Public Utilities Commission - Renewable Energy Standard

C.R.S. tit. 40, art. 2

in effect

C.R.S. § 40-2-101 Creation - appointment - term - subject to termination - repeal of part

40-2-101. Creation - appointment - term - subject to termination - repeal of part. (1) (a) A public utilities commission is created in the department of regulatory agencies, which is known as the public utilities commission of the state of Colorado. The public utilities commission is a type 1 entity, as defined in section 24-1-105. (b) The public utilities commission consists of three members appointed by the governor with the consent of the senate. Persons holding office on July 1, 1993, shall continue to serve in such office, but the term of one of these persons shall expire on the Monday preceding the second Tuesday of January, 1995, of another, the Monday preceding the second Tuesday of January, 1996, and of the third, the Monday preceding the second Tuesday of January, 1997, all as the governor shall designate; except that such designation shall not result in the extension of the term of any member to more than four years' duration. Thereafter, appointments shall be made for terms of four years. (2) No more than two members of the public utilities commission shall be affiliated with the same political party, and any appointment to fill a vacancy shall be for the unexpired term. Each commissioner shall be a qualified elector of this state. The governor shall designate one member of the commission as chair of the commission. The commissioners shall devote their entire time to the duties of their office to the exclusion of any other employment and shall receive such compensation as is designated by law. A majority of the commission shall constitute a quorum for the transaction of its business. (3) (a) The provisions of section 24-34-104, C.R.S., concerning the termination schedule for regulatory bodies of the state unless extended as provided in that section, are applicable to the public utilities commission created by this section. (b) (I) This part 1 is repealed, effective September 1, 2026. (II) Before the repeal, the public utilities commission is scheduled for review in accordance with section 24-34-104.

C.R.S. § 40-2-102 Oath - qualifications

40-2-102. Oath - qualifications. Each commissioner, before entering upon the duties of his office, shall take the constitutional oath of office. No person in the employ of or holding any official relation to any corporation or person, which said corporation or person is subject in whole or in part to regulation by the commission, and no person owning stocks or bonds of any such corporation or who is in any manner pecuniarily interested therein shall be appointed to or hold the office of commissioner or be appointed or employed by the commission; but if any such person becomes the owner of such stocks or bonds or becomes pecuniarily interested in such corporation otherwise than voluntarily, he shall divest himself of such ownership or interest within six months; failing to do so, his office or employment shall become vacant.

C.R.S. § 40-2-103 Director - duties

40-2-103. Director - duties. (1) The executive director of the department of regulatory agencies, pursuant to section 13 of article XII of the state constitution, and with the approval of the commission, shall appoint a director of the commission. The director shall manage the operations of the agency in order to carry out the public utilities law, to carry out and implement policies, procedures, and decisions made by the commission, and to meet the requirements of the commission concerning any matters within the authority of a type 1 entity, as defined in section 24-1-105, and which requirements are under the jurisdiction of the commission. The director has all the powers and responsibilities of the division director for this purpose, including the power to issue all necessary process, writs, warrants, and notices. The director has the requisite power to serve warrants and other process in any county or city and county of this state and to delegate such actions to duly authorized employees or agents of the agency as appropriate. (2) Repealed.

C.R.S. § 40-2-104 Assistants and employees - utilization of independent experts

40-2-104. Assistants and employees - utilization of independent experts. (1) The director of the commission may appoint such experts, engineers, statisticians, accountants, investigative personnel, clerks, and other employees as are necessary to carry out the provisions of this title or to perform the duties and exercise the powers conferred by law upon the commission. (2) (Deleted by amendment, L. 93, p. 2058, § 6, effective July 1, 1993.) (3) The director of the commission shall hire and designate employees of the commission as administrative law judges who shall have the power to administer oaths, examine witnesses, receive evidence, and conduct hearings, investigations, and other proceedings on behalf of the commission. (4) (a) Of the money that the commission receives from the public utilities commission fixed utility fund pursuant to section 40-2-114 (1)(b)(II), up to two hundred fifty thousand dollars per year may be allocated to personal services contracts with outside consultants and experts that meet criteria specified by the commission. (b) The amount allocated for outside consultants and experts pursuant to subsection (4)(a) of this section shall be adjusted annually in accordance with changes in the United States department of labor's bureau of labor statistics consumer price index for Denver-Aurora-Lakewood for all items and all urban consumers, or its successor index.

C.R.S. § 40-2-104.5 Financial disclosures by intervenors

40-2-104.5. Financial disclosures by intervenors. (1) An intervenor in any matter before the commission shall disclose any of the following relationships that exist or, within the immediately preceding twenty-four months, existed between the intervenor and the regulated utility in the matter: (a) Any corporate affiliation with the regulated utility; (b) The receipt of any funding from the regulated utility; or (c) Any other financial relationship between the intervenor and the regulated utility. (2) The commission shall publish on its website all disclosures made pursuant to this section.

C.R.S. § 40-2-105 Office - sessions - seal - supplies

40-2-105. Office - sessions - seal - supplies. (1) The office of the commission shall be in the city and county of Denver. The office shall be open every day, legal holidays, Saturdays, and Sundays excepted. Hearings under this title may be held in such places within this state as shall be determined by the commission. It is the duty of the office of state planning and budgeting to provide suitable quarters for the commission and its employees. (2) The commission shall have a seal bearing the following inscription: "The public utilities commission of the state of Colorado". The seal shall be affixed to all writs and authentications of copies of records and to such other instruments as the commission shall direct. All courts shall take judicial notice of said seal. (3) Necessary expenses of the commission shall be paid from appropriations made by the general assembly to the commission.

C.R.S. § 40-2-106 Reports and decisions of the commission

40-2-106. Reports and decisions of the commission. Whenever an investigation is made, a hearing is held, or a decision is entered by the commission, it is the duty of the commission to make a report or decision in writing in respect thereto which shall state its findings of fact and conclusions thereon, together with its decision or requirement in the premises. All such reports and decisions shall be entered of record and a copy thereof shall be furnished to all parties to the proceedings and to such other persons as the commission may deem advisable.

C.R.S. § 40-2-107 Compensation and expenses of employees

40-2-107. Compensation and expenses of employees. (1) All employees of the commission shall receive such compensation as may be fixed pursuant to law. (2) Repealed. (3) All expenses incurred by the commission pursuant to the provisions of this title, including the actual and necessary traveling expenses and other expenses and disbursements of the commissioners, their officers, and employees shall be paid by the controller from the funds appropriated for the use of the commission upon vouchers of the commission therefor.

C.R.S. § 40-2-108 Rules - legislative declaration

40-2-108. Rules - legislative declaration. (1) The commission shall promulgate such rules as are necessary for the proper administration and enforcement of this title and shall furnish, without charge, copies of the appropriate rules to each public utility under its jurisdiction and, upon request, to any public officer, agency, political subdivision, association of officers, agencies, or political subdivisions and to any representative of twenty-five or more consumers. The commission shall be governed by the provisions of article 4 of title 24, C.R.S., for the promulgation and adoption of rules; except that, notwithstanding any provision of the said article 4 of title 24, C.R.S., to the contrary, the commission shall issue a decision whenever it adopts rules in accordance with this section. (2) Notwithstanding section 24-4-103 (6), C.R.S., any temporary or emergency rule adopted by the commission shall be effective until a permanent rule that replaces the temporary or emergency rule is effective but not for more than two hundred ten days after the date of adoption. (3) (a) The general assembly finds, determines, and declares that: (I) Certain communities, both in Colorado and internationally, have historically been forced to bear a disproportionate burden of adverse human health or environmental effects, as documented in numerous studies, including the "Toxic Wastes and Race at Twenty, 1987-2007" report by the United Church of Christ Justice & Witness Ministries; the federal environmental protection agency's annual environmental justice progress reports; and a 2021 report from the "Mapping for Environmental Justice" project at the Berkeley Public Policy/The Goldman School that shows how the pollution burden is distributed in Colorado, while also facing systemic exclusion from environmental decision-making processes and enjoying fewer environmental benefits; and (II) The purpose of this subsection (3) is to ensure that the commission, in exercising its regulatory authority, will take account of and, where possible, help to correct these historical inequities. (b) The commission shall promulgate rules requiring that the commission, in all of its work including its review of all filings and its determination of all adjudications, consider how best to provide equity, minimize impacts, and prioritize benefits to disproportionately impacted communities and address historical inequalities. (c) (I) In promulgating rules pursuant to this subsection (3), the commission shall identify disproportionately impacted communities. In identifying the communities, the commission shall consider minority, low-income, tribal, or indigenous populations in the state that experience disproportionate environmental harm and risks resulting from such factors as increased vulnerability to environmental degradation, lack of opportunity for public participation, or other factors. Increased vulnerability may be attributable to an accumulation of negative or a lack of positive environmental, health, economic, or social conditions within these populations. (II) When making decisions relating to retail customer programs, the commission shall host informational meetings, workshops, and hearings that invite input from disproportionately impacted communities and shall ensure, to the extent reasonably possible, that such programs, including any associated incentives and other relevant investments, include floor expenditures, set aside as equity budgets, to ensure that low-income customers and disproportionately impacted communities will have at least proportionate access to the benefits of such programs, incentives, and investments. (d) Repealed.

C.R.S. § 40-2-109 Report to executive director of the department of revenue

40-2-109. Report to executive director of the department of revenue. (1) Repealed. (2) (a) On March 1 of each year, the public utilities commission shall furnish the executive director of the department of revenue with a list of those public utilities subject to its jurisdiction, supervision, and regulation on January 1 of each year. The provisions of this subsection (2) shall not apply to: (I) Motor carriers subject to the passenger-mile tax imposed by sections 42-3-304 and 42-3-306, so long as the cost of regulation of such motor carriers is defrayed from the proceeds of such passenger-mile tax; and (II) Rail fixed guideway systems that are regulated by the public utilities commission pursuant to part 1 of article 18 of this title. (b) The director of the public utilities commission shall provide written notice to the revisor of statutes once the federal grant moneys made available under the "Moving Ahead for Progress in the 21st Century Act", 49 U.S.C. sec. 5329, have been awarded to the state. This subsection (2) takes effect upon the receipt by the revisor of statutes of such written notice.

C.R.S. § 40-2-109.5 Incentives for distributed generation - definition

40-2-109.5. Incentives for distributed generation - definition. (1) The commission shall develop a policy to establish incentives for consumers who produce distributed generation, including, but not limited to, small wind turbines, thermal biomass, electric biomass, and solar thermal energy. The commission shall consider whether a credit program similar to the renewable energy standard set forth in section 40-2-124 would work for consumers who produce distributed generation. The commission shall present the policy and findings regarding a credit program to the house of representatives transportation and energy committee and the senate agriculture, natural resources, and energy committee, or their successor committees. (2) As used in this section, "distributed generation" means a system by which a consumer generates heat or electricity using renewable energy resources for his or her own needs and may also send surplus electrical power back into the power grid. (3) Effective January 1, 2012, all photovoltaic installations funded wholly or partially through financial incentives under this section shall be subject to the requirements set forth in section 40-2-128.

C.R.S. § 40-2-110 Appropriation and fees

40-2-110. Appropriation and fees. (1) At each regular session, the general assembly shall determine the amounts to be expended by the public utilities commission for its administrative expenses in supervising and regulating the public utilities which are under its jurisdiction, a list of which the commission is required by section 40-2-109 to furnish to the department of revenue, and shall appropriate to the public utilities commission from the public utilities commission fixed utility fund, established in section 40-2-114, the full amount so determined, and such amount shall be defrayed out of the fees to be paid by such public utilities, as provided in section 40-2-112. (2) (a) (I) At each regular session, the general assembly shall determine the amounts to be expended by the public utilities commission for its administrative expenses in the supervision and regulation of motor carriers as provided by law and shall appropriate such amounts from the public utilities commission motor carrier fund established in section 40-2-110.5 as are necessary to be expended by the commission to accomplish said purposes. (II) Repealed. (b) Repealed.

C.R.S. § 40-2-110.5 Annual fees - public utilities commission motor carrier fund - created

40-2-110.5. Annual fees - public utilities commission motor carrier fund - created. (1) (Deleted by amendment, L. 2011, (HB 11-1198), ch. 127, p. 419, § 15, effective August 10, 2011.) (2) (a) (Deleted by amendment, L. 2003, p. 2380, § 2, effective August 6, 2003.) (b) to (e) (Deleted by amendment, L. 93, p. 2059, § 9, effective July 1, 1993.) (2.5) (Deleted by amendment, L. 2005, p. 31, § 1, effective August 8, 2005.) (3) Repealed. (4) and (5) (Deleted by amendment, L. 2011, (HB 11-1198), ch. 127, p. 419, § 15, effective August 10, 2011.) (6) The public utilities commission motor carrier fund is hereby created in the state treasurer's office. The moneys in the fund shall be subject to annual appropriation by the general assembly for the purposes specified in section 40-2-110 (2)(a)(I). Any unexpended balance remaining in said fund at the end of any fiscal year shall remain in the fund. (6.5) and (7) Repealed. (8) Notwithstanding the amount specified for any fee in section 40-10.1-111, the commission by rule or as otherwise provided by law may reduce the amount of one or more of the fees if necessary pursuant to section 24-75-402 (3), C.R.S., to reduce the uncommitted reserves of the fund to which all or any portion of one or more of the fees is credited. After the uncommitted reserves of the fund are sufficiently reduced, the commission by rule or as otherwise provided by law may increase the amount of one or more of the fees as provided in section 24-75-402 (4), C.R.S. (9) (a) For the 2013-14 fiscal year and for each fiscal year thereafter, if the amount of uncommitted reserves in the motor carrier fund at the conclusion of any given fiscal year exceeds ten percent of the fund's expenditures during that fiscal year, the amount of the excess that is attributable to revenues received from any motor carrier, motor private carrier, broker, freight forwarder, leasing company, or any other person required to register with the United States department of transportation under the unified carrier registration system as authorized by federal law and as provided for in section 40-10.5-102 shall be transferred to the motor carrier safety fund created in section 42-4-235 (6), C.R.S. (b) The distribution required by paragraph (a) of this subsection (9) is in lieu of, and shall supersede, any provision to the contrary in section 24-75-402, C.R.S.

C.R.S. § 40-2-111 Report of utilities to department of revenue

40-2-111. Report of utilities to department of revenue. Each public utility required to pay such fees shall, on or before May 15 of each year, file a return with the department of revenue on such forms as shall be prescribed by the executive director of the department of revenue and the public utilities commission setting forth the gross operating revenues of such public utility from intrastate utility business only transacted in the state of Colorado during the preceding calendar year. Such return shall be executed and verified by two of the executive officers of the utility making the return and shall contain or be verified by a written declaration that it is made under the penalties of perjury in the second degree, and any officer who knowingly and willfully makes and signs a false return is guilty of perjury in the second degree.

C.R.S. § 40-2-112 Computation of fees

40-2-112. Computation of fees. (1) (a) On or before June 1 of each year, the executive director of the department of revenue shall ascertain the aggregate amount of gross operating revenues of telephone corporations and all other public utilities filing returns as provided in section 40-2-111. Based on appropriations made by the general assembly, the executive director of the department of regulatory agencies shall specify, for the telecommunications utility fund, created in section 40-2-114 (1)(b)(I), and the public utilities commission fixed utility fund, created in section 40-2-114 (1)(b)(II), the revenue needed to provide for the direct and indirect costs of the supervision and regulation of telephone corporations and all other public utilities under the jurisdiction of the department of regulatory agencies, excluding the amount of money provided as administrative support from the various telecommunications programs administered by the commission, including the high cost support mechanism, established in section 40-15-208, the 911 surcharge, established in section 29-11-102.3, the 988 surcharge, established in section 40-17.5-102, and the telecommunications relay service surcharge, established in section 40-17-103. (b) (I) For each telephone corporation, the executive director of the department of regulatory agencies shall compute the percentage which the amount of revenue needed for the direct and indirect costs of the supervision and regulation of telephone corporations is of the aggregate amount of gross operating revenues of the telephone corporation derived from intrastate utility business transacted during the preceding calendar year, and that percentage shall be the basis upon which fees due from telephone corporations for the ensuing year shall be fixed. (II) For each public utility other than a telephone corporation, the executive director of the department of regulatory agencies shall compute the percentage which the amount of revenue needed for the direct and indirect costs of the supervision and regulation of public utilities other than telephone corporations is of the aggregate amount of gross operating revenues of such public utilities derived from intrastate utility business transacted during the preceding calendar year, and that percentage shall be the basis upon which fees due from the public utilities for the ensuing year shall be fixed. (2) In recognition of the fact that nonprofit generation and transmission electric corporations or associations may be subject to less regulation and to no rate regulation by the commission, the executive director of the department of revenue shall disregard any revenues reported by such entities in making the computations required under subsection (1) of this section. In addition, the executive director of the department of revenue shall, in consultation with the director of the commission, enter into an agreement with each nonprofit generation and transmission electric corporation or association whereby such entity agrees to pay an amount equal to the administrative expenses reasonably anticipated to be incurred by the commission for the regulation of such entity. Said agreement shall be made by May 1 of the year in which it is to become effective and shall remain effective for not less than two and not more than five years. In the event that the anticipated amount set forth in the agreement proves to be substantially higher or lower than the commission's actual expenses incurred, the agreement for the next following year or years shall be adjusted so as to take such fact into account. If no such agreement is made as provided in this subsection (2), the commission, on its own motion or upon application by the executive director of the department of revenue or by such entity, shall set the matter for hearing and determine the amount to be paid by the entity xpenses incurred, the agreement for the next following year or years shall be adjusted so as to take such fact into account. If no such agreement is made as provided in this subsection (2), the commission, on its own motion or upon application by the executive director of the department of revenue or by such entity, shall set the matter for hearing and determine the amount to be paid by the entity. Amounts paid under agreements as contemplated by this subsection (2) or by order of the commission shall be used to reduce amounts paid by other utilities under subsection (1) of this section.

C.R.S. § 40-2-113 Collection of fees - limitation

40-2-113. Collection of fees - limitation. (1) On or before June 15 of each year, the department of revenue shall notify each public utility subject to this article 2 of the amount of its fee for the ensuing fiscal year beginning July 1, computed by multiplying its gross intrastate utility operating revenues for the preceding calendar year, as set forth in its return filed for that purpose, by the percentage determined in accordance with section 40-2-112; except that the department of revenue shall not require a public utility that is a telephone corporation to pay a fee in excess of two-fifths of one percent of its gross intrastate utility operating revenues for the preceding calendar year and shall not require any other public utility to pay a fee in excess of forty-five one-hundredths of one percent of its gross intrastate utility operating revenues for the preceding calendar year. (2) Each public utility, including penal communications service providers, as defined in section 17-42-103 (2), shall pay the fee assessed against it to the department of revenue in equal quarterly installments on or before July 15, October 15, January 15, and April 15 in each fiscal year. If a public utility does not make a payment by one of the quarterly deadlines, the department of revenue shall charge the public utility a penalty of ten percent of the installment due, together with interest at the rate of one percent per month on the amount of the unpaid installment until the full amount of the installment, penalty, and interest has been paid. Upon failure, refusal, or neglect of any public utility to pay the fee, or any penalty or interest, the attorney general shall bring suit in the name of the state to collect the amount due. (3) The commission shall allow a public utility that is not a telephone corporation full recovery of fees assessed and remitted to the department of revenue pursuant to this section. The recovery mechanism must include the ability of the utility, at its option, to use a deferred account to track changes in fees between rate proceedings.

C.R.S. § 40-2-114 Disposition of fees collected - telecommunications utility fund - fixed utility fund - appropriation

40-2-114. Disposition of fees collected - telecommunications utility fund - fixed utility fund - appropriation. (1) (a) Three percent of the fees collected under section 40-2-113 by the department of revenue shall be remitted to the state treasurer and credited by the state treasurer as follows: (I) Notwithstanding any other provision of this paragraph (a), for the 2016-17 fiscal year and for any fiscal year thereafter in which a grant match is required for the receipt of federal money under the federal "Moving Ahead for Progress in the 21st Century Act", Pub.L. 112-141, 126 Stat. 405, for rail fixed guideway system safety oversight responsibilities under article 18 of this title, the lesser of all of the fees or up to one hundred fifty thousand dollars of the fees, or as much thereof as the commission deems necessary, to the public utilities commission fixed utility fund created in paragraph (b) of this subsection (1); (II) For the 2017-18 fiscal year and for each fiscal year thereafter, the lesser of all of the fees remaining after fees are credited as required by subparagraph (I) of this paragraph (a) or an amount of the fees equal to two hundred forty thousand dollars plus a cumulative inflation adjustment of two percent for each fiscal year beginning with the 2017-18 fiscal year to the highway-rail crossing signalization fund created in section 40-29-116 (1); and (III) Any remaining fees to the general fund. (b) For the remaining ninety-seven percent of the fees collected, the state treasurer shall credit: (I) Fees paid by public utilities that are telephone corporations to the telecommunications utility fund, which fund is hereby created; and (II) Fees paid by other public utilities to the public utilities commission fixed utility fund, which fund is hereby created. (2) (a) Money in the funds created in subsection (1) of this section shall be expended only to defray the full amount determined by the general assembly for: (I) The administrative expenses of the commission for the supervision and regulation of the public utilities paying the fees; (II) The financing of the office of the utility consumer advocate created in article 6.5 of this title 40; and (III) With regard only to expenditures from the public utilities commission fixed utility fund created in subsection (1)(b) of this section, the administrative expenses, not to exceed five hundred thousand dollars annually, incurred by the Colorado electric transmission authority in carrying out its duties under article 42 of this title 40. The Colorado electric transmission authority shall remit to the public utilities commission fixed utility fund any amounts it receives in excess of its actual administrative expenses plus a fifty percent reserve margin. (b) The state treasurer shall retain any unexpended balance remaining in either fund at the end of any fiscal year to defray the administrative expenses of the commission during subsequent fiscal years, and the executive director of the department of revenue shall take any such unexpended balance into account when computing the percentage upon which fees for the ensuing fiscal year will be based.

C.R.S. § 40-2-115 Cooperation with other states and with the United States - natural gas pipeline safety - customer-owned service line maintenance and repairs notice of responsibility - rules - definitions

40-2-115. Cooperation with other states and with the United States - natural gas pipeline safety - customer-owned service line maintenance and repairs notice of responsibility - rules - definitions. (1) (a) The commission may confer with or hold joint hearings with the authorities of any state or any agency of the United States in connection with any matter arising in proceedings under this title 40, under the laws of any state, or under the laws of the United States; avail itself of the cooperation, services, records, and facilities of authorities of this state, any other state, or any agency of the United States as may be practicable in the enforcement or administration of the provisions of this title 40; and enter into cooperative agreements with the various states and with any agency of the United States to enforce the economic and safety laws and rules of this state and of the United States. (b) The commission may provide for the exchange of information concerning the enforcement of the economic and safety laws and rules of this state, any other state, and the United States relating to public utilities or to safety of transportation of gas by any person, including a municipality. In particular, the commission may submit a certification to, or enter into an agreement with, the United States secretary of transportation under 49 U.S.C. sec. 60105 or 60106, respectively, so that the commission may enforce the rules of the United States department of transportation concerning pipeline safety promulgated under 49 U.S.C. sec. 60101 et seq. The commission shall adopt such rules as are necessary and proper to comply with federal requirements. (c) The commission's rules adopted pursuant to this section must apply to all persons and entities constituting the intrastate pipeline system to the maximum extent permissible under federal law and the Colorado constitution, including all: (I) Public utilities and municipal or quasi-municipal corporations transporting gas or providing gas service; (II) Operators of natural gas master metered systems; (III) Operators of liquid petroleum gas distribution systems; (IV) Operators of pipelines transporting gas in intrastate commerce; and (V) Operators of intrastate liquefied natural gas facilities. (d) (I) The commission shall adopt pipeline safety rules that incorporate the most current federal requirements under 49 CFR 191, 192, 193, and 199, as applicable, to maintain minimum standards for gas pipeline safety. (II) The commission's gas pipeline safety rules must address, and may be more stringent than required by federal standards with regard to: (A) Qualifications and verifiable credentials for personnel engaged in pipeline construction, inspection, and repair activities; (B) Reduction of the risks posed by abandoned gas pipelines; (C) Mapping of all pipelines within the commission's jurisdiction. For this purpose, the commission may incorporate information from any existing flowline maps or other maps prepared by the energy and carbon management commission created in section 34-60-104.3 (1) and showing pipelines subject to the jurisdiction of that agency. The public utilities commission's mapping requirements for pipelines within its jurisdiction must incorporate the same standards for confidentiality, security, and public access and limitations on the scale of publicly available images as adopted by the energy and carbon management commission in 2 CCR 404-1, rule 1101.e. (D) Increased frequency of inspections of all pipelines within the commission's jurisdiction; (E) Use of advanced leak detection technology to meet the need for pipeline safety and protection of the environment; (F) Expansion of annual reporting requirements for pipeline operators; (G) Requirements for commission investigation of specific types of pipeline damage and pursuit of appropriate civil remedies for such damage; inspections of all pipelines within the commission's jurisdiction; (E) Use of advanced leak detection technology to meet the need for pipeline safety and protection of the environment; (F) Expansion of annual reporting requirements for pipeline operators; (G) Requirements for commission investigation of specific types of pipeline damage and pursuit of appropriate civil remedies for such damage; (H) On or before March 1, 2024, requirements for the installation or reinstallation of service regulators by the owner or operator so that any vents associated with the service regulators are at least twelve inches above ground level and located in an area that is protected from external blockage; and (I) On or before March 1, 2024, requirements for the visual inspection of gas meters and service regulators by a qualified individual no less frequently than every five calendar years with intervals not to exceed sixty-three months and record documentation of each inspection and for the owner or operator of the gas meter or service regulator to retain the documentation for the lifetime of the gas meter or service regulator. (e) In addition to all other powers and duties conferred on the commission by this title 40, the commission may issue orders requiring any person to comply with, or to cease and desist from any violation of, the rules adopted under this section. (f) Notwithstanding any provision of this section to the contrary, the commission shall not adopt any rules that regulate underground natural gas storage facilities. (1.5) (a) On or before March 1, 2024, the commission shall promulgate rules to establish a process for determining whether an owner or operator or a customer has responsibility for the maintenance and repairs of a customer-owned service line installed on or after August 14, 1995, and before March 1, 2024. (b) On or before March 1, 2024, the commission shall promulgate rules requiring an owner or operator that distributes natural gas to a customer-owned service line installed by the owner or operator on or after March 1, 2024, to provide written notice to the customer within ninety days after installation that, at a minimum, informs the customer whether the customer or the owner or operator is responsible for maintaining and repairing the customer-owned service line. (c) The commission's rules pursuant to subsection (1.5)(b) of this section must include specific circumstances for when a customer may be responsible for maintaining and repairing the customer-owned service line and a requirement that: (I) The owner or operator use best efforts to obtain a copy of the written notice described in subsection (1.5)(b) of this section with the customer's signature from the customer within ninety days after installation of the customer-owned service line; (II) With respect to the copy of the written notice described in subsection (1.5)(b) of this section that includes the customer's signature in accordance with subsection (1.5)(c)(I) of this section, the owner or operator: (A) Provide a copy to the customer for the customer's records; (B) Maintain a copy for the owner's or operator's records for the duration of the lifetime of the customer-owned service line; (C) Provide a copy to an inspector upon request; and (D) If the property on which the customer-owned service line is located changes ownership, use best efforts to obtain a new copy of the written notice described in subsection (1.5)(b) of this section with the new property owner's signature from the new property owner within ninety days after the change of ownership if the owner or operator is aware of the change; and n inspector upon request; and (D) If the property on which the customer-owned service line is located changes ownership, use best efforts to obtain a new copy of the written notice described in subsection (1.5)(b) of this section with the new property owner's signature from the new property owner within ninety days after the change of ownership if the owner or operator is aware of the change; and (III) If the owner or operator fails to obtain a copy of the written notice described in subsection (1.5)(b) of this section with the customer's signature from the customer in accordance with subsection (1.5)(c)(I) of this section, the owner or operator either maintain proof of efforts to obtain the customer's signature or document the customer's refusal to provide a signature. (d) Notwithstanding any other provision of this section to the contrary, an owner or operator is responsible for all maintenance and repairs of the portion of a service line that is upstream from the gas meter. (e) Notwithstanding any other provision of this section to the contrary, the commission's gas pipeline safety rules pursuant to this section must permit any activity that is within the best practices and standards for the industry given continuous improvement and changes to technology. (2) As used in this section, unless the context otherwise requires, or as otherwise defined in commission rules: (a) "Customer-owned service line" means the portion of the service line that extends downstream from the gas meter to the customer's primary residential or commercial structure that is serviced with natural gas. (b) (I) "Distribution system" means the piping and associated facilities used to deliver natural gas to customers. (II) "Distribution system" does not include the facilities that an owner or operator owns that are classified as production, storage, gathering, or transmission facilities. (c) "Gas" means natural gas, flammable gas, and any gas that is toxic or corrosive. (d) "Gas meter" means the meter that measures the transfer of gas from an owner or operator of a customer-owned service line to a customer. (e) "Main line" means the portion of a distribution system that serves, or is designed to serve, as a common source of gas supply for more than one service line. (f) "Owner or operator" means an owner or operator of a distribution system or an investor-owned natural gas utility. (g) "Qualified" has the meaning set forth in 49 CFR 192.803. (h) "Service line" has the meaning set forth in 49 CFR 192.3. (i) "Service regulator" means the device on a service line that controls the pressure of gas delivered from a higher pressure to the pressure provided to the customer. A service regulator may serve one customer or multiple customers through a meter header or manifold. (j) "Transportation of gas" or "transporting gas" means the gathering, transmission, or distribution of gas by pipeline, as defined in 49 CFR 192.3. (k) "Underground natural gas storage facility" has the meaning set forth in section 34-64-102 (3.5).

C.R.S. § 40-2-116 Motor carriers - motor vehicle carriers exempt from regulation as public utilities - safety regulations

40-2-116. Motor carriers - motor vehicle carriers exempt from regulation as public utilities - safety regulations. (Repealed)

C.R.S. § 40-2-117 Legislative declaration - commission to conduct review of rate structures

40-2-117. Legislative declaration - commission to conduct review of rate structures. (Repealed)

C.R.S. § 40-2-118 Comprehensive energy report

40-2-118. Comprehensive energy report. (Repealed)

C.R.S. § 40-2-119 Exemption of rail carrier transportation

40-2-119. Exemption of rail carrier transportation. (1) The commission shall by rule or regulation establish standards and procedures to be used in determining whether certain transportation provided by a rail carrier in this state should be exempted, in whole or in part, from one or more provisions of this title. Such rules and regulations shall provide for such exemption when the commission finds that: (a) Jurisdiction, regulation, and control by the commission are not necessary to carry out the transportation policy of this title; and (b) Either the transaction or service is of limited scope or the application of a provision of this title is not needed to protect shippers from the abuse of market power.

C.R.S. § 40-2-120 Rail transportation policy

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.

C.R.S. § 40-2-121 Transportation of natural gas report - legislative declaration

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

C.R.S. § 40-2-122 Natural gas - deregulation of supply - voluntary separation of service offerings - consumer protection - legislative declaration - definition - rules

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. 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. ission 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. deration 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; (C) Appropriate credit and collection practices; (D) The terms under which service may be discontinued; (E) How partial payments are allocated; (F) Protecting customer privacy; nditions 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; (C) Appropriate credit and collection practices; (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. ased 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. ivery 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); (C) Investments in assets that are stranded by competition for natural gas supply service; (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. 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. ality 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.

C.R.S. § 40-2-123 Energy technologies - consideration by commission - incentives - demonstration projects - definitions

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 moneys. (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) (a) The commission shall consider proposals by Colorado investor-owned utilities for the following types of projects: (I) To construct, own, and operate electric generation or storage facilities utilizing innovative energy technology; or (II) To partner with other energy developers or independent power producers to construct, acquire, or contract for electric generation or storage facilities utilizing innovative energy technology. oposals by Colorado investor-owned utilities for the following types of projects: (I) To construct, own, and operate electric generation or storage facilities utilizing innovative energy technology; or (II) To partner with other energy developers or independent power producers to construct, acquire, or contract for electric generation or storage facilities utilizing innovative energy technology. (b) (I) An investor-owned utility may apply under this subsection (2) to the commission for approval of innovative energy technology projects in areas of the state that have been economically affected by the accelerated retirements of existing generation resources. Any such projects are eligible for cost recovery through the clean energy plan revenue rider, and, if approved by the commission, prudently incurred costs that do not constitute clean energy plan activities are eligible for recovery through an adjustment clause or other similar cost-recovery mechanism other than the clean energy plan revenue rider, in accordance with the retail rate stability provisions of section 40-2-125.5 (5), following the project's commencement of commercial operation and until any project is placed in base rates. Nothing in this section prohibits or deters cost-effective innovative energy technology deployment; except that, if an innovative energy technology project is abandoned or cancelled, in whole or in part, the utility is not entitled to recover any costs of research, planning, development, construction, start-up, or operation in connection with the project absent a finding by the commission that such costs were prudently incurred, and in any cost-recovery proceeding the utility shall bear the burden of proof. (II) An investor-owned utility shall present any innovative energy technology projects as part of its electric resource planning process so that the projects can be evaluated as part of a comprehensive plan to meet the investor-owned utility's energy and capacity needs. The presentation for each project must address: (A) How the project will be developed; (B) Whether the project involves a change to an existing generation resource to meet the requirements as an innovative energy technology project or whether the project is a newly developed innovative energy technology project; (C) How the project mitigates the impacts of the transition to cleaner generation technologies in affected areas of Colorado; and (D) As applicable, how the project furthers the efforts of any workforce transition plan or community assistance plan developed pursuant to section 40-2-125.5 (4)(a)(VII) or 40-2-133 associated with any accelerated retirement of an electric generating facility and how the project complies with section 40-2-129. (III) (A) Any innovative energy technology projects approved pursuant to this subsection (2) proportionally count toward the targets in section 40-2-125.5 (5)(b); except that innovative energy technology projects developed by an investor-owned utility pursuant to this subsection (2) must not exceed, in the aggregate, a nameplate capacity of three hundred megawatts. (B) Notwithstanding any other provision of law, the commission shall not permit an investor-owned utility to earn a total return from an innovative energy technology project that exceeds the total return the utility would have earned from a photovoltaic solar generation facility or wind generation facility of equivalent capacity. in the aggregate, a nameplate capacity of three hundred megawatts. (B) Notwithstanding any other provision of law, the commission shall not permit an investor-owned utility to earn a total return from an innovative energy technology project that exceeds the total return the utility would have earned from a photovoltaic solar generation facility or wind generation facility of equivalent capacity. (c) To facilitate financing of an innovative energy technology project, one or more investor-owned utilities may develop, construct, or own a project through a special-purpose entity or other affiliated partnership or corporation, including a public-private partnership or partnership formed with other energy developers or independent power producers. For this purpose, an investor-owned utility is entitled to structure the partnership in the manner that it deems appropriate; to negotiate ownership interests in the project; and to use appropriate means to solicit potential partnerships, including requests for information, requests for proposals, or bilateral negotiations. (d) (I) In the construction or expansion of an innovative energy technology project approved pursuant to this subsection (2), an investor-owned utility shall use its own employees or qualified contractors, or both, but shall not use a contractor unless the contractor's employees have access to an apprenticeship program registered with the United States department of labor's office of apprenticeship or by a state apprenticeship agency recognized by that office; except that this apprenticeship requirement does not apply to: (A) The design, planning, or engineering of the transmission facilities; (B) Management functions to operate the transmission facilities; or (C) Any work included in a warranty. (II) The commission shall not approve any construction or expansion under this subsection (2) until the commission has completed the rule-making initiated before December 31, 2020, addressing in part section 40-2-129. (e) As used in this subsection (2): (I) "Innovative energy technology" means a generation technology or storage technology that, alone or in combination with other technologies used in a project: (A) Generates or stores electricity without emitting greenhouse gas emissions into the atmosphere; (B) At the time of any application under this subsection (2), has not been widely deployed in the United States. In evaluating whether a technology is "widely deployed" within the meaning of this subsection (2)(e)(I)(B), the commission may evaluate the number of commercial projects in which the technology is installed in the United States for purposes of electric generation and how long those projects have been in commercial operation. (C) Does not include stand-alone wind, solar, or lithium-ion battery storage resources or wind or solar resources paired with lithium-ion battery storage. (II) "Innovative energy technology project" or "project" means an electric generation or energy storage facility that demonstrates the use of innovative energy technology in Colorado and for which the investment in the innovative energy technology portion of the project constitutes the majority of the total project investment. (f) This subsection (2) is repealed, effective December 31, 2024. (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. ater 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.

C.R.S. § 40-2-124 Renewable energy standards - qualifying retail and wholesale utilities - definitions - net metering - legislative declaration - rules

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 (C) Methane produced at landfills or as a by-product of the treatment of wastewater residuals. (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. 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. 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. (c) Electric resource standards: (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. 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; (C) Six percent of retail electricity sales in Colorado for the years 2015 through 2019; and (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. rado 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) ects 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. ves 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 (C) Is consistent with timely attainment of the state's clean energy and climate goals. (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. ation 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. f 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. 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. red 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. 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. t 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.) sed 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; (c) Years eight through twelve: Six percent of retail electricity sales; and (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.) he 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. ion 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. le 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.

C.R.S. § 40-2-125 Eminent domain restrictions

40-2-125. Eminent domain restrictions. (1) A qualifying retail utility shall not have the authority to condemn or exercise the power of eminent domain over any real estate, right-of-way, easement, or other right pursuant to section 38-2-101, C.R.S., to site the generation facilities of a renewable energy system used in whole or in part to meet the electric resource standards set forth in section 40-2-124. This section shall not be construed to limit the authority of a home rule municipality under article XX of the Colorado constitution. (2) Section 3 of this initiated measure provides that this section and section 40-2-124 shall be effective December 1, 2004.

C.R.S. § 40-2-125.5 Carbon dioxide emission reductions - goal to eliminate by 2050 - legislative declaration - interim targets - submission and approval of plans - definitions - cost recovery - reports - rules

40-2-125.5. Carbon dioxide emission reductions - goal to eliminate by 2050 - legislative declaration - interim targets - submission and approval of plans - definitions - cost recovery - reports - rules. (1) Legislative declaration. The general assembly finds and declares that: (a) It is a matter of statewide importance to promote the development of cost-effective clean energy and new technologies and reduce the carbon dioxide emissions from the Colorado electric generating system; (b) The creation of a low-cost, reliable, and clean electricity system is critical to achieving the level of greenhouse gas emissions necessary to avoid the worst impacts of climate change and advancing a robust and efficient low-carbon economy for the state of Colorado and the nation; (c) Technology advancement has already allowed Colorado to achieve reductions in carbon dioxide emissions from the electric utility sector, and continued technology development is key to extend progress toward a reliable, low-cost, clean energy future; (d) Alternative financing mechanisms may result in lower costs to electric utility customers; therefore, it is helpful to provide alternative financing mechanisms that utilities may use to reduce the total amount of costs being included in customer rates resulting from accelerating the retirement of electric generating facilities; and (e) A bold clean energy policy will support this progress and allow Coloradans to enjoy the benefits of reliable clean energy at an affordable cost. (2) Definitions. As used in this section, unless the context otherwise requires: (a) "Clean energy plan" means a plan filed by a qualifying retail utility as part of its electric resource plan to reduce the qualifying retail utility's carbon dioxide emissions associated with electricity sales to the qualifying retail utility's electricity customers by eighty percent from 2005 levels by 2030, and that seeks to achieve providing its customers with energy generated from one-hundred-percent clean energy resources by 2050. (b) "Clean energy resource" means any electricity-generating technology that generates or stores electricity without emitting carbon dioxide into the atmosphere. Clean energy resources include, without limitation, eligible energy resources as defined in section 40-2-124 (1)(a). (c) (I) "Qualifying retail utility" means a retail utility providing electric service to more than five hundred thousand customers in this state or any other electric utility that opts in pursuant to subsection (3)(b) of this section. (II) "Qualifying retail utility" does not include a municipally owned utility. (3) Clean energy targets. (a) In addition to the other requirements of this section, a qualifying retail utility shall meet the following clean energy targets: (I) By 2030, the qualifying retail utility shall reduce the carbon dioxide emissions associated with electricity sales to the qualifying retail utility's electricity customers by eighty percent from 2005 levels. (II) For the years 2050 and thereafter, or sooner if practicable, the qualifying retail utility shall seek to achieve the goal of providing its customers with energy generated from one-hundred-percent clean energy resources so long as doing so is technically and economically feasible, in the public interest, and consistent with the requirements of this section. (III) The qualifying retail utility shall retire renewable energy credits established under section 40-2-124 (1)(d), in the year generated, by any eligible energy resources used to comply with the requirements of this section. d-percent clean energy resources so long as doing so is technically and economically feasible, in the public interest, and consistent with the requirements of this section. (III) The qualifying retail utility shall retire renewable energy credits established under section 40-2-124 (1)(d), in the year generated, by any eligible energy resources used to comply with the requirements of this section. (b) Any other electric public utility may opt into the full terms of this entire section upon notification to the commission. (4) Submission and approval of plans. (a) The first electric resource plan that a qualifying retail utility files with the commission after January 1, 2020, must include a clean energy plan that will achieve the clean energy target set forth in subsection (3)(a)(I) of this section and make progress toward the one-hundred-percent clean energy goal set forth in subsection (3)(a)(II) of this section in accordance with the following: (I) The electric resource plan containing the clean energy plan must utilize a resource acquisition period that extends through 2030. (II) The clean energy plan submitted to the commission must set forth a plan of actions and investments by the qualifying retail utility projected to achieve compliance with the clean energy targets in subsections (3)(a)(I) and (3)(a)(II) of this section and that result in an affordable, reliable, and clean electric system. (III) In the electric resource plan that includes the clean energy plan, the qualifying retail utility shall clearly distinguish between the set of resources necessary to meet customer demands in the resource acquisition period and the additional clean energy plan activities that may be undertaken to meet the clean energy target in subsection (3)(a)(I) of this section, which may create an additional resource need for the clean energy plan. These activities may include retirement of existing generating facilities, changes in system operation, or any other necessary actions. (IV) After conducting any procurement process pursuant to subsection (5)(b) of this section or otherwise, the qualifying retail utility shall set forth the actions and investments required to fill the additional resource need identified for the clean energy plan to satisfy the clean energy target in subsection (3)(a)(I) of this section. These actions and investments may include development of new clean energy resources, development of new transmission and other supporting infrastructure, and clean energy resource acquisitions. Any new transmission development is subject to existing commission and stakeholder transmission planning processes, as applicable. (V) The clean energy plan must describe the effect of the actions and investments included in the clean energy plan on the safety, reliability, renewable energy integration, and resilience of electric service in the state of Colorado. (VI) The clean energy plan must set forth the projected cost of its implementation and anticipated reductions in carbon dioxide and other emissions. as applicable. (V) The clean energy plan must describe the effect of the actions and investments included in the clean energy plan on the safety, reliability, renewable energy integration, and resilience of electric service in the state of Colorado. (VI) The clean energy plan must set forth the projected cost of its implementation and anticipated reductions in carbon dioxide and other emissions. (VII) If the clean energy plan includes accelerated retirement of any existing generating facilities, the clean energy plan must include workforce transition and community assistance plans for utility workers impacted by any clean energy plan and a plan to pay community assistance to any local government or school district, the voters of which have approved projects the costs of which are expected to be paid for from property taxes that are directly impacted by the accelerated retirement of the electric generating facility in an amount equal to the costs of the voter-approved projects that were expected to be paid from the revenue sources directly impacted by the accelerated retirement of the projects, including but not limited to the payment of bonds, notes, or other multiple-fiscal year obligations or financed purchase of an asset or certificate of participation agreements that have been issued or entered into to pay the costs of such projects. Any payment of community assistance shall be reduced on an equivalent basis to the extent that property tax is derived from new electric infrastructure developed in the same impacted community. The qualifying retail utility may propose a cost-recovery mechanism to recover the prudently incurred costs of any workforce transition and community assistance plans, while giving due consideration to the impact on low-income customers. The qualifying retail utility will not earn its authorized rate of return on any noncapital costs incurred as part of any workforce transition plan. The workforce transition and community assistance plans must include, to the extent feasible, estimates of: (A) The number of workers employed by the utility or a contractor of the utility at the electric generating facility; (B) The total number of existing workers with jobs that will be retained and the total number of existing workers with jobs that will be eliminated due to the retirement of the electric generating facility; (C) With respect to the existing workers with jobs that will be eliminated due to the retirement of the electric generating facility, the total number and number by job classification of workers for whom: Employment will end without being offered other employment by the utility; the workers will retire as planned, be offered early retirement, or leave voluntarily; the workers will be retained by being transferred to other electric generating facilities or offered other employment by the utility; and the workers will be retrained to continue to work for the utility in a new job classification; (D) If the utility is replacing the electric generating facility being retired with a new electric generating facility: The number of workers from the retired electric generating facility that will be offered employment at the new electric generating facility and the number of jobs at the new electric generating facility that will be outsourced to subcontractors. The utility shall develop a training or apprenticeship program, under the terms of an applicable collective bargaining agreement, if any, for the maintenance and operation of any new combination generation and storage facility owned by the utility that does not emit carbon dioxide, to which facility displaced workers may transfer as appropriate. facility that will be outsourced to subcontractors. The utility shall develop a training or apprenticeship program, under the terms of an applicable collective bargaining agreement, if any, for the maintenance and operation of any new combination generation and storage facility owned by the utility that does not emit carbon dioxide, to which facility displaced workers may transfer as appropriate. (VIII) If the minimum amounts of electricity from eligible energy resources set forth in section 40-2-124 (1)(c) are satisfied, a qualifying retail utility may propose to use up to one-half of the funds collected annually under section 40-2-124 (1)(g), as well as any accrued funds, to recover the incremental cost of clean energy resources and their directly related interconnection facilities. The utility may account for these funds in calculating the cost of the plan. (b) The division of administration in the department of public health and environment shall participate in any proceeding seeking approval of a clean energy plan developed by a qualifying retail utility pursuant to this section. The division shall describe the methods of measuring carbon dioxide emissions and shall verify the projected carbon dioxide emission reductions as a result of the clean energy plan. (c) (I) After consulting with the air quality control commission, the division of administration shall determine whether a clean energy plan as filed under this section will result in an eighty percent reduction, relative to 2005 levels, in carbon dioxide emissions from the qualifying retail utility's Colorado electricity sales by 2030 and is otherwise consistent with any greenhouse gas emission reduction goals established by the state of Colorado. The division shall publish, and shall report to the public utilities commission, the division's calculation of carbon dioxide emission reductions attributable to any approved clean energy plan. Nothing in the division's engagement in this process shall be construed to diminish or override the commission's authority under this title 40. (II) Notwithstanding anything in this section to the contrary, the division shall comply with section 25-7-105 (1)(e)(VIII.2) in making any calculation or determination pursuant to subsection (4)(c)(I) of this section. (d) The commission shall approve the clean energy plan if the commission finds it to be in the public interest and consistent with the clean energy target in subsection (3)(a)(I) of this section, and the commission may modify the plan if the modification is necessary to ensure that the plan is in the public interest. In evaluating whether a clean energy plan submitted to the commission is in the public interest, the commission shall consider the following factors, among other relevant factors as defined by the commission: (I) Reductions in carbon dioxide and other emissions that will be achieved through the clean energy plan and the environmental and health benefits of those reductions; (II) The feasibility of the clean energy plan and the clean energy plan's impact on the reliability and resilience of the electric system. The commission shall not approve any plan that does not protect system reliability. (III) Whether the clean energy plan will result in a reasonable cost to customers, as evaluated on a net present value basis. In evaluating the cost impacts of the clean energy plan, the commission shall consider the effect on customers of the projected costs associated with the plan as set forth in subsection (4)(a)(VI) of this section as well as any projected savings associated with the plan, including projected avoided fuel costs. ill result in a reasonable cost to customers, as evaluated on a net present value basis. In evaluating the cost impacts of the clean energy plan, the commission shall consider the effect on customers of the projected costs associated with the plan as set forth in subsection (4)(a)(VI) of this section as well as any projected savings associated with the plan, including projected avoided fuel costs. (e) If the commission finds that approval of the clean energy plan is not in the public interest, or if the commission modifies the plan, the utility may choose to submit an amended plan to the commission for approval in lieu of having no plan or implementing the modified plan. No clean energy plan is effective without commission approval. (5) Regulatory matters. (a) Ensuring retail rate stability. (I) The commission shall establish a maximum electric retail rate impact of one and one-half percent of the total electric bill annually for each customer for implementation of the approved additional clean energy plan activities, consistent with this subsection (5). Nothing in this subsection (5)(a) supersedes subsection (3)(a)(I) of this section. (II) A qualifying retail utility shall collect revenues for the additional clean energy plan activities through a clean energy plan revenue rider assessed on a percentage basis on all retail customer bills, as deemed prudent by the commission. The revenue rider may be established as early as the year following approval of a clean energy plan by the commission, and the qualifying retail utility may propose a commencement date and level no greater than the maximum electric retail rate impact. The revenue rider shall afford the qualifying retail utility cost-recovery treatment up to the maximum electric retail rate impact until the first rate case following the final implementation of the clean energy plan, at which time the remaining costs and savings associated with the clean energy plan will be incorporated into base rates. The qualifying retail utility may propose to adjust the level of the retail rate rider over time so long as it does not exceed the maximum retail rate impact and as deemed prudent by the commission. Nothing in this subsection (5) affects the commission's authority to evaluate the prudence of costs associated with approved clean energy plan activities. (III) The clean energy plan revenue rider will be utilized for costs of a qualifying retail utility's clean energy plan capital investments and operating and related expenses, exclusive of: (A) Fuel and transmission costs; (B) Costs associated with the capital investments and operating and related expenses within the overall approved resource portfolio necessary to fully satisfy the resource need identified for the electric resource plan without the clean energy plan; (C) The incremental costs of eligible energy resources recovered with funds collected under section 40-2-124 (1)(g); and (D) The incremental costs of any clean energy resources and their directly related interconnection facilities that, subject to commission approval, are recovered with funds collected under section 40-2-124 (1)(g) in accordance with subsection (4)(a)(VIII) of this section. Savings associated with the plan will return to customers through existing rate riders and base rate adjustments. (IV) The clean energy plan revenue rider shall afford customers certainty on the maximum rate impact of the approved additional clean energy plan activities through at least calendar year 2030. Annually, the qualifying retail utility shall file a report with the commission indicating, at a minimum: (A) The amount of rider collections; (B) The revenue requirement associated with the approved additional clean energy plan activities to be paid for from the rider collections; (C) Any positive or negative rider account balance; (D) Interest expense associated with the revenue rider balance; and (E) Any other information required by the commission. ith the commission indicating, at a minimum: (A) The amount of rider collections; (B) The revenue requirement associated with the approved additional clean energy plan activities to be paid for from the rider collections; (C) Any positive or negative rider account balance; (D) Interest expense associated with the revenue rider balance; and (E) Any other information required by the commission. (V) In the first rate case following the final implementation of the clean energy plan, the commission shall conduct a final reconciliation of the clean energy plan revenue rider and determine how to account for any positive or negative rider balance. In the manner determined by the commission, any remaining positive balance shall be returned to customers or used to reduce customer rates and any negative balance shall be incorporated into the qualifying retail utility's rates. (b) The qualifying retail utility shall utilize a competitive bidding process, as defined by the commission in rules, to procure any energy resources to fill the cumulative resource need derived from the electric resource plan and the clean energy plan in subsection (4)(a)(III) of this section. The commission shall allow the qualifying retail utility, inclusive of any ownership by its affiliates, to own a target of fifty percent of the energy and capacity associated with the clean energy resources and any other energy resources developed or acquired to meet the resource need, as well as all associated infrastructure, if the commission finds the cost of utility or affiliate ownership of the generation assets comes at a reasonable cost and rate impact. Utility ownership may come from utility or affiliate self-builds, build-transfers from independent power producers, or sales of existing assets from independent power producers or similar commercial arrangements. Nothing in this subsection (5)(b) alters the commission's authority under subsection (4)(d) of this section. (c) Any actions, including transmission development, taken by the qualifying retail utility shall be presumed prudent to the extent those actions are a part of an approved clean energy plan. (d) For the purposes of this section, the clean energy target evaluation will be based upon the qualifying retail utility's electricity sales within its electric service territory as it existed on January 1, 2019. In the event of a significant acquisition, the qualifying retail utility may file within one year after the acquisition an additional clean energy plan to address that acquisition, and the commission shall consider the additional clean energy plan consistent with the goals of this section. (e) The commission may, on its own motion or upon application by a qualifying retail utility, amend an approved clean energy plan if amendment is necessary to ensure the reliability and resilience of the electric system. The commission may require the qualifying retail utility to provide such periodic reports on the reliability and resiliency of the electric system as it may deem appropriate to ensure the clean energy plan does not adversely impact reliability or resiliency. (f) The commission shall consider affected communities within the filing qualifying retail utility's service territory with a tangible and pecuniary interest, and organizations representing those communities shall be presumed to have standing in a proceeding seeking approval of any clean energy plan filed pursuant to this section. n energy plan does not adversely impact reliability or resiliency. (f) The commission shall consider affected communities within the filing qualifying retail utility's service territory with a tangible and pecuniary interest, and organizations representing those communities shall be presumed to have standing in a proceeding seeking approval of any clean energy plan filed pursuant to this section. (g) (I) A clean energy plan voluntarily filed by a municipal utility or a cooperative electric association that has voted to exempt itself from regulation by the commission pursuant to article 9.5 of this title 40 shall be deemed approved by the commission as filed if: (A) The division of administration, in consultation with the commission, verifies that the plan demonstrates that, by 2030, the municipal utility or cooperative electric association will achieve at least an eighty-percent reduction in greenhouse gas emissions caused by the entity's Colorado electricity sales relative to 2005 levels; and (B) The clean energy plan has previously been approved by a vote of the entity's governing body. (II) Voluntary submission of a clean energy plan by a municipal utility or a cooperative electric association does not alter the entity's regulatory status with respect to the commission, including under article 9.5 of this title 40. (h) Nothing in this subsection (5) precludes the use of bonds as a mechanism for recovering utility capital in a retired electric generating facility. (6) Reports. One year after approval of any electric resource plan that incorporates a clean energy plan, the qualifying retail utility shall prepare a report to the governor, the general assembly, the public utilities commission, and the air quality control commission outlining progress toward the clean energy targets set forth in this section. The report must set forth the clean energy resources developed under any clean energy plan, the cost and customer impact of those clean energy resources, the effect of any approved clean energy plan on system reliability, and any other relevant information. The report must also identify the need for new or additional technology development necessary to achieve the clean energy targets of this section. (7) Future electric resource plans. Any electric resource plan submitted to the commission after approval of the clean energy plan must include an update on the progress made toward the approved clean energy plan, as well as actions and investments by the qualifying retail utility projected to achieve compliance with the emission reduction target identified in subsection (3)(a)(I) of this section and make progress toward the one-hundred-percent clean energy goal set forth in subsection (3)(a)(II) of this section. The commission may solicit input from the division of administration for assistance in evaluating the emission reductions associated with any future electric resource plan and consistent with the clean energy targets of this section. The commission shall review the qualifying retail utility's actions and investments in accordance with the standards set forth in subsection (4)(d) of this section.

C.R.S. § 40-2-126 Transmission facilities - biennial review - energy resource zones - definitions - plans - approval - cost recovery - powerline trail consideration

40-2-126. Transmission facilities - biennial review - energy resource zones - definitions - plans - approval - cost recovery - powerline trail consideration. (1) As used in this section, unless the context otherwise requires: (a) "Energy resource zone" means a geographic area in which transmission constraints hinder the delivery of electricity to Colorado consumers, the development of new electric generation facilities to serve Colorado consumers, or both. (b) "Local government" has the meaning set forth in section 33-45-102 (3). (c) "Powerline trail" has the meaning set forth in section 33-45-102 (5). (2) Biennially, on or before a date determined by the commission, commencing in 2016, each Colorado electric utility subject to rate regulation by the commission shall: (a) Designate energy resource zones; (b) Develop plans for the construction or expansion of transmission facilities necessary to deliver electric power consistent with the timing of the development of beneficial energy resources located in or near such zones; (c) Consider how transmission can be provided to encourage local ownership of renewable energy facilities, whether through renewable energy cooperatives as provided in section 7-56-210, C.R.S., or otherwise; and (d) Submit proposed plans, designations, and applications for certificates of public convenience and necessity to the commission for review pursuant to subsection (3) of this section. (2.5) In reviewing a plan that an electric utility submits pursuant to subsection (2)(d) of this section, the commission shall consider the need for expanded transmission capacity in the state, including the ability to expand capacity through the construction of new transmission lines, improvements to existing transmission lines, and connections to organized wholesale markets, as defined in section 40-5-108 (1)(a). (3) The commission may, consistent with its authority, approve a utility's application for a certificate of public convenience and necessity for the cost-effective construction or expansion of transmission facilities pursuant to subsection (2)(b) of this section if the commission finds that: (a) The construction or expansion: (I) Is required to: (A) Ensure the reliable delivery of electricity to Colorado consumers, either alone or in combination with the consumers of other states served by an organized wholesale market as defined in section 40-5-108 (1)(a); or (B) Enable the utility to meet the renewable energy standards set forth in section 40-2-124 or achieve emission reductions under section 25-7-102 or 40-2-125.5; (II) Can reasonably accommodate future expansion, through the addition of more lines or greater capacity, as may be required to support the utility's participation in an organized wholesale market as defined in section 40-5-108 (1)(a); and B) Enable the utility to meet the renewable energy standards set forth in section 40-2-124 or achieve emission reductions under section 25-7-102 or 40-2-125.5; (II) Can reasonably accommodate future expansion, through the addition of more lines or greater capacity, as may be required to support the utility's participation in an organized wholesale market as defined in section 40-5-108 (1)(a); and (b) The present or future public convenience and necessity require such construction or expansion. (4) Notwithstanding any other provision of law, in response to any application for a certificate of public convenience and necessity for the construction or expansion of transmission facilities that is submitted to the commission pursuant to subsection (2)(d) of this section, the commission shall issue a final order within two hundred forty days after the application is deemed complete and public notice of the application is given; except that the applicant may waive this two-hundred-forty-day deadline. Absent such waiver, if the commission does not issue a final order within that period, the application is deemed approved. (5) In any construction or expansion approved pursuant to this section, the utility shall use its own employees or qualified contractors, or both, but shall not use a contractor unless the contractor's employees have access to an apprenticeship program registered with the United States department of labor's office of apprenticeship or by a state apprenticeship agency recognized by that office; except that this apprenticeship requirement does not apply to: (a) The design, planning, or engineering of the transmission facilities; (b) Management functions to operate the transmission facilities; or (c) Any work performed in response to a warranty claim. (6) The commission shall amend its rules requiring the filing of ten-year transmission plans by utilities to also require utilities to: (a) Consider and address plans for the construction of new powerline trails in coordination with applicable local governments in each two-year update to a ten-year transmission plan; and (b) Demonstrate compliance with section 33-45-103 (2).

C.R.S. § 40-2-127 Community energy funds - community solar gardens - definitions - rules - legislative declaration - applicability - repeal

40-2-127. Community energy funds - community solar gardens - definitions - rules - legislative declaration - applicability - repeal. (1) Legislative declaration. The general assembly hereby finds and declares that: (a) Local communities can benefit from the further development of renewable energy, energy efficiency, conservation, and environmental improvement projects, and the general assembly hereby encourages electric utilities to establish community energy funds for the development of such projects; (b) It is in the public interest that broader participation in solar electric generation by Colorado residents and commercial entities be encouraged by the development and deployment of distributed solar electric generating facilities known as community solar gardens, in order to: (I) Provide Colorado residents and commercial entities with the opportunity to participate in solar generation in addition to the opportunities available for rooftop solar generation on homes and businesses; (II) Allow renters, low-income utility customers, and agricultural producers to own interests in solar generation facilities; (III) Allow interests in solar generation facilities to be portable and transferrable; and (IV) Leverage Colorado's solar generating capacity through economies of scale. (2) Definitions. As used in this section, unless the context otherwise requires: (a) The definitions in section 40-2-124 apply; and (b) In addition: (I) (A) "Community solar garden" means a solar electric generation facility with a nameplate rating within the range specified under subsection (2)(b)(I)(D) of this section that is located in or near a community served by a qualifying retail utility where the beneficial use of the electricity generated by the facility belongs to the subscribers to the community solar garden. There shall be at least ten subscribers. The owner of the community solar garden may be the qualifying retail utility or any other for-profit or nonprofit entity or organization, including a subscriber organization organized under this section, that contracts to sell the output from the community solar garden to the qualifying retail utility. A community solar garden shall be deemed to be "located on the site of customer facilities". (B) A community solar garden shall constitute "retail distributed generation" within the meaning of section 40-2-124, as amended by House Bill 10-1001, enacted in 2010. (C) Notwithstanding any provision of this section or section 40-2-124 to the contrary, a community solar garden constitutes retail distributed generation for purposes of a cooperative electric association's compliance with the applicable renewable energy standard under section 40-2-124. (D) A community solar garden must have a nameplate rating of five megawatts or less; except that the commission may, in rules adopted pursuant to subsection (3)(b) of this section, approve the formation of a community solar garden with a nameplate rating of up to ten megawatts on or after July 1, 2023. (II) "Subscriber" means a retail customer of a qualifying retail utility who owns a subscription and who has identified one or more physical locations to which the subscription is attributed. Such physical locations must be within the service territory of the same qualifying retail utility as the community solar garden. The subscriber may change from time to time the premises to which the community solar garden electricity generation shall be attributed, so long as the premises are within the same service territory. ne or more physical locations to which the subscription is attributed. Such physical locations must be within the service territory of the same qualifying retail utility as the community solar garden. The subscriber may change from time to time the premises to which the community solar garden electricity generation shall be attributed, so long as the premises are within the same service territory. (III) "Subscription" means a proportional interest in solar electric generation facilities installed at a community solar garden, together with the renewable energy credits associated with or attributable to such facilities under section 40-2-124. Each subscription shall be sized to represent at least one kilowatt of the community solar garden's generating capacity and to supply no more than one hundred twenty percent of the average annual consumption of electricity by each subscriber at the premises to which the subscription is attributed, with a deduction for the amount of any existing solar facilities at such premises. Subscriptions in a community solar garden may be transferred or assigned to a subscriber organization or to any person or entity who qualifies to be a subscriber under this section. (3) Subscriber organization - subscriber qualifications - transferability of subscriptions. (a) The community solar garden may be owned by a subscriber organization, whose sole purpose shall be beneficially owning and operating a community solar garden. The subscriber organization may be any for-profit or nonprofit entity permitted by Colorado law. The community solar garden may also be built, owned, and operated by a third party under contract with the subscriber organization. (b) The commission shall adopt rules as necessary to implement this section, including rules to facilitate the financing of subscriber-owned community solar gardens. The rules must include: (I) Minimum capitalization; (II) The share of a community solar garden's eligible solar electric generation facilities that a subscriber organization may at any time own in its own name; and (III) Authorizing subscriber organizations to enter into leases, sale-and-leaseback transactions, operating agreements, and other ownership arrangements with third parties. (c) If a subscriber ceases to be a customer at the premises on which the subscription is based but, within a reasonable period as determined by the commission, becomes a customer at another premises in the service territory of the qualifying retail utility and within the geographic area served by the community solar garden, the subscription shall continue in effect but the bill credit and other features of the subscription shall be adjusted as necessary to reflect any differences between the new and previous premises' customer classification and average annual consumption of electricity. (3.5) Standards for construction and operation. The following requirements apply to any community solar garden exceeding two megawatts: (a) The initial installation of any photovoltaic module or associated electrical equipment is subject to final inspection and approval in accordance with section 12-115-120. revious premises' customer classification and average annual consumption of electricity. (3.5) Standards for construction and operation. The following requirements apply to any community solar garden exceeding two megawatts: (a) The initial installation of any photovoltaic module or associated electrical equipment is subject to final inspection and approval in accordance with section 12-115-120. (b) Following the development or acquisition by a qualifying retail utility of a community solar garden in which the qualifying retail utility retains ownership, the qualifying retail utility shall either use its own employees to operate and maintain the community solar garden or contract for operation and maintenance of the community solar garden by a contractor whose employees have access to an apprenticeship program registered with the United States department of labor's office of apprenticeship or with a state apprenticeship agency recognized by that office; except that this apprenticeship requirement does not apply to: (I) The design, planning, or engineering of the infrastructure; (II) Management functions to operate the infrastructure; or (III) Any work included in a warranty. (3.7) Energy sector public works projects. If the development of a community solar garden is an energy sector public works project, as defined in section 24-92-303 (5), then the project must comply with the applicable requirements of the "Colorado Energy Sector Public Works Project Craft Labor Requirements Act", part 3 of article 92 of title 24. (4) Community solar gardens not subject to regulation. Neither the owners of nor the subscribers to a community solar garden shall be considered public utilities subject to regulation by the commission solely as a result of their interest in the community solar garden. Prices paid for subscriptions in community solar gardens shall not be subject to regulation by the commission. (5) Purchases of the output from community solar gardens. (a) (I) Each qualifying retail utility shall set forth in its plan for acquisition of renewable resources a plan to purchase the electricity and renewable energy credits generated from one or more community solar gardens over the period covered by the plan. (II) For the first three compliance years commencing with the 2011 compliance year, each qualifying retail utility shall issue one or more standard offers to purchase the output from community solar gardens of five hundred kilowatts or less at prices that are comparable to the prices offered by the qualifying retail utility under standard offers issued for on-site solar generation. During these three compliance years, the qualifying retail utility shall acquire, through these standard offers, one-half of the solar garden generation it plans to acquire, to the extent the qualifying retail utility receives responses to its standard offers. Notwithstanding any provision of this subparagraph (II) to the contrary, renewable energy credits generated from solar gardens shall not be used to achieve more than twenty percent of the retail distributed generation standard in years 2011 through 2013. (III) For the first three compliance years commencing with the 2011 compliance year, a qualifying retail utility shall not be obligated to purchase the output from more than six megawatts of newly installed community solar garden generation. (III.5) Subsections (5)(a)(II) and (5)(a)(III) of this section and this subsection (5)(a)(III.5) are repealed, effective July 1, 2043. rs 2011 through 2013. (III) For the first three compliance years commencing with the 2011 compliance year, a qualifying retail utility shall not be obligated to purchase the output from more than six megawatts of newly installed community solar garden generation. (III.5) Subsections (5)(a)(II) and (5)(a)(III) of this section and this subsection (5)(a)(III.5) are repealed, effective July 1, 2043. (IV) For each qualifying retail utility's compliance years commencing in 2014 through 2025, the commission shall determine the minimum and maximum purchases of electrical output from newly installed community solar gardens of different output capacity that the qualifying retail utility shall plan to acquire, without regard to the six-megawatt ceiling of the first three compliance years. In addition, as necessary, the commission shall formulate and implement policies consistent with this section that simultaneously encourage: (A) The ownership by customers of subscriptions in community solar gardens and of other forms of distributed generation, to the extent the commission finds there to be customer demand for such ownership; (B) Ownership in community solar gardens by residential retail customers and agricultural producers, including low-income customers, to the extent the commission finds there to be demand for such ownership; (C) The development of community solar gardens with attributes that the commission finds result in lower overall total costs for the qualifying retail utility's customers; (D) Successful financing and operation of community solar gardens owned by subscriber organizations; and (E) The achievement of the goals and objectives of section 40-2-124. (b) (I) (A) The output from a community solar garden shall be sold only to the qualifying retail utility serving the geographic area where the community solar garden is located. (B) Once a community solar garden is part of a qualifying retail utility's plan for acquisition of renewable resources, as approved by the commission, the commission shall, by January 30, 2020, initiate a proceeding, or consider in an active proceeding, to determine whether the qualifying retail utility shall purchase all of the electricity and renewable energy credits generated by the community solar garden or whether a subscriber may, upon becoming a subscriber, choose to retain or sell to the qualifying retail utility the subscriber's renewable energy credits. (C) The amount of electricity and renewable energy credits generated by each community solar garden shall be determined by a production meter installed by the qualifying retail utility or third-party system owner and paid for by the owner of the community solar garden. (II) (A) The purchase of the output of a community solar garden by a qualifying retail utility must take the form of a net metering credit against the qualifying retail utility's electric bill to each community solar garden subscriber at the premises set forth in the subscriber's subscription. (B) For a subscriber organization that directs the qualifying retail utility to provide the subscriber organization's subscribers with a bill credit that changes annually, the net metering credit is calculated by multiplying the subscriber's share of the electricity production from the community solar garden by the qualifying retail utility's total aggregate retail rate as charged to the subscriber, minus a reasonable charge as determined by the commission. The charge will be used to cover the utility's costs of delivering to the subscriber's premises the electricity generated by the community solar garden, integrating the solar generation with the utility's system, and administering the community solar garden's contracts and net metering credits. ate retail rate as charged to the subscriber, minus a reasonable charge as determined by the commission. The charge will be used to cover the utility's costs of delivering to the subscriber's premises the electricity generated by the community solar garden, integrating the solar generation with the utility's system, and administering the community solar garden's contracts and net metering credits. (C) For a subscriber organization that directs the qualifying retail utility to provide the subscriber organization's subscribers with a fixed bill credit, the net metering credit is calculated by multiplying the subscriber's share of the electricity production from the community solar garden by the qualifying retail utility's total aggregate retail rate as charged to the subscriber at the time the subscriber organization applies for or bids capacity into a utility community solar garden program, minus a reasonable charge, as determined by the commission at the time the subscriber organization applies for or bids capacity into a utility community solar garden program. The charge will be used to cover the utility's costs related to: Delivering to the subscriber's premises the electricity generated by the community solar garden, integrating the solar generation with the utility's system, and administering contracts and net metering credits for the community solar garden. (D) For community solar gardens eligible for a fixed bill credit, and solely for the purpose of applying the bill credit to a subscriber's bill, the bill credit shall not be applied toward the following rate rider charges, unless the rate rider charges are included in the reasonable charge: Rate rider charges that promote clean energy technologies, including beneficial electrification; rate rider charges that provide low-income bill assistance; or rate rider charges that provide other public benefits as determined by the commission. (E) By June 30, 2024, the commission shall adopt rules to implement the fixed bill credit. The rules must consider the change of value to community solar garden customers of the fixed bill credit over time through rate adjustments or other mechanisms. (F) The commission shall allow a qualifying retail utility to recover the costs incurred in implementing and maintaining billing systems for the various bill credit processes required pursuant to this subsection (5)(b)(II). (G) The commission shall ensure that the reasonable charge that the commission determines pursuant to subsections (5)(b)(II)(B) and (5)(b)(II)(C) of this section does not reflect costs that are already recovered by the utility from the subscriber through other charges. (H) If, and to the extent that, a subscriber's net metering credit exceeds the subscriber's electric bill in any billing period, the net metering credit shall be carried forward and applied against future bills. (I) The qualifying retail utility and the owner of the community solar garden must agree on whether the purchase of the renewable energy credits from subscribers will be accomplished through a credit on each subscriber's electricity bill or by a payment to the owner of the community solar garden. (c) The owner of the community solar garden shall provide real-time production data to the qualifying retail utility to facilitate incorporation of the community solar garden into the utility's operation of its electric system and to facilitate the provision of net metering credits. through a credit on each subscriber's electricity bill or by a payment to the owner of the community solar garden. (c) The owner of the community solar garden shall provide real-time production data to the qualifying retail utility to facilitate incorporation of the community solar garden into the utility's operation of its electric system and to facilitate the provision of net metering credits. (d) The owner of the community solar garden shall be responsible for providing to the qualifying retail utility, on a monthly basis and within reasonable periods set by the qualifying retail utility, the percentage shares that should be used to determine the net metering credit to each subscriber. If the electricity output of the community solar garden is not fully subscribed, the qualifying retail utility shall purchase the unsubscribed renewable energy and the renewable energy credits at a rate equal to the qualifying retail utility's average hourly incremental cost of electricity supply over the immediately preceding calendar year. (e) Each qualifying retail utility shall set forth in its plan for acquisition of renewable resources a proposal for including low-income customers as subscribers to a community solar garden. The utility may give preference to community solar gardens that have low-income subscribers. (f) Qualifying retail utilities shall be eligible for the incentives and subject to the ownership limitations set forth in section 40-2-124 (1)(f) for utility investments in community solar gardens and may recover through rates a margin, in an amount determined by the commission, on all energy and renewable energy credits purchased from community solar gardens. Such incentive payments shall be excluded from the cost analysis required by section 40-2-124 (1)(g). (6) Nothing in this section shall be construed to waive or supersede the retail rate impact limitations in section 40-2-124 (1)(g). Utility expenditures for unsubscribed energy and renewable energy credits generated by community solar gardens shall be included in the calculations of retail rate impact required by that section. (7) Applicability to cooperative electric associations and municipally owned utilities. This section shall not apply to cooperative electric associations or to municipally owned utilities. (8) Applicability. (a) This section applies to community solar capacity that is allocated on or before December 31, 2025. (b) Community solar capacity that is allocated on or after January 1, 2026, is allocated pursuant to section 40-2-127.2.

C.R.S. § 40-2-127.2 Inclusive community solar development - definitions - subscription requirements - program capacity - energy bill credits - administration - rules - reports - applicability

40-2-127.2. Inclusive community solar development - definitions - subscription requirements - program capacity - energy bill credits - administration - rules - reports - applicability. (1) Definitions - rules. As used in this section, unless the context otherwise requires: (a) "Agrivoltaics" has the meaning set forth in section 35-1-114 (4)(a). (b) (I) "Community solar bill credit" means the credit value of the electricity generated by a community solar facility and allocated to a subscriber to offset the subscriber's utility bill. (II) A "community solar bill credit" is calculated pursuant to the net metering credit methodology established in section 40-2-127 (5)(b)(II)(A) to (5)(b)(II)(H). (c) "Community solar facility", "community solar project", or "facility" means a facility: (I) Owned by a subscriber organization that generates electricity by means of a solar photovoltaic device; (II) Through which a subscriber to the facility receives a community solar bill credit for the electricity generated in proportion to the subscriber's share of the facility's kilowatt-hour output; (III) That constitutes "retail distributed generation" as described in section 40-2-124; and (IV) That is allocated inclusive community solar capacity on or after January 1, 2026. (d) "Consolidated billing" means the inclusion of the community solar bill credit and the subscription charges on a customer's monthly electric utility bill. (e) "Inclusive community solar" means the capacity, interconnection, and subscription requirements set forth in this section with which an investor-owned electric utility, subscriber organization, and subscription coordinator must comply with regard to community solar facilities that are allocated capacity on or after January 1, 2026. (f) "Income-qualified subscriber" means a residential utility customer who: (I) Has a household income at or below two hundred percent of the current federal poverty line, as defined in 42 U.S.C. sec. 9902 (2); (II) Has a household income at or below eighty percent of the area median income, as determined by the United States department of housing and urban development; (III) Meets income eligibility requirements as determined by the Colorado department of human services by rule pursuant to section 40-8.5-105; or (IV) Demonstrates participation in one or more of the income-qualified programs that are listed in subsection (5)(c)(III) of this section or that the commission determines pursuant to subsection (5)(c)(III)(G) of this section qualifies a prospective subscriber for eligibility as an income-qualified subscriber. (g) "Investor-owned electric utility" or "utility" means a retail electric utility in the state that is not a cooperative electric association or a municipally owned electric utility. (h) "Preferred location" means location on a rooftop; a parking lot; another impervious surface; a brownfield site, as defined in 42 U.S.C. sec. 9601 (39), as amended; a body of water; a municipal property; a state property; or another previously disturbed location as established by the commission as part of a distribution system plan pursuant to section 40-2-132 or other appropriate proceeding. (i) "Subscriber" means a retail customer of an investor-owned electric utility that has one or more subscriptions with a community solar facility that is interconnected with the utility. (j) "Subscriber organization" means a person that develops, owns, or operates a community solar facility and may include a municipality, a county, a for-profit organization, or a nonprofit organization but does not include an investor-owned electric utility. (k) "Subscription" means a contract between a subscriber and a subscriber organization or a subscription coordinator for a portion of the output of a community solar facility. a person that develops, owns, or operates a community solar facility and may include a municipality, a county, a for-profit organization, or a nonprofit organization but does not include an investor-owned electric utility. (k) "Subscription" means a contract between a subscriber and a subscriber organization or a subscription coordinator for a portion of the output of a community solar facility. (l) "Subscription coordinator" means a person that: (I) Markets community solar facilities or otherwise provides services related to community solar facilities; (II) Performs any administrative action to allocate subscriptions for a community solar facility, connect a subscriber to a community solar facility, or enroll a customer in a community solar facility; and (III) Manages interactions between a subscriber organization and an investor-owned electric utility. (2) Community solar facility and subscription requirements - rules. (a) A community solar facility must: (I) Have a nameplate capacity rating of five megawatts or less, as measured in alternating current; (II) Interconnect to the electric distribution system of an investor-owned electric utility; (III) Comply with all applicable requirements of the "Colorado Energy Sector Public Works Project Craft Labor Requirements Act", part 3 of article 92 of title 24, if the community solar facility qualifies as an "energy sector public works project" as defined in section 24-92-303 (5); (IV) Reserve at least fifty-one percent of the community solar facility capacity for subscribers who are income-qualified subscribers; and (V) Not allocate to a single subscriber more than forty percent of the generating capacity of the facility. (b) A subscription to a community solar facility must: (I) Supply no more than one hundred twenty percent of the subscriber's reasonably expected average annual total consumption of electricity; except that no more than two hundred percent of a subscriber's reasonably expected average annual total consumption of electricity may be supplied to a subscriber who is a direct bill, income-qualified subscriber; and (II) Be portable and transferable within the service territory of the investor-owned electric utility in which the community solar facility is interconnected to the utility's electric grid. (c) Community solar facilities that are owned by the same subscriber organization or by persons affiliated with the subscriber organization must not exceed five megawatt capacity measured in alternating current on a single parcel of land in an annual capacity allocation cycle. (d) A community solar facility that is sited on a preferred location or that utilizes agrivoltaics may have an aggregate capacity of up to ten megawatts measured in alternating current. (3) Inclusive community solar capacity - allocation - interconnection application - rules. (a) (I) On or after January 1, 2026, but before February 1, 2026, an investor-owned electric utility with more than five hundred thousand customers shall make available an annual capacity allocation of at least fifty megawatts of inclusive community solar capacity, and make available any unclaimed community solar capacity as determined in the utility's most recent commission-approved renewable energy plan, in accordance with this section. (II) On or before February 1, 2027, an investor-owned electric utility with more than five hundred thousand customers shall make available an annual capacity allocation of at least fifty megawatts of inclusive community solar capacity, and make available any unclaimed inclusive community solar capacity from the previous allocation cycle, in accordance with this section. ordance with this section. (II) On or before February 1, 2027, an investor-owned electric utility with more than five hundred thousand customers shall make available an annual capacity allocation of at least fifty megawatts of inclusive community solar capacity, and make available any unclaimed inclusive community solar capacity from the previous allocation cycle, in accordance with this section. (b) (I) On or after January 1, 2026, but before February 1, 2026, an investor-owned electric utility with five hundred thousand or fewer customers shall make available an annual capacity allocation of three and one-half megawatts of inclusive community solar capacity in accordance with this section. (II) On or before February 1, 2027, an investor-owned electric utility with five hundred thousand or fewer customers shall make available an annual capacity allocation of three and one-half megawatts of inclusive community solar capacity available in accordance with this section. (c) On or before February 1, 2028, and periodically thereafter, the commission shall determine, by rule or by order, the amount of inclusive community solar capacity that investor-owned electric utilities are required to make available and may adjust any requirements related to inclusive community solar specified in this section. (d) (I) All inclusive community solar capacity made available pursuant to this section must be allocated to a subscriber organization that demonstrates site control, has received all applicable nonministerial permits, and has an executed interconnection agreement with the relevant utility. (II) Except as provided in subsection (8)(b)(II) of this section, inclusive community solar capacity must be allocated on a first-come, first-served basis based on the day the application is received. (e) In order to facilitate equitable access to clean energy, an investor-owned electric utility shall allow all interconnection applicants for retail distributed generation projects as described in section 40-2-124, including community solar facilities, to begin the interconnection process no later than sixty days after May 22, 2024. (4) Community solar bill credits, unsubscribed electricity, and renewable energy credits - rules. (a) Beginning January 1, 2026, an investor-owned electric utility shall: (I) Acquire the entire electrical output of a community solar facility that is connected to the utility's distribution system; (II) Apply community solar bill credits to subscribers' monthly bills as soon as practicable but no later than sixty days after the month during which the community solar facility generated the electricity; (III) Provide community solar bill credits to a community solar facility's subscribers for a term of twenty years after the date the facility begins generating bill credits or until the community solar facility is decommissioned or the subscriber organization ceases operations of a community solar facility, whichever occurs first; (IV) Carry over any amount of a community solar bill credit that exceeds the subscriber's monthly bill and apply it to the subscriber's next monthly bill until the subscriber cancels service with the utility, at which point the utility shall donate any remaining community solar bill credits to a third-party administrator that is qualified and approved by the utility for the purpose of providing energy assistance and bill reductions to income-qualified subscribers within the utility's service territory; (V) On a monthly basis, provide to a subscriber organization or subscription coordinator a report indicating the total value of community solar bill credits generated by the community solar facility in the prior month and the amount of the community solar bill credits applied to each subscriber; and stance and bill reductions to income-qualified subscribers within the utility's service territory; (V) On a monthly basis, provide to a subscriber organization or subscription coordinator a report indicating the total value of community solar bill credits generated by the community solar facility in the prior month and the amount of the community solar bill credits applied to each subscriber; and (VI) Provide, if an investor-owned electric utility has more than five hundred thousand customers, at the request of a subscriber organization or subscription coordinator, consolidated billing by: (A) Including the subscriber organization's or subscription coordinator's monthly subscription charge on the customer's monthly bill for electric service and supply from the utility; and (B) Remitting the customer's payment of the subscriber organization's or subscription coordinator's monthly subscription charge to the subscriber organization or subscription coordinator. (b) A subscriber organization shall, on a monthly basis and in an electronic format, provide the investor-owned electric utility a subscriber list indicating the kilowatts of a community solar facility's nameplate capacity attributable to each subscriber. A subscriber organization shall update subscriber lists monthly to reflect any new subscribers, subscribers that have canceled their subscription, or subscribers that have adjusted subscription capacity. (c) (I) An investor-owned electric utility's purchase of the output of a community solar facility must take the form of a community solar bill credit on the subscriber's monthly bill. (II) An investor-owned electric utility shall calculate the community solar bill credit on a subscriber's monthly bill pursuant to the methodology established for community solar gardens in section 40-2-127 (5)(b)(II)(A) to (5)(b)(II)(H). (d) If a community solar facility is not fully subscribed in a given month, the unsubscribed electricity generated by the facility may be rolled forward on the community solar facility account for up to one year after the month of generation and allocated by the subscriber organization or subscription coordinator to subscribers at any time during that year. At the end of the one-year period in which the unsubscribed electricity was rolled forward, any undistributed community solar bill credits are removed, and the investor-owned electric utility with which the community solar facility is interconnected shall purchase the unsubscribed energy at the utility's average hourly incremental cost of electricity supply over the immediately preceding calendar year. (e) A subscriber organization, subscription coordinator, or subscriber may elect to donate banked community solar bill credits to a third-party administrator that is qualified and approved by the utility for the purpose of providing energy assistance and bill reductions to income-qualified subscribers within the utility's service territory. (f) The subscriber organization shall retire any renewable energy credits for electricity generated by a community solar facility on behalf of the subscriber in the year the electricity is generated. The subscriber organization shall transfer any renewable energy credits for unsubscribed energy to the utility, which shall retire the credits on behalf of the utility's customers in the year the credits are generated in accordance with section 25-7-105 (1)(e)(VIII)(H). (5) Subscriber enrollment, verification, and protections. (a) Subscriber organizations, subscription coordinators, and representatives of such persons are prohibited from: (I) Using credit scores, utility customer scores, or any utility deposit requirements to approve or deny a prospective residential subscriber's participation in a community solar facility; (II) Charging a sign-up fee or termination fee to a residential subscriber; (III) Engaging in misleading or deceptive conduct; and (IV) Making false or misleading representations. ersons are prohibited from: (I) Using credit scores, utility customer scores, or any utility deposit requirements to approve or deny a prospective residential subscriber's participation in a community solar facility; (II) Charging a sign-up fee or termination fee to a residential subscriber; (III) Engaging in misleading or deceptive conduct; and (IV) Making false or misleading representations. (b) (I) A subscriber organization shall provide an income-qualified subscriber who is a subscriber a discount of at least twenty-five percent of the value of the subscriber's community solar bill credit by limiting the subscriber's subscription charge to no more than seventy-five percent of the value of the subscriber's community solar bill credit. (II) For a community solar facility that receives federal tax incentives created by the federal "Inflation Reduction Act of 2022", Pub.L. 117-169, for the specific purpose of being located in an energy community, the subscriber organization shall provide an income-qualified subscriber who is a subscriber a discount of at least thirty percent of the value of the subscriber's community solar bill credit by limiting the subscriber's subscription charge to no more than seventy percent of the value of the subscriber's community solar bill credit. (III) For a community solar facility that receives federal tax incentives created by the federal "Inflation Reduction Act of 2022", Pub.L. 117-169, to provide utility bill savings to income-qualified households pursuant to federal eligibility requirements, the subscriber organization shall provide an income-qualified subscriber who is a subscriber a discount of at least fifty percent of the value of the subscriber's community solar bill credit by limiting the subscriber's subscription charge to no more than fifty percent of the value of the subscriber's community solar bill credit. (IV) For a community solar facility that receives both of the federal tax incentives described in subsections (5)(b)(II) and (5)(b)(III) of this section, the subscriber organization shall provide an income-qualified subscriber who is a subscriber a discount of at least fifty-five percent of the value of the subscriber's community solar bill credit by limiting the subscriber's subscription charge to no more than forty-five percent of the value of the subscriber's community solar bill credit. (V) A subscriber organization or subscription coordinator shall provide, at the request of the commission, details regarding the guaranteed discounts described in subsections (5)(b)(I), (5)(b)(II), (5)(b)(III), and (5)(b)(IV) of this section granted to income-qualified subscribers in a form that is specified by the commission. (VI) In the event that there is unclaimed inclusive community solar capacity, stakeholders may petition the commission to, or the commission may through an appropriate proceeding, consider altering the guaranteed discounts described in subsections (5)(b)(I), (5)(b)(II), (5)(b)(III), and (5)(b)(IV) of this section for income-qualified subscribers. ers in a form that is specified by the commission. (VI) In the event that there is unclaimed inclusive community solar capacity, stakeholders may petition the commission to, or the commission may through an appropriate proceeding, consider altering the guaranteed discounts described in subsections (5)(b)(I), (5)(b)(II), (5)(b)(III), and (5)(b)(IV) of this section for income-qualified subscribers. (c) A subscriber organization or subscription coordinator shall use any one or more of the following methods to verify the income of a prospective subscriber, or a member of the household for which the subscription is attributed, for eligibility as an income-qualified subscriber: (I) Self-attestation; (II) Proof of residence in an affordable housing community; or (III) Evidence of eligibility for or enrollment in at least one of the following programs: (A) The weatherization assistance program in the Colorado energy office, as described in section 24-38.5-102 (1)(g); (B) The supplemental nutrition assistance program in the department of human services, established in part 3 of article 2 of title 26; (C) Medicaid, as defined in section 10-16-1203 (8); (D) The head start program in the department of early childhood, as defined in section 26.5-4-103 (6); (E) Free and reduced-price school meals pursuant to the federal "Richard B. Russell National School Lunch Act", 42 U.S.C. sec. 1751 et seq., or a similar free or reduced-price school meals program; (F) The federal low-income home energy assistance program administered by the United States department of health and human services' administration for children and families pursuant to 42 U.S.C. sec. 8621 et seq., as amended; or (G) Any other governmental or local assistance program that the commission determines qualifies a prospective subscriber for eligibility as an income-qualified subscriber. (d) The commission shall adopt a uniform disclosure form that identifies the information that a subscriber organization or subscription coordinator shall provide to a potential subscriber. The disclosure form must: (I) Disclose future costs and benefits of subscriptions; (II) Disclose key contract terms; (III) Provide grievance, enforcement, and cancellation procedures; (IV) Provide other relevant information pertaining to the subscriptions; and (V) Be offered in both English and Spanish languages and, when appropriate, Native American or Indigenous languages. (e) Subscriber organizations are encouraged to conduct targeted outreach to tribal customers by partnering with Colorado-based nonprofit organizations that have a primary mission of improving the socioeconomic conditions of and providing energy assistance for tribal customers who are not located on a reservation. (6) Cost recovery. An investor-owned electric utility shall be allowed to recover prudently incurred costs, including energy purchases and administrative and information technology expenses, in a manner approved by the commission by rule or other appropriate mechanism. (7) Interconnection - reports. (a) An investor-owned electric utility shall share all results from any interconnection study conducted pursuant to commission rules with the interconnection applicant pursuant to utility confidentiality requirements. (b) On or before January 31, 2025, an investor-owned electric utility with more than five hundred thousand customers shall file with the commission updates to appropriate tariffs that are necessary to implement pro rata interconnection cost-sharing mechanisms for system upgrades whereby a community solar facility only pays the facility's proportional share of newly created hosting capacity associated with the facility. ry 31, 2025, an investor-owned electric utility with more than five hundred thousand customers shall file with the commission updates to appropriate tariffs that are necessary to implement pro rata interconnection cost-sharing mechanisms for system upgrades whereby a community solar facility only pays the facility's proportional share of newly created hosting capacity associated with the facility. (c) When an investor-owned electric utility with more than five hundred thousand customers files a distribution system plan with the commission pursuant to section 40-2-132, the investor-owned electric utility shall: (I) Provide information when interconnection costs for a community solar facility exceed twenty cents per watt, measured in alternating current, and propose to the commission potential solutions to facilitate future interconnections in that same geographic area that may include: (A) Cost-sharing mechanisms among subscriber organizations or between an interconnection applicant and the utility; (B) Distribution grid upgrades, such as distributed energy storage, which may be funded by the utility, interconnection applicant, or some combination of the utility and interconnection applicant; or (C) Flexible interconnection practices; and (II) Include the following information in a report to the commission as part of the distribution system plan, which is filed with the commission pursuant to section 40-2-132: (A) The amount of inclusive community solar capacity awarded pursuant to this section; (B) The amount of operational community solar capacity developed pursuant to this section and section 40-2-127; and (C) A narrative detailing the utility's progress toward facilitating cost-effective interconnection of community solar facilities with the utility's distribution system. (8) Program administration. (a) The commission shall: (I) Adopt and enforce all rules required under this section; (II) Require investor-owned electric utilities to file the tariffs, the agreements, or other forms necessary for the implementation of this section; (III) Establish a deadline by which an investor-owned electric utility with more than five hundred thousand customers shall implement a consolidated billing program and direct the utility to track all costs associated with implementing and operating the consolidated billing program so that the commission may establish a fee to be paid to the investor-owned electric utility by subscriber organizations that elect to utilize a consolidated billing program in order to offset the costs of implementing and operating the consolidated billing program; (IV) Coordinate with the Colorado energy office created in section 24-38.5-101 (1) to ensure alignment with any federal grant funding received by the state for the purpose of supporting low-income community solar projects; (V) Clarify that subscriber organizations, subscription coordinators, or subscribers are not considered public utilities subject to regulation by the commission solely as a result of their participation in inclusive community solar; (VI) Consider the integration of community solar subscriptions for income-qualified subscribers with other programs designed to reduce customer utility bills and deliver energy-related services, including programs related to demand-side management, beneficial electrification, and transportation electrification; and (VII) Conduct multilingual and culturally relevant outreach to engage, educate, and solicit input from representatives from disproportionately impacted communities, in accordance with section 40-2-108, and consider additional strategies as necessary to ensure robust participation by members of disproportionately impacted communities in any rule-making related to inclusive community solar. The commission shall consider a process to compensate individuals who participate in the outreach for their participation, at a level determined appropriate by the commission. accordance with section 40-2-108, and consider additional strategies as necessary to ensure robust participation by members of disproportionately impacted communities in any rule-making related to inclusive community solar. The commission shall consider a process to compensate individuals who participate in the outreach for their participation, at a level determined appropriate by the commission. (b) On or before November 1, 2025, an investor-owned electric utility shall file an application with the commission, either as a standalone application or as part of another application that is being filed with the commission, that: (I) Enables the allocation of inclusive community solar capacity that is required to be made available by the investor-owned electric utility pursuant to this section; and (II) Establishes a process for the investor-owned electric utility to prioritize community solar facilities located on preferred locations over community solar facilities not located on preferred locations, which process must only be used to prioritize between facilities applying for inclusive community solar capacity on the day that qualified community solar facility applications exceed the remaining available capacity in an annual capacity allocation cycle; however, the investor-owned electric utility shall not create a waiting list that carries over into the next year. (c) On or before January 1, 2029, the commission shall report to the house of representatives energy and environment committee and the senate transportation and energy committee, or their successor committees, on the community solar facilities developed pursuant to this section. The report must include: (I) The percentage of awarded inclusive community solar capacity that was successfully interconnected to investor-owned electric utility distribution systems; (II) The total number of income-qualified subscribers who are subscribers served by a community solar facility and any impacts that the subscriptions have on the average annual bill cost of those income-qualified subscribers; (III) The total number of income-qualified subscribers who participated in inclusive community solar in conjunction with other programs designed to reduce customer utility bills, support beneficial electrification, and advance energy efficiency; and (IV) Any other information related to community solar facilities developed pursuant to this section that the commission deems necessary. (9) Applicability. (a) This section applies to inclusive community solar capacity that is allocated on or after January 1, 2026. (b) Community solar capacity that is allocated on or before December 31, 2025, is allocated pursuant to section 40-2-127.

C.R.S. § 40-2-127.5 Community energy funds - community geothermal gardens - rules - legislative declaration - definitions - repeal

40-2-127.5. Community energy funds - community geothermal gardens - rules - legislative declaration - definitions - repeal. (1) Legislative declaration. The general assembly hereby finds and declares that: (a) Local communities can benefit from the further development of renewable energy, energy efficiency, conservation, and environmental improvement projects, and the general assembly hereby encourages electric utilities to establish community energy funds for the development of such projects; (b) It is in the public interest that broader participation in geothermal electric generation by Colorado residents and commercial entities be encouraged by the development and deployment of distributed geothermal electric generating facilities known as community geothermal gardens in order to: (I) Provide Colorado residents and commercial entities with the opportunity to participate in geothermal electricity generation; (II) Allow renters, low-income utility customers, and agricultural producers to own interests in such geothermal generation facilities; (III) Allow interests in such geothermal generation facilities to be portable and transferrable; and (IV) Leverage Colorado's geothermal electricity generating capacity through economies of scale. (2) Definitions. As used in this section, unless the context otherwise requires, the definitions in section 40-2-124 apply, and: (a) (I) "Community geothermal garden" means a geothermal facility that produces electricity from the earth's heat with a nameplate rating within the range specified under subsection (2)(a)(IV) of this section that is located in or near a community served by a qualifying retail utility where the beneficial use of the electricity generated by the facility belongs to the subscribers to the community geothermal garden. There must be at least ten subscribers. The owner of the community geothermal garden may be the qualifying retail utility or any other for-profit or nonprofit entity or organization, including a subscriber organization organized under this section, that contracts to sell the output from the community geothermal garden to the qualifying retail utility. A community geothermal garden is deemed to be "located on the site of customer facilities". (II) A community geothermal garden constitutes "retail distributed generation" within the meaning of section 40-2-124. (III) Notwithstanding any provision of this section or section 40-2-124 to the contrary, a community geothermal garden constitutes retail distributed generation for purposes of a cooperative electric association's compliance with the applicable renewable energy standard under section 40-2-124. (IV) A community geothermal garden must have a nameplate rating of five megawatts or less; except that the commission may, in rules adopted pursuant to subsection (3)(b) of this section, approve the formation of a community geothermal garden with a nameplate rating of up to ten megawatts. (b) "Subscriber" means a retail customer of a qualifying retail utility who owns a subscription and who has identified one or more physical locations to which the subscription is attributed. Such physical locations must be within the service territory of the same qualifying retail utility as the community geothermal garden. The subscriber may change from time to time the premises to which the community geothermal garden electricity generation is attributed, so long as the premises are within the same service territory. r more physical locations to which the subscription is attributed. Such physical locations must be within the service territory of the same qualifying retail utility as the community geothermal garden. The subscriber may change from time to time the premises to which the community geothermal garden electricity generation is attributed, so long as the premises are within the same service territory. (c) "Subscription" means a proportional interest in geothermal electric generation facilities installed at a community geothermal garden, together with the renewable energy credits associated with or attributable to such facilities under section 40-2-124. Each subscription must be sized to represent at least one kilowatt of the community geothermal garden's generating capacity and to supply no more than one hundred twenty percent of the average annual consumption of electricity by each subscriber at the premises to which the subscription is attributed, with a deduction for the amount of any existing geothermal facilities at such premises. Subscriptions in a community geothermal garden may be transferred or assigned to a subscriber organization or to any person or entity who qualifies to be a subscriber under this section. (3) Subscriber organization - subscriber qualifications - transferability of subscriptions. (a) The community geothermal garden may be owned by a subscriber organization whose sole purpose is beneficially owning and operating a community geothermal garden. The subscriber organization may be any for-profit or nonprofit entity permitted by Colorado law. The community geothermal garden may also be built, owned, and operated by a third party under contract with the subscriber organization. (b) The commission shall adopt rules as necessary to implement this section, including rules to facilitate the financing of subscriber-owned community geothermal gardens. The rules must include: (I) Minimum capitalization; (II) The share of a community geothermal garden's geothermal electric generation facilities that a subscriber organization may at any time own in its own name; and (III) Authorizing subscriber organizations to enter into leases, sale-and-leaseback transactions, operating agreements, and other ownership arrangements with third parties. (c) If a subscriber ceases to be a customer at the premises on which the subscription is based but, within a reasonable period as determined by the commission, becomes a customer at another premises in the service territory of the qualifying retail utility and within the geographic area served by the community geothermal garden, the subscription continues in effect but the bill credit and other features of the subscription are adjusted as necessary to reflect any differences between the new and previous premises' customer classification and average annual consumption of electricity. (4) Standards for construction and operation. The following requirements apply to any community geothermal garden exceeding two megawatts: (a) The initial installation of any electrical equipment associated with the community geothermal garden is subject to final inspection and approval in accordance with section 12-115-120. customer classification and average annual consumption of electricity. (4) Standards for construction and operation. The following requirements apply to any community geothermal garden exceeding two megawatts: (a) The initial installation of any electrical equipment associated with the community geothermal garden is subject to final inspection and approval in accordance with section 12-115-120. (b) Following the development or acquisition by a qualifying retail utility of a community geothermal garden in which the qualifying retail utility retains ownership, the qualifying retail utility shall either use its own employees to operate and maintain the community geothermal garden or contract for operation and maintenance of the community geothermal garden by a contractor whose employees have access to an apprenticeship program registered with the United States department of labor's office of apprenticeship or with a state apprenticeship agency recognized by that office; except that this apprenticeship requirement does not apply to: (I) The design, planning, or engineering of the infrastructure; (II) Management functions to operate the infrastructure; or (III) Any work included in a warranty. (5) Community geothermal gardens not subject to regulation. Neither the owners of nor the subscribers to a community geothermal garden are considered public utilities subject to regulation by the commission solely as a result of their interest in the community geothermal garden. Prices paid for subscriptions in community geothermal gardens shall not be subject to regulation by the commission. (6) Purchases of the output from community geothermal gardens. (a) (I) Each qualifying retail utility may set forth in its plan for acquisition of renewable resources a plan to purchase the electricity and renewable energy credits generated from one or more community geothermal gardens over the period covered by the plan. (II) For each qualifying retail utility's compliance years commencing in 2026 and thereafter, the commission shall determine the minimum and maximum purchases of electrical output from newly installed community geothermal gardens of different output capacity that the qualifying retail utility may plan to acquire. In addition, as necessary and appropriate, the commission shall formulate and implement policies consistent with this section that simultaneously encourage: (A) The ownership by customers of subscriptions in community geothermal gardens and of other forms of distributed generation, to the extent the commission finds there to be customer demand for such ownership; (B) Ownership in community geothermal gardens by residential retail customers and agricultural producers, including low-income customers, to the extent the commission finds there to be demand for such ownership; (C) The development of community geothermal gardens with attributes that the commission finds result in lower overall total costs for the qualifying retail utility's customers; (D) Successful financing and operation of community geothermal gardens owned by subscriber organizations; and (E) The achievement of the goals and objectives of section 40-2-124. ds there to be demand for such ownership; (C) The development of community geothermal gardens with attributes that the commission finds result in lower overall total costs for the qualifying retail utility's customers; (D) Successful financing and operation of community geothermal gardens owned by subscriber organizations; and (E) The achievement of the goals and objectives of section 40-2-124. (b) (I) (A) The output from a community geothermal garden must be sold only to the qualifying retail utility serving the geographic area where the community geothermal garden is located. (B) Once a community geothermal garden is part of a qualifying retail utility's plan for acquisition of renewable resources, as approved by the commission, the commission shall initiate a proceeding, or consider in an active proceeding, to determine whether the qualifying retail utility must purchase all of the electricity and renewable energy credits generated by the community geothermal garden or whether a subscriber may, upon becoming a subscriber, choose to retain or sell to the qualifying retail utility the subscriber's renewable energy credits. (C) The amount of electricity and renewable energy credits generated by each community geothermal garden is determined by a production meter installed by the qualifying retail utility or third-party system owner and paid for by the owner of the community geothermal garden. (II) The purchase of the output of a community geothermal garden by a qualifying retail utility takes the form of a net metering credit against the qualifying retail utility's electric bill to each community geothermal garden subscriber at the premises set forth in the subscriber's subscription. The net metering credit is calculated by multiplying the subscriber's share of the electricity production from the community geothermal garden by the qualifying retail utility's total aggregate retail rate as charged to the subscriber, minus a reasonable charge as determined by the commission to cover the utility's costs of delivering to the subscriber's premises the electricity generated by the community geothermal garden, integrating the geothermal generation with the utility's system, and administering the community geothermal garden's contracts and net metering credits. The commission shall ensure that this charge does not reflect costs that are already recovered by the utility from the subscriber through other charges. If, and to the extent that, a subscriber's net metering credit exceeds the subscriber's electric bill in any billing period, the net metering credit is carried forward and applied against future bills. The qualifying retail utility and the owner of the community geothermal garden must agree on whether the purchase of the renewable energy credits from subscribers will be accomplished through a credit on each subscriber's electricity bill or by a payment to the owner of the community geothermal garden. (c) The owner of the community geothermal garden must provide real-time production data to the qualifying retail utility to facilitate incorporation of the community geothermal garden into the utility's operation of its electric system and to facilitate the provision of net metering credits. (d) The owner of the community geothermal garden is responsible for providing to the qualifying retail utility, on a monthly basis and within reasonable periods set by the qualifying retail utility, the percentage shares that should be used to determine the net metering credit to each subscriber. If the electricity output of the community geothermal garden is not fully subscribed, the qualifying retail utility shall purchase the unsubscribed renewable energy and the renewable energy credits at a rate equal to the qualifying retail utility's average hourly incremental cost of electricity supply over the immediately preceding calendar year. termine the net metering credit to each subscriber. If the electricity output of the community geothermal garden is not fully subscribed, the qualifying retail utility shall purchase the unsubscribed renewable energy and the renewable energy credits at a rate equal to the qualifying retail utility's average hourly incremental cost of electricity supply over the immediately preceding calendar year. (e) If a qualifying retail utility includes a plan to purchase the electricity and renewable energy credits generated by one or more community geothermal gardens, then the qualifying retail utility shall set forth in its plan for acquisition of renewable resources a proposal for including low-income customers as subscribers to a community geothermal garden, if possible. The utility may give preference to community geothermal gardens that have low-income subscribers. (f) Qualifying retail utilities are eligible for the incentives and subject to the ownership limitations set forth in section 40-2-124 (1)(f) for utility investments in community geothermal gardens and may recover through rates a margin, in an amount determined by the commission, on all energy and renewable energy credits purchased from community geothermal gardens. Such incentive payments are excluded from the cost analysis required by section 40-2-124 (1)(g). (7) Nothing in this section waives or supersedes the retail rate impact limitations in section 40-2-124 (1)(g). Utility expenditures for unsubscribed energy and renewable energy credits generated by community geothermal gardens must be included in the calculations of retail rate impact required by that section. (8) Applicability to cooperative electric associations and municipally owned utilities. This section shall not apply to cooperative electric associations or to municipally owned utilities.

C.R.S. § 40-2-128 Solar photovoltaic installations - supervision by certified practitioners - qualifications of electrical contractors - definitions

40-2-128. Solar photovoltaic installations - supervision by certified practitioners - qualifications of electrical contractors - definitions. (1) For all photovoltaic installations allowed under section 40-2-124 with a direct current design capacity of less than three hundred kilowatts: (a) (I) (A) The performance of all photovoltaic electrical work, the installation of photovoltaic modules, and the installation of photovoltaic module mounting equipment is subject to on-site supervision by a certified photovoltaic energy practitioner, as designated by the North American Board of Certified Energy Practitioners (NABCEP), or a licensed master electrician, licensed journeyman electrician, or licensed residential wireman, as defined in section 12-115-103. (B) In the case of building-integrated photovoltaic technology, if the type of building-integrated photovoltaic technology installed or the scope of the building-integrated photovoltaic installation involved does not require a licensed master electrician, licensed journeyman electrician, or licensed residential wireman to perform the installation work and the installation work concerns the installation of roofing materials, the on-site supervision may be performed by a certified solar energy installer, as designated by NABCEP or Roof Integrated Solar Energy (RISE). (C) For a building-integrated photovoltaic installation, a licensed master electrician, licensed journeyman electrician, or licensed residential wireman must perform the installation work for any stage of the installation after the installation materials penetrate the roof, a structural wall, or another part of the building, or any stage of the installation in which the building-integrated photovoltaic materials transition to a surface-mounted junction box and utilize types of conduit and building wire that are approved by the national electrical code, as defined in section 12-115-103 (8). (D) By submitting an initial application for funding or an initial contract proposal, the applicant assumes responsibility for employing or contracting with one or more certified energy practitioners or licensed master electricians, licensed journeyman electricians, or licensed residential wiremen to supervise the installation and as necessary to maintain the three-to-one ratio required by subsection (1)(b) of this section, including during any off-site, preinstallation assembly. Payment of any incentives for the work shall not be approved until the applicant supplies the name and certification number of each certified energy practitioner or the license number of each master electrician, journeyman electrician, or residential wireman who actually provided on-site supervision or was present to maintain the three-to-one ratio required by subsection (1)(d) of this section. (II) Neither the commission nor the utility shall have responsibility for monitoring or enforcing compliance with this section. It shall be the responsibility of the applicant to obtain the information required by subparagraph (I) of this paragraph (a), and it shall be the responsibility of the qualifying retail utility to obtain from the applicant and retain, for at least one year after completion of the installation, copies of all documentation submitted by the applicant in connection with the installation. (b) All work performed on the alternating-current side of the inverter will be performed by an electrical contractor who employs a licensed journeyman electrician or a licensed residential wireman who will perform the work. All electrical work that pertains to article 115 of title 12 will be performed by an electrical apprentice registered with the appropriate state regulatory agency, a licensed journeyman electrician, or a licensed residential wireman. The appropriate ratio of no less than one journeyman or residential wireman for every three electrical apprentices will be maintained. (c) Repealed. erform the work. All electrical work that pertains to article 115 of title 12 will be performed by an electrical apprentice registered with the appropriate state regulatory agency, a licensed journeyman electrician, or a licensed residential wireman. The appropriate ratio of no less than one journeyman or residential wireman for every three electrical apprentices will be maintained. (c) Repealed. (d) On a system with a direct current design capacity of less than three hundred kilowatts: (I) The ratio of the number of persons who are assisting with the work and who are neither licensed electricians nor registered electrical apprentices to the number of persons who are certified as provided in paragraph (a) of this subsection (1) shall never exceed three to one, and a person who is both licensed and certified shall not count double for purposes of measuring this ratio, during the following stages: (A) The installation of photovoltaic modules; (B) The installation of photovoltaic module mounting equipment; and (C) Any photovoltaic electrical work; and (II) There shall be, at all times, at least one on-site supervisor who is certified as provided in paragraph (a) of this subsection (1). (2) As used in this section, unless the context otherwise requires: (a) (I) "Photovoltaic electrical work" means wiring, grounding, or repairing electrical apparatus and equipment in a photovoltaic distributed generation system. (II) "Photovoltaic electrical work" includes the preinstallation assembly of photovoltaic modules to photovoltaic module mounting equipment for installation on-site. (III) "Photovoltaic electrical work" does not include site preparation, trenching or excavating, hauling, or other work that is not specifically described in subparagraph (I) or (II) of this paragraph (a). (b) "Photovoltaic module" means the module or panel that generates electricity through a photovoltaic process. (c) "Photovoltaic module mounting equipment" means the racking, mounting, apparatus, equipment, or structure that physically supports and secures one or more photovoltaic modules in place or to a roof, wall, foundation, or pedestal.

C.R.S. § 40-2-129 New resource acquisitions - factors in determination - local employment - "best value" employment metrics - rules - report

40-2-129. New resource acquisitions - factors in determination - local employment - "best value" employment metrics - rules - report. (1) (a) (I) When evaluating electric resource acquisitions and requests for a certificate of convenience and necessity for construction or expansion of generating facilities, including but not limited to pollution control or fuel conversion upgrades and conversion of existing coal-fired plants to natural gas plants, the commission shall consider, in all decisions involved in electric resource acquisition processes, best value regarding employment of Colorado labor, as defined in section 8-17-101 (2)(a), and positive impacts on the long-term economic viability of Colorado communities. To this end, the commission shall require utilities to obtain and provide to the commission the following information regarding "best value" employment metrics: (A) The availability of training programs, including training through apprenticeship programs registered with the United States department of labor's office of apprenticeship or by state apprenticeship agencies recognized by that office for all apprenticeable trades required to effectively deliver the project to completion; (B) Employment of Colorado labor as compared to importation of out-of-state workers; (C) The ability of the project to employ workers from traditionally underserved communities or disproportionately impacted communities as defined in section 24-4-109 (2)(b)(II); (D) How the project supports domestic manufacturing through the utilization of Colorado and domestically produced materials, including consideration of the potential for domestically manufactured materials being unavailable in the marketplace; (E) Long-term career opportunities; and (F) Industry-standard wages, health care, and pension benefits. (II) When a utility proposes to construct new facilities of its own, the utility shall supply similar information to the commission. (b) Any electric resource acquisition decision must be based in part on review of the "best value" employment metrics criteria set forth in any solicitation document. The commission shall not approve any electric resource plan, acquisition, or power purchase agreement that fails to either: (I) Provide the "best value" employment metrics documentation specified in the solicitation document; or (II) In the alternative, certify compliance with objective "best value" employment metrics performance standards set forth in the solicitation document. (c) The commission may waive the requirements of this section if a utility agrees to use a project labor agreement for construction or expansion of a generating facility. (2) Following development or acquisition of a generating facility by a utility, for all generating facilities owned by the utility that do not emit carbon dioxide, the utility shall use utility employees or qualified contractors if the contractors' employees have access to an apprenticeship program registered with the United States department of labor's office of apprenticeship or by a state apprenticeship agency recognized by that office; except that this apprenticeship requirement does not apply to: (a) The design, planning, or engineering of the infrastructure; (b) Management functions to operate the infrastructure; or the contractors' employees have access to an apprenticeship program registered with the United States department of labor's office of apprenticeship or by a state apprenticeship agency recognized by that office; except that this apprenticeship requirement does not apply to: (a) The design, planning, or engineering of the infrastructure; (b) Management functions to operate the infrastructure; or (c) Any work included in a warranty. (3) The provisions of this section regarding "best value" employment metrics do not apply to projects involving retail distributed generation, as defined in section 40-2-124 (1)(a)(VIII), 40-2-127 (2)(b)(I)(B), or 40-2-127.5 (2)(a)(II). (4) Repealed. (5) The commission shall promulgate rules requiring utilities, when submitting annual progress reports for an electric resource acquisition, to collect and provide to the commission information concerning the implementation of "best value" employment metrics, as described in subsection (1)(a) of this section, which metrics were approved by the commission during the acquisition planning process and which acquisitions are under construction by either the utility or by others. (6) (a) On or before December 31, 2024, and on or before December 31 of each year thereafter, the commission shall submit a report to the energy and environment committee of the house of representatives and the transportation and energy committee of the senate, or any successor committees. The report must summarize the information concerning "best value" employment metrics that is reported to the commission by utilities pursuant to subsections (1)(a) and (5) of this section and indicate the manner in which the commission considered the information. (b) Notwithstanding the limitation described in section 24-1-136 (11)(a)(I), the reporting requirement described in subsection (6)(a) of this section continues in perpetuity.

C.R.S. § 40-2-130 Distributed resources - energy storage systems - definitions - legislative declaration - rules

40-2-130. Distributed resources - energy storage systems - definitions - legislative declaration - rules. (1) Legislative declaration. (a) The general assembly finds and determines that: (I) Colorado's economy, as well as the health and safety of its residents, depends on a reliable and efficient supply of electricity; and (II) The threat of interruptions in electric supply due to weather, malicious interference, or malfunctions in centralized generation and transmission facilities makes distributed resources, including energy storage systems paired with other distributed resources, an effective way for residents to provide their own reliable and efficient supply of electricity. (b) Therefore, the general assembly declares that: (I) It is in the public interest to limit barriers to the installation, interconnection, and use of customer-sited energy storage facilities in Colorado; and (II) Colorado's consumers of electricity have a right to install, interconnect, and use energy storage systems on their property without the burden of unnecessary restrictions or regulations and without unfair or discriminatory rates or fees. (2) Definitions. As used in this section, unless the context otherwise requires: (a) "Energy storage system" means any commercially available, customer-sited system, including batteries and the batteries paired with on-site generation, that is capable of retaining, storing, and delivering energy by chemical, thermal, mechanical, or other means. (b) "Utility" or "electric utility" means a qualifying retail utility, as described in section 40-2-124 (1); except that the term does not include a municipally owned utility or a cooperative electric association. (3) Authority of commission - rules. The commission shall adopt rules allowing the installation, interconnection, and use of energy storage systems by customers of utilities. The commission shall incorporate the following principles into the rules: (a) It is in the public interest to limit barriers to the installation, interconnection, and use of customer-sited energy storage systems in Colorado; (b) Colorado's consumers of electricity have a right to install, interconnect, and use energy storage systems on their property without the burden of unnecessary restrictions or regulations and without discriminatory rates or fees; (c) Utility approval processes and any required interconnection reviews of energy storage systems shall be simple, streamlined, and affordable for customers; and (d) Utilities shall not require the installation of customer-sited meters in addition to a single net energy meter for the purposes of monitoring energy storage systems; except that the commission may authorize the requirement of metering for certain large energy storage systems, as determined by the commission. (4) Nothing in this section alters or supersedes either: (a) The principles of net metering as described in section 40-2-124; or (b) Any existing electrical permit requirements or any licensing or certification requirements for installers, manufacturers, or equipment.

C.R.S. § 40-2-130.5 Dispatchable distributed generation - energy storage - definitions - program capacity - program administration - rules

40-2-130.5. Dispatchable distributed generation - energy storage - definitions - program capacity - program administration - rules. (1) Definitions. As used in this section, unless the context otherwise requires: (a) "Dispatchable distributed generation" means distributed generation paired with a co-located energy storage system that is: (I) Directly interconnected to an investor-owned electric utility's distribution system and is not behind a customer meter; and (II) Measured by the capacity of the distributed generation in alternating current. (b) "Distributed generation" means a renewable energy resource as defined in section 40-2-124 (1)(a)(VII) that interconnects to a utility's distribution system. (c) "Energy storage system" has the same meaning as set forth in section 40-2-130 (2)(a). (d) "Investor-owned electric utility" or "utility" means a retail electric utility in the state that is not a cooperative electric association or a municipally owned electric utility. (2) Program capacity. (a) On or before June 1, 2026, an investor-owned electric utility with more than five hundred thousand customers shall acquire at least fifty megawatts of dispatchable distributed generation. (b) On or after January 1, 2027, but before June 1, 2027, an investor-owned electric utility with more than five hundred thousand customers shall acquire at least fifty megawatts of dispatchable distributed generation. (c) To ensure that an investor-owned electric utility with more than five hundred thousand customers acquires dispatchable distributed generation in accordance with subsections (2)(a) and (2)(b) of this section, the commission shall: (I) Determine the procedures for a utility to acquire dispatchable distributed generation; (II) Establish a methodology that ascribes value to dispatchable distributed generation located in specific areas of the electric grid in order to direct the development of dispatchable distributed generation resources in optimal locations; and (III) Adopt any other program- or project-specific requirements the commission deems necessary to facilitate the acquisition of dispatchable distributed generation, including all applicable requirements of the "Colorado Energy Sector Public Works Project Craft Labor Requirements Act", part 3 of article 92 of title 24, for dispatchable distributed generation projects that qualify as an "energy sector public works project" as defined in section 24-92-303 (5). (d) On or before June 1, 2028, and periodically thereafter, the commission shall determine the procedure and capacity amounts for future acquisitions of dispatchable distributed generation by an investor-owned electric utility. (3) Program administration. The commission shall: (a) Adopt and enforce all rules required under this section; (b) Require all applicable investor-owned electric utilities to file the tariffs, agreements, or other forms and documents necessary for the implementation of this section; and (c) Consult with the Colorado electric transmission authority, created in section 40-42-103, as necessary to plan for and optimize the use of dispatchable distributed generation that is acquired and developed in accordance with this section.

C.R.S. § 40-2-131 State of 911 report

40-2-131. State of 911 report. (1) Notwithstanding section 24-1-136 (11)(a)(I), on or before September 15, 2018, and on or before September 15 of each year thereafter, the commission shall publish a "state of 911" report and submit the report to the members of the general assembly. The report must provide an overall understanding of the state of 911 service in Colorado and must address, at a minimum, the following: (a) The commission's actions related to 911 service in the state during the previous year as well as planned implementation actions related to 911 service for the upcoming year; (b) The current statewide structure, technology, and general operations of 911 service in Colorado; (c) 911 network reliability and resiliency; (d) Identified gaps, vulnerabilities, and needs related to 911 service in the state; (e) The impact on and involvement of the state in federal activities and national trends affecting 911 service in Colorado; (f) The state's planning for, transition to, and implementation of next generation 911 and other or future standards-based improvements to 911, including a projected timeline for full statewide implementation; (g) A discussion of 911 funding and fiscal outlook, including current funding sources and whether they are adequate for 911 service in the state, and potential funding mechanisms for the transition to and implementation of next generation 911 and other or future standards-based improvements to 911; and (h) The activity of the 911 services enterprise created in section 29-11-108, including use of the revenue of the 911 services enterprise. (2) In developing the report each year, the commission shall consult with public safety answering points as defined in section 29-11-101 (23), 911 governing bodies as defined in section 29-11-101 (16), and statewide organizations that represent public safety agencies. (3) On or before February 1, 2019, and on or before February 1 of each year thereafter, the commission shall present the report to the senate committee on business, labor, and technology, or its successor committee, and the house of representatives committee on business affairs and labor or its successor committee. (4) Nothing in this section shall be interpreted to grant the commission the authority to regulate any providers or services exempt from jurisdiction under section 40-15-401.

C.R.S. § 40-2-132 Distribution system planning - definition - rules

40-2-132. Distribution system planning - definition - rules. (1) The commission shall promulgate rules establishing the filing of a distribution system plan. The commission's rules must: (a) Define the following terms: (I) Distributed energy resources that include: (A) Distributed renewable electric generation; (B) Energy storage systems connected to the distribution grid; (C) Microgrids; (D) Energy efficiency measures; and (E) Demand response measures; and (II) Non-wires alternatives; (b) Develop a methodology for evaluating the costs and net benefits of using distributed energy resources as non-wires alternatives; (c) Determine a threshold for the size of a new distribution project, whether in dollars, meters, or another factor, as determined by the commission, for when a qualifying retail utility must consider implementation or use of non-wires alternatives, potentially including energy efficiency measures under utility programs for new electric service to any planned new neighborhoods or housing developments; (d) Direct each qualifying retail utility to file a distribution system plan; (e) Determine what shall be included in a distribution system plan, which at a minimum must include the following: (I) Information regarding: (A) System and substation historical data; (B) Peak demand; (C) Adoption of distributed energy resources; and (D) Distribution system investments; (II) To provide new electric service to any planned new neighborhoods or housing developments expected to include more than ten thousand new residences, a description of the qualifying retail utility's consideration of non-wires alternatives, potentially including energy efficiency measures under utility programs; (III) An updated load forecast that includes any new load resulting from projected or forecasted growth from beneficial electrification programs; (IV) A forecast of the growth of distributed energy resources for the years covered by the plan; (V) A high-level summary of its planning process for addressing cyber and physical security risks. As part of the summary, the qualifying retail utility need not report any confidential, proprietary, or other information in the plan that could in any way compromise or decrease the qualifying retail utility's ability to prevent, mitigate, or recover from potential system disruptions caused by weather events, physical events, or cyber attacks. (VI) A proposed cost-recovery method or mechanism for any non-wires alternative investments found to be outside the ordinary course of business; (VII) A description of the qualifying retail utility's anticipated new distribution system expansion investments for the years covered by the plan; (VIII) A process to evaluate the plan's feasibility and the economic impacts of using non-wires alternatives for certain projects; (IX) An estimate of the year in which peak demand growth or distributed energy resource growth would merit analysis of new non-wires alternative projects; and (X) Any other information that the commission deems relevant. (2) The commission shall approve a qualifying retail utility's investment in non-wires alternatives if the commission finds the investment to be in the public interest. (3) (a) The commission shall determine whether a qualifying retail utility's ratepayers would realize benefits from a non-wires alternative investment and whether the associated costs are just and reasonable. (b) To evaluate the success of any non-wires alternative investment authorized pursuant to a qualifying retail utility's distribution system plan, the commission may adopt criteria, benchmarks, or accountability mechanisms with which the qualifying retail utility must comply. (4) As used in this section, "qualifying retail utility" has the meaning described in section 40-2-124 (1); except that the term does not mean a municipally owned utility or a cooperative electric association.

C.R.S. § 40-2-132.5 Distribution system planning - grant program - cash fund - requirements - study - staffing - labor - cost recovery - virtual power plant program - undergrounding of power lines - report - rules - legislative declaration - definitions - repeal

40-2-132.5. Distribution system planning - grant program - cash fund - requirements - study - staffing - labor - cost recovery - virtual power plant program - undergrounding of power lines - report - rules - legislative declaration - definitions - repeal. (1) Legislative declaration. (a) The general assembly finds that: (I) Distribution system planning requirements for investor-owned utilities were established by Senate Bill 19-236, enacted in 2019; (II) The commission's distribution system planning rules and plans established pursuant to Senate Bill 19-236, enacted in 2019, have provided a forum for planning the distribution system in order to support state policy goals based on current information about utility systems and proactive planning, although considerable work remains and customers are increasingly challenged by distribution system constraints; (III) Colorado has goals of cost-effectively and reliably reducing greenhouse gas emissions from transportation, electricity generation, building heating and cooling, water heating, and industrial fuel uses. To affordably and reliably reduce emissions from these uses as well as to meet federal, state, regional, and local air quality and decarbonization targets, standards, plans, and regulations, the state will need to rapidly shift customer end uses from fossil fuels to a cleaner electrical grid, which will drive a large increase in electricity demand. (IV) Consumer demand for distributed energy resources, electric vehicles, and beneficial electrification measures is expected to increase dramatically given state incentives and new rebates and incentives in the federal "Inflation Reduction Act of 2022", Pub.L. 117-169; (V) Customer demand for electric power may start exceeding qualifying retail utility capacity on the distribution system in certain locations; (VI) To affordably and reliably meet federal, state, regional, and local air quality and decarbonization targets, standards, plans, and regulations, the state's electricity distribution systems must be substantially and strategically upgraded, new customers must be able to connect to the electrical distribution system, and existing customers must have their service levels promptly upgraded; (VII) The state has an urgent need to increase its supply of affordable and infill housing, requiring both new electrical distribution capacity and the prompt connection of new affordable housing to the distribution system; (VIII) Improved and proactive distribution system planning to reduce delays and meet building, affordable housing, and transportation electrification needs in an affordable and reliable manner is critical to protect Coloradans from the worst impacts of climate change, including extreme heat or cold, drought, and wildfires; (IX) Electrifying transportation and buildings may put downward pressure on rates by spreading fixed costs over more kilowatt-hours of usage so long as demand and supply can be dynamically integrated in ways that encourage utility investment in an affordable and reliable system that optimizes the use of grid assets; (X) Constraints in the capacity of the electrical distribution system can limit the ability of an individual customer to cost-effectively and reliably interconnect distributed energy resources and energize beneficial electrification and transportation electrification resources; and (XI) Virtual power plants can offer the potential to cost-effectively and reliably increase the grid value of distributed energy resources, limit costs for incorporating distributed energy resources, and increase the operational efficiency of the distribution system. interconnect distributed energy resources and energize beneficial electrification and transportation electrification resources; and (XI) Virtual power plants can offer the potential to cost-effectively and reliably increase the grid value of distributed energy resources, limit costs for incorporating distributed energy resources, and increase the operational efficiency of the distribution system. (b) The general assembly further finds that: (I) A modern electric distribution system should take into account the need for improved resilience and safety due to the increased occurrence of extreme weather events and climate-related wildfire risk; (II) Undergrounding power lines can significantly help in avoiding the risk of wildfires and power outages due to strong winds, severe storms, and dry conditions; and (III) It is in the public interest that all ratepayers of a qualifying retail utility, including those who do not live in a jurisdiction with a franchise agreement, have nondiscriminatory and equal access to the opportunity to benefit from investments in undergrounding power lines. (c) The general assembly therefore determines and declares that: (I) It is a matter of state urgency to ensure that there is sufficient capacity on the distribution system to affordably and reliably meet Colorado's decarbonization goals and support consumer demand for retail distributed generation and beneficial electrification measures consistent with their benefit to the electrical grid; (II) When determining where to make undergrounding conversion expenditures, a qualifying retail utility should not, as a policy or course of business, discriminate against jurisdictions that do not have franchise agreements with the qualifying retail utility; and (III) A qualifying retail utility should establish programs for nonfranchised areas to have the same benefit under the same or similar terms as offered to areas that have franchise agreements with the qualifying retail utility. (2) Definitions. As used in this section, unless the context otherwise requires: (a) "Affordable housing" means affordable housing that: (I) Has received loans, grants, equity, bonds, or tax credits from any source to support the creation, preservation, or rehabilitation of affordable housing that, as a condition of funding, encumbers the property with a restricted use covenant or similar recorded agreement to ensure affordability; or has been income-restricted under a local inclusionary zoning ordinance or other regulation or program; (II) Restricts or limits maximum rental or sale price for households of a given size at a given area median income, as established annually by the United States department of housing and urban development; and (III) Ensures occupancy by low- to moderate-income households for a specified period detailed in a restrictive use covenant or similar recorded agreement. (b) "Apprentice" has the meaning set forth in section 8-15.7-101 (1). (c) "Automated distributed resource management system" means a category of technologies that manage distributed generation or load and that may be used to reduce or eliminate the need for system upgrades to the distribution system, customer service connection, or electrical infrastructure on the customer side of the service meter. These technologies include: (I) Automated load management technologies; (II) Certified power control systems; and (III) Smart inverters. (d) "Certified power control system" means software or hardware serving as the interface of an automated distributed resource management system that can curtail the import and export of electricity, that has electricity import and export control set points, and that has been certified by a nationally recognized testing laboratory. (e) "Department" means the department of labor and employment. s. (d) "Certified power control system" means software or hardware serving as the interface of an automated distributed resource management system that can curtail the import and export of electricity, that has electricity import and export control set points, and that has been certified by a nationally recognized testing laboratory. (e) "Department" means the department of labor and employment. (f) "DER aggregator" means a company or an organization that controls, monitors, and manages aggregated distributed energy resources to ensure performance of the aggregated distributed energy resources in a qualifying virtual power plant. (g) "Distributed energy resources" or "DER" includes distributed generation, energy storage systems, electric vehicles, microgrids, fuel cells, and demand-side management measures, including energy efficiency, demand response, and demand flexibility that are deployed at the distribution grid level on either the customer or utility side of the meter. (h) "Distribution activities" means: (I) Capital investment and operations and maintenance expenses associated with equipment upgrades, repair and replacement programs, conductor replacements, conductor installations, pole repair and replacement, overhead rebuilds, inspection, modeling, asset data gathering, defect corrections, and major line rebuilds; and (II) Similar activities and investments, including information and operational technology investments, with the objective of enhancing the distribution system to meet state decarbonization goals and federal, state, regional, and local air quality and decarbonization targets, standards, plans, and regulations. (i) (I) "Energization" or "energize" means connecting new customer load to the electrical grid or upgrading electrical capacity to provide upgraded service to an existing customer, including establishing adequate electrical capacity to provide for the required service. (II) "Energization" or "energize" does not include activities related to interconnecting distributed generation. (j) "Energization time period" means the elapsed time period beginning when the qualifying retail utility receives a substantially complete energization project application and ending when the electrical service is installed and energized. (k) "Flexible interconnection or energization tariff" means a set of rules and requirements for expeditiously energizing new load or interconnecting a distributed energy resource to a qualifying retail utility's distribution system and includes an agreement for curtailing the import or export of electricity from and to the distribution system. (l) "Fund" means the Colorado lineworker apprenticeship grant program cash fund created in subsection (3)(h)(I) of this section. (m) "Grant program" means the grant program created pursuant to subsection (3)(a) of this section. (n) "Hosting capacity" means the amount of distributed energy resources or transportation or beneficial electrification that can be interconnected or energized to the qualifying retail utility's distribution system at a given time and at a given location under existing electrical grid conditions and that can operate without adversely impacting safety, power quality, reliability, or other operational criteria and without requiring system upgrades. Hosting capacity may be expressed in terms of a load or generation profile. (o) "Hybrid facility" means a facility that has more than one device of different technology types for the production, storage, or consumption of electricity that are located on the same site and have a single point of interconnection to the utility distribution system. (p) "Infill housing" means the development of housing within existing development patterns, as delineated by census urban areas established by the most recent federal decennial census. n one device of different technology types for the production, storage, or consumption of electricity that are located on the same site and have a single point of interconnection to the utility distribution system. (p) "Infill housing" means the development of housing within existing development patterns, as delineated by census urban areas established by the most recent federal decennial census. (q) "Non-wires alternatives" means the strategic deployment of distributed energy resources by a qualifying retail utility or a third party and associated control or aggregation of systems and technologies intended to cost-effectively defer or avoid the need for major distribution grid projects. (r) "Office" means the Colorado energy office created in section 24-38.5-101 (1). (s) "Office of future of work" means the office of future of work created in section 8-15.8-103. (t) "Performance-based compensation" means a financial payment that is made to a qualified DER aggregator or passed through a DER aggregator to eligible customers participating in a VPP operated by that DER aggregator and that is provided based on the performance of a qualified virtual power plant during a qualified virtual power plant event. (u) "Phased interconnection or energization agreement" means an agreement between a qualifying retail utility and a customer to provide certain levels of electrical service capacity on a guaranteed timeline in exchange for the customer participating in the qualifying retail utility's flexible interconnection or energization tariff while necessary grid upgrades are being completed. (v) "Prosumer" means a customer of a qualifying retail utility that participates in a commission-approved virtual power plant program. (w) "Qualified aggregator" means a DER aggregator that has control over prosumer resources and has the demonstrated technical capability to dispatch distributed energy resources at required capacity levels when called upon by a qualifying retail utility using available technology, such as metering, telemetry, control software measurement and verification, and financial settlements. (x) "Qualifying distribution activity recovery" means distribution activities for which the commission approves recovery through the grid modernization adjustment clause. (y) "Qualifying retail utility" means an investor-owned electric utility serving five hundred thousand customers or more. (z) "State apprenticeship agency" has the meaning set forth in section 8-15.7-101 (16). (aa) "System upgrades" means the additions, modifications, and system upgrades to a qualifying retail utility's distribution or commission-jurisdictional transmission system, including customer-driven upgrades necessary to interconnect distributed energy resources, energize or service-connect transportation and beneficial electrification measures, or facilitate service connections to affordable housing or infill housing. (bb) "Virtual power plant" or "VPP" means a commission-approved program that achieves the collective management of dispatchable demand or distributed energy resources connected to the utility distribution grid. (3) Grant program - report - cash fund - repeal. (a) The office of future of work, in coordination with the office, shall create a grant program for lineworker apprenticeship programs to expand apprenticeship programs registered with the United States department of labor's office of apprenticeship or the state apprenticeship agency. (b) The office of future of work shall create a competitive application process through which the office of future of work selects eligible registered apprenticeship programs as grant recipients. grant program for lineworker apprenticeship programs to expand apprenticeship programs registered with the United States department of labor's office of apprenticeship or the state apprenticeship agency. (b) The office of future of work shall create a competitive application process through which the office of future of work selects eligible registered apprenticeship programs as grant recipients. (c) A grant recipient must satisfy, at a minimum, the following criteria: (I) The grant recipient must train apprentices as transmission or distribution lineworkers on construction projects and related installations; and (II) The grant recipient must match the grant award with actual or in-kind resources. (d) The office of future of work shall offer grants for the following purposes: (I) Funding for training materials or software, apprenticeship tools and supplies, and hands-on training equipment or technology upgrades to expand registered apprenticeship programs that instruct transmission or distribution lineworkers; and (II) Additional staffing to expand instruction capacity of registered apprenticeship programs to instruct transmission or distribution lineworkers. (e) The office of future of work shall reserve at least fifty percent of the grant funding for grants that are directed toward programs that are organized as a multiemployer registered apprenticeship program organized through a joint apprenticeship training committee. (f) The office of future of work shall encourage the primary applicant for a grant to include a diverse set of co-applicants, which may include trade associations, employers, labor union organizations, public utilities, accredited institutions of higher education, state-accredited community colleges, or other co-applicants that can advance the goals of allowing apprentices to reach full journeyworker status as a utility transmission or distribution lineworker. (g) The office of future of work shall: (I) Publish the grant application no later than January 1, 2025; (II) Develop performance expectations for grant recipients, which may contemplate the termination of a grant recipient's participation in the grant program if the grant recipient fails to satisfy the performance expectations; (III) Require grant recipients to annually report data to the office of future of work, which must include, at a minimum, a detailed statement of the grant recipient's allocation of grant money received pursuant to the grant program, including administration costs; and (IV) Beginning in 2026, and in each year thereafter, submit a report compiling the data received pursuant to subsection (3)(g)(III) of this section to the business, labor, and technology committee of the senate and the business affairs and labor committee of the house of representatives, or any successor committees. (h) (I) The Colorado lineworker apprenticeship grant program cash fund is created in the state treasury. The fund consists of gifts, grants, and donations and any money that the general assembly may appropriate or transfer to the fund. The state treasurer shall credit all interest and income derived from the deposit and investment of money in the fund to the fund. Money in the fund is continuously appropriated to the department for allocation to the office of future of work for the purposes of administering the grant program pursuant to this subsection (3). The office of future of work may seek, accept, and expend gifts, grants, or donations from private or public sources for the purposes of administering the grant program pursuant to this subsection (3). (II) (A) On July 1, 2024, the state treasurer shall transfer eight hundred thousand dollars from the general fund to the fund. (B) This subsection (3)(h)(II) is repealed, effective July 1, 2026. . The office of future of work may seek, accept, and expend gifts, grants, or donations from private or public sources for the purposes of administering the grant program pursuant to this subsection (3). (II) (A) On July 1, 2024, the state treasurer shall transfer eight hundred thousand dollars from the general fund to the fund. (B) This subsection (3)(h)(II) is repealed, effective July 1, 2026. (i) This subsection (3) is repealed, effective July 1, 2028. (4) Near-term actions - interconnection and energization backlogs - identification of hosting capacity - cost recovery. (a) Qualifying retail utilities shall upgrade the state's electrical distribution systems as needed and in time to affordably and reliably support the achievement of the state's beneficial and transportation electrification and decarbonization goals and support implementation of federal, state, regional, and local air quality and decarbonization targets, standards, plans, and regulations. (b) To promptly, affordably, and reliably interconnect and energize new customers and comply with the obligation to serve without substantial delay, a qualifying retail utility shall: (I) Commence a data collection process to inform future energization timelines. The commission may open or use an existing miscellaneous proceeding to accept information collected by the qualifying retail utility and from other stakeholders. (II) Meet the interconnection deadlines specified in section 40-2-135 and commission rules; (III) Adopt the following cost caps, which cost caps must remain in effect until the commission completes the rule-making described in subsection (6) of this section: (A) For distributed generation systems that are twenty-five kilowatts or less, adopt a cap of no more than three hundred dollars for an individual customer's responsibility for interconnection costs for a customer-caused upgrade of the qualifying retail utility's distribution system, so long as the costs above the cap remain recoverable by the qualifying retail utility; (B) For residential customers energizing transportation electrification or beneficial electrification, not require the customer to pay for the costs of associated distribution system upgrades, so long as the costs remain recoverable by the qualifying retail utility; and (C) For affordable housing developments, cap the costs for interconnection or energization for a project-caused upgrade of the qualifying retail utility's distribution system at a level of three hundred dollars per residential unit of affordable housing, so long as costs above the cap remain recoverable by the qualifying retail utility; (IV) Propose, and the commission shall authorize, modify, or deny in a manner consistent with the public interest, the use of an optional flexible interconnection or energization tariff or phased interconnection or energization agreement by a customer as an alternative to a system upgrade that would otherwise be required by the qualifying retail utility in response to the customer's request to interconnect or energize a distributed energy resource; and (V) Establish a procedure for customers with a hybrid facility to complete the interconnection and energization processes through a single application. (c) A qualifying retail utility shall identify interconnection and load hosting capacity for DERs, including beneficial electrification and transportation electrification, for disproportionately impacted communities within its service territory. (V) Establish a procedure for customers with a hybrid facility to complete the interconnection and energization processes through a single application. (c) A qualifying retail utility shall identify interconnection and load hosting capacity for DERs, including beneficial electrification and transportation electrification, for disproportionately impacted communities within its service territory. (d) (I) Prior to the establishment of the grid modernization adjustment clause, a qualifying retail utility shall recover the forecasted investments placed in service and expenses incurred for distribution activities during the period beginning on May 22, 2024, and ending on December 31, 2025, consistent with this section. (II) Cost recovery must occur through the transmission cost adjustment clause or another existing adjustment clause, subject to: (A) A one-half percent retail rate impact cap on an annualized basis for 2024; and (B) A one and one-fourth percent retail rate impact cap on an annualized basis for 2025. (III) Within thirty days after May 22, 2024, a qualifying retail utility shall file an advice letter with the commission identifying the distribution activities for recovery, including the revenue requirement for the distribution activities and a return at the qualifying retail utility's most recently approved weighted average cost of capital, for the period beginning on May 22, 2024, and ending on December 31, 2024, to be included in the transmission cost adjustment clause or an existing adjustment clause with an effective date within sixty days after May 22, 2024. (IV) On or before November 1, 2024, a qualifying retail utility shall file an advice letter with the commission identifying the distribution activities for recovery, including the revenue requirement for the distribution activities and a return at the qualifying retail utility's most recently approved weighted average cost of capital, for the period beginning January 1, 2025, and ending December 31, 2025, to be included in the transmission cost adjustment clause or an existing adjustment clause with an effective date of January 1, 2025. (V) The amounts recovered pursuant to this subsection (4)(d) are subject to a true-up with any positive or negative balance credited to customers or recovered by the qualifying retail utility in the subsequent year and with the financing cost for the transmission cost adjustment clause or the applicable existing adjustment clause applied to the positive or negative balances. All amounts recovered are subject to a prudence review by the commission through either a standalone prudence review proceeding or in a base rate proceeding. (VI) In addition to the amounts recovered pursuant to this subsection (4)(d), a qualifying retail utility may spend and recover through the transmission cost adjustment clause or another existing adjustment clause the revenue requirement associated with up to an additional one hundred fifty million dollars in investment to order equipment to advance distribution activities, such as power transformers, service transformers, capacitor banks, switch cabinets, and feeder cables, as long as the investments are prudently incurred for the purposes of achieving economies of scale, addressing supply chain concerns, or other similar purposes. sociated with up to an additional one hundred fifty million dollars in investment to order equipment to advance distribution activities, such as power transformers, service transformers, capacitor banks, switch cabinets, and feeder cables, as long as the investments are prudently incurred for the purposes of achieving economies of scale, addressing supply chain concerns, or other similar purposes. (5) Long-term actions - distribution system plan requirements - approval by commission - staffing requirements - labor requirements - report. (a) A qualifying retail utility shall file distribution system plans pursuant to section 40-2-132, subject to review, approval, modification, or denial by the commission, to create sufficient hosting capacity across its electrical distribution system to affordably and reliably support the implementation of the following: (I) Federal, state, regional, and local air quality and decarbonization targets, standards, plans, and regulations; (II) The transportation, affordable housing, new infill housing, and building electrification policies of state and local law, including: (A) The rules adopted by the air quality control commission related to greenhouse gas emission reductions from light-duty and heavy-duty motor vehicles; and (B) The rules adopted by the air quality control commission pursuant to section 25-7-142 or local building performance standards; (III) State agency, local agency, and local government plans and requirements related to housing, economic development, critical facilities, transportation, and building electrification; (IV) Enforceable and funded federal, state, regional, and local policies, plans, goals, incentives, or requirements designed to increase access to distributed energy resources, electrified transportation, and building electrification in disproportionately impacted communities; and (V) The qualifying retail utility's approved renewable energy standard plan, clean heat plan, beneficial electrification plan, demand-side management plan, gas infrastructure plan, and transportation electrification plan required by this title 40. (b) In developing distribution system plans pursuant to section 40-2-132, consistent with state-level recognized best practices for community outreach, a qualifying retail utility shall consult with and provide opportunities for meaningful engagement and education through multilingual and culturally relevant outreach to disproportionately impacted communities. (c) (I) As part of a distribution system plan proceeding, a qualifying retail utility shall present at least two future planning scenarios with corresponding investments to show different future states of the distribution system. (II) In determining the distribution capacity necessary to meet projected load growth and distributed energy resource expansion, including to affordably and reliably support implementation of applicable targets, standards, plans, and regulations described in subsection (5)(a) of this section, a qualifying retail utility shall incorporate a scenario that incorporates load and managed generation flexibility that may increase system capacity utilization, reduce the need for system upgrades, and lower system costs. (III) In determining to which portions of the distribution system to propose system upgrades to affordably and reliably support the implementation of the applicable targets, standards, plans, and regulations described in subsection (5)(a) of this section, a qualifying retail utility shall prioritize capacity investments in areas of its distribution system that are at or near their hosting capacity limits or that are projected to have energization loads that cannot be met without a system upgrade. A qualifying retail utility shall prioritize system upgrades targeted at improving infrastructure for income-qualified or disproportionately impacted communities with residential capacity constraints. apacity investments in areas of its distribution system that are at or near their hosting capacity limits or that are projected to have energization loads that cannot be met without a system upgrade. A qualifying retail utility shall prioritize system upgrades targeted at improving infrastructure for income-qualified or disproportionately impacted communities with residential capacity constraints. (IV) Specific to reliability investments, a qualifying retail utility shall prioritize investments for disproportionately impacted communities based on reliability information provided in the qualifying retail utility's quality of service plan. (d) In evaluating a qualifying retail utility's distribution system plans, the commission shall evaluate whether the distribution system plan: (I) Establishes a long-term distribution system plan, which must cover at least five years, that includes timelines and budgets to create sufficient hosting capacity across the qualifying retail utility's electrical distribution system to affordably and reliably support the implementation of the applicable targets, standards, plans, and regulations described in subsection (5)(a) of this section; (II) Includes the identification of specific distribution investments needed to strategically support the applicable targets, standards, plans, and regulations described in subsection (5)(a) of this section over the planning period, which must cover at least five years, with increased specificity in the first two years of the planning period; (III) Includes detailed mapping of distribution hosting capacity with appropriate safeguards to protect critical infrastructure, as determined by the commission; (IV) Includes a process to identify and evaluate infill housing loads; (V) Includes proposed, unless already informed or satisfied by commission rules, standardized, quantifiable, and transparent processes and timelines within the planning period for formal load and generation interconnection and energization requests, so long as the qualifying retail utility is not required to include energization timelines as part of its first distribution system plan filed after May 22, 2024; (VI) Includes proposed actions to facilitate programs for: (A) The competitive acquisition of cost-effective non-wires alternatives to defer or avoid identified system distribution infrastructure projects, subject to investment thresholds in commission rules; (B) Load and generation flexibility, including interruptible programs, with due consideration given to programs proposed or approved in other commission proceedings; and (C) Other alternatives to system upgrades, which may include automated distributed resource management systems; (VII) Includes adequate reporting and system mapping to implement the proposed plan and programs, as well as: (A) To the extent available at the time of the distribution system plan filing, the average, median, and standard deviation time between receiving a formal application for interconnection or energization and energizing the electrical service; constraints and obstacles to each type of interconnection or energization, such as funding limitations, qualified staffing availability, or equipment availability; and any other information required by the commission; and (B) If the interconnection and energization time periods exceed any established, commission-approved average target energization time periods, as determined in a qualifying retail utility's distribution system plan proceeding, or if the qualifying retail utility has a substantial number of interconnection or energization applications that exceed any established commission-approved maximum target energization time periods, a strategy for meeting the target energization time periods in the future; and (VIII) Includes documentation demonstrating progress toward implementation of previously approved distribution system plans. if the qualifying retail utility has a substantial number of interconnection or energization applications that exceed any established commission-approved maximum target energization time periods, a strategy for meeting the target energization time periods in the future; and (VIII) Includes documentation demonstrating progress toward implementation of previously approved distribution system plans. (e) The distribution system plan must include a performance-based framework, which must consist of: (I) Applicable interconnection timelines; (II) Applicable energization timelines, so long as: (A) The energization timelines are not applicable to the first distribution system plan filed after May 22, 2024; (B) In the second distribution system plan filed after May 22, 2024, measurement of any energization timelines must commence upon submission by the customer of a formal load request, and any performance-based framework must only include the steps in the energization process that are the sole responsibility of the qualifying retail utility; (C) Any energization timelines in a performance-based framework must account for extenuating circumstances, as demonstrated by the qualifying retail utility, that do not result in any finding of noncompliance by the commission for the qualifying retail utility; (D) Any energization timelines and performance requirements do not include conceptual capacity checks or other informational evaluations that may precede a formal load request; and (E) The qualifying retail utility must be required to track and collect data on steps and outcomes that may precede the formal energization process, and the commission may consider this data in updating any performance-based energization timeline requirements in the third distribution system plan filed after May 22, 2024; and (III) Reasonable and cost-effective targets measured in megawatts for flexible load and demand management, so long as: (A) A general target-setting framework must be evaluated in the first distribution system plan filed after May 22, 2024, and further developed through other planning processes, including subsequent distribution system plans, electric resource plans, and demand-side management plans; and (B) The targets are applicable in the second distribution system plan filed after May 22, 2024, and subsequent distribution system plans. (f) (I) A qualifying retail utility shall include in its distribution system plan a detailed analysis of its current qualified staffing level and future required qualified staffing level for each job classification needed to achieve the policies and requirements of this section. The analysis of workforce needs must include review of both the anticipated needs of future utility employees as well as the anticipated needs for workforce acquired through third-party utility and construction contractors. Adequate staffing includes engineering and programming staff necessary to oversee the timely interconnection of distributed energy resources, energization of electrified end uses, and energization of new service connections to the qualifying retail utility's distribution system. (II) The commission shall review whether each qualifying retail utility has adequate qualified staffing needed to achieve the policies and requirements of this section. The analysis of adequate staffing must be considered in a qualifying retail utility's distribution system plan proceeding. d uses, and energization of new service connections to the qualifying retail utility's distribution system. (II) The commission shall review whether each qualifying retail utility has adequate qualified staffing needed to achieve the policies and requirements of this section. The analysis of adequate staffing must be considered in a qualifying retail utility's distribution system plan proceeding. (g) A qualifying retail utility shall ensure that, in any construction, expansion, or maintenance of distribution projects undertaken as a part of the distribution system plan, all labor is performed either by the employees of the qualifying retail utility or by qualified contractors, or both, and that, except as otherwise provided in subsection (5)(i) of this section, a qualifying retail utility shall not use a contractor unless: (I) The contractor is chosen from a list of qualified contractors prepared and updated at least annually by the department; and (II) The contractor's employees have access to an apprenticeship program registered with the United States department of labor's office of apprenticeship or the state apprenticeship agency; except that this apprenticeship program requirement does not apply to: (A) The design, planning, or engineering of the facilities; (B) Management functions to operate the facilities; or (C) Any work performed in response to a warranty claim. (h) To qualify pursuant to subsection (5)(g)(I) of this section, an apprenticeship program must certify to the qualifying retail utility that: (I) Its curriculum includes requirements for the completion of: (A) At least seven thousand hours of on-the-job training to achieve journeyman lineman status, with at least six hundred fifty of those hours spent working on energized power lines at voltages of at least six hundred volts; and (B) A class in electric transmission and distribution offered by the federal occupational safety and health administration known as the "OSHA ET&D ten-hour training" and comprising content substantially equivalent to that of the "OSHA 10" class offered during calendar year 2021; and (II) Supervision of apprentices meets the following standards: (A) Apprentices must work under the supervision of a journeyman-level worker at all times; and (B) The ratio of apprentices to journeymen linemen does not exceed two to one when working on distribution projects for both energized and nonenergized work. (i) The request for proposal for any contract work on facilities subject to this section must be submitted to the list of qualified contractors described in subsection (5)(g)(I) of this section for at least sixty days. If none of the contractors on the list submits a qualifying bid within sixty days, then the entity procuring the work may solicit bids from contractors that are not on the list but otherwise qualify under the terms of the request for proposal so long as those terms include compliance with all applicable laws and regulations related to safety. tion (5)(g)(I) of this section for at least sixty days. If none of the contractors on the list submits a qualifying bid within sixty days, then the entity procuring the work may solicit bids from contractors that are not on the list but otherwise qualify under the terms of the request for proposal so long as those terms include compliance with all applicable laws and regulations related to safety. (j) Notwithstanding section 24-1-136 (11)(a)(I), two years after the approval of any distribution system plan, and every two years thereafter, a qualifying retail utility shall prepare a report and submit the report to the general assembly and the commission outlining progress toward the objectives set forth in this section, including progress toward meeting the hosting capacity needs in disproportionately impacted communities identified pursuant to subsection (4)(c) of this section. The progress reports must be posted on the qualifying retail utility's website and the commission's website. (6) Longer-term requirements - rules. (a) Following the adjudication and final commission decision on a qualifying retail utility's first distribution system plan filing after May 22, 2024, the commission shall open a rule-making, for a qualifying retail utility, to consider and establish: (I) Target average and maximum energization timelines; (II) Any necessary updates to existing interconnection rules; (III) Rules for interconnection, energization, and electrification of end uses in new construction homes, particularly regarding time frames for responding to cost projection requests, the reliability of utility cost estimates, and reasonable construction schedules; and (IV) Maximum individual customer cost caps or fees for interconnection or energization of resources of all sizes to help defray or eliminate the costs of interconnecting new distributed generation or energizing transportation or beneficial electrification load to the electrical grid. The rules, where appropriate, should specifically exempt income-qualified customers from payment of system upgrade fees. (b) The rule-making described in subsection (6)(a) of this section may set different fees based on the inclusion of technologies or agreements to reduce system costs, including flexible interconnection or energization tariffs and automated distributed resource management systems. (c) The commission's consideration of the rule-making proceeding described in subsections (6)(a) and (6)(b) of this section must conclude in a time that is sufficient to allow the qualifying retail utility to file its second distribution system plan after May 22, 2024. (7) Cost recovery - grid modernization adjustment clause. (a) A qualifying retail utility shall recover, on an annual basis, projected distribution activities through a grid modernization adjustment clause established as part of the qualifying retail utility's first distribution system plan application after May 22, 2024, so long as the grid modernization adjustment clause continues in effect through subsequent distribution system plans. justment clause. (a) A qualifying retail utility shall recover, on an annual basis, projected distribution activities through a grid modernization adjustment clause established as part of the qualifying retail utility's first distribution system plan application after May 22, 2024, so long as the grid modernization adjustment clause continues in effect through subsequent distribution system plans. (b) (I) Within the distribution system plan, a qualifying retail utility shall propose, and the commission shall evaluate, whether the projected distribution activities and corresponding budgets strategically benefit or advance the applicable targets, standards, plans, and regulations described in subsection (5)(a) of this section or state energy policy goals, including greenhouse gas emission reductions, beneficial electrification, increased reliability, and increased resiliency, and the commission shall allow grid modernization adjustment clause recovery for such approved distribution activities. (II) If the commission finds that the projected distribution activities and corresponding budgets affordably and strategically benefit or advance the goals described in subsection (7)(b)(I) of this section, the distribution activities are qualifying distribution activity recovery and recovery must occur through the grid modernization adjustment clause in a manner consistent with this section. (III) For projected distribution activities and corresponding budgets that the commission finds do not benefit or advance the goals described in subsection (7)(b)(I) of this section, recovery may occur through the grid modernization adjustment clause if the qualifying retail utility meets the criteria established in the performance-based framework approved by the commission pursuant to subsection (5)(e) of this section through the distribution system planning process. (c) (I) The grid modernization adjustment clause is subject to annual adjustments, which are effective on January 1 of each year. (II) A qualifying retail utility shall make a grid modernization adjustment clause advice letter filing with the commission annually, and no later than November 1 of each year, with an effective date of January 1 of the subsequent year, which must include the qualifying distribution activity recovery and other distribution activities approved pursuant to subsection (7)(b) of this section for the next twelve months, including a return at the qualifying retail utility's most recently approved weighted average cost of capital. (III) The grid modernization adjustment clause must be reduced to the extent that any prudently incurred costs being recovered through the grid modernization adjustment clause have already been included in the qualifying retail utility's base rates as a result of the commission's final order in a rate case, and recovered qualifying distribution activity recovery is subject to a true-up with any positive or negative balance credited to customers or recovered by the qualifying retail utility in the subsequent year and an appropriate financing cost applied to the positive or negative balances. (d) Recovery through the grid modernization adjustment clause must not apply to wholesale customers with rates under federal jurisdiction or customers that do not take distribution service from the qualifying retail utility. (8) Virtual power plant program. (a) No later than February 1, 2025, a qualifying retail utility shall create and file with the commission an application to implement a virtual power plant program, including a tariff for performance-based compensation for a qualified virtual power plant. er federal jurisdiction or customers that do not take distribution service from the qualifying retail utility. (8) Virtual power plant program. (a) No later than February 1, 2025, a qualifying retail utility shall create and file with the commission an application to implement a virtual power plant program, including a tariff for performance-based compensation for a qualified virtual power plant. (b) A virtual power plant program implemented pursuant to subsection (8)(a) of this section: (I) Must define the goals of the virtual power plant program and consider the role that virtual power plants can play in modeling and meeting system needs in the resource planning process and eligibility requirements for DER aggregators and technologies; (II) Must establish a requirement for a DER aggregator to participate in a virtual power plant as a qualified aggregator, including communication, dispatch, measurement and verification, and settlement of performance-based compensation; (III) May set a cap for individual resource capacity and minimum aggregation capacity for participation in the virtual power plant program; (IV) Must have provisions for the enrollment of prosumers by DER aggregators; (V) Must have requirements for a DER aggregator to participate in a virtual power plant tariff, including requirements for the measurements of distributed energy resources associated with the virtual power plant; (VI) Must have requirements for a standard tariff or tariffs to set performance requirements and performance-based compensation for the DER aggregator, which requirements must include: (A) A requirement that otherwise eligible customers must participate in the tariff or tariffs through a DER aggregator, regardless of the customer's electricity service rate; and (B) A requirement to explore the costs and benefits of setting the tariff requirements and compensation for a period of five years, after which DER aggregators may be required to transition to different tariff requirements and compensation; (VII) Must have streamlined and reasonable data requirements for the participation of qualified aggregators, prosumers, or otherwise eligible customers in the virtual power plant program; (VIII) Must provide that prosumers or otherwise eligible customers must not be disqualified from participation in a commission-approved virtual power plant program or performance-based compensation due to receipt of other incentives, including up-front incentives or performance payments for energy, capacity, or other grid services that are distinct from the virtual power plant; (IX) Must provide that prosumers or otherwise eligible customers are not compensated for the provision of the same service more than once; (X) Must require that DER aggregators adhere to all relevant interconnection rules, tariffs, and applicable qualifying retail utility procedures to ensure the safe operation of virtual power plants within the distribution system; (XI) Must prescribe the method for setting performance-based compensation. The virtual power plant program may make use of tariff riders to reflect standard and additional values provided by certain resources, locations, times, or grid conditions. To the extent applicable, the performance-based compensation methodology must reflect the full value of services, which may include: (A) Local and system peak demand reduction; (B) Clean peak service; (C) Voltage support and other ancillary services; (D) The avoidance or deferral of electric or gas transmission or distribution upgrades or capacity expansion; (E) Locational value as revealed by a grid needs assessment or participation in non-wires alternatives identified in the qualifying retail utility's distribution system plan; (F) The use of telemetry for settlement; and (G) Other functions that the commission determines are supportive of efficient planning and operation of the electrical grid; and or distribution upgrades or capacity expansion; (E) Locational value as revealed by a grid needs assessment or participation in non-wires alternatives identified in the qualifying retail utility's distribution system plan; (F) The use of telemetry for settlement; and (G) Other functions that the commission determines are supportive of efficient planning and operation of the electrical grid; and (XII) Must allow a qualifying retail utility to serve as a DER aggregator so long as the tariff or access to necessary data does not provide the utility a competitive advantage over third-party aggregators. (c) As part of the tariff application, the commission shall consider whether it is appropriate to set different performance-based compensation and requirements for different technologies or services. (d) Any tariff filed by a qualifying retail utility pursuant to subsection (8)(a) of this section must include, at a minimum, the following terms for the commission to approve, modify, or deny the tariff: (I) Minimum and maximum numbers of grid events for which the qualifying retail utility may dispatch the virtual power plant; (II) Months of the year that grid events can occur; (III) Days of the week that grid events can occur; (IV) Times of day that grid events can occur; (V) The maximum duration of grid events; and (VI) Minimum advance notification requirements of grid events. (e) Nothing in this section affects a qualifying retail utility's net metering program required by section 40-2-124 for energy that is exported outside of a commission-approved virtual power plant program. (f) A qualifying retail utility shall recover costs to facilitate a virtual power plant program, including foundational technology costs or investments, operations and maintenance expenses, operating technology costs or investments, and information technology costs or investments, through the grid modernization adjustment clause. (g) (I) In order to participate in a virtual power plant program under this section, an individual energy storage project put out to bid by the project owner after June 30, 2024, with a usable energy capacity of one megawatt or higher is subject to the requirements of sections 24-92-304, 24-92-305, 24-92-306, and 24-92-307. (II) The DER aggregator administering the VPP shall file an affidavit under penalty of perjury with the commission stating that all energy storage systems with a usable energy capacity of one megawatt or higher participating in the VPP are in compliance with this section. (III) The commission may ask the qualifying retail utility to get additional information or documentation from the DER aggregator if the commission deems it necessary to ensure compliance with this section. (IV) After the initial filing of the affidavit with the commission, if a DER aggregator adds an individual additional storage system capacity of one megawatt or higher, the DER aggregator shall file another affidavit with the commission. (h) Unless implemented in another proceeding, the commission shall determine whether to direct a qualifying retail utility to propose a competitive solicitation for virtual power plants that may operate in conjunction with the tariff-based virtual power plant program in evaluating the approval of the tariff. (9) Underground conversion and community benefit programs - plans - definition. (a) By January 1, 2025, a qualifying retail utility shall file with the commission a plan to implement community-directed underground conversion and community benefit programs for the undergrounding of utility distribution infrastructure and other community benefit investments in nonfranchised areas of the qualifying retail utility in the state using one percent of the area's gross electric revenues from the prior year. a qualifying retail utility shall file with the commission a plan to implement community-directed underground conversion and community benefit programs for the undergrounding of utility distribution infrastructure and other community benefit investments in nonfranchised areas of the qualifying retail utility in the state using one percent of the area's gross electric revenues from the prior year. (b) As part of a qualifying retail utility's distribution system plans, the qualifying retail utility shall consider the public benefit of undergrounding existing and new distribution system infrastructure and other community benefit investments. A qualifying retail utility shall include in its distribution system plans a description of how such public benefit has been considered in its distribution system planning. (c) In order to account for the fact that undergrounding significant portions of utility distribution infrastructure may not be feasible or efficient in some areas, as used in this subsection (9), "community benefit investments" means community-directed projects such as microgrids, customer-sited energy storage, and other similar projects aimed at community energy resiliency.

C.R.S. § 40-2-133 Workforce transition planning filing - definition

40-2-133. Workforce transition planning filing - definition. (1) A qualifying retail utility regulated by the commission that submits a filing, including a resource plan or application, that includes a proposed accelerated retirement of an electric generating facility shall also include a workforce transition plan as part of its filing. (2) To the extent practicable, a workforce transition plan must include estimates of: (a) The number of workers employed by the qualifying retail utility or a contractor of the qualifying retail utility at the electric generating facility, which number must include all workers that directly deliver fuel to the electric generating facility; (b) The total number of workers whose existing jobs, as a result of the retirement of the electric generating facility: (I) Will be retained; and (II) Will be eliminated; (c) With respect to the workers whose existing jobs will be eliminated due to the retirement of the electric generating facility, the total number and the number by job classification of workers: (I) Whose employment will end without them being offered other employment; (II) Who will retire as planned, be offered early retirement, or leave on their own; (III) Who will be retained by being transferred to other electric generating facilities or offered other employment by the qualifying retail utility; and (IV) Who will be retained to continue to work for the qualifying retail utility in a new job classification; and (d) If the qualifying retail utility is replacing the electric generating facility being retired with a new electric generating facility, the number of: (I) Workers from the retired electric generating facility who will be employed at the new electric generating facility; and (II) Jobs at the new electric generating facility that will be outsourced to contractors or subcontractors. (3) As used in this section, "qualifying retail utility" has the meaning described in section 40-2-124 (1); except that the term does not mean a municipally owned utility or a cooperative electric association.

C.R.S. § 40-2-134 Wholesale electric cooperatives - electric resource planning - definition - rules

40-2-134. Wholesale electric cooperatives - electric resource planning - definition - rules. (1) (a) The commission shall promulgate rules that require each wholesale electric cooperative to submit to the commission an application for approval of an integrated or electric resource plan. The commission shall evaluate a wholesale electric cooperative plan using rules that the commission has adopted that are applicable to wholesale electric cooperatives. (b) In developing rules for a wholesale electric cooperative, the commission must consider, among other factors determined by the commission, whether each wholesale electric cooperative: (I) Serves a multistate operational jurisdiction; (II) Has a not-for-profit ownership structure; and (III) Has a resource plan that meets the energy policy goals of the state. (2) As used in this section, "wholesale electric cooperative" means any generation and transmission cooperative electric association that provides wholesale electric service directly to cooperative electric associations.

C.R.S. § 40-2-135 Retail distributed generation - customers' rights - rules - penalties

40-2-135. Retail distributed generation - customers' rights - rules - penalties. (1) A retail electric utility customer is entitled to generate, consume, store, and export electricity produced from eligible energy resources to the electric grid through the use of customer-sited retail distributed generation, as defined in section 40-2-124 (1)(a)(VIII), subject to reliability standards, interconnection rules, and procedures, as determined by the commission. (2) (a) A retail electric utility violates this section if the utility fails to provide reasonable, good faith, and timely service to an interconnection customer, and such violation may result in commission action, including the assessment of monetary fines against the retail electric utility. If a retail electric utility fails to provide timely service and adhere to timelines that the commission establishes as part of the commission's interconnection rules, the retail electric utility may be subject to penalties of up to two thousand dollars per day for each day that the violation occurred. (b) The commission shall adopt rules to annually adjust the penalty amount set forth in subsection (2)(a) of this section based on the annual percentage change in the United States department of labor's bureau of labor statistics consumer price index for the Denver-Aurora-Lakewood area for all items paid by all urban consumers, or its successor index. (c) (I) For a retail distributed generation resource that is twenty-five kilowatts or less, a public utility shall provide an interconnection customer an executed interconnection agreement no more than thirty business days after receiving payment of an interconnection fee from the interconnection customer. (II) Following the construction of a retail distributed generation resource, a public utility must provide interconnection of the customer's retail distributed generation resource no more than thirty business days after the interconnection customer submits to the public utility a certificate of completion. (III) If the sum of a public utility's compliance with the times set forth in this subsection (2)(c) exceeds sixty days, the public utility may be subject to penalties consistent with this subsection (2). (d) A public utility is not subject to penalties under this subsection (2) if the public utility can demonstrate that: (I) The interconnection customer failed to timely remedy any material defects in the completion of the interconnection customer's application for interconnection and the public utility identified the defects during its review of the application; (II) The retail distributed generation resource cannot be safely interconnected to the public utility's system in a manner consistent with the commission's interconnection rules; or (III) Other extenuating circumstances caused a delay in interconnection. (3) (a) An interconnection customer may file a complaint with the commission in accordance with section 40-6-108 alleging that a public utility has violated subsection (2) of this section. (b) In considering a complaint filed pursuant to this subsection (3), the commission may order the public utility to refund interconnection study fees charged to the interconnection customer. If a public utility is ordered to refund such interconnection study fees, such refund is not an expense that the public utility may recover from its ratepayers. (4) The commission shall only assess the penalties set forth in subsection (2)(a) of this section against a public utility if: (a) An interconnection customer or commission staff has filed, and the commission has adjudicated, a complaint pursuant to section 40-6-108; and refund such interconnection study fees, such refund is not an expense that the public utility may recover from its ratepayers. (4) The commission shall only assess the penalties set forth in subsection (2)(a) of this section against a public utility if: (a) An interconnection customer or commission staff has filed, and the commission has adjudicated, a complaint pursuant to section 40-6-108; and (b) The public utility has a tariff on file with the commission that provides incentives and penalties to provide interconnection service and the public utility has exceeded the timelines established in the tariff filing. (5) In jurisdictions that allow interconnection without a public utility present, an interconnection customer may install all necessary metering equipment and energize the system following installation if: (a) The interconnection customer has an interconnection agreement with a public utility and a certificate of completion from a local government's building code enforcement authority; and (b) The installation and energizing work is overseen by a licensed master electrician. (6) A public utility may recover its prudently incurred costs to facilitate a timely interconnection, which costs may include the cost of equipment that the public utility procures for future upgrades needed to interconnect retail distributed generation resources. A public utility may recover the costs of any such equipment inventory as capital work in progress if the inventory is projected to be used within five years of its procurement and with a return at the most recently authorized weighted average cost of capital.

C.R.S. § 40-2-136 Energy storage systems - terms and conditions for installation, interconnection, and use by cooperatives - legislative declaration - definitions

40-2-136. Energy storage systems - terms and conditions for installation, interconnection, and use by cooperatives - legislative declaration - definitions. (1) (a) The general assembly finds and determines that: (I) Cardinal principles of cooperative electric associations include democratic member control, autonomy, and independence; and (II) Rapidly evolving technologies in generation, energy storage, and demand management offer cooperative electric associations a variety of options to meet the needs of their members reliably. (b) Therefore, the general assembly declares that: (I) It is in the public interest to limit barriers to the installation, interconnection, and use of energy storage systems by cooperative electric associations in Colorado; and (II) Cooperative electric associations in Colorado should be able to install, interconnect, and use energy storage systems that are connected to the cooperative electric association's electrical system and will not, at any time, flow onto the transmission facilities of a wholesale electric cooperative or other third party without prior agreement as part of meeting their members' needs for reliable, affordable energy without unfair or discriminatory rates or fees. (2) A wholesale electric cooperative shall not subject the installation, interconnection, or use of an energy storage system by a retail cooperative electric association to any unjust, unreasonable, discriminatory, or preferential charge, classification, contract, fare, fee, practice, rate, regulation, rule, schedule, service, or toll. (3) As used in this section, unless the context otherwise requires: (a) "Cooperative electric association" means a nonprofit electric corporation or association other than a wholesale electric cooperative. (b) "Energy storage system" has the meaning set forth in section 40-2-202 (2). (c) "Wholesale electric cooperative" means any generation and transmission cooperative electric association that provides wholesale electric service directly to cooperative electric associations.

C.R.S. § 40-2-137 Investor-owned utility electric resource planning - retirement of electric generating facility - commission to consider securitization as means of financing

40-2-137. Investor-owned utility electric resource planning - retirement of electric generating facility - commission to consider securitization as means of financing. (1) For each investor-owned electric utility that submits for commission approval an electric resource plan that includes a portfolio in which an existing electric generating facility in the state would be retired, the commission shall require the investor-owned electric utility to present as part of the resource plan the net present value of revenue requirements for the portfolio based on: (a) A projection in which the investor-owned electric utility issues CO-EI bonds, as defined in section 40-41-102 (5), to recover, finance, or refinance costs arising from the retirement of the electric generating facility pursuant to the "Colorado Energy Impact Bond Act", article 41 of this title 40; and (b) A projection in which the investor-owned electric utility does not issue CO-EI bonds. (2) The commission shall consider the two net present value of revenue requirement options presented by the investor-owned electric utility in its review of the investor-owned electric utility's electric resource plan.

C.R.S. § 40-2-138 Projects for the production of clean hydrogen - proceeding - hydrogen hub projects - rules - reports - definitions

40-2-138. Projects for the production of clean hydrogen - proceeding - hydrogen hub projects - rules - reports - definitions. (1) As used in this section, unless the context otherwise requires: (a) "Clean hydrogen" means: (I) Green hydrogen, as defined in section 40-3.2-108 (2)(j); or (II) Hydrogen that is produced through a process that results in lifecycle greenhouse gas emissions rates that are within the lifecycle greenhouse gas emissions rate ranges set forth in 26 U.S.C. secs. 45V (b)(2)(C) and 45V (b)(2)(D), as amended. (b) (I) "Clean hydrogen project" means a project that results in the production of clean hydrogen by an investor-owned utility. (II) "Clean hydrogen project" may include pipelines, electrolyzers, environmental controls, monitoring equipment, dedicated renewable energy sources for electrolysis, the purchase of clean hydrogen from third parties, and an upgrade to a turbine at an electric generating station if that upgrade is part of a state or federal application for a regional clean hydrogen hub under 42 U.S.C. sec. 16161a. (c) "Cumulative impacts" means the incremental effects of a clean hydrogen project on the environment, including effects on air quality, water quality, water resource availability, climate, and public health, that a clean hydrogen project has when added to the impacts from other past, present, and reasonably foreseeable future development of any type on the relevant area, including an airshed or watershed, as determined by rule by the commission, or on a disproportionately impacted community. (d) "Disproportionately impacted community" has the meaning set forth in section 24-4-109 (2)(b)(II). (e) (I) "Hard to decarbonize end use" means industrial uses that include: (A) The generation of heat of at least one hundred fifty degrees Celsius for industrial purposes; and (B) Addition as feedstock for industrial purposes, including manufacture of steel, ammonia, fertilizer, and chemicals. (II) "Hard to decarbonize end use" does not include the direct use of hydrogen for residential or commercial heating. (f) "Hydrogen hub project" means a project that is part of an application for federal funding by a partnership of regulated utilities, private partners, and companies and may include state or federal government agencies in collaboration with other states that is designed to utilize available federal funds and tax credits, which may include the production, transport, and use of clean hydrogen. (g) "Lifecycle greenhouse gas emissions rate" means lifecycle greenhouse gas emissions, as defined in 26 U.S.C. sec. 45V (c)(1)(A), as amended, measured in accordance with any applicable federal internal revenue service regulations or guidance. (h) "Office" means the Colorado energy office created in section 24-38.5-101. (i) "Qualified use" means the use of clean hydrogen in the state for: (I) Hard to decarbonize end uses; (II) The operation of a heavy-duty motor vehicle, as defined in section 25-7.5-102 (11); and (III) Aviation. (2) The commission shall initiate an investigatory proceeding, no later than September 1, 2023, to consider: (a) The potential for clean hydrogen projects operated by investor-owned utilities subject to regulation by the commission to contribute to meeting the greenhouse gas emission reduction goals described in section 25-7-102 (2)(g), including lifecycle greenhouse gas emissions rates, with a preference for qualified uses; (b) The impact of clean hydrogen projects on the emission of air pollutants other than greenhouse gases and human health; (c) Potential markets for clean hydrogen in Colorado; (d) The impact of clean hydrogen production on water quality and quantity in Colorado; (e) The potential impacts of pipeline leakage and best practices for mitigation; (f) The potential for the development of clean hydrogen to help create or sustain jobs in Colorado, including utility jobs; ants other than greenhouse gases and human health; (c) Potential markets for clean hydrogen in Colorado; (d) The impact of clean hydrogen production on water quality and quantity in Colorado; (e) The potential impacts of pipeline leakage and best practices for mitigation; (f) The potential for the development of clean hydrogen to help create or sustain jobs in Colorado, including utility jobs; (g) The cost, capabilities, and market availability of clean hydrogen technologies, including pipeline investments; (h) The appropriate roles for investor-owned utilities in the production, sale, or use of clean hydrogen, including considering whether costs may be recovered from ratepayers; (i) The potential impact of investor-owned utility investments in a clean hydrogen project on ratepayers, including on bills, rates, and rate stability, and options for avoiding potential cross-subsidization and cost shifting across rate classes; (j) Principles and requirements for any tariffs for the sale of clean hydrogen to third parties, including principles and requirements to ensure that costs arising from the development, production, transport, and delivery of the clean hydrogen under those tariffs are not borne by customers who do not take service from those tariffs; (k) The process and data necessary and available to implement a requirement for the adoption of methods for: (I) The measurement of lifecycle greenhouse gas emissions rates, including for hourly matching of electricity used; (II) The tracking of the deployment of new renewable energy resources or use of curtailed renewable energy to meet electricity requirements for production of clean hydrogen in the same load balancing area; and (III) The commission to determine when at least two hundred megawatts of electrolyzers are operational in the state; (l) The process and data necessary for an investor-owned utility to conduct a cumulative impact analysis of a clean hydrogen project and any process necessary to avoid adverse cumulative impacts on disproportionately impacted communities, if any, which may include the commission considering: (I) The time frame over which a cumulative impact analysis should be conducted; (II) The geographical scope of a cumulative impact analysis; and (III) Whether the cumulative impact analysis should be compared to alternative projects; (m) Requirements for any application for a clean hydrogen project, in addition to the requirements described in subsection (3)(a)(VI) of this section and subject to subsections (4) and (5) of this section; (n) Any data or information necessary or available to evaluate a clean hydrogen project against alternative projects, including how to measure, track, and report lifecycle greenhouse gas emissions rates, cumulative impacts, and the cumulative impacts and individual impacts on jobs, local economic benefits, and water use by clean hydrogen projects under the commission's jurisdiction; (o) Opportunities to encourage non-utility production of clean hydrogen in Colorado, including opportunities for an investor-owned utility to propose a tariff for the sale of renewable energy that would otherwise be curtailed; and pacts, and the cumulative impacts and individual impacts on jobs, local economic benefits, and water use by clean hydrogen projects under the commission's jurisdiction; (o) Opportunities to encourage non-utility production of clean hydrogen in Colorado, including opportunities for an investor-owned utility to propose a tariff for the sale of renewable energy that would otherwise be curtailed; and (p) Any other relevant issues that the commission determines are necessary to consider. (3) (a) No later than December 1, 2024, unless the office files a notice with the commission stating that the federal department of energy has extended or otherwise altered the deadline regarding funding for a hydrogen hub project, the commission shall adopt rules that: (I) Unless the commission determines that investor-owned utilities should not develop clean hydrogen projects for cost recovery from ratepayers, establish requirements for the presentation of a clean hydrogen project to the commission for the commission's approval; (II) Establish requirements for lifecycle greenhouse gas emissions rate accounting for clean hydrogen projects; (III) Address the appropriate role of investor-owned utilities in the production, sale, and use of clean hydrogen, including whether and how costs may be recovered from ratepayers and appropriate treatment of revenues from clean hydrogen sales; (IV) Address how investor-owned utilities may use competitive solicitations in a clean hydrogen project and any limitations for the use of competitive solicitations to develop the clean hydrogen project; (V) Establish a requirement that any planned or potential use for the clean hydrogen in buildings or gas distribution systems of an investor-owned utility be proposed to and approved by the commission through a clean heat plan, as defined in section 40-3.2-108 (2)(b); and (VI) Address what is required in an application by an investor-owned utility for a clean hydrogen project, subject to subsections (4) and (5) of this section, including: (A) A comparison of a clean hydrogen project to alternative projects, including an analysis of the costs and benefits of the clean hydrogen project compared to alternative projects; (B) A description of how the investor-owned utility will measure and track the annual and cumulative lifecycle greenhouse gas emissions rates and the emission of other air pollutants in accordance with the rules adopted pursuant to subsection (3)(a)(II) of this section; (C) A description of how the investor-owned utility will: Minimize the lifecycle greenhouse gas emissions rates of the clean hydrogen project, conduct leak detection throughout the life of the clean hydrogen project, and conduct a cumulative impact analysis of the clean hydrogen project; (D) An assessment of the annual water volume that will be used in the clean hydrogen project, including the source of water to be used; (E) A description of any planned uses, including potential end uses by the investor-owned utility's customers, of the clean hydrogen produced through the clean hydrogen project, with a preference for qualified uses; (F) A description of any planned sales of clean hydrogen to non-utility customers, with a preference for qualified uses; (G) A description of the proposed method of cost recovery for the clean hydrogen project, including information regarding which rate classes will cover the costs of the clean hydrogen project; (H) A description of the total revenue requirement for the clean hydrogen project; (I) A description of the rate and bill impacts of the clean hydrogen project; (J) A description of any tariffs for the sale of clean hydrogen produced by the clean hydrogen project; r the clean hydrogen project, including information regarding which rate classes will cover the costs of the clean hydrogen project; (H) A description of the total revenue requirement for the clean hydrogen project; (I) A description of the rate and bill impacts of the clean hydrogen project; (J) A description of any tariffs for the sale of clean hydrogen produced by the clean hydrogen project; (K) A proposal for the allocation of revenues received from the sale of clean hydrogen produced by the clean hydrogen project to non-utility customers among customers and the investor-owned utility, including which party bears the risk that the amount of revenue anticipated from the clean hydrogen project is not ultimately received; (L) A cumulative impact analysis framework; and (M) If the investor-owned utility plans to use a competitive solicitation process as part of the clean hydrogen project, a description of how the planned competitive solicitation process will be used and in what circumstances the process will be used. (b) (I) The rules adopted by the commission pursuant to subsection (3)(a)(II) of this section must include requirements for: (A) The matching of electrolyzer energy consumption with electricity production on an hourly basis, if the technology is available; (B) Identifying the applicable energy source, if the investor-owned utility is reporting the energy source as resulting in zero emissions for clean hydrogen production and demonstrating that the electricity used to produce clean hydrogen comes from renewable energy that would otherwise have been curtailed or not delivered to load or from new zero carbon generation that began production no more than thirty-six months before the start of the operations of the electrolyzer; and (C) The deliverability of renewable energy used by the electrolyzer into the same load balancing area as the electrolyzer. (II) The commission shall make the rules adopted by the commission pursuant to subsection (3)(a)(II) of this section effective no later than January 1, 2028, or no later than one year after the deployment of hydrogen electrolyzers in the state exceeds two hundred megawatts, whichever is earlier. (c) (I) In developing the rules pursuant to subsection (3)(a) of this section, the commission shall consider the potential for federal funding for clean hydrogen projects and that clean hydrogen projects implemented by investor-owned utilities may be necessary to secure federal funding. (II) In developing the rules pursuant to subsection (3)(a)(II) of this section, the commission shall consider what information and market mechanisms are necessary and available for hydrogen producers to comply with the rules. If the federal internal revenue service issues guidance that meets or exceeds the rules, the commission shall adopt rules that comply with the guidance. (d) If the office files the notice described in subsection (3)(a) of this section with the commission, the commission shall coordinate with the office to determine an appropriate date for the adoption of the rules described in subsection (3)(a) of this section. (4) (a) The commission shall allow an investor-owned utility to present to the commission a stand-alone application for a clean hydrogen project for which an investor-owned utility has applied for federal funding as part of a hydrogen hub project at any time before June 1, 2024, unless the office files a notice with the commission stating that the federal department of energy has extended or otherwise altered the deadline regarding funding for a hydrogen hub project. The application may only address elements of a hydrogen hub project that are not located in the Denver metropolitan area. for federal funding as part of a hydrogen hub project at any time before June 1, 2024, unless the office files a notice with the commission stating that the federal department of energy has extended or otherwise altered the deadline regarding funding for a hydrogen hub project. The application may only address elements of a hydrogen hub project that are not located in the Denver metropolitan area. (b) The application process described in subsection (4)(a) of this section must be consistent with the requirements of subsection (3) of this section. An investor-owned utility seeking approval of a clean hydrogen project pursuant to subsection (4)(a) of this section shall also demonstrate that a time-sensitive review of the investor-owned utility's application is necessary based on the timing requirements for obtaining necessary funding, not including tax credits, from, or a partnership with, a federal or state agency for the acquisition of necessary facilities and that the funding or partnership cannot be accomplished through any pending or future electric resource planning process. (c) If the funding or partnership described in subsection (4)(b) of this section, including any associated contracts, awards, or timing requirements, allows for competitive solicitations as part of the development of the clean hydrogen project, the commission may direct the investor-owned utility to issue a solicitation to acquire the necessary projects or facilities for the clean hydrogen project. The commission shall review any approved competitive solicitation process and bids received prior to the investor-owned utility's acquisition of the necessary facilities for the clean hydrogen project. An investor-owned utility that filed the clean hydrogen project application pursuant to subsection (4)(a) of this section may submit a bid in response to a solicitation pursuant to this subsection (4)(c). (5) (a) In reviewing, approving, denying, or amending an application pursuant to this section, the commission shall consider, at a minimum: (I) Whether it is in the public interest for an investor-owned utility to invest in the elements of the clean hydrogen project as set forth in the application; (II) The potential contribution of the clean hydrogen project in meeting the greenhouse gas emission reduction goals described in section 25-7-102 (2)(g), including lifecycle greenhouse gas emissions rates; (III) The impacts of the clean hydrogen project compared to alternative projects, including: (A) Rate and bill impacts; (B) The impacts on rate stability; and (C) Any other impacts identified by the commission pursuant to this subsection (5)(a); (IV) The use of competitive solicitations, if any; (V) If the clean hydrogen project contemplates the sale of clean hydrogen, the potential for cross-subsidization and cost shifting across rate classes; (VI) The impacts of the clean hydrogen project on the utility workforce in the state, including the use of "best value" employment metrics pursuant to section 40-2-129; (VII) The impacts of the clean hydrogen project on a community's tax base and revenues; (VIII) The uses of the clean hydrogen produced by the clean hydrogen project, with a preference for qualified uses; (IX) The public health and safety impacts of the clean hydrogen project; and (X) The availability of federal funding for the clean hydrogen project. (b) The commission shall review any clean hydrogen project application submitted pursuant to this section in accordance with any applicable electric resource planning rules. duced by the clean hydrogen project, with a preference for qualified uses; (IX) The public health and safety impacts of the clean hydrogen project; and (X) The availability of federal funding for the clean hydrogen project. (b) The commission shall review any clean hydrogen project application submitted pursuant to this section in accordance with any applicable electric resource planning rules. (c) In reviewing, approving, denying, or amending an application pursuant to this section, if the clean hydrogen project is proposed to be sited in an area that would affect a disproportionately impacted community, the commission shall weigh the applicant's cumulative impacts analysis and determine whether, on balance, the clean hydrogen project will have a positive effect on the disproportionately impacted community. Any proposal that will have net negative cumulative impacts on any disproportionately impacted community must be denied. The commission's determination must include a plain language summary of its determination. (6) Notwithstanding any provision of this section to the contrary, an investor-owned utility shall provide notice to the commission of any application for federal funding as part of a hydrogen hub project, including: (a) Any hydrogen hub project milestones; (b) A description of any deadlines for submission of materials to support the application, including whether any additional filings will be required; and (c) To the extent known or consistent with any requirements or limitations of the federal department of energy or any related joint memorandums of understanding or other contracts entered into by the investor-owned utility and the state, information regarding when funding awards will be determined. (7) (a) An investor-owned utility that operates a clean hydrogen project approved pursuant to this section shall submit to the commission an annual report that shows: (I) The lifecycle greenhouse gas emissions rates from the clean hydrogen project; (II) The greenhouse gas emissions from the clean hydrogen project; (III) Any emission of other air pollutants from the clean hydrogen project; (IV) The water use of the clean hydrogen project; (V) Production volumes and sales of hydrogen, including types of customers and uses; (VI) Project development and cost updates for projects with cost recovery from ratepayers; and (VII) Net cumulative impact updates for projects located in disproportionately impacted communities. (b) If the clean hydrogen project includes the production and the use or consumption of clean hydrogen by the investor-owned utility, the investor-owned utility shall report the lifecycle greenhouse gas emissions rates of the clean hydrogen project separately by each production facility and use. (c) The annual report must include information that allows the office to make the verifications required pursuant to section 39-22-557 (4)(a)(II).

C.R.S. § 40-2-139 Investor-owned utility electric resource planning - maximum discount rate authorized

40-2-139. Investor-owned utility electric resource planning - maximum discount rate authorized. If the commission relies on the use of a discount rate when calculating net present value of future carbon-based fuel costs in an electric resource plan, the discount rate must not exceed the long-term rate of inflation, as determined by the commission. In determining the long-term rate of inflation, the commission shall determine an appropriate rate of inflation specifically for fuel costs.

C.R.S. § 40-2-201 Legislative declaration

40-2-201. Legislative declaration. (1) The general assembly finds, determines, and declares that: (a) Energy storage systems provide potential opportunities to: (I) Reduce system costs; (II) Support diversification of energy resources; and (III) Enhance grid safety and reliability; (b) For these reasons, it is in the public interest to explore the use of energy storage systems in Colorado and to integrate into the planning process mechanisms for the procurement of energy storage systems by Colorado's electric utilities through evaluation and procurement methodologies.

C.R.S. § 40-2-202 Definitions

40-2-202. Definitions. As used in this part 2, unless the context otherwise requires: (1) "Electric utility" means an investor-owned electric utility subject to regulation under articles 1 to 7 of this title 40. (2) "Energy storage system" means commercially available technology that is capable of retaining energy, storing the energy for a period of time, and delivering the energy after storage by chemical, thermal, mechanical, or other means. (3) "Procure" or "procurement" means to acquire by ownership or by a contractual right to use the energy from, or the capacity of, an energy storage system.

C.R.S. § 40-2-203 Procurement mechanisms - determination by commission - rules

40-2-203. Procurement mechanisms - determination by commission - rules. (1) On or before February 1, 2019, the commission shall establish, by rule, as part of the planning process, mechanisms for the procurement of energy storage systems by an electric utility; except that these mechanisms must not affect any ongoing resource acquisitions or competitive bidding processes that existed on February 1, 2018. (2) In adopting the rules required by subsection (1) of this section, the commission shall use its best efforts to create conditions under which the procurement of energy storage systems by an electric utility will provide systemic benefits, including: (a) Increased integration of energy into the grid of the electric utility; (b) Improved reliability of the grid; (c) A reduction in the need for the increased generation of electricity during periods of peak demand; and (d) The avoidance, reduction, or deferral of investment by the electric utility. (3) Pursuant to subsection (1) of this section, and in consideration of all known and measurable benefits and costs to an electric utility, the commission shall adopt rules: (a) Establishing mechanisms for the inclusion of benefits and costs associated with energy storage systems into the planning conducted by electric utilities; (b) Requiring electric utilities to provide to the commission, and allowing electric utilities to provide to third parties as approved by the commission, appropriate data and analysis of potential storage acquisitions in their planning processes, including potential interconnection points. The commission shall treat information provided to the commission or to approved third parties under this subsection (3)(b) as confidential and ensure that the commission and any approved third party manages the information in accordance with all commission rules and federal and state laws concerning customer data and personally identifiable information. If the commission finds that a third party has failed to comply with any applicable rules, laws, or conditions of approval under this subsection (3)(b), the commission may deem that party ineligible to bid or develop storage systems in the subsequent electric resource plan. (c) Ensuring that any storage system project added to the electric grid will not compromise the security, safety, or reliability of the electric grid or any part of the electric grid; (d) Establishing that an energy storage system may be owned by an electric utility or by any other person; (e) (I) Establishing requirements for the filing by an electric utility of acquisition plans containing an analysis of the integration and use of electric storage systems. (II) The requirements under this subsection (3)(e) must include the requirement that an electric utility provide in its acquisition plans: (A) Modeling assumptions used to assess the costs and benefits of energy storage systems; and (B) Model contracts for procurement of energy storage systems. (f) Requiring the electric utility to include such other information as the commission may require in its documentation relating to planning. (4) On or before May 1, 2019, electric utilities may file applications for rate-based projects, not to exceed fifteen megawatts of capacity, for energy storage systems. Nothing in this section is intended to prohibit or deter cost-effective storage deployment.

Source: Open US Law by Vaquill AI (CC BY 4.0)URL: https://leg.colorado.gov/sites/default/files/images/olls/crs2024-title-40.docxFetched: 10/6/2026