge for natural gas supply where the commission finds that the plan provides customers with adequate choices, ensures the provision of reliable natural gas supply on a fallback basis on terms and conditions that are just and reasonable to all customers, promotes the development of a competitive market for gas supply, limits the unreasonable exercise of market power, and retains and enhances programs to support low-income consumers.

(2) (a) Natural gas public utilities shall continue to be regulated with respect to their delivery functions and shall be required to continue to offer nondiscriminatory natural gas delivery services over their pipeline systems so that Colorado natural gas consumers, both individually and on an aggregated basis, shall have ready access to natural gas supply from among competing sources.

(b) Any natural gas public utility providing for individual consumer choice between competing suppliers shall implement a separately stated distribution charge, applicable to all customers regardless of the identity of the natural gas supplier and denoted as a public benefits charge, to help defray the costs associated with funding low-income energy assistance programs such as bill assistance and weatherization for residential energy consumers in Colorado, subject to the following conditions:

(I) The total amount collected annually through such public benefits charge shall be at least three-quarters of one percent of the real dollar equivalent of each utility's 1998 nominal-dollar regulated gas revenues received for the geographic area or group of customers that is subject to the plan. Additionally, within one year following the implementation of the first natural gas supplier choice program by a natural gas utility that affects a significant number of low-income households, the public benefits charges for all natural gas public utilities that have implemented a voluntary plan shall be set at a level sufficient to raise a total additional sum of one hundred fifty thousand dollars to fund the study provided for in subsection (12) of this section.

(II) The public benefits charge shall be separately stated on each customer's bill for natural gas delivery service in the same manner and with the same prominence as is the charge to defray the utility's transition costs; and

(III) The public benefits charge shall be imposed on all natural gas delivered by the utility in a manner that is competitively neutral and nonbypassable.

(c) The governing body of each municipal utility providing natural gas service shall have the authority to consider and approve or reject a voluntary plan submitted by the natural gas municipal utility, for all or a portion of its service territory, that provides for:

(I) The separation of natural gas service into natural gas supply service and natural gas delivery service; and

(II) The deregulation of municipal natural gas supply service. In making a determination to approve or reject the voluntary plan submitted, the governing body shall apply the criteria set forth in paragraph (c) of subsection (3) of this section, but only to the extent applicable to municipal utility operations.

(d) (I) If the governing body of a municipality approves a plan for the voluntary separation of natural gas service offerings and the deregulation of natural gas supply, the municipal utility may request authority from the governing body of the municipality to treat any proposed contracts or agreements for natural gas supply service being negotiated by the municipal utility as confidential information until such contracts or agreements are formally executed. Upon such request, the governing body of the municipality shall hold a hearing to determine whether confidential treatment of such contracts is warranted in order to allow the municipal utility to compete effectively as a provider of natural gas supply service.

(II) If, after a hearing pursuant to subparagraph (I) of this paragraph (d), the governing body determines that confidential treatment of the contracts is warranted, then:

(A) Such contracts shall not be subject to public disclosure under section 24-72-203, C.R.S., until formally executed by the parties; and

(B) Discussion by the governing body of such contracts or the contents thereof prior to execution may properly be the subject of an executive session, as the term is used in section 24-6-402, C.R.S. This paragraph (d) shall not be construed to limit or condition the governing body's authority to meet in executive session for any other reason enumerated in section 24-6-402, C.R.S.

(e) The commission or other governing body shall retain the authority to establish guidelines regarding gas transportation service. Such guidelines may include, but are not limited to, provisions concerning the establishment of rates, terms, and conditions for the provisioning of gas transportation services by a natural gas public utility, regardless of whether the utility has an approved voluntary plan.

(3) (a) The commission is hereby granted the authority to consider and approve, reject, or approve with modifications a voluntary plan submitted by a natural gas public utility, for all or a portion of its service territory, that:

(I) Provides for the separation of natural gas service into natural gas supply service and natural gas delivery service; and

(II) Allows for competition in natural gas supply service.

(b) The commission may also consider and approve, reject, or approve with modifications as a part of any plan submitted in accordance with paragraph (a) of this subsection (3), the proposal of a natural gas public utility to participate as a competing supplier of natural gas. If the commission finds that a utility's plan meets the criteria set forth in paragraph (c) of this subsection (3) and is in the public interest, the commission shall approve the plan. If the plan is approved or approved with modifications, the commission shall determine the requirements or conditions under which the natural gas public utility shall be permitted to offer supply service. The commission may, without limitation, determine that the natural gas public utility shall be permitted to compete as a supplier of natural gas on an unregulated basis or determine that the natural gas public utility shall be permitted to compete as a supplier of natural gas on an unregulated basis only through an affiliate. Alternatively, the commission may establish such requirements or conditions as are in the public interest considering the market position of the natural gas public utility. After the plan is approved, all natural gas supply service, other than fallback service, established under the plan as a competitive service shall thereafter be sold on an unregulated basis without an obligation to serve.

(c) The commission shall not approve a plan submitted pursuant to subsection (3)(a) of this section unless the price charged for natural gas delivery services does not subsidize natural gas supply service under the plan and, in addition, the plan:

(I) Provides for nondiscriminatory natural gas delivery service over the public utility's pipelines so that all natural gas consumers covered by the plan, including those who are currently transportation customers of the natural gas public utility, shall have ready access to natural gas supply service from competing sources;

(II) Does not present any unnecessary barriers that prevent or reduce ready access to natural gas supply service for all classes of consumers, including ensuring nondiscriminatory access to upstream capacity and storage services by all competitors;

(III) Establishes safeguards to eliminate the unreasonable exercise of market power by any person to the detriment of consumers or competitors;

(IV) Provides for consumer protection deemed necessary by the commission to assure reliable natural gas supply service, taking into consideration the needs of consumers. Such protections may include, but shall not be limited to, backup gas supply availability, excess peak day supply margins, standards of conduct, and full-rate recovery of any prudent costs incurred by a natural gas public utility related to any reasonable efforts the utility may undertake to avoid gas supply interruptions to consumers served by its delivery system.

(V) Further provides for those consumer protections deemed necessary by the commission to assure that fallback retail natural gas supply service, on a firm basis with adequate backup, is available to customers under reasonable terms and conditions. Such fallback retail natural gas supply service protection may or may not be provided by the incumbent natural gas public utility. These protections shall include, but are not limited to, the development of a commission-approved standard offer gas supply service or the use of a commission-approved competitive bidding process to assure that natural gas supply is available at fair and reasonable prices for those customers who do not receive supply offers, who do not select a competitive natural gas provider, who are refused service by a supplier, whose service is canceled by a supplier, who need service while moving or during other transitions, or whose supplier fails to supply service. If a utility provides regulated fallback service, the utility shall be allowed to recover all prudently incurred costs related to the provision of fallback supplies through regulated standard offer gas supply service.

(VI) Provides for consumer education concerning the natural gas public utility's restructuring of its rates and the choices that will be made available to consumers in the competitive supply market;

(VII) Does not degrade the integrity or reliability of natural gas delivery service or of any upstream third-party pipeline and storage services that are necessary to maintain such reliability and that may be held by the public utility as part of the plan; except that this subparagraph (VII) shall not preclude the necessary upstream third-party pipeline and storage services from being held by competitive natural gas providers unless the commission finds that such condition results in a degradation of the integrity or reliability of natural gas distribution service;

(VIII) Provides for funding of low-income energy assistance programs such as bill assistance and weatherization through the assessment of a separately stated distribution charge, denoted a public benefits charge, consistent with the authority of the utility to collect the public benefits charge as established in this section. The moneys received through the implementation of the public benefits charge shall be administered by the Colorado energy assistance foundation, which is the entity created under section 40-8.5-104, or its successor, to be used for the purposes of low-income energy assistance payments and programs, low-income weatherization assistance and programs, low-income energy education, and energy conservation. The Colorado energy assistance foundation shall file a report with the commission annually showing amounts of money collected under the public benefits charge and demonstrating that the moneys were used to fund low-income energy assistance programs as established herein.

(IX) Contains all terms and conditions that the commission deems necessary to protect the public interest and to foster competition in the supply of natural gas, including, without limitation, terms and conditions that address the following issues:

(A) The manner in which price and terms and conditions should be disclosed;

(B) The extent to which natural gas utilities and suppliers are obligated to serve all customers;

(D) The terms under which service may be discontinued;

(E) How partial payments are allocated;

(F) Protecting customer privacy;

(G) Prohibiting unfair and deceptive marketing practices; and

(H) The degree of access to customer information needed by suppliers to promote competition;

(X) Provides that, as an aspect of implementing the plan, no consumer's natural gas supplier may be changed without the consumer's prior express consent except as ordered by the commission. Either through rule-making or through consideration of methodology proposed in the plan, the commission shall establish allowable express consent verification methods which may include written confirmation, third-party oral confirmation, or other appropriate procedures. The commission shall also establish and determine the extent to which a supplier who causes consumers to be changed without their consent is liable to those consumers and their chosen providers.

(XI) Provides for funding of the commission and the office of the utility consumer advocate based upon a charge to end-use customers, as determined by the commission, as a part of the natural gas delivery function, regardless of the identity of the natural gas supplier. Such new funding method must be competitively neutral and shall be designed to generate annual revenues equivalent to the average annual revenues generated under sections 40-2-109 to 40-2-114 during calendar years 1994 to 1998 associated with the sale of natural gas service from the geographic area or group of customers affected by the plan. Whenever such new funding method is instituted for any specific geographic area or group of customers, the natural gas public utilities serving the area or group shall no longer pay the fees that would otherwise have been required under the sections.

(XII) (A) Maintains regulated, cost-based rates for gas supply service from the public utility until such time as, in the aggregate, no less than thirty-three and one-third percent of the customers covered by a plan are served by competitive natural gas providers, which may include affiliates of the public utility; there are a minimum of five competitive natural gas providers not affiliated with the public utility unless the commission determines that, in geographic areas covered by the plan, less than five competitive natural gas suppliers provide effective competition; and the competitive natural gas suppliers not affiliated with the public utility serve no less than eighteen percent of the customers covered by a plan. When these conditions are met, the public utility supply service to the geographic area or to customers covered by a plan may be deregulated and the fallback supply provision of the plan shall become effective.

(B) For purposes of this subparagraph (XII), the number of customers served by competitive natural gas suppliers shall be determined based on the number of natural gas meters served by competitive natural gas suppliers in the geographic area covered by the plan, other than those meters served under the natural gas utility's gas transportation tariffs at the time the plan is implemented, whether directly or through a marketer or broker, compared to the total number of natural gas meters in the geographic area covered by the plan.

(4) If the commission approves a natural gas public utility's voluntary plan with modifications, the utility shall have the option to reject the modified plan and continue to be regulated as before. However, if a natural gas public utility exercises this option, it may not file another voluntary plan for a minimum of two years unless otherwise permitted by the commission and it may not recover in rates the costs and administrative charges incurred associated with the design and litigation of its voluntary plan proposal.

(5) The department of revenue is hereby authorized to collect funding for the commission and the office of the utility consumer advocate in accordance with subsection (3)(c)(XI) of this section.

(6) The commission shall establish, by rule or by alternative filing by natural gas public utilities or gas supply companies, such certification requirements, terms and conditions for gas supply service, reporting requirements, and compliance procedures for competitive suppliers, aggregators other than municipalities or counties operating as aggregators within their jurisdictional boundaries, or brokers as the commission deems necessary to provide Colorado retail consumers with reliable natural gas supply service. Such requirements may include, without limitation, complaint procedures for enforcement of the commission's rules and procedures for the suspension or revocation of certification and operating authority of competitive suppliers, aggregators other than municipalities or counties operating as aggregators within their jurisdictional boundaries, or brokers for violation of commission rules as well as the assessment of fines and penalties for violations of commission rules and standards of conduct, in addition to other commission rules and enforcement mechanisms. In the certification requirements the commission shall require natural gas suppliers to operate a customer service location in the state and provide customers with a toll-free telephone number to reach the natural gas supplier.

(7) (a) The commission shall permit each natural gas public utility recovery, through its tariff rates for delivery of natural gas, of all or a portion of the utility's transition costs as may be just and reasonable if such recovery, for transition costs other than costs identified in sub-subparagraphs (G) and (H) of subparagraph (II) of paragraph (b) of this subsection (7), does not increase the annual charges for regulated gas delivery service in excess of one percent of the utility's jurisdictional gas revenues booked or recorded in calendar year 1998 unless the utility is thereby unable to recover such transition costs as may be approved by the commission pursuant to this subsection (7) within fifteen years. In such a case, the commission shall ensure that the recovery of the utility's transition costs, excluding those identified in sub-subparagraphs (G) and (H) of subparagraph (II) of paragraph (b) of this subsection (7), does not increase the annual charges for regulated gas delivery service in excess of two percent of the utility's jurisdictional gas revenues booked or recorded in calendar year 1998. To the extent the commission approves the recovery of transition costs identified in sub-subparagraphs (G) and (H) of subparagraph (II) of paragraph (b) of this subsection (7), those costs shall be recovered over a reasonable period of time, as determined by the commission.

(b) (I) As used in this subsection (7), transition costs means all costs determined by the commission to be legitimate, verifiable, and prudently incurred in the provision of natural gas service to customers in Colorado that arise from or are related to contracts, investments, or other obligations existing on or before the date of implementation of the voluntary plan and no longer recoverable under the plan, whether such costs are in the form of direct expenditures for capital assets, operating expenses, investments, long-term supply contracts or other future obligations, or any other form.

(II) Transition costs may include, but are not limited to, the following:

(A) Costs and administrative charges incurred by a natural gas public utility resulting from the design and implementation of its voluntary plan;

(B) Costs incurred before, on, or after the date of implementation of the voluntary plan and that are related to preexisting gas supply, transportation, or storage service contracts, including any contract buyout or buy-down costs, contract reformation or termination costs, contract litigation costs, fees, judgments, or settlements, other than those costs that have been the subject of litigation prior to January 1, 1999, as identified in sub-subparagraph (H) of this subparagraph (II);

(D) Interstate or intrastate third-party pipeline costs;

(E) Balancing costs;

(F) Underground storage costs;

(G) Deferred or prior-period gas costs not yet recovered at the time of conversion to competition in the provision of natural gas supply service;

(H) Costs incurred before, on, or after the date of implementation of the voluntary plan and that are related to preexisting gas supply contracts that have been the subject of litigation prior to January 1, 1999, including any above market costs, contract buyout, buy-down, reformation, or termination costs, litigation costs, fees, judgments, or settlements; and

(I) Any other costs that the commission determines to be recoverable transition costs.

(III) Transition costs shall not include:

(A) Costs that are or could be included within the existing rates of the natural gas public utility and that would result in double recovery of such costs if they were so included; or

(B) Costs committed to or incurred after the implementation date of the voluntary plan unless the commission determines that allowing recovery of such costs is in the public interest or that the incurrence of such costs is reasonable and prudent for the purpose of resolving or mitigating other transition costs.

(IV) A natural gas public utility shall not be entitled to recover its transition costs unless the commission finds that the utility has made reasonable efforts to mitigate transition costs. The commission shall determine the appropriate method and amortization period for a utility's recovery of transition costs and may establish such other reasonable procedures and conditions for the recovery of transition costs as the commission may determine are consistent with this section and in the public interest.

(c) Except to the extent provided in plan provisions or rules adopted by the commission governing the relationship between the public utility and its affiliates, the commission shall not impose on a natural gas public utility or its affiliate, with respect to competitive natural gas supply services, any requirement that is not imposed upon competing, non-utility providers of natural gas supply services, unless the commission determines that the imposition of such requirement is necessary to protect the public interest.

(8) The public benefits charge and its funding method shall continue in effect until at least December 31, 2005, and shall remain in effect thereafter until and unless replaced with a different legislatively adopted funding mechanism for statewide low-income energy assistance programs that assures the availability of adequate resources and that is consistent with the recommendations of the 1998 governor's energy assistance reform task force for the purpose of defraying the costs of low-income energy assistance. On or before December 1, 2004, the Colorado energy assistance foundation, which is the entity created under section 40-8.5-104, or its successor, in conjunction with any interested natural gas utility or natural gas supplier, shall recommend such a different funding mechanism for low-income energy assistance programs to the general assembly for adoption.

(9) Repealed.

(10) The general assembly determines that a new funding formula should be devised to adequately fund the commission's and office of the utility consumer advocate's administrative expenses. On or before December 1, 2000, the commission and the office shall recommend to the general assembly those legislative changes needed to develop appropriate funding mechanisms for the public utilities commission and the office. This provision is intended to provide a comprehensive replacement for the funding method contained in the utility plan under subsection (3)(c)(XI) of this section.

(11) The commission is specifically authorized at its sole discretion to adopt all necessary rules in furtherance of this section, including, but not limited to, standards of conduct, unfair and deceptive marketing practices, and consumer protections.

(12) Repealed.

(13) In any area where competitive gas supply choices are afforded to customers, any municipality or county or combination thereof may serve as a competitive supplier or, without buying and selling gas, act as an aggregator of the loads of its residents and businesses and contract with a certified supplier for its gas supply needs and the gas supply needs of its residents or businesses or both such residents and businesses; except that nothing in this subsection (13) shall require either a resident or business to buy natural gas supply service from a municipality serving as a supplier or acting as an aggregator of the loads of its residents or businesses.

(14) Each provider of natural gas supply service and natural gas delivery service shall collect and remit all applicable sales and use taxes. In a transaction involving the sale or furnishing of natural gas service, the transaction shall be deemed to occur where the natural gas is used or consumed.

(15) The commission shall undertake an investigation into natural gas public utilities' supply acquisition practices. The investigation shall examine, among other items, how public utilities currently acquire supply and their ability to manage the risk of price spikes in natural gas markets. Based on the investigation's findings, the commission may provide recommendations as to how natural gas portfolios might be structured in the future so as to provide greater long-term natural gas price stability for consumers. Information from the investigation shall be made available to interested parties at the commission's office. Such portfolio shall include a comparison of costs of natural gas contracts to the cost of coal syngas contracts that may become available in the future.

Source: L. 99: Entire section added, p. 954, � 1, effective August 4. L. 2001: (15) added, p. 1523, � 2, effective August 8. L. 2002: (9) and (12) repealed, p. 260, � 1, effective August 7. L. 2004: (15) amended, p. 585, � 2, effective August 4. L. 2021: IP(3)(c), (3)(c)(XI), (5), and (10) amended, (SB 21-103), ch. 477, p. 3414, � 12, effective September 1.

40-2-123. Energy technologies - consideration by commission - incentives - demonstration projects - definitions. (1) (a) The commission shall give the fullest possible consideration to the cost-effective implementation of new clean energy and energy-efficient technologies in its consideration of generation acquisitions for electric utilities, bearing in mind the beneficial contributions such technologies make to Colorado's energy security, economic prosperity, insulation from fuel price increases, and environmental protection, including risk mitigation in areas of high wildfire risk as designated by the state forest service. The commission shall consider utility investments in energy efficiency to be an acceptable use of ratepayer money.

(b) (I) The commission may give consideration to the likelihood of new environmental regulation and the risk of higher future costs associated with the emission of greenhouse gases such as carbon dioxide and methane when it considers utility proposals to acquire resources or to implement DSM programs. The commission shall collaborate with the air quality control commission to ensure that any emissions reductions achieved through gas DSM programs are appropriately accounted for in meeting the state's greenhouse gas reduction goals.

(II) For purposes of evaluating a gas DSM program or measure that incorporates innovative technologies with the potential for significant impact, such as energy-saving technologies that go beyond what is achievable using energy efficiency measures alone, the commission may find the program or measure cost-effective, notwithstanding section 40-1-102 (5)(a), even if its initial benefit-cost ratio is not greater than one when calculated using currently available data and assumptions.

(c) The commission shall give the fullest possible consideration to proposals under the reenergize Colorado program, created in section 24-33-115, C.R.S., with particular attention to those projects offering the prospect of job creation and local economic growth.

(d) In its consideration of generation acquisitions for electric utilities, the commission shall consider the economic opportunities that may be provided through workforce transition and community assistance plans, as well as whether the acquisitions will create benefits for low-income customers and disproportionately impacted communities.

(2) Repealed.

(3) (a) (I) Energy is critically important to Colorado's welfare and development and its use has a profound impact on the economy and environment. In order to diversify Colorado's energy resources, attract new businesses and jobs, promote development of rural economies, minimize water use for electric generation, reduce the impact of volatile fuel prices, and improve the natural environment of the state, the general assembly finds it in the best interests of the citizens of Colorado to develop and utilize solar energy resources in increasing amounts.

(II) For purposes of this subsection (3), utility-scale means projects with nameplate ratings in excess of two megawatts.

(b) The commission may consider whether acquisition of utility-scale solar resources is in the public interest, taking into account the associated costs and benefits, and, if so, the appropriate amount of utility-scale solar resources that should be acquired. In making this determination, the commission may consider the following potential attributes of utility-scale solar electric generation:

(I) Whether the proposed generation could provide energy storage to match the times during which utility generation is generally higher cost;

(II) Whether the proposed generation, due to modularity, scalability, and rapid deployment, could result in reduction of performance and financial risk for the utility;

(III) Whether utility-scale solar electric generation could reduce the consumption of water for electric generation;

(IV) Whether future costs can be stabilized through mitigation of the impact of unpredictable fossil fuel prices; and

(V) Whether carbon-free generation reduces long-term costs and risks related to potential carbon regulation or taxation.

(3.2) In its consideration of generation acquisitions for electric utilities, the commission may give the fullest possible consideration, at a utility's request, to the cost-effective implementation of new energy technologies for the generation of electricity from:

(a) Geothermal energy;

(b) The combustion of biomass, biosolids derived from the treatment of wastewater, and municipal solid waste. For purposes of this paragraph (b), biomass has the meaning established in section 40-2-124 (1)(a), as clarified by the commission.

(c) Hydroelectricity and pumped hydroelectricity, taking into account the associated costs and benefits. For purposes of this paragraph (c):

(I) Hydroelectricity means the generation and delivery to the interconnection meter of any source of electrical or mechanical energy by harnessing the kinetic energy of water that is:

(A) A new facility that is an addition to water infrastructure such as a reservoir, ditch, or pipeline that existed before January 1, 2011, and does not result in any change in the quantity or timing of diversions or releases for purposes of peak power generation; or

(B) A new facility that is placed into production as part of new water infrastructure such as a reservoir, ditch, or pipeline constructed on or after January 1, 2011, and operated for primary beneficial uses of water other than solely for production of electricity.

(II) Pumped hydroelectricity means electricity that is generated during periods of high electrical demand from water that has been pumped during periods of low electrical demand from a lower-elevation reservoir to a higher-elevation reservoir taking into account the potential benefits or impacts of the proposed facility on fishery health.

(3.3) In its consideration of generation acquisitions for electric utilities, the commission may give the fullest possible consideration to the cost-effective implementation of new energy technologies for the generation of electricity from methane produced biogenically in geologic strata as a result of human intervention.

(3.5) Repealed.

(4) This section does not expand or contract the commission's jurisdiction over cooperative electric associations under this title.

(5) Any project approved pursuant to this section that is an energy sector public works project, as defined in section 24-92-303 (5), 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.

Source: L. 2001: Entire section added, p. 1524, � 4, effective August 8. L. 2006: Entire section amended, p. 1413, � 2, effective June 1. L. 2008: (2)(j) amended, p. 75, � 16, effective March 18; (1) amended and (3) and (4) added, p. 1686, � 1, effective June 2. L. 2009: (3.5) added, (SB 09-297), ch. 285, p. 1297, � 3, effective May 20. L. 2010: (1)(c) added, (HB 10-1349), ch. 387, p. 1816, � 4, effective June 8; (3.2) added, (SB 10-174), ch. 189, p. 815, � 11, effective August 11; (3.2) added, (SB 10-177), ch. 392, p. 1864, � 6, effective August 11; (3.3) added, ch. 389, p. 1825, � 1, effective August 11. L. 2011: (3.2)(c) added, (HB 11-1083), ch. 68, p. 179, � 1, effective August 10. L. 2012: (2)(j) amended, (HB 12-1315), ch. 224, p. 980, � 48, effective July 1. L. 2013: (1)(a) amended, (SB 13-273), ch. 406, p. 2375, � 6, effective June 5. L. 2017: (2)(k) repealed, (SB 17-294), ch. 264, p. 1415, � 110, effective May 25. L. 2019: (2) repealed, (SB 19-236), ch. 359, p. 3291, � 3, effective May 30. L. 2021: (1)(d) added, (SB 21-272), ch. 220, p. 1159, � 5, effective June 10; (1)(b) amended, (HB 21-1238), ch. 330, p. 2132, � 3, effective September 7; (2) RC&RE, (HB 21-1324), ch. 441, p. 2918, � 2, effective September 7. L. 2023: IP(2)(d)(I) amended, (SB 23-051), ch. 37, p. 149, � 31, effective March 23; (5) added, (SB 23-292), ch. 247, p. 1360, � 4, effective January 1, 2024.

Editor's note: (1) Amendments to subsection (3.2) by Senate Bill 10-174 and Senate Bill 10-177 were harmonized.

(2) Subsection (3.5)(e) provided for the repeal of subsection (3.5), effective July 1, 2013. (See L. 2009, p. 1297.)

(3) Subsection (2)(f) provided for the repeal of subsection (2), effective December 31, 2024. (See L. 2021, p. 2918).

Cross references: For the legislative declaration contained in the 2006 act amending this section, see section 1 of chapter 300, Session Laws of Colorado 2006. For the legislative declaration in HB 21-1238, see section 1 of chapter 330, Session Laws of Colorado 2021. For the legislative declaration in HB 21-1324, see section 1 of chapter 441, Session Laws of Colorado 2021.

40-2-124. Renewable energy standards - qualifying retail and wholesale utilities - definitions - net metering - legislative declaration - rules. (1) Each provider of retail electric service in the state of Colorado, other than municipally owned utilities that serve forty thousand customers or fewer, is a qualifying retail utility. Each qualifying retail utility, with the exception of cooperative electric associations that have voted to exempt themselves from commission jurisdiction pursuant to section 40-9.5-104 and municipally owned utilities, is subject to the rules established under this article 2 by the commission. No additional regulatory authority is provided to the commission other than that specifically contained in this section. In accordance with article 4 of title 24, the commission shall revise or clarify existing rules to establish the following:

(a) Definitions of eligible energy resources that can be used to meet the standards. Eligible energy resources means recycled energy, renewable energy resources, and renewable energy storage. In addition, resources using coal mine methane and synthetic gas produced by pyrolysis of waste materials are eligible energy resources if the commission determines that the electricity generated by those resources is greenhouse gas neutral. The commission shall determine, following an evidentiary hearing, the extent to which such electric generation technologies utilized in an optional pricing program may be used to comply with this standard. A fuel cell using hydrogen derived from an eligible energy resource is also an eligible electric generation technology. Fossil and nuclear fuels and their derivatives are not eligible energy resources. As used in this section:

(I) Biomass means:

(A) Nontoxic plant matter consisting of agricultural crops or their by-products, urban wood waste, mill residue, slash, or brush;

(B) Animal wastes and products of animal wastes; or

(II) Coal mine methane means methane captured from active and inactive coal mines where the methane is escaping to the atmosphere. In the case of methane escaping from active mines, only methane vented in the normal course of mine operations that is naturally escaping to the atmosphere is coal mine methane for purposes of eligibility under this section.

(III) Distributed renewable electric generation or distributed generation means:

(A) Retail distributed generation; and

(B) Wholesale distributed generation.

(IV) Greenhouse gas neutral, with respect to electricity generated using biomass or by a coal mine methane or synthetic gas facility, means that the greenhouse gases emitted into the atmosphere as a result of the process of converting the fuel source to electricity do not exceed the greenhouse gases that would have been emitted into the atmosphere over the next five years, beginning with the commencement of the process or initial date of operation of the facility, if the fuel source had not been converted to electricity, where greenhouse gases are measured in terms of carbon dioxide equivalent.

(IV.5) Off-site means located on noncontiguous property owned or leased by a customer of a qualifying retail utility.

(V) Pyrolysis means the thermochemical decomposition of material at elevated temperatures without the participation of oxygen.

(VI) (A) Recycled energy means energy produced by a generation unit with a nameplate capacity of not more than fifteen megawatts that either converts the otherwise lost energy from the heat from exhaust stacks or pipes to electricity and does not combust additional fossil fuel or is pumped hydroelectricity generation that does not combust fossil fuel to pump water; is not located on a natural waterway; includes measures to prevent fish mortality in the facility; does not impact any decreed instream flow; and does not cause any violation of state water quality standards when operated.

(B) Subject to subsection (1)(a)(VI)(A) of this section, recycled energy does not include energy produced by any system that uses energy, lost or otherwise, from a process whose primary purpose is the generation of electricity, including, without limitation, any process involving engine-driven generation.

(VII) Renewable energy resources means solar, wind, geothermal, biomass that is greenhouse gas neutral, new hydroelectricity with a nameplate rating of ten megawatts or less, and hydroelectricity in existence on January 1, 2005, with a nameplate rating of thirty megawatts or less and that does not require the construction of any new dams or reservoirs. Notwithstanding any other provision of this subsection (1)(a)(VII), a biomass electric generation facility that was in existence on or before January 1, 2021, or that has a nameplate rating of ten megawatts or less, shall be considered a renewable energy resource.

(VII.5) Renewable energy storage means an energy storage system, as defined in section 40-2-130 (2)(a), that stores energy produced only by renewable energy resources.

(VIII) Except as provided in subsection (1)(c)(II)(D) of this section with respect to cooperative electric associations, retail distributed generation means a renewable energy resource or renewable energy storage that is located on any property owned or leased by the customer within the service territory of the qualifying retail utility and is interconnected on the customer's side of the utility meter. In addition, retail distributed generation shall provide electric energy primarily to serve the customer's loads and shall be sized to supply no more than two hundred percent of the reasonably expected average annual total consumption of electricity at all properties owned or leased by the customer within the utility's service territory.

(IX) Wholesale distributed generation means a renewable energy resource with a nameplate rating of thirty megawatts or less and that does not qualify as retail distributed generation.

(b) Standards for the design, placement, and management of electric generation technologies that use eligible energy resources to ensure that the environmental impacts of such facilities are minimized.

(I) Except as provided in subparagraph (V) of this paragraph (c), the electric resource standards shall require each qualifying retail utility to generate, or cause to be generated, electricity from eligible energy resources in the following minimum amounts:

(A) Three percent of its retail electricity sales in Colorado for the year 2007;

(B) Five percent of its retail electricity sales in Colorado for the years 2008 through 2010;

(C) Twelve percent of its retail electricity sales in Colorado for the years 2011 through 2014, with distributed generation equaling at least one percent of its retail electricity sales in 2011 and 2012 and one and one-fourth percent of its retail electricity sales in 2013 and 2014;

(D) Twenty percent of its retail electricity sales in Colorado for the years 2015 through 2019, with distributed generation equaling at least one and three-fourths percent of its retail electricity sales in 2015 and 2016 and two percent of its retail electricity sales in 2017, 2018, and 2019; and

(E) Thirty percent of its retail electricity sales in Colorado for the years 2020 and thereafter, with distributed generation equaling at least three percent of its retail electricity sales.

(II) (A) Of the amounts of distributed generation in sub-subparagraphs (C), (D), and (E) of subparagraph (I), sub-subparagraph (D) of subparagraph (V), and subparagraph (V.5) of this paragraph (c), at least one-half must be derived from retail distributed generation; except that this sub-subparagraph (A) does not apply to a qualifying retail utility that is a municipal utility.

(A.5) Notwithstanding sub-subparagraph (A) of this subparagraph (II), a qualifying retail utility that is a cooperative electric association may subtract industrial retail sales from total retail sales in calculating its minimum retail distributed generation requirement.

(B) A qualifying retail utility that is investor-owned shall not limit the sizing of on-site retail distributed generation capacity based solely on past consumption. Cooperative electric associations are not subject to this subsection (1)(c)(II)(B).

(C) Distributed generation amounts in the electric resource standard for the years 2015 and thereafter may be changed by the commission for the period after December 31, 2014, if the commission finds, upon application by a qualifying retail utility, that these percentage requirements are no longer in the public interest. If such a finding is made, the commission may set the lower distributed generation requirements, if any, that shall apply after December 31, 2014. If the commission finds that the public interest requires an increase in the distributed generation requirements, the commission shall report its findings to the general assembly.

(D) For purposes of a cooperative electric association's compliance with the retail distributed generation requirement set forth in sub-subparagraph (A) of this subparagraph (II), an electric generation facility constitutes retail distributed generation if it uses only renewable energy resources; has a nameplate rating of two megawatts or less; is located within the service territory of a cooperative electric association; generates electricity for the beneficial use of subscribers who are members of the cooperative electric association in the service territory in which the facility is located; and has at least four subscribers if the facility has a nameplate rating of fifty kilowatts or less and at least ten subscribers if the facility has a nameplate rating of more than fifty kilowatts. A subscriber's share of the production from the facility may not exceed one hundred twenty percent of the subscriber's average annual consumption. Each cooperative electric association may establish, in the manner it deems appropriate, the: Subscriber; subscription; pricing, including consideration of low-income members; metering; accounting; renewable energy credit ownership; and other requirements and terms associated with electric generation facilities described in this sub-subparagraph (D).

(III) Each kilowatt-hour of electricity generated from eligible energy resources, other than retail distributed generation and other than eligible energy resources beginning operation on or after January 1, 2015, counts as one and one-fourth kilowatt-hours for the purposes of compliance with this standard.

(IV) To the extent that the ability of a qualifying retail utility to acquire eligible energy resources is limited by a requirements contract with a wholesale electric supplier, the qualifying retail utility shall acquire the maximum amount allowed by the contract. For any shortfalls to the amounts established by the commission pursuant to subparagraph (I) of this paragraph (c), the qualifying retail utility shall acquire an equivalent amount of either renewable energy credits; documented and verified energy savings through energy efficiency and conservation programs; or a combination of both. Any contract entered into by a qualifying retail utility after December 1, 2004, shall not conflict with this section.

(V) Notwithstanding any other provision of law but subject to subsection (4) of this section, the electric resource standards must require each cooperative electric association that is a qualifying retail utility and that provides service to fewer than one hundred thousand meters, and each municipally owned utility that is a qualifying retail utility, to generate, or cause to be generated, electricity from eligible energy resources in the following minimum amounts:

(A) One percent of its retail electricity sales in Colorado for the years 2008 through 2010;

(B) Three percent of retail electricity sales in Colorado for the years 2011 through 2014;

(D) Ten percent of retail electricity sales in Colorado for the years 2020 and thereafter.

(V.5) Notwithstanding any other provision of law, each cooperative electric association that provides electricity at retail to its customers and serves one hundred thousand or more meters shall generate or cause to be generated at least twenty percent of the energy it provides to its customers from eligible energy resources in the years 2020 and thereafter.

(VI) Each kilowatt-hour of electricity generated from eligible energy resources at a community-based project must be counted as one and one-half kilowatt-hours. For purposes of this subparagraph (VI), community-based project means a project:

(A) That is owned by individual residents of a community, by an organization or cooperative that is controlled by individual residents of the community, or by a local government entity or tribal council;

(B) The generating capacity of which does not exceed thirty megawatts; and

(C) For which there is a resolution of support adopted by the local governing body of each local jurisdiction in which the project is to be located.

(VII) (A) For purposes of compliance with the standards set forth in subparagraphs (V) and (V.5) of this paragraph (c), each kilowatt-hour of renewable electricity generated from solar electric generation technologies shall be counted as three kilowatt-hours.

(B) For each qualifying retail utility that is a cooperative electric association, sub-subparagraph (A) of this subparagraph (VII) applies only to solar electric technologies that begin producing electricity prior to July 1, 2015, and for solar electric technologies that begin producing electricity on or after July 1, 2015, each kilowatt-hour of renewable electricity shall be counted as one kilowatt-hour for purposes of compliance with the renewable energy standard.

(C) For each qualifying retail utility that is a municipally owned utility, sub-subparagraph (A) of this subparagraph (VII) applies only to solar electric technologies that are under contract for development prior to August 1, 2015, and begin producing electricity prior to December 31, 2016, and for solar electric technologies that are not under contract for development prior to August 1, 2015, and begin producing electricity on or after December 31, 2016, each kilowatt-hour of renewable electricity shall be counted as one kilowatt-hour for purposes of compliance with the renewable energy standard.

(VIII) Electricity from eligible energy resources shall be subject to only one of the methods for counting kilowatt-hours set forth in subparagraphs (III), (VI), and (VII) of this paragraph (c).

(IX) For purposes of stimulating rural economic development and for projects up to thirty megawatts of nameplate capacity that have a point of interconnection rated at sixty-nine kilovolts or less, each kilowatt hour of electricity generated from renewable energy resources that interconnects to electric transmission or distribution facilities owned by a cooperative electric association or municipally owned utility may be counted for the life of the project as two kilowatt hours for compliance with the requirements of this paragraph (c) by qualifying retail utilities. This multiplier shall not be claimed for interconnections that first occur after December 31, 2014, and shall not be used in conjunction with another compliance multiplier. For qualifying retail utilities other than investor-owned utilities, the benefits described in this subparagraph (IX) apply only to the aggregate first one hundred megawatts of nameplate capacity of projects statewide that report having achieved commercial operations to the commission pursuant to the procedure described in this subparagraph (IX). To the extent that a qualifying retail utility claims the benefit described in this subparagraph (IX), those kilowatt-hours of electricity do not qualify for satisfaction of the distributed generation requirement of subparagraph (I) of this paragraph (c). The commission shall analyze the implementation of this subparagraph (IX) and submit a report to the senate local government and energy committee and the house of representatives committee on transportation and energy, or their successor committees, by December 31, 2011, regarding implementation of this subparagraph (IX), including how many megawatts of electricity have been installed or are subject to a power purchase agreement pursuant to this subparagraph (IX) and whether the commission recommends that the multiplier established by this subparagraph (IX) should be changed either in magnitude or expiration date. Any entity that owns or develops a project that will take advantage of the benefits of this subparagraph (IX) shall notify the commission within thirty days after signing a power purchase agreement and within thirty days after beginning commercial operations of an applicable project.

(X) Of the minimum amounts of electricity required to be generated or caused to be generated by qualifying retail utilities in accordance with subparagraph (V.5) and sub-subparagraph (D) of subparagraph (V) of this paragraph (c), one-tenth, or one percent of total retail electricity sales, must be from distributed generation; except that:

(A) For a cooperative electric association that is a qualifying retail utility and that provides service to fewer than ten thousand meters, the distributed generation component may be three-quarters of one percent of total retail electricity sales; and

(B) This subparagraph (X) does not apply to a qualifying retail utility that is a municipal utility.

(d) (I) (A) Subject to rules promulgated pursuant to subsection (1)(d)(II) of this section, a system of tradable renewable energy credits that a qualifying retail utility may use to comply with this standard. The commission shall also analyze the effectiveness of utilizing any regional system of renewable energy credits in existence at the time of its rule-making process and determine whether the system is governed by rules that are consistent with the rules established for this article 2.

(B) The commission shall not restrict the qualifying retail utility's ownership or purchase of renewable energy if: The qualifying retail utility complies with the electric resource standard of subsection (1)(c) of this section and the conditions of any rate recovery mechanism adopted pursuant to subsection (1)(f)(IV) of this section; the qualifying retail utility uses definitions of eligible energy resources that are limited to those identified in subsection (1)(a) of this section, as clarified by the commission, and does not exceed the retail rate impact established by subsection (1)(g) of this section; and the commission finds that the resources are prudently acquired at a reasonable cost and rate impact.

(C) Once a qualifying retail utility either receives a permit pursuant to article 7 or 8 of title 25 for a generation facility that relies on or is affected by the definitions of eligible energy resources or enters into a contract that relies on or is affected by the definitions of eligible energy resources, the definitions apply to the contract or facility notwithstanding any subsequent alteration of the definitions, whether by statute or rule.

(D) For purposes of compliance with the renewable energy standard, if a generation system uses a combination of fossil fuel and eligible renewable energy resources to generate electricity, a qualifying retail utility that is not an investor-owned utility may count as eligible renewable energy only the proportion of the total electric output of the generation system that results from the use of eligible renewable energy resources.

(II) The system of tradable renewable energy credits must include requirements for the retirement of renewable energy credits to ensure that compliance with the renewable energy standard:

(A) Is effectuated in a manner that benefits Colorado's cities, counties, and businesses;

(B) Enables a utility's customers to account for the environmental benefits of the renewable energy generated to serve those customers and purchased for those customers; and

(e) A requirement that each qualifying retail utility, except for cooperative electric associations and municipally owned utilities, make available to their customers a standard rebate offer and net metering service, under which:

(I) (A) Customers are offered a specified amount per watt for the installation of eligible solar electric generation on the customers' premises, up to a maximum of one hundred kilowatts per installation.

(A.5) A qualifying retail utility's interconnection standards for distributed energy resources must allow for customer ownership and use of a meter collar adapter to permit the interconnection of distributed energy resources and for electrical isolation of the customer's site for energy backup purposes. The qualifying retail utility shall, within one hundred eighty days after June 21, 2021, adopt a transparent process for approving customer-owned meter collar adapters that meet minimum safety requirements. The commission shall resolve any disputes concerning the substance or procedures involved in the approval process or its application in any specific case. The approval process must take no more than sixty days after the date of submission for approval of a specific meter collar adapter by the proposing party. Approved meter collar adapters must be UL listed and must be suitable per the adapter's UL listing documentation for use in meter sockets of up to two hundred amperes. The qualifying retail utility shall define and publish in its tariffs a process to request and install a meter collar adapter, which process is timely and not unduly burdensome to the customer. The qualifying retail utility shall post on its website its list of approved meter collar adapters, which list must be updated at least annually.

(B) The qualifying retail utility's net metering service must allow the customer's retail electricity consumption to be offset by the electricity generated by customer-sited renewable energy generation facilities. To the extent that the electricity thus generated exceeds the customer's consumption during a billing month, the qualifying retail utility shall carry forward the value of the excess electricity as a credit to the customer's consumption in the following month. The monthly carry-forward continues from month to month indefinitely until the customer terminates service with the qualifying retail utility at all service addresses within the service territory of the qualifying retail utility, at which time the qualifying retail utility is not required to pay the customer for any remaining excess electricity supplied by the customer; except that, to the extent that solar electricity generation exceeds the customer's consumption during a calendar year, the customer may elect, in writing, to be reimbursed by the qualifying retail utility at the end of each calendar year at the qualifying retail utility's average hourly incremental cost of electricity supply over that calendar year. The customer, at the end of the calendar year, and the qualifying retail utility, upon termination of service to the customer, shall be permitted to donate any of the customer's remaining excess billing credits to a third-party administrator that is qualified and approved by the qualifying retail utility or the commission for the purpose of providing low-income energy assistance and bill reductions within the qualifying retail utility's service territory. The qualifying retail utility shall not apply unreasonably burdensome requirements to interconnection, reimbursement, or donation options in connection with the qualifying retail utility's net metering service. Electricity generated under this program is eligible for purposes of the qualifying retail utility's compliance with this article 2 so long as the qualifying retail utility purchases the associated renewable energy credits. The commission shall not permit a qualifying retail utility to place a customer in a different rate class, other than the customer's default rate class, solely as a result of the customer's participation in a rebate offer or net metering service.

(C) For retail distributed generation that is used to meet loads of a noncontiguous property owned or leased by the customer, a qualifying retail utility's net metering program must provide the customer a net metering credit minus a reasonable charge, as determined by the commission, to cover the utility's costs of delivering to the customer's premises the electricity generated by the retail distributed generation and of administering the off-site net metering credits. The reasonable charge shall be fixed for the term of the interconnection agreement pertaining to the retail distributed generation facilities and shall be determined by a utility tariff filing, which may be updated once annually. The commission shall ensure that this charge does not reflect costs that are already recovered by the utility from the customer through other charges. If, and to the extent that, a customer's net metering credit exceeds the customer's electric bill in any billing period, the net metering credit shall be carried forward and applied against future bills.

(D) The commission may permit a qualifying retail utility to limit the total amount carried forward on behalf of a customer pursuant to subsection (1)(e)(I)(B) of this section so long as the limit is not less than one hundred percent of the customer's reasonably expected average annual consumption. Any excess electricity above the limit shall be reimbursed at the qualifying retail utility's average hourly incremental cost of electricity supply over the immediately preceding twelve-month period.

(E) For the 2022 and 2023 compliance years, each qualifying retail utility shall issue one or more standard offers to interconnect and net meter off-site, customer-owned distributed generation and shall reserve, for this purpose, capacity equal to one-quarter of one percent of the utility's annual retail sales from the immediately preceding year. Thereafter, the commission may set limits, based on market demand, on annual minimum and maximum available capacity for newly installed off-site distributed generation that the qualifying retail utility shall plan to interconnect and net meter. The customer may choose to retain or sell to the qualifying retail utility the customer's renewable energy credits.

(I.5) The amount of the standard rebate offer shall be two dollars per watt; except that the commission may set the rebate at a lower amount if the commission determines, based upon a qualifying retail utility's renewable resource plan or application, that market changes support the change.

(II) The owner or operator of solar electric generation facilities located on any property owned or leased by the consumer, which property is within the service territory of the qualifying retail utility, may sell electricity to the consumer. If a solar electric generation facility is not owned by the consumer, then the commission shall not require the qualifying retail utility to pay for the renewable energy credits generated by the facility on any basis other than a metered basis. The owner or operator of the solar electric generation facility shall pay the cost of installing the production meter.

(III) The qualifying retail utility may establish one or more standard offers to purchase renewable energy credits generated from eligible energy resources on the customer's premises so long as the generation is one megawatt or less in size. When establishing the standard offers, the qualifying retail utility should set the prices for renewable energy credits at levels sufficient to encourage increased distributed generation and renewable energy storage in the size ranges covered by each standard offer, but at levels that will still allow the qualifying retail utility to comply with the electric resource standards set forth in subsection (1)(c) of this section without exceeding the retail rate impact limit in subsection (1)(g) of this section.

(IV) The commission shall encourage qualifying retail utilities to design rebate offers and other incentive programs that allow consumers of all income levels, particularly those in low-income and disproportionately impacted communities, to obtain the benefits offered by distributed generation and energy storage, and shall encourage programs that are designed to extend participation to customers in these and other market segments that have previously been underrepresented in the standard offer program.

(f) Policies for the recovery of costs incurred with respect to these standards for qualifying retail utilities that are subject to rate regulation by the commission. These policies must provide incentives to qualifying retail utilities to invest in eligible energy resources and must include:

(I) Repealed.

(II) Allowing qualifying retail utilities to earn an extra profit on their investment in eligible energy resource technologies if these investments provide net economic benefits to customers as determined by the commission. The allowable extra profit in any year shall be the qualifying retail utility's most recent commission authorized rate of return plus a bonus limited to fifty percent of the net economic benefit.

(III) Allowing qualifying retail utilities to earn their most recent commission authorized rate of return, but no bonus, on investments in eligible energy resource technologies if these investments do not provide a net economic benefit to customers.

(IV) Considering, when the qualifying retail utility applies for a certificate of public convenience and necessity under section 40-5-101, rate recovery mechanisms that provide for earlier and timely recovery of costs prudently and reasonably incurred by the qualifying retail utility in developing, constructing, and operating the eligible energy resource, including:

(A) Rate adjustment clauses until the costs of the eligible energy resource can be included in the utility's base rates; and

(B) A current return on the utility's capital expenditures during construction at the utility's weighted average cost of capital, including its most recently authorized rate of return on equity, during the construction, startup, and operation phases of the eligible energy resource.

(V) If the commission approves the terms and conditions of an eligible energy resource contract between the qualifying retail utility and another party, the contract and its terms and conditions shall be deemed to be a prudent investment, and the commission shall approve retail rates sufficient to recover all just and reasonable costs associated with the contract. All contracts for acquisition of eligible energy resources shall have a minimum term of twenty years; except that the contract term may be shortened at the sole discretion of the seller. All contracts for the acquisition of renewable energy credits from solar electric technologies located on site at customer facilities shall also have a minimum term of twenty years; except that such contracts for systems of between one hundred kilowatts and one megawatt may have a different term if mutually agreed to by the parties.

(VI) A requirement that qualifying retail utilities consider proposals offered by third parties for the sale of renewable energy or renewable energy credits. The commission may develop standard terms for the submission of such proposals.

(VII) A requirement that all distributed renewable electric generation facilities with a nameplate rating of one megawatt or more be registered with a renewable energy generation information tracking system designated by the commission.

(g) Retail rate impact rule:

(I) (A) Except as otherwise provided in subparagraph (IV) of this paragraph (g), for each qualifying utility, the commission shall establish a maximum retail rate impact for this section for compliance with the electric resource standards of two percent of the total electric bill annually for each customer. The retail rate impact shall be determined net of new alternative sources of electricity supply from noneligible energy resources that are reasonably available at the time of the determination.

(B) If the retail rate impact does not exceed the maximum impact permitted by this paragraph (g), the qualifying utility may acquire more than the minimum amount of eligible energy resources and renewable energy credits required by this section. At the request of the qualifying retail utility and upon the commission's approval, the qualifying retail utility may advance funds from year to year to augment the amounts collected from retail customers under this paragraph (g) for the acquisition of more eligible energy resources. Such funds shall be repaid from future retail rate collections, with interest calculated at the qualifying retail utility's after-tax weighted average cost of capital, so long as the retail rate impact does not exceed two percent of the total annual electric bill for each customer.

(C) As between residential and nonresidential retail distributed generation, the commission shall direct the utility to allocate its expenditures according to the proportion of the utility's revenue derived from each of these customer groups; except that the utility may acquire retail distributed generation at levels that differ from these group allocations based upon market response to the utility's programs.

(D) To address historical equity issues concerning access by low-income customers to renewable energy and retail distributed generation programs and prioritize investment and direct benefits for disproportionately impacted communities, the commission shall require qualifying retail utilities to plan their expenditures so that, before reaching the limits imposed by this subsection (1)(g), they will prioritize renewable energy investment and programs for low-income customers and disproportionately impacted communities. Beginning on January 1, 2022, and continuing through at least December 31, 2028, not less than forty percent of such expenditures, not including any funds set aside to recover the cost of clean energy resources and directly related interconnection facilities pursuant to section 40-2-125.5 (4)(a)(VIII), shall be directed to programs, incentives, or other direct investments benefitting low-income customers and disproportionately impacted communities.

(II) Each wholesale energy provider shall offer to its wholesale customers that are cooperative electric associations the opportunity to purchase their load ratio share of the wholesale energy provider's electricity from eligible energy resources. If a wholesale customer agrees to pay the full costs associated with the acquisition of eligible energy resources and associated renewable energy credits by its wholesale provider by providing notice of its intent to pay the full costs within sixty days after the wholesale provider extends the offer, the wholesale customer shall be entitled to receive the appropriate credit toward the renewable energy standard as well as any associated renewable energy credits. To the extent that the full costs are not recovered from wholesale customers, a qualifying retail utility shall be entitled to recover those costs from retail customers.

(III) Subject to the maximum retail rate impact permitted by this paragraph (g), the qualifying retail utility shall have the discretion to determine, in a nondiscriminatory manner, the price it will pay for renewable energy credits from on-site customer facilities that are no larger than five hundred kilowatts.

(IV) (A) For cooperative electric associations, the maximum retail rate impact for this section is two percent of the total electric bill annually for each customer.

(B) Notwithstanding subparagraph (I) of this paragraph (g), the commission may ensure that customers who install distributed generation continue to contribute, in a nondiscriminatory fashion, their fair share to their utility's renewable energy program fund or equivalent renewable energy support mechanism even if such contribution results in a charge that exceeds two percent of such customers' annual electric bills.

(h) Annual reports. Each qualifying retail utility shall submit to the commission an annual report that provides information relating to the actions taken to comply with this article including the costs and benefits of expenditures for renewable energy. The report shall be within the time prescribed and in a format approved by the commission.

(i) Rules necessary for the administration of this article including enforcement mechanisms necessary to ensure that each qualifying retail utility complies with this standard, and provisions governing the imposition of administrative penalties assessed after a hearing held by the commission pursuant to section 40-6-109. The commission shall exempt a qualifying retail utility from administrative penalties for an individual compliance year if the utility demonstrates that the retail rate impact cap described in paragraph (g) of this subsection (1) has been reached and the utility has not achieved full compliance with paragraph (c) of this subsection (1). The qualifying retail utility's actions under an approved compliance plan shall carry a rebuttable presumption of prudence. Under no circumstances shall the costs of administrative penalties be recovered from Colorado retail customers.

(j) Rules to accommodate aggregation and interconnection of retail distributed generation, including:

(I) Allowing electricity generated from a single renewable retail distributed generation resource on a multiunit property to be allocated as net metering credits to either common areas of the property or to individually metered accounts without requiring the resource to be physically interconnected with each owner's or lessee's meter;

(II) Allowing a utility customer with retail distributed generation interconnected with a master meter to allocate excess net metering credits to any meter on property owned or leased by the customer in accordance with a customer-defined system share for each additional meter, with excess net metering credits applied to the additional meter;

(III) Where retail distributed generation is being used to offset the load of multiple, separately metered properties that are not on the same rate schedule, allowing allocation of the bill credits that may be applied to any of the metered accounts;

(IV) Requiring qualifying retail utilities to apply the same installation standards and list of approved meter collar adapters developed pursuant to subsection (1)(e)(I)(A.5) of this section to all customers desiring to use retail distributed generation to offset their individual energy loads;

(V) Requiring qualifying retail utilities to develop optional programs and tariffs to support the adoption and use of dispatchable renewable distributed generation and storage resources to provide grid benefits, such as enhancing the efficiency, capacity, and resilience of the electric grid, and to reduce greenhouse gas emissions. As used in this subsection (1)(j)(V), dispatchable means that the power output supplied to the electric grid by a customer-sited renewable energy generation or storage facility can be turned on and off or otherwise adjusted on demand.

(VI) Requiring qualifying retail utilities to adopt procedures designed to ensure that, for all renewable distributed generation or storage facilities included in their net metering service:

(A) The size of any off-site, single-meter installation does not exceed five hundred kilowatts;

(B) The size of any off-site, multi-meter installation does not exceed three hundred kilowatts per meter; and

(C) For any off-site facility exceeding three hundred kilowatts, the installation and any necessary repair or maintenance work is performed by a licensed master electrician, licensed journeyman electrician, or licensed residential wireman or by properly supervised apprentices, in addition to complying with all applicable interconnection rules.

(1.5) Notwithstanding any provision of law to the contrary, subsections (1)(e) and (1)(j) of this section do not apply to a municipally owned utility or to a cooperative electric association.

(2) (Deleted by amendment, L. 2007, p. 257, � 1, effective March 27, 2007.)

(3) Each municipally owned electric utility that is a qualifying retail utility shall implement a renewable energy standard substantially similar to this section. The municipally owned utility shall submit a statement to the commission that demonstrates such municipal utility has a substantially similar renewable energy standard. The statement submitted by the municipally owned utility is for informational purposes and is not subject to approval by the commission. Upon filing of the certification statement, the municipally owned utility shall have no further obligations under subsection (1) of this section. The renewable energy standard of a municipally owned utility shall, at a minimum, meet the following criteria:

(a) The eligible energy resources shall be limited to those identified in paragraph (a) of subsection (1) of this section;

(b) The percentage requirements shall be equal to or greater in the same years than those identified in subparagraph (V) of paragraph (c) of subsection (1) of this section, counted in the manner allowed by said paragraph (c); and

(c) The utility must have an optional pricing program in effect that allows retail customers the option to support through utility rates emerging renewable energy technologies.

(4) For municipal utilities that become qualifying retail utilities after December 31, 2006, the percentage requirements identified in subparagraph (V) of paragraph (c) of subsection (1) of this section shall begin in the first calendar year following qualification as follows:

(a) Years one through three: One percent of retail electricity sales;

(b) Years four through seven: Three percent of retail electricity sales;

(d) Years thirteen and thereafter: Ten percent of retail electricity sales.

(5) Procedure for exemption and inclusion - election.

(a) (Deleted by amendment, L. 2007, p. 257, � 1, effective March 27, 2007.)

(b) The board of directors of each municipally owned electric utility not subject to this section may, at its option, submit the question of its inclusion in this section to its consumers on a one meter equals one vote basis. Approval by a majority of those voting in the election shall be required for such inclusion, providing that a minimum of twenty-five percent of eligible consumers participates in the election.

(5.5) Each cooperative electric association that is a qualifying retail utility shall submit an annual compliance report to the commission no later than June 1 of each year in which the cooperative electric association is subject to the renewable energy standard requirements established in this section. The annual compliance report shall describe the steps taken by the cooperative electric association to comply with the renewable energy standards and shall include the same information set forth in the rules of the commission for jurisdictional utilities. Cooperative electric associations shall not be subject to any part of the compliance report review process as provided in the rules for jurisdictional utilities. Cooperative electric associations shall not be required to obtain commission approval of annual compliance reports, and no additional regulatory authority of the commission other than that specifically contained in this subsection (5.5) is created or implied by this subsection (5.5).

(6) (Deleted by amendment, L. 2007, p. 257, � 1, effective March 27, 2007.)

(7) (a) Definitions. For purposes of this subsection (7), unless the context otherwise requires:

(I) Customer-generator means an end-use electricity customer that generates electricity on the customer's side of the meter using eligible energy resources.

(II) Municipally owned utility means a municipally owned utility that serves five thousand customers or more.

(b) Each municipally owned utility shall allow a customer-generator's retail electricity consumption to be offset by the electricity generated from eligible energy resources on the customer-generator's side of the meter that are interconnected with the facilities of the municipally owned utility, subject to the following:

(I) Monthly excess generation. If a customer-generator generates electricity in excess of the customer-generator's monthly consumption, all such excess energy, expressed in kilowatt-hours, shall be carried forward from month to month and credited at a ratio of one to one against the customer-generator's energy consumption, expressed in kilowatt-hours, in subsequent months.

(II) Annual excess generation. Within sixty days after the end of each annual period, or within sixty days after the customer-generator terminates its retail service, the municipally owned utility shall account for any excess energy generation, expressed in kilowatt-hours, accrued by the customer-generator and shall credit such excess generation to the customer-generator in a manner deemed appropriate by the municipally owned utility.

(III) Nondiscriminatory rates. A municipally owned utility shall provide net metering service at nondiscriminatory rates.

(IV) Interconnection standards. Each municipally owned utility shall adopt and post small generation interconnection standards and insurance requirements that are functionally similar to those established in the rules promulgated by the public utilities commission pursuant to this section; except that the municipally owned utility may reduce or waive any of the insurance requirements. If any customer-generator subject to the size specifications specified in subparagraph (V) of this paragraph (b) is denied interconnection by the municipally owned utility, the utility shall provide a written technical or economic explanation of such denial to the customer.

(V) Size specifications. Each municipally owned utility may allow customer-generators to generate electricity subject to net metering in amounts in excess of those specified in this subparagraph (V), and shall allow:

(A) Residential customer-generators to generate electricity subject to net metering up to ten kilowatts; and

(B) Commercial or industrial customer-generators to generate electricity subject to net metering up to twenty-five kilowatts.

(8) Qualifying wholesale utilities - definition - electric resource standard - tradable credits - reports. (a) Definition. Each generation and transmission cooperative electric association that provides wholesale electric service directly to Colorado electric associations that are its members is a qualifying wholesale utility. Commission rules adopted under subsections (1) to (7) of this section do not apply directly to qualifying wholesale utilities, and this subsection (8) does not provide the commission with additional regulatory authority over qualifying wholesale utilities.

(b) Electric resource standard. Notwithstanding any other provision of law, each qualifying wholesale utility shall generate, or cause to be generated, at least twenty percent of the energy it provides to its Colorado members at wholesale from eligible energy resources in the year 2020 and thereafter. If, and to the extent that, the purchase of energy generated from eligible energy resources by a Colorado member from a qualifying wholesale utility would cause an increase in rates for the Colorado member that exceeds the retail rate impact limitation in sub-subparagraph (A) of subparagraph (IV) of paragraph (g) of subsection (1) of this section, the obligation imposed on the qualifying wholesale utility is reduced by the amount of such energy necessary to enable the Colorado member to comply with the rate impact limitation.

(c) A qualifying wholesale utility may count the energy generated or caused to be generated from eligible energy resources by its Colorado members or by the qualifying wholesale utility on behalf of its Colorado members pursuant to subparagraph (V) of paragraph (c) of subsection (1) of this section toward compliance with the energy resource standard established in this subsection (8).

(d) Preferences for certain eligible energy resources and the limit on their applicability established in subparagraph (VIII) of paragraph (c) of subsection (1) of this section may be used by a qualifying wholesale utility in meeting the energy resource standard established in this subsection (8).

(e) Tradable renewable energy credits. A qualifying wholesale utility shall use a system of tradable renewable energy credits to comply with the electric resource standard established in this subsection (8); except that a renewable energy credit acquired under this subsection (8) expires at the end of the fifth calendar year following the calendar year in which it was generated.

(f) In implementing the electric resource standard established in this subsection (8), a qualifying wholesale utility shall assure that the costs, both direct and indirect, attributable to compliance with the standard are recovered from its Colorado members. The qualifying wholesale utility shall employ such cost allocation methods as are required to assure that any direct or indirect costs attributable to compliance with the standard established in this subsection (8) do not affect the cost or price of the qualifying wholesale utility's sales to customers outside of Colorado.

(g) Reports. Each qualifying wholesale utility shall submit an annual report to the commission no later than June 1, 2014, and June 1 of each year thereafter. In addition, the qualifying wholesale utility shall post an electronic copy of each report on its website and shall provide the commission with an electronic copy of the report. In each report, the qualifying wholesale utility shall:

(I) Describe the steps it took during the immediately preceding twelve months to comply with the electric resource standard established in this subsection (8);

(II) In the years before 2020, describe whether it is making sufficient progress toward meeting the standard in 2020 or is likely to meet the 2020 standard early. If it is not making sufficient progress toward meeting the standard in 2020, it shall explain why and shall indicate the steps it intends to take to increase the pace of progress; and

(III) In 2020 and thereafter, describe whether it has achieved compliance with the electric resource standard established in this subsection (8) and whether it anticipates continuing to do so. If it has not achieved such compliance or does not anticipate continuing to do so, it shall explain why and shall indicate the steps it intends to take to meet the standard and by what date.

(h) Nothing in this subsection (8) amends or waives any provision of subsections (1) to (7) of this section.

Source: Initiated 2004: Entire section added, see L. 2005, p. 2337, effective December 1, 2004, proclamation of the Governor issued December 1, 2004. L. 2005: Entire section amended, p. 234, � 1, effective August 8; (6) added by revision, see L. 2005, p. 2340, � 3. L. 2007: Entire section amended, p. 257, � 1, effective March 27. L. 2008: (7) added, p. 190, � 3, effective August 5. L. 2009: (1)(c)(II), (1)(e), and (1)(f)(V) amended and (1.5) added, (SB 09-051), ch. 157, p. 678, � 11, effective September 1. L. 2010: IP(1), (1)(a), (1)(c)(I), (1)(c)(II), (1)(c)(III), (1)(c)(IV), (1)(c)(VIII), (1)(e)(I), (1)(f)(IV), (1)(g)(I), (1)(g)(III), (1)(g)(IV), and (1)(i) amended and (1)(e)(I.5) and (1)(f)(VII) added, (HB 10-1001), ch. 37, pp. 144, 147, 148, �� 1, 2, 3, effective August 11; (1)(c)(VI)(A) amended and (1)(c)(IX) added, (HB 10-1418), ch. 406, p. 2007, � 1, effective August 11; (1)(d) amended, (SB 10-177), ch. 392, p. 1864, � 7, effective August 11. L. 2013: IP(1), (1)(a), (1)(c)(II)(A), (1)(c)(III), IP(1)(c)(V), IP(1)(c)(VI), (1)(c)(VII)(A), IP(1)(f), (1)(g)(I)(A), and (1)(g)(IV)(A) amended and (1)(c)(V.5), (1)(c)(X), and (8) added, (SB 13-252), ch. 414, p. 2452, � 1, effective July 1. L. 2015: (1)(c)(VII) amended, (SB 15-254), ch. 257, p. 934, � 1, effective May 29; (1)(c)(II)(A.5) added, (SB 15-046), ch. 142, p. 433, � 1, effective August 5; (1)(c)(II)(D) added, (HB 15-1377), ch. 200, p. 691, � 1, effective August 5. L. 2019: IP(1) amended and (1)(f)(I) repealed, (SB 19-236), ch. 359, p. 3291, � 4, effective May 30. L. 2021: (1)(d) amended and (1)(g)(I)(D) added, (SB 21-272), ch. 220, p. 1159, � 6, effective June 10; IP(1)(a), (1)(a)(IV), (1)(a)(VII), (1)(a)(VIII), (1)(c)(II)(B), IP(1)(e), (1)(e)(I), (1)(e)(II), (1)(e)(III), and (1.5) amended and (1)(a)(IV.5), (1)(a)(VII.5), (1)(e)(IV), and (1)(j) added, (SB 21-261), ch. 280, p. 1619, � 5, effective June 21; IP(1)(a) and (1)(a)(VI) amended, (HB 21-1052), ch. 52, p. 220, � 1, effective September 7.

Editor's note: (1) A declaration of intent was contained in the initiated measure, Amendment 37, and is reproduced below:

SECTION 1. Legislative declaration of intent:

Energy is critically important to Colorado's welfare and development, and its use has a profound impact on the economy and environment. Growth of the state's population and economic base will continue to create a need for new energy resources, and Colorado's renewable energy resources are currently underutilized.

Therefore, in order to save consumers and businesses money, attract new businesses and jobs, promote development of rural economies, minimize water use for electricity generation, diversify Colorado's energy resources, reduce the impact of volatile fuel prices, and improve the natural environment of the state, it is in the best interests of the citizens of Colorado to develop and utilize renewable energy resources to the maximum practicable extent.

(2) This initiated measure was approved by a vote of the registered electors of the state of Colorado on November 2, 2004. The vote count for the measure was as follows:

FOR: 1,066,023

AGAINST: 922,577

(3) Amendments to subsection IP(1)(a) by SB 21-261 and HB 21-1052 were harmonized.

Cross references: For the legislative declaration in SB 21-261, see section 1 of chapter 280, Session Laws of Colorado 2021.