General and Administrative

40-1-101. Public utilities law.

Articles 1 to 7 of this title shall be known and may be cited as the "Public Utilities Law" and shall apply to the public utilities and public services described in said articles 1 to 7 and to the commission referred to in article 2 of this title.

Source: L. 13: p. 464, § 1. C.L. § 2911. CSA: C. 137, § 1. CRS 53: § 115-1-1. C.R.S. 1963: § 115-1-1.

40-1-102. Definitions.

As used in articles 1 to 7 of this title 40, unless the context otherwise requires:

1. "Alternative fuel vehicle" means any automobile, truck, motor bus, boat, airplane, train, tractor, or other type of motorized off-highway equipment or other self-propelled device or vessel that is capable of moving itself or being moved from place to place utilizing, in whole or in part, liquefied petroleum gas, natural gas, electricity, or a combination of natural gas and electricity as transportation fuel, whether or not the vehicle is used in agricultural, commercial, domestic, or industrial operations.

   (1.1) "Behind-the-meter thermal renewable source" means a technology through which a utility customer accesses a renewable heating or cooling source to serve the customer's electric or heating needs for one or more end uses, including water heating, space heating or cooling, or industrial processes.

   1. (1.2) (a) "Beneficial electrification" means converting the energy source of a customer's end use from a nonelectric fuel source to a high-efficiency electric source, or avoiding the use of nonelectric fuel sources in new construction or industrial applications, if the result of the conversion or avoidance is to:
      1. Reduce net greenhouse gas emissions over the lifetime of the conversion or avoidance; and
      2. Reduce societal costs or provide for more efficient utilization of grid resources.
   2. "Beneficial electrification" does not include:
      1. Retail distributed generation, as defined in section 40-2-124 (1)(a)(VIII); or
      2. An energy storage system, as defined in section 40-2-130 (2)(a).

   (1.3) "Charge" includes any consideration, however denominated, paid or provided by a retail cooperative electric association to a wholesale electric cooperative in connection with an agreement by which the retail cooperative electric association terminates a wholesale electric service contract with the wholesale electric cooperative.

   (1.5) "Commission" means the public utilities commission of the state of Colorado.

2. "Commissioner" means one of the members of the commission.
3. 1. "Common carrier" means:

      (I) Every person directly or indirectly affording a means of transportation, or any service or facility in connection therewith, within this state by motor vehicle or other vehicle whatever by indiscriminately accepting and carrying passengers for compensation; and

      (II) Every person affording a means of transportation within this state by railroad by indiscriminately accepting and carrying for compensation passengers or property.

   2. "Common carrier" does not include a motor carrier that provides transportation not subject to regulation pursuant to section 40-10.1-105, a motor carrier that is subject to part 3, 4, 5, or 7 of article 10.1 of this title 40, a transportation network company, as defined in section 40-10.1-602 (3), or a transportation network company driver, as defined in section 40-10.1-602 (4).
4. "Compensation" means any money, property, service, or thing of value charged or received, or to be charged or received, whether directly or indirectly.
5. 1. "Cost-effective", with reference to a natural gas or electric demand-side management program, a beneficial electrification program, or any measure related to either a demand-side management or beneficial electrification program, means having a benefit-cost ratio greater than one.
   2. In calculating the benefit-cost ratio, the benefits must include, in a base case, the following, as applicable:
      1. The utility's avoided generation, transmission, distribution, capacity, and energy costs;
      2. The valuation of avoided greenhouse gas emissions, calculated as the social cost of carbon dioxide in accordance with sections 40-3.2-106 and 40-3.2-107 and the social cost of methane in accordance with section 40-3.2-107, as separate items in the cost-benefit calculation; and
      3. Other costs or benefits as determined by the commission.
   3. In calculating the benefit-cost ratio, the costs must include utility and participant expenditures for the following, as applicable:
      1. Program design, administration, evaluation, advertising, and promotion;
      2. Customer education;
      3. Incentives and discounts;
      4. Capital costs; and
      5. Operation and maintenance expenses.
   4. In addition to the base case analysis of cost-effectiveness described in subsection (5)(b) of this section, a utility may provide a case that does not include the social costs of methane and carbon dioxide.
6. "Demand-side management programs" or "DSM programs" means any of the following programs or combination of programs:
   1. Energy efficiency, including weatherization and insulation;
   2. Conservation;
   3. Load management;
   4. Beneficial electrification, as defined in subsection (1.2) of this section; and
   5. Demand response programs.
7. "Education program" means a program, including, but not limited to, an energy audit, that contributes indirectly to a cost-effective demand-side management program. Education programs shall not be subject to independent cost-effectiveness requirements.
8. "Full service customer" means a residential or commercial customer that purchases natural gas or electric supply from an investor-owned utility.

   (8.5) "Meter collar adapter" means a device that is installed between the electric meter and the meter socket box on a utility customer's premises and that has electrical connection points both electrically upstream and electrically downstream of the meter.

9. "Net present value of revenue requirements" means the current worth of the expected stream of future revenue requirements associated with a particular resource portfolio, expressed in dollars in the year the plan is filed. To determine the current worth of the expected stream of future revenue requirements, a discount rate at the utility's weighted average cost of capital shall be applied to the expected stream of future revenue requirements.
10. "Person" means any individual, firm, partnership, corporation, company, association, joint stock association, and other legal entity.
11. "Renewable energy" means useful electrical, thermal, or mechanical energy converted directly or indirectly from resources of continuous energy flow or that are perpetually replenished and whose utilization is sustainable indefinitely. The term includes, without limitation, sunlight, the wind, geothermal energy, hydrodynamic forces, and organic matter available on a renewable basis such as forest residues, agricultural crops and wastes, wood and wood wastes, animal wastes, livestock operation residue, aquatic plants, and municipal wastes.
12. "Technical support document" means the 2016 technical support document of the federal interagency working group on social cost of greenhouse gases, entitled "Technical Update of the Social Cost of Carbon for Regulatory Impact Analysis Under Executive Order 12866".

Source: L. 13: p. 464, § 2. L. 15: p. 393, § 1. C.L. § 2912. CSA: C. 137, § 2. CRS 53: § 115-1-2. C.R.S. 1963: § 115-1-2. L. 69: p. 927, § 1. L. 79: (3) amended, p. 1561, § 28, effective June 20. L. 80: (3) amended, p. 742, § 1, effective June 30. L. 84: (3) amended, p. 1051, § 2, effective April 12. L. 85: (3) amended, p. 1307, § 2, effective May 29. L. 94: (6) added, p. 611, § 2, effective April 8. L. 95: (3) amended, p. 1209, § 21, effective May 31. L. 96: (3) amended, p. 143, § 1, effective April 8. L. 2004: (3)(b) amended, p. 905, § 31, effective May 21. L. 2007: (5) and (6) amended and (7) to (11) added, p. 982, § 1, effective May 22. L. 2011: (3)(a)(I) and (3)(b) amended, (HB 11-1198), ch. 127, p. 418, § 11, effective August 10. L. 2012: (1) amended and (1.5) added, (HB 12-1258), ch. 147, p. 529, § 1, effective August 8. L. 2014: (3)(b) amended, (SB 14-125), ch. 323, p. 1408, § 1, effective June 5. L. 2018: IP and (3)(b) amended, (HB 18-1320), ch. 363, p. 2164, § 1, effective August 8. L. 2020: (1.3) added, (HB 20-1225), ch. 94, p. 372, § 2, effective March 27. L. 2021: (8.5) added, (SB 21-261), ch. 280, p. 1617, § 2, effective June 21; (1.1) added and (5) and (6) amended, (HB 21-1238), ch. 330, p. 2131, § 2, effective September 7; (1.2) and (12) added and (5)(a) amended, (SB 21-246), ch. 283, p. 1676, § 3, effective September 7.

40-1-103. Public utility defined.

1. 1. 1. The term "public utility", when used in articles 1 to 7 of this title, includes every common carrier, pipeline corporation, gas corporation, electrical corporation, telephone corporation, water corporation, person, or municipality operating for the purpose of supplying the public for domestic, mechanical, or public uses and every corporation, or person declared by law to be affected with a public interest, and each of the preceding is hereby declared to be a public utility and to be subject to the jurisdiction, control, and regulation of the commission and to the provisions of articles 1 to 7 of this title. (1) (a) (I) The term "public utility", when used in articles 1 to 7 of this title, includes every common carrier, pipeline corporation, gas corporation, electrical corporation, telephone corporation, water corporation, person, or municipality operating for the purpose of supplying the public for domestic, mechanical, or public uses and every corporation, or person declared by law to be affected with a public interest, and each of the preceding is hereby declared to be a public utility and to be subject to the jurisdiction, control, and regulation of the commission and to the provisions of articles 1 to 7 of this title.
      2. As used in this paragraph (a), "water corporation" includes a combined water and sewer corporation, whether as a single entity or as different entities under common ownership.
   2. Nothing in articles 1 to 7 of this title 40 apply to:
      1. Irrigation systems, the chief or principal business of which is to supply water for the purpose of irrigation;
      2. Exemptions provided for in the constitution of the state of Colorado relating to municipal utilities;
      3. Hotels, motels, or other lodging-type entities that resell intrastate toll services to their lodging patrons and not to the general public;
      4. Any consumer who owns pay telephone terminal equipment and who resells local exchange and toll service paid for by coin deposit, credit card, or otherwise by using the tariff services and facilities of regulated telephone utilities;
      5. The provision or resale to the general public of communications services over a cellular radio system. For purposes of this subparagraph (V), a "cellular radio" means a mobile communications system in which the radio frequency spectrum is divided into discrete channels which are assigned in groups to geographic cells within a service area and which are capable of being reused in different cells within that service area.
      6. Repealed.
2. 1. Every cooperative electric association, or nonprofit electric corporation or association, and every other supplier of electric energy, whether supplying electric energy for the use of the public or for the use of its own members, is hereby declared to be affected with a public interest and to be a public utility and to be subject to the jurisdiction, control, and regulation of the commission and to the provisions of articles 1 to 7 of this title.
   2. 1. Paragraph (a) of this subsection (2) requiring regulation by the commission shall not be applicable to a cooperative electric association which has voted to exempt itself from regulation pursuant to the provisions of section 40-9.5-103. Regulation of such cooperative electric associations shall be in the manner provided in part 1 of article 9.5 of this title.
      2. Repealed.
   3. The supply of electricity or heat to a consumer of the electricity or heat from renewable energy generation facilities owned or operated by an entity other than the consumer, including a master meter operator, as described in section 40-1-103.5, does not subject the owner or operator of the renewable energy generation facilities to regulation as a public utility by the commission if the renewable energy generation facilities are located on property owned or leased by either:
      1. The consumer; or
      2. A master meter operator or another consumer served by the master meter operator.
3. For the purposes of articles 1 to 7 of this title 40, a motor carrier that provides transportation not subject to regulation pursuant to section 40-10.1-105 or that is subject to part 3, 4, 5, or 7 of article 10.1 of this title 40 is not a public utility.
4. Repealed.

Source: L. 13: p. 465, § 3. C.L. § 2913. CSA: C. 137, § 3. CRS 53: § 115-1-3. L. 61: p. 627, § 1. C.R.S. 1963: § 115-1-3. L. 80: (3) added, p. 742, § 2, effective June 30. L. 83: (1) amended, p. 1547, § 1, effective May 25; (2) amended, p. 1572, § 2, effective July 1. L. 84: (1) amended, p. 1032, § 1, effective April 2; (3) amended, p. 1051, § 3, effective April 12. L. 85: (2)(b)(I) amended and (2)(b)(II) repealed, pp. 1301, 1303, §§ 1, 6, effective April 5; (1)(b)(IV) and (1)(b)(V) added, pp. 1293, 1294, §§ 1, 1, effective April 30; (3) amended, p. 1308, § 3, effective May 29. L. 86: (2)(b)(I) amended, p. 1161, § 2, effective May 27. L. 90: (4) added, p. 1811, § 2, effective June 7. L. 91: (3) amended, p. 1758, § 1, effective March 12. L. 95: (3) amended, p. 1209, § 22, effective May 31. L. 98: (1)(b)(III) amended, p. 845, § 4, effective May 26. L. 2003: (1)(b)(VI) added, p. 2592, § 3, effective June 5. L. 2008: (1)(a) amended, p. 1792, § 4, effective July 1. L. 2009: (2)(c) added, (SB 09-051), ch. 157, p. 678, § 10, effective September 1. L. 2011: (3) amended, (HB 11-1198), ch. 127, p. 418, § 12, effective August 10. L. 2012: (4) repealed, (HB 12-1258), ch. 147, p. 529, § 2, effective August 8. L. 2018: (3) amended, (HB 18-1320), ch. 363, p. 2164, § 2, effective August 8. L. 2021: (2)(c) amended, (SB 21-261), ch. 280, p. 1618, § 3, effective June 21; IP(1)(b) amended and (1)(b)(VI) repealed, (HB 21-1201), ch. 389, p. 2598, § 2, effective June 30.

Editor's note: Section 7 of chapter 280 (SB 21-261), Session Laws of Colorado 2021, provides that the act changing this section applies to contracts for distributed generation and energy storage facilities executed on or after June 21, 2021.

Cross references: (1) For constitutional provisions relating to exemption of municipally owned utilities, see article XXV of the Colorado Constitution; for the regulation of rates and charges by municipal utilities, see article 3.5 of this title.

(2) For the legislative declaration in SB 21-261, see section 1 of chapter 280, Session Laws of Colorado 2021.

40-1-103.3. Alternative fuel vehicles - definition.

1. As used in this section, "property or premises", with respect to an electric, natural gas, or liquefied petroleum gas extension or connection of service, includes alternative fuel vehicle charging and fueling facilities in addition to buildings and other improvements.
2. For the purposes of articles 1 to 7 of this title 40, persons generating electricity for use in alternative fuel vehicle charging or fueling facilities as authorized by subsection (4) of this section, persons reselling electricity supplied by a public utility, or persons reselling compressed or liquefied natural gas, liquefied petroleum gas, or any component parts or by-products to governmental entities or to the public for use as fuel in alternative fuel vehicles or buying electricity stored in such vehicles for resale are not subject to regulation as a public utility. Electric public utilities may provide the services described in this subsection (2) as unregulated or regulated services. Natural gas public utilities may provide these services as unregulated services.
3. Owners or operators of property or premises containing an alternative fuel vehicle charging or fueling facility, or the owners or operators of the facility, shall purchase the electricity required for the facility from a public utility with the right to sell electricity to the property, premises, or facility except when the owners or operators of the property, premises, or facility generate electricity on the property or premises for use in alternative fuel vehicles as authorized by subsection (4) of this section.
4. The owner or operator of a facility that generates electricity for use in alternative fuel vehicle charging or fueling facilities is not subject to regulation as a public utility, if:
   1. The electricity is generated on the property or premises where the charging or fueling facilities are located; and
   2. The electricity is generated from a renewable resource that:
      1. Qualifies as "retail distributed generation" as defined in section 40-2-124 (1)(a)(VIII), if located on the system of an entity subject to the requirements of section 40-2-124. The electric power requirements for the property pursuant to section 40-2-124 (1) include the demand for existing or proposed alternative fuel vehicle charging or fueling facilities in addition to buildings and other improvements.
      2. Complies with section 40-9.5-118, if located on the system of a cooperative electric association; or
      3. Complies with section 40-2-124 (7), if located on the system of a municipally owned utility.
5. Sale of electricity or natural gas by a public utility to the owner or operator of an alternative fuel vehicle charging or fueling facility is a retail transaction.
6. An electric public utility may recover the costs of distribution system investments to accommodate alternative fuel vehicle charging, subject to evaluation and cost recovery provisions that are comparable to other regulated investments in the distribution grid; except that distribution system investments that are a component of a transportation electrification plan submitted in accordance with section 40-5-107 are subject to sections 40-3-116 and 40-5-107. The commission shall consider revenues from electric vehicles in the utility's service territory in evaluating the retail rate impact. The retail rate impact from the development of electric vehicle infrastructure must not exceed one-half of one percent of the total annual revenue requirements of the utility.

Source: L. 2012: Entire section added, (HB 12-1258), ch. 147, p. 530, § 3, effective August 8. L. 2014: (4)(b)(I) amended, (HB 14-1363), ch. 302, p. 1275, § 45, effective May 31. L. 2019: (2) and (6) amended, (SB 19-077), ch. 383, p. 3434, § 2, effective May 31.

Cross references: For the legislative declaration in SB 19-077, see section 1 of chapter 383, Session Laws of Colorado 2019.

40-1-103.5. Limited exemption of master meter operators - conditions - rules.

1. Upon its own motion or upon application by any person who purchases gas or electric service from a regulated public utility for the purpose of delivery of such service to end users whose aggregate usage is to be measured by a master meter or other composite measurement device, the commission may exempt such person from regulation of rates under the "Public Utilities Law", articles 1 to 7 of this title 40, as the commission deems appropriate, so long as all of the following conditions are met:
   1. Such person, referred to in this section as a "master meter operator" or "MMO", does not charge the end users, as part of its billing for utility service, for any costs in addition to the actual cost billed to the MMO by the serving utility, including without limitation costs of construction, maintenance, financing, administration, metering, or billing for the utility distribution system owned by the MMO; except that this subsection (1)(a) does not apply to refunds, rebates, rate reductions, net metering credits, or similar adjustments attributable to the use of electricity generated from retail distributed generation that is located on property owned or leased by the MMO or by a customer served by the MMO;
   2. If the MMO bills the end users separately for service, the sum of such billings does not exceed the amount billed to the MMO by the serving utility;
   3. If the MMO bills the end users separately for service, the MMO passes on to the end users any refunds, rebates, rate reductions, or similar adjustments it receives from the serving utility;
   4. Any other conditions deemed necessary by the commission.
2. In passing on refunds, rebates, rate reductions, or similar adjustments to end users, the MMO shall notify its current end users, either by first-class mail with a certificate of mailing or by inclusion in any monthly or more frequent regular written communication, of the adjustments and inform the end users that they may claim the adjustments within ninety days after receipt of the notice. The MMO may retain any portion of the adjustments that rightfully belongs to the MMO. Upon the expiration of the ninety-day claims period, the MMO shall identify any such adjustments that are unclaimed and, if the aggregate amount unclaimed exceeds one hundred dollars, the MMO shall contribute the unclaimed amount to the fund established by the legislative commission on low-income energy and water assistance pursuant to section 40-8.5-104.
3. 1. The commission shall adopt such rules as it deems necessary to implement this section.
   2. No later than December 31, 2022, the commission shall adopt new or amended rules that would enable landlords of multi-unit buildings and tenants in multi-unit buildings to share in the production from a net metered retail distributed generation installation. In adopting rules, the commission shall consider Colorado's greenhouse gas emission reduction goals and the need to electrify buildings, transportation, and other commercial and industrial sectors to meet those goals. The commission shall also consider rules that would encourage landlords to bear the attendant costs and to retain at least a portion of the resulting benefits in addition to any other incentives the commission finds appropriate.

Source: L. 93: Entire section added, p. 291, § 1, effective April 7. L. 2021: IP(1), (1)(a), and (3) amended, (SB 21-261), ch. 280, p. 1618, § 4, effective June 21; (2) amended, (HB 21-1105), ch. 488, p. 3507, § 16, effective September 7.

Editor's note: Section 7 of chapter 280 (SB 21-261), Session Laws of Colorado 2021, provides that the act changing this section applies to contracts for distributed generation and energy storage facilities executed on or after June 21, 2021.

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

40-1-104. Securities - issuance.

1. 1. The term "securities", when used in articles 1 to 7 of this title, includes stocks, bonds, notes, and other evidences of indebtedness.
   2. The requirements of this section apply only to public utilities providing electricity or gas service.
2. The power of every gas corporation and of every electrical corporation operating as a public utility as defined in section 40-1-103 that derives more than five percent of its consolidated gross revenues in the state of Colorado as a public utility, or derives a lesser percentage if said revenues are realized by supplying an amount of energy which equals five percent or more of this state's consumption, to issue or assume securities and to create liens on its property situated within this state is a special privilege, hereby subjected to the supervision and control of the commission. Such public utility, when authorized by order of the commission and not otherwise, may issue or assume securities with a maturity date of more than twelve months after the date of issuance for the following purposes: The acquisition of property; the construction, completion, extension, or improvement of its facilities; the improvement or maintenance of its service; the discharge or lawful refunding of its obligations; the reimbursement of moneys actually expended for said purposes from income or from any other moneys in the treasury not secured by or obtained from the issue of securities within five years next prior to the filing of an application with the commission for the required authorization; or any of such purposes or any other lawful purpose authorized by the commission.
3. Such public utility, by written petition filed with the commission setting forth the pertinent facts involved, shall make application to the commission for an order authorizing the proposed issue or assumption of securities and the application of the proceeds therefrom to the purpose specified. The commission, with or without a hearing and upon such notice as the commission may prescribe, shall enter its written order approving the petition and authorizing the proposed securities transactions unless the commission finds that such transactions are inconsistent with the public interest or that the purpose thereof is not permitted or is inconsistent with the provisions of this section.
4. Such public utility may issue or renew, extend, or assume liability on securities, other than stocks, with a maturity date of not more than twelve months after the date of issuance and secured or unsecured, without application to or order of the commission; but no such securities so issued shall in whole or in part be refunded by any issue of securities having a maturity of more than twelve months except on application to and approval of the commission.
5. All applications for the issuance or assumption of securities shall be placed at the head of the commission's docket and shall be disposed of promptly, within thirty days after the petition is filed with the commission unless it is necessary for good cause to continue the same for a longer period. Whenever such application is continued beyond thirty days after the time it is filed, the commission shall enter an order making such continuance and stating fully the facts necessitating the continuance.
6. No provision of this section nor any act or deed performed in connection therewith shall be construed to obligate the state of Colorado to pay or guarantee in any manner whatsoever any security authorized, issued, or assumed under the provisions of this section.
7. All securities issued or assumed without application to and approval of the commission, except the securities mentioned in subsection (4) of this section, shall be void.
8. The commission shall provide for a serial number or other device to be placed on the face of any such securities for the proper and easy identification thereof.
9. Notwithstanding any provision of law to the contrary, the commission may approve a petition from a public utility proposing an investment in any of the following if the commission determines that such investment is not otherwise inconsistent with the public interest or that such investment is not otherwise inconsistent with this section:
   1. Any public-private initiative with the department of transportation, as defined in section 43-1-1201 (3), C.R.S.;
   2. Bonds issued for turnpikes in accordance with part 2 of article 3 of title 43, C.R.S.; or
   3. Repealed.
   4. Any other public-private initiative program for transportation system projects in Colorado authorized by law.

Source: L. 13: p. 465, § 3. C.L. § 2913. CSA: C. 137, § 3. L. 47: p. 701, § 1. CRS 53: § 115-1-4. C.R.S. 1963: § 115-1-4. L. 81: (2) amended, p. 1905, § 1, effective March 27; (3) amended, p. 1922, § 1, effective July 1. L. 98: (9) added, p. 446, § 7, effective August 5. L. 2000: (2), (3), (5), (6), and (7) amended, p. 131, § 1, effective August 2. L. 2005: (9)(c) repealed, p. 289, § 40, effective August 8. L. 2016: (1) amended, (HB 16-1035), ch. 129, p. 369, § 1, effective April 21.

Cross references: For the legislative declaration contained in the 1998 act amending this section, see section 1 of chapter 154, Session Laws of Colorado 1998.

40-1.1-101. Legislative declaration.

In order to promote improved transportation for the elderly, for persons with disabilities, and for the residents of rural areas and small towns through an expanded and coordinated transportation network, the general assembly hereby declares it to be the policy of the state to legally define and to recognize people service transportation and volunteer transportation as separate but contributing components of the transportation system. Therefore, it is the policy of the state to remove barriers to low-cost people service transportation and volunteer transportation. For this purpose, transportation systems meeting the criteria prescribed in this article will not be classified as public utilities or as any form of carrier subject to regulation by the commission but as people service transportation and volunteer transportation subject to appropriate regulation and administration.

Source: L. 81: Entire article added, p. 1907, § 1, effective July 1. L. 93: Entire section amended, p. 1671, § 89, effective July 1.

40-1.1-102. Definitions.

As used in this article, unless the context otherwise requires:

1. "Charitable organization" means any charitable unit primarily supported by private donation and not for profit, including but not limited to churches, civic groups, clubs, scout troops, or the American red cross.
2. "Nonprofit" as applied to people service transportation or volunteer transportation means motor vehicle transportation provided for purposes other than for pecuniary gain, whether or not compensation is paid in connection with such transportation.
3. "People service agency" means any people service unit primarily supported by public funds and not for profit, such as clinics, day care centers, job programs, congregate meal centers, senior citizen programs, and other government funded bodies.
4. "People service organization" means a people service agency or a charitable organization.
5. "People service transportation" means motor vehicle transportation provided on a nonprofit basis by a people service organization generally for the purpose of transporting clients or program beneficiaries in connection with people service programs sponsored by the organization, or by another people service organization. The motor vehicle may be owned, leased, borrowed, or contracted for use by the people service organization.
6. "Volunteer transportation" means motor vehicle transportation provided on a nonprofit basis by an individual, company, firm, partnership, agency, or corporation under the direction, sponsorship, or supervision of a people service organization. The volunteers may receive an allowance to defray the expected cost of operating the vehicle but may not receive compensation for their time.

Source: L. 81: Entire article added, p. 1907, § 1, effective July 1.

40-1.1-103. Classification of transportation.

People service transportation and volunteer transportation, as defined in section 40-1.1-102, shall be classified as such for purposes of regulation, insurance, and general administration.

Source: L. 81: Entire article added, p. 1908, § 1, effective July 1.

40-1.1-104. Inapplicable laws and regulations.

1. People service transportation and volunteer transportation shall not be considered transportation for compensation, commercial transportation, or any form of carrier. Thus, the following laws and regulations do not apply to motor vehicles while being used for the purpose of people service transportation or volunteer transportation:
   1. Articles 1 and 2 to 9 of this title, concerning public utilities and common carriers;
   2. Article 10.1 of this title, concerning motor carriers; and
   4. (Deleted by amendment, L. 2011, (HB 11-1198), ch. 127, p. 419, § 13, effective August 10, 2011.)
   5. Articles 20 to 33 of this title, concerning railroads.

Source: L. 81: Entire article added, p. 1908, § 1, effective July 1. L. 2011: IP(1), (1)(b), (1)(c), and (1)(d) amended, (HB 11-1198), ch. 127, p. 419, § 13, effective August 10.

40-1.1-105. Insurance for volunteers.

People service agencies of the state or any political subdivision thereof are authorized to purchase insurance to cover volunteers when they provide volunteer transportation.

Source: L. 81: Entire article added, p. 1908, § 1, effective July 1.

40-1.1-106. Safety and insurance regulation.

1. The provisions of parts 2, 3, and 5 of article 4 of title 42, C.R.S., shall be applicable to motor vehicles used in people service transportation or volunteer transportation.
2. Before a motor vehicle designed to transport more than sixteen passengers and used in people service transportation or volunteer transportation is operated or permitted to operate on any public highway of this state, the owner of such vehicle shall file with the department of revenue a certificate, in a form as approved by said department, evidencing a motor vehicle liability insurance policy issued by an insurance carrier or insurer authorized to do business in the state of Colorado or a surety bond issued by a company authorized to do a surety business in the state of Colorado with a minimum sum of fifty thousand dollars for damages to property of others, a minimum sum of one hundred thousand dollars for damages for or on account of bodily injury or death of one person as a result of any one accident, and, subject to such limit as to one person, a minimum sum of three hundred thousand dollars for or on account of bodily injury to or death of all persons as a result of any one accident.
3. Any state agency which provides public funds to a people service agency may establish insurance and safety requirements which are in addition to and consistent with any other applicable insurance and safety requirements and which shall apply to people service transportation or volunteer transportation which it funds.

Source: L. 81: Entire article added, p. 1908, § 1, effective July 1. L. 94: (1) amended, p. 2570, § 92, effective January 1, 1995.

40-2-101. Creation - appointment - term - subject to termination - repeal of part.

1. A public utilities commission is hereby created, which shall be known as the public utilities commission of the state of Colorado, to consist of three members who shall be 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. 1. 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.
   2. 1. This part 1 is repealed, effective September 1, 2026.
      2. Before the repeal, the public utilities commission is scheduled for review in accordance with section 24-34-104.

Source: L. 13: p. 465, § 4. C.L. § 2915. CSA: C. 137, § 5. CRS 53: § 115-2-1. C.R.S. 1963: § 115-2-1. L. 69: p. 928, § 2. L. 76: (3) added, p. 627, § 40, effective July 1. L. 87: (1) amended, p. 914, § 31, effective June 15. L. 91: (3) amended, p. 691, § 71, effective April 20. L. 93: (1) and (3)(b) amended, p. 2057, § 4, effective July 1. L. 98: (3)(b) amended, p. 404, § 1, effective July 1. L. 2003: (3)(b) amended, p. 731, § 3, effective March 20; (2) amended, p. 1698, § 1, effective May 14. L. 2008: (3)(b)(I) amended, p. 1791, § 1, effective July 1. L. 2018: (3)(b)(I) amended, (HB 18-1270), ch. 360, p. 2153, § 3, effective August 8. L. 2019: (3)(b) amended, (SB 19-236), ch. 359, p. 3290, § 1, effective May 30.

Cross references: (1) For salaries of commissioners, see § 24-9-102; for the powers and duties of the public utilities commission in regard to motor vehicle carriers, see article 10.1 of this title.

(2) For the short title ("Energy Storage Procurement Act") in HB 18-1270, see section 1 of chapter 360, Session Laws of Colorado 2018.

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.

Source: L. 13: p. 466, § 5. C.L. § 2916. CSA: C. 137, § 6. CRS 53: § 115-2-2. C.R.S. 1963: § 115-2-2. L. 69: p. 928, § 3.

Cross references: For the oath of office, see § 8 of article XII of the Colorado Constitution.

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 an agency transferred by a type 1 transfer, as defined in section 24-1-105, C.R.S., 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.

Source: L. 13: p. 466, § 6. C.L. § 2917. CSA: C. 137, § 7. CRS 53: § 115-2-3. C.R.S. 1963: § 115-2-3. L. 69: p. 928, § 4. L. 89: Entire section amended, p. 1524, § 2, effective April 12. L. 93: Entire section amended, p. 2057, § 5, effective July 1. L. 2013: Entire section amended, (HB 13-1027), ch. 83, p. 267, § 1, effective August 7. L. 2017: (2) repealed, (SB 17-044), ch. 4, p. 7, § 5, effective August 9.

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. 1. 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.
   2. 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.

Source: L. 13: p. 466, § 7. C.L. § 2918. CSA: C. 137, § 8. CRS 53: § 115-2-4. C.R.S. 1963: § 115-2-4. L. 69: p. 928, § 5. L. 89: (1) and (3) amended, p. 1524, § 3, effective April 12. L. 93: Entire section amended, p. 2058, § 6, effective July 1. L. 2021: (4) added, (SB 21-272), ch. 220, p. 1156, § 1, effective June 10.

Editor's note: Section 14 of chapter 220 (SB 21-272), Session Laws of Colorado 2021, provides that the act changing this section applies to conduct occurring on or after June 10, 2021.

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:
   1. Any corporate affiliation with the regulated utility;
   2. The receipt of any funding from the regulated utility; or
   3. 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.

Source: L. 2021: Entire section added, (SB 21-272), ch. 220, p. 1156, § 2, effective June 10.

Editor's note: Section 14 of chapter 220 (SB 21-272), Session Laws of Colorado 2021, provides that the act adding this section applies to conduct occurring on or after June 10, 2021.

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.

Source: L. 13: p. 467, § 8. C.L. § 2919. CSA: C. 137, § 9. CRS 53: § 115-2-5. C.R.S. 1963: § 115-2-5. L. 69: p. 929, § 6. L. 75: (1) amended, p. 821, § 18, effective July 18. L. 89: (1) amended, p. 1525, § 4, effective April 12.

Cross references: For legal holidays, see article 11 of title 24; for payment of expenses, see § 40-2-107.

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.

Source: L. 13: p. 467, § 9. C.L. § 2920. CSA: C. 137, § 10. L. 45: p. 525, § 1. CRS 53: § 115-2-6. C.R.S. 1963: § 115-2-6. L. 69: p. 929, § 7.

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.

Source: L. 13: p. 468, § 10. C.L. § 2921. CSA: C. 137, § 11. CRS 53: § 115-2-7. C.R.S. 1963: § 115-2-7. L. 69: p. 930, § 8. L. 89: (3) amended, p. 1525, § 5, effective April 12. L. 93: (2) repealed, p. 2058, § 7, effective July 1.

Cross references: For appropriations, see part 1 of article 75 of title 24.

40-2-108. Rules - definitions - 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. 1. The general assembly finds, determines, and declares that:
      1. 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
      2. 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.
   2. 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.
   3. 1. 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.
      2. 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.
   4. As used in this subsection (3):
      1. "Cost-burdened" means a household that spends more than thirty percent of its income on housing.
      2. "Disproportionately impacted community" means a community that is in a census block group, as determined in accordance with the most recent United States census, where the proportion of households that are low income is greater than forty percent, the proportion of households that identify as minority is greater than forty percent, or the proportion of households that are housing cost-burdened is greater than forty percent; or is any other community as identified or approved by a state agency, if:
         1. The community has a history of environmental racism perpetuated through redlining, anti-Indigenous, anti-immigrant, anti-Hispanic, or anti-Black laws; or
         2. The community is one where multiple factors, including socioeconomic stressors, disproportionate environmental burdens, vulnerability to environmental degradation, and lack of public participation, may act cumulatively to affect health and the environment and contribute to persistent disparities.
      3. "Low income" means meeting one or more of the following criteria:
         1. Median household income less than or equal to two hundred percent of the federal poverty guideline;
         2. Median household income less than or equal to eighty percent of the area median income; or
         3. Qualification under income guidelines adopted by the department of human services pursuant to section 40-8.5-105.

Source: L. 13: p. 468, § 12. C.L. § 2923. CSA: C. 137, § 13. CRS 53: § 115-2-9. C.R.S. 1963: § 115-2-9. L. 64: p. 166, § 124. L. 69: p. 930, § 9. L. 89: Entire section amended, p. 1525, § 6, effective April 12. L. 93: Entire section amended, p. 2058, § 8, effective July 1. L. 95: Entire section amended, p. 232, § 1, effective April 17. L. 2021: (3) added, (SB 21-272), ch. 220, p. 1157, § 3, effective June 10.

Editor's note: Section 14 of chapter 220 (SB 21-272), Session Laws of Colorado 2021, provides that the act changing this section applies to conduct occurring on or after June 10, 2021.

40-2-109. Report to executive director of the department of revenue.

1. Repealed.
2. 1. 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:
      1. 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
      2. Rail fixed guideway systems that are regulated by the public utilities commission pursuant to part 1 of article 18 of this title.
   2. 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.

Source: L. 55: p. 695, § 1. CRS 53: § 115-2-10. C.R.S. 1963: § 115-2-10. L. 89: Entire section amended, p. 1597, § 14, effective January 1, 1990. L. 94: Entire section amended, p. 2570, § 93, effective January 1, 1995. L. 2005: Entire section amended, p. 1184, § 37, effective August 8. L. 2011: Entire section amended, (HB 11-1198), ch. 127, p. 419, § 14, effective August 10. L. 2013: Entire section amended, (HB 13-1103), ch. 96, p. 309, § 1, effective August 7. L. 2018: (2)(a)(I) amended, (HB 18-1375), ch. 274, p. 1723, § 85, effective May 29.

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.

Source: L. 2007: Entire section added, p. 1761, § 7, effective June 1. L. 2010: (3) added, (HB 10-1001), ch. 37, p. 154, § 7, effective August 11.

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. 1. 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 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. (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.
      2. Repealed.
   2. Repealed.

Source: L. 55: p. 695, § 1. CRS 53: § 115-2-11. L. 57: p. 599, § 1. C.R.S. 1963: § 115-2-11. L. 69: p. 930, § 10. L. 82: (2) amended, p. 584, § 1, effective July 1. L. 85: (2)(a)(II) and (2)(b)(II) amended, p. 1295, § 1, effective July 1. L. 88: (2)(a)(I) amended and (2)(a)(II) and (2)(b) repealed, pp. 1351, 1352, §§ 1, 3, effective July 1.

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. 1. (Deleted by amendment, L. 2003, p. 2380 , § 2, effective August 6, 2003.)
   5. (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.
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.

Source: L. 82: Entire section added, p. 585, § 2, effective July 1. L. 83: (1) and (2) amended and (2.5) added, p. 1548, § 1, effective June 1; (2.5) amended, p. 2056, § 38, effective October 14. L. 84: (2) amended, p. 1034, § 1, effective April 2; (1) and (2) amended, p. 1051, § 4, effective April 12. L. 85: (1) amended, p. 1308, § 4, effective May 29; (7) amended, p. 1295, § 2, effective July 1. L. 88: (3) and (6) amended and (7) repealed, pp. 1351, 1352, §§ 2, 3, effective July 1; (3) repealed, p. 1351, § 2, effective July 1, 1989. L. 93: (2) and (4) amended, p. 2059, § 9, effective July 1. L. 95: (1) amended, p. 1211, § 27, effective May 31. L. 98: (8) added, p. 1348, § 86, effective June 1. L. 2003: (6.5) added, p. 458, § 20, effective March 5; (1) and (2)(a) amended, p. 2380, § 2, effective August 6. L. 2005: (1) and (2.5) amended, p. 31, § 1, effective August 8. L. 2006: (6.5) repealed and (9) added, pp. 1102, 1094, §§ 24, 4, effective August 7. L. 2008: (1) amended, p. 1792, § 5, effective July 1. L. 2009: (1) and (4) amended, (SB 09-292), ch. 369, p. 1981, § 119, effective August 5. L. 2011: (1), (4), (5), and (8) amended, (HB 11-1198), ch. 127, p. 419, § 15, effective August 10. L. 2014: (9)(a) amended, (HB 14-1081), ch. 8, p. 90, § 1, effective February 27.

Editor's note: Amendments to subsection (2) by Senate Bill 84-85 and House Bill 84-1252 were harmonized.

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.

Source: L. 55: p. 166, § 1. CRS 53: § 115-2-12. C.R.S. 1963: § 115-2-12. L. 69: p. 964, § 75. L. 72: p. 565, § 39.

Cross references: For perjury in the second degree, see § 18-8-503.

40-2-112. Computation of fees.

1. 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 all public utilities filing returns as provided in section 40-2-111. The executive director shall then compute the percentage which the full amount determined by the general assembly for administrative expenses of the public utilities commission for the supervision and regulation of such public utilities 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 the percentage so computed shall be the basis upon which fees 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. 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.

Source: L. 55: p. 696, § 1. CRS 53: § 115-2-13. L. 57: p. 599, § 1. C.R.S. 1963: § 115-2-13. L. 93: Entire section amended, p. 2060, § 10, effective July 1.

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.

Source: L. 55: p. 696, § 1. CRS 53: § 115-2-14. C.R.S. 1963: § 115-2-14. L. 2015: Entire section amended, (HB 15-1372), ch. 247, p. 906, § 1, effective May 29. L. 2021: Entire section amended, (SB 21-272), ch. 220, p. 1158, § 4, effective June 10; entire section amended, (HB 21-1201), ch. 389, p. 2599, § 3, effective June 30.

40-2-114. Disposition of fees collected - telecommunications utility fund - fixed utility fund.

1. 1. 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:
      1. 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);
      2. 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
      3. Any remaining fees to the general fund.
   2. For the remaining ninety-seven percent of the fees collected, the state treasurer shall credit:
      1. Fees paid by public utilities that are telephone corporations to the telecommunications utility fund, which fund is hereby created; and
      2. Fees paid by other public utilities to the public utilities commission fixed utility fund, which fund is hereby created.
      3. 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 fixed utility fund any amounts it receives in excess of its actual administrative expenses plus a fifteen percent reserve margin.
2. 1. 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

   2. 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.

Source: L. 55: p. 697, § 1. CRS 53: § 115-2-15. L. 57: p. 600, § 1. C.R.S. 1963: § 115-2-15. L. 64: p. 654, § 10. L. 69: p. 930, § 11. L. 84: Entire section amended, p. 1047, § 4, effective July 1. L. 2015: Entire section amended, (HB 15-1372), ch. 247, p. 907, § 2, effective May 29. L. 2016: (1) amended, (HB 16-1186), ch. 212, p. 820, § 1, effective June 6; (1)(a) amended, (SB 16-087), ch. 217, p. 831, § 1, effective June 6. L. 2021: (2) amended, (SB 21-072), ch. 329, p. 2128, § 10, effective June 24; (2) amended, (SB 21-103), ch. 477, p. 3413, § 11, effective September 1.

40-2-115. Cooperation with other states and with the United States - rules - definitions.

1. 1. 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.
   2. 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.
   3. 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:
      1. Public utilities and municipal or quasi-municipal corporations transporting gas or providing gas service;
      2. Operators of natural gas master metered systems;
      3. Operators of liquid petroleum gas distribution systems;
      4. Operators of pipelines transporting gas in intrastate commerce; and
      5. Operators of intrastate liquefied natural gas facilities.
   4. 1. 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.
      2. The commission's gas pipeline safety rules must address, and may be more stringent than required by federal standards with regard to:
         1. Qualifications and verifiable credentials for personnel engaged in pipeline construction, inspection, and repair activities;
         2. Reduction of the risks posed by abandoned gas pipelines;
         3. 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 oil and gas conservation commission 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 oil and gas conservation commission in 2 CCR 404-1, rule 1101.e.
         4. Increased frequency of inspections of all pipelines within the commission's jurisdiction;
         5. Use of advanced leak detection technology to meet the need for pipeline safety and protection of the environment;
         6. Expansion of annual reporting requirements for pipeline operators; and
         7. Requirements for commission investigation of specific types of pipeline damage and pursuit of appropriate civil remedies for such damage.
   5. 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.
2. As used in this section:
   1. "Gas" means natural gas, flammable gas, and any gas that is toxic or corrosive.
   2. "Transportation of gas" or "transporting gas" means the gathering, transmission, or distribution of gas by pipeline, as defined in 49 CFR 192.3, or its storage.

Source: L. 55: p. 697, § 1. CRS 53: § 115-2-16. L. 57: p. 600, § 1. C.R.S. 1963: § 115-2-16. L. 69: p. 931, § 12. L. 71: p. 1098, § 1. L. 89: (1) amended, p. 1526, § 7, effective April 12. L. 93: Entire section amended, p. 2061, § 11, effective July 1. L. 2000: (1) and (1.5) amended, p. 1868, § 95, effective August 2. L. 2003: (1), (1.5), and (2)(a) amended, p. 1699, § 5, effective May 14. L. 2021: Entire section amended, (SB 21-108), ch. 465, p. 3353, § 2, effective July 6.

Cross references: For the legislative declaration in SB 21-108, see section 1 of chapter 465, Session Laws of Colorado 2021.

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

Source: L. 69: p. 931, § 13. C.R.S. 1963: § 115-2-17. L. 78: Entire section amended, p. 518, § 1, effective July 1. L. 85: Entire section amended, p. 1308, § 5, effective May 29. L. 96: Entire section amended, p. 1546, § 2, effective July 1. L. 2003: (1) amended, p. 2381, § 5, effective August 6. L. 2010: (1) amended, (HB 10-1167), ch. 125, p. 415, § 1, effective April 15. L. 2011: Entire section repealed, (HB 11-1198), ch. 127, p. 416, § 3, effective August 10.

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

Source: L. 77: Entire section added, p. 1856, § 1, effective July 1.

Editor's note: Subsection (7) provided for the repeal of this section, effective July 1, 1979. (See L. 77, p. 1856 .)

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

Source: L. 79: Entire section added, p. 1510, § 1, effective June 22.

Editor's note: Subsection (6) provided for the repeal of this section, effective March 1, 1984. (See L. 79, p. 1510 .)

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:
   1. Jurisdiction, regulation, and control by the commission are not necessary to carry out the transportation policy of this title; and
   2. 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.

Source: L. 84: Entire section added, p. 1036, § 1, effective July 1.

40-2-120. Rail transportation policy.

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

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

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

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

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

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

1. The general assembly finds, determines, and declares that natural gas service is essential to the health and well-being of all Colorado natural gas customers. The general assembly further finds, determines, and declares that natural gas is traded in competitive markets at the wellhead and in downstream markets for sale to utilities, industrial customers, and large commercial customers and there may be the potential for natural gas also to be traded competitively for sale to all other classes of consumers. As a result, it may be predicted that competition in the natural gas supply market may increase the choices available to consumers and reduce the price of such service. Accordingly, it is the policy of the state of Colorado to encourage competition after a reasonable transition period during which consumers are educated about choices in natural gas supply that are now available or will be available in the future. The commission is authorized to approve voluntary plans consistent with this section that separate the sale of natural gas to retail customers into natural gas delivery and natural gas supply and, after a transition period, deregulate the charge for natural gas supply where the commission finds that the plan provides customers with adequate choices, ensures the provision of reliable natural gas supply on a fallback basis on terms and conditions that are just and reasonable to all customers, promotes the development of a competitive market for gas supply, limits the unreasonable exercise of market power, and retains and enhances programs to support low-income consumers.
2. 1. 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.
   2. 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:
      1. 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.
      2. 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
      3. The public benefits charge shall be imposed on all natural gas delivered by the utility in a manner that is competitively neutral and nonbypassable.
   3. 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:
      1. The separation of natural gas service into natural gas supply service and natural gas delivery service; and
      2. 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.
   4. 1. 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.
      2. 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:
         1. Such contracts shall not be subject to public disclosure under section 24-72-203, C.R.S., until formally executed by the parties; and
         2. 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.
   5. 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. 1. 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:
      1. Provides for the separation of natural gas service into natural gas supply service and natural gas delivery service; and
      2. Allows for competition in natural gas supply service.
   2. 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.
   3. 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:
      1. 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;
      2. 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;
      3. Establishes safeguards to eliminate the unreasonable exercise of market power by any person to the detriment of consumers or competitors;
      4. 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.
      5. 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.
      6. 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;
      7. 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;
      8. 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.
      9. 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:
         1. The manner in which price and terms and conditions should be disclosed;
         2. The extent to which natural gas utilities and suppliers are obligated to serve all customers;
         3. Appropriate credit and collection practices;
         4. The terms under which service may be discontinued;
         5. How partial payments are allocated;
         6. Protecting customer privacy;
         7. Prohibiting unfair and deceptive marketing practices; and
         8. The degree of access to customer information needed by suppliers to promote competition;
      10. 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.
      11. 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.
      12. 1. 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.
          2. For purposes of this subparagraph (XII), the number of customers served by competitive natural gas suppliers shall be determined based on the number of natural gas meters served by competitive natural gas suppliers in the geographic area covered by the plan, other than those meters served under the natural gas utility's gas transportation tariffs at the time the plan is implemented, whether directly or through a marketer or broker, compared to the total number of natural gas meters in the geographic area covered by the plan.
4. If the commission approves a natural gas public utility's voluntary plan with modifications, the utility shall have the option to reject the modified plan and continue to be regulated as before. However, if a natural gas public utility exercises this option, it may not file another voluntary plan for a minimum of two years unless otherwise permitted by the commission and it may not recover in rates the costs and administrative charges incurred associated with the design and litigation of its voluntary plan proposal.
5. The department of revenue is hereby authorized to collect funding for the commission and the office of the utility consumer advocate in accordance with subsection (3)(c)(XI) of this section.
6. The commission shall establish, by rule or by alternative filing by natural gas public utilities or gas supply companies, such certification requirements, terms and conditions for gas supply service, reporting requirements, and compliance procedures for competitive suppliers, aggregators other than municipalities or counties operating as aggregators within their jurisdictional boundaries, or brokers as the commission deems necessary to provide Colorado retail consumers with reliable natural gas supply service. Such requirements may include, without limitation, complaint procedures for enforcement of the commission's rules and procedures for the suspension or revocation of certification and operating authority of competitive suppliers, aggregators other than municipalities or counties operating as aggregators within their jurisdictional boundaries, or brokers for violation of commission rules as well as the assessment of fines and penalties for violations of commission rules and standards of conduct, in addition to other commission rules and enforcement mechanisms. In the certification requirements the commission shall require natural gas suppliers to operate a customer service location in the state and provide customers with a toll-free telephone number to reach the natural gas supplier.
7. 1. 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.
   2. 1. 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.
      2. Transition costs may include, but are not limited to, the following:
         1. Costs and administrative charges incurred by a natural gas public utility resulting from the design and implementation of its voluntary plan;
         2. 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);
         3. Investments in assets that are stranded by competition for natural gas supply service;
         4. Interstate or intrastate third-party pipeline costs;
         5. Balancing costs;
         6. Underground storage costs;
         7. Deferred or prior-period gas costs not yet recovered at the time of conversion to competition in the provision of natural gas supply service;
         8. 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
         9. Any other costs that the commission determines to be recoverable transition costs.
      3. Transition costs shall not include:
         1. 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
         2. 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.
      4. 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.
   3. Except to the extent provided in plan provisions or rules adopted by the commission governing the relationship between the public utility and its affiliates, the commission shall not impose on a natural gas public utility or its affiliate, with respect to competitive natural gas supply services, any requirement that is not imposed upon competing, non-utility providers of natural gas supply services, unless the commission determines that the imposition of such requirement is necessary to protect the public interest.
8. The public benefits charge and its funding method shall continue in effect until at least December 31, 2005, and shall remain in effect thereafter until and unless replaced with a different legislatively adopted funding mechanism for statewide low-income energy assistance programs that assures the availability of adequate resources and that is consistent with the recommendations of the 1998 governor's energy assistance reform task force for the purpose of defraying the costs of low-income energy assistance. On or before December 1, 2004, the Colorado energy assistance foundation, which is the entity created under section 40-8.5-104, or its successor, in conjunction with any interested natural gas utility or natural gas supplier, shall recommend such a different funding mechanism for low-income energy assistance programs to the general assembly for adoption.
9. Repealed.
10. The general assembly determines that a new funding formula should be devised to adequately fund the commission's and office of the utility consumer advocate's administrative expenses. On or before December 1, 2000, the commission and the office shall recommend to the general assembly those legislative changes needed to develop appropriate funding mechanisms for the public utilities commission and the office. This provision is intended to provide a comprehensive replacement for the funding method contained in the utility plan under subsection (3)(c)(XI) of this section.
11. The commission is specifically authorized at its sole discretion to adopt all necessary rules in furtherance of this section, including, but not limited to, standards of conduct, unfair and deceptive marketing practices, and consumer protections.
12. Repealed.
13. In any area where competitive gas supply choices are afforded to customers, any municipality or county or combination thereof may serve as a competitive supplier or, without buying and selling gas, act as an aggregator of the loads of its residents and businesses and contract with a certified supplier for its gas supply needs and the gas supply needs of its residents or businesses or both such residents and businesses; except that nothing in this subsection (13) shall require either a resident or business to buy natural gas supply service from a municipality serving as a supplier or acting as an aggregator of the loads of its residents or businesses.
14. Each provider of natural gas supply service and natural gas delivery service shall collect and remit all applicable sales and use taxes. In a transaction involving the sale or furnishing of natural gas service, the transaction shall be deemed to occur where the natural gas is used or consumed.
15. The commission shall undertake an investigation into natural gas public utilities' supply acquisition practices. The investigation shall examine, among other items, how public utilities currently acquire supply and their ability to manage the risk of price spikes in natural gas markets. Based on the investigation's findings, the commission may provide recommendations as to how natural gas portfolios might be structured in the future so as to provide greater long-term natural gas price stability for consumers. Information from the investigation shall be made available to interested parties at the commission's office. Such portfolio shall include a comparison of costs of natural gas contracts to the cost of coal syngas contracts that may become available in the future.

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

40-2-123. Energy technologies - consideration by commission - incentives - demonstration projects - definitions - repeal.

1. 1. 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.
   2. 1. 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.
      2. 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.
   3. 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.
   4. 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. 1. The commission shall consider proposals by Colorado investor-owned utilities for the following types of projects:
      1. To construct, own, and operate electric generation or storage facilities utilizing innovative energy technology; or
      2. 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.
   2. 1. 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.
      2. 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:
         1. How the project will be developed;
         2. 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;
         3. How the project mitigates the impacts of the transition to cleaner generation technologies in affected areas of Colorado; and
         4. 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.
      3. 1. 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.
         2. 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.
         3. Any work included in a warranty.
   3. 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.
   4. 1. 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 council recognized by that office; except that this apprenticeship requirement does not apply to:
      2. 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.

      (A) The design, planning, or engineering of the transmission facilities;

      (B) Management functions to operate the transmission facilities; or

   5. As used in this subsection (2):
      1. "Innovative energy technology" means a generation technology or storage technology that, alone or in combination with other technologies used in a project:
         1. Generates or stores electricity without emitting greenhouse gas emissions into the atmosphere;
         2. 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.
         3. Does not include stand-alone wind, solar, or lithium-ion battery storage resources or wind or solar resources paired with lithium-ion battery storage.
      2. "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.
   6. This subsection (2) is repealed, effective December 31, 2024.
3. 1. 1. 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. (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.
      2. For purposes of this subsection (3), "utility-scale" means projects with nameplate ratings in excess of two megawatts.
   2. 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:
      1. Whether the proposed generation could provide energy storage to match the times during which utility generation is generally higher cost;
      2. Whether the proposed generation, due to modularity, scalability, and rapid deployment, could result in reduction of performance and financial risk for the utility;
      3. Whether utility-scale solar electric generation could reduce the consumption of water for electric generation;
      4. Whether future costs can be stabilized through mitigation of the impact of unpredictable fossil fuel prices; and
      5. 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:

   1. Geothermal energy;
   2. 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.
   3. Hydroelectricity and pumped hydroelectricity, taking into account the associated costs and benefits. For purposes of this paragraph (c):
      1. "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:
         1. 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
         2. 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.
      2. "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.

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

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:
   1. 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:
      1. "Biomass" means:
         1. Nontoxic plant matter consisting of agricultural crops or their by-products, urban wood waste, mill residue, slash, or brush;
         2. Animal wastes and products of animal wastes; or
         3. Methane produced at landfills or as a by-product of the treatment of wastewater residuals.
      2. "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.
      3. "Distributed renewable electric generation" or "distributed generation" means:
         1. Retail distributed generation; and
         2. Wholesale distributed generation.
      4. "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.

      5. "Pyrolysis" means the thermochemical decomposition of material at elevated temperatures without the participation of oxygen.
      6. 1. "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 in-stream flow; and does not cause any violation of state water quality standards when operated.
         2. 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.
      7. "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.

      8. 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.
      9. "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.
   2. 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.
   3. Electric resource standards:
      1. 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:
         1. Three percent of its retail electricity sales in Colorado for the year 2007;
         2. Five percent of its retail electricity sales in Colorado for the years 2008 through 2010;
         3. 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;
         4. 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
         5. 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.
      2. 1. 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.
         2. 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).
         3. 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.
         4. 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).

         (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.

      3. 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.
      4. 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.
      5. 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:
         1. One percent of its retail electricity sales in Colorado for the years 2008 through 2010;
         2. Three percent of retail electricity sales in Colorado for the years 2011 through 2014;
         3. Six percent of retail electricity sales in Colorado for the years 2015 through 2019; and
         4. 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.

      6. 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:
         1. 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;
         2. The generating capacity of which does not exceed thirty megawatts; and
         3. 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.
      7. 1. 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.
         2. 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.
         3. 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.
      8. 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).
      9. For purposes of stimulating rural economic development and for projects up to thirty megawatts of nameplate capacity that have a point of interconnection rated at sixty-nine kilovolts or less, each kilowatt hour of electricity generated from renewable energy resources that interconnects to electric transmission or distribution facilities owned by a cooperative electric association or municipally owned utility may be counted for the life of the project as two kilowatt hours for compliance with the requirements of this paragraph (c) by qualifying retail utilities. This multiplier shall not be claimed for interconnections that first occur after December 31, 2014, and shall not be used in conjunction with another compliance multiplier. For qualifying retail utilities other than investor-owned utilities, the benefits described in this subparagraph (IX) apply only to the aggregate first one hundred megawatts of nameplate capacity of projects statewide that report having achieved commercial operations to the commission pursuant to the procedure described in this subparagraph (IX). To the extent that a qualifying retail utility claims the benefit described in this subparagraph (IX), those kilowatt-hours of electricity do not qualify for satisfaction of the distributed generation requirement of subparagraph (I) of this paragraph (c). The commission shall analyze the implementation of this subparagraph (IX) and submit a report to the senate local government and energy committee and the house of representatives committee on transportation and energy, or their successor committees, by December 31, 2011, regarding implementation of this subparagraph (IX), including how many megawatts of electricity have been installed or are subject to a power purchase agreement pursuant to this subparagraph (IX) and whether the commission recommends that the multiplier established by this subparagraph (IX) should be changed either in magnitude or expiration date. Any entity that owns or develops a project that will take advantage of the benefits of this subparagraph (IX) shall notify the commission within thirty days after signing a power purchase agreement and within thirty days after beginning commercial operations of an applicable project.
      10. 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:
          1. 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
          2. This subparagraph (X) does not apply to a qualifying retail utility that is a municipal utility.
   4. 1. 1. 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. (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.
         2. 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.
         3. 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.
         4. 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.
      2. 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:
         1. Is effectuated in a manner that benefits Colorado's cities, counties, and businesses;
         2. 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
         3. Is consistent with timely attainment of the state's clean energy and climate goals.
   5. 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:
      1. 1. 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.
         2. 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.
         3. 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.
         4. 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.
         5. 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.

         (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.

      2. 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.
      3. 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.
      4. 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.
   6. 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:
      1. Repealed.
      2. 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.
      3. 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.
      4. 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:
         1. Rate adjustment clauses until the costs of the eligible energy resource can be included in the utility's base rates; and
         2. 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.
      5. 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.
      6. 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.
      7. 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.
   7. Retail rate impact rule:
      1. 1. 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.
         2. 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.
         3. 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.
         4. 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.
      2. 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.
      3. 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.
      4. 1. For cooperative electric associations, the maximum retail rate impact for this section is two percent of the total electric bill annually for each customer.
         2. 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.
   8. 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.
   9. 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.
   10. Rules to accommodate aggregation and interconnection of retail distributed generation, including:
       1. Allowing electricity generated from a single renewable retail distributed generation resource on a multi-unit 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;
       2. 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;
       3. 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;
       4. 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;
       5. 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.
       6. 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:
          1. The size of any off-site, single-meter installation does not exceed five hundred kilowatts;
          2. The size of any off-site, multi-meter installation does not exceed three hundred kilowatts per meter; and
          3. For any off-site facility exceeding three hundred kilowatts, the installation and any necessary repair or maintenance work is performed by a licensed master electrician, licensed journeyman electrician, or licensed residential wireman or by properly supervised apprentices, in addition to complying with all applicable interconnection rules.

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

2. (Deleted by amendment, L. 2007, p. 257 , § 1, effective March 27, 2007.)
3. Each municipally owned electric utility that is a qualifying retail utility shall implement a renewable energy standard substantially similar to this section. The municipally owned utility shall submit a statement to the commission that demonstrates such municipal utility has a substantially similar renewable energy standard. The statement submitted by the municipally owned utility is for informational purposes and is not subject to approval by the commission. Upon filing of the certification statement, the municipally owned utility shall have no further obligations under subsection (1) of this section. The renewable energy standard of a municipally owned utility shall, at a minimum, meet the following criteria:
   1. The eligible energy resources shall be limited to those identified in paragraph (a) of subsection (1) of this section;
   2. 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
   3. 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:
   1. Years one through three: One percent of retail electricity sales;
   2. Years four through seven: Three percent of retail electricity sales;
   3. Years eight through twelve: Six percent of retail electricity sales; and
   4. Years thirteen and thereafter: Ten percent of retail electricity sales.
5. Procedure for exemption and inclusion - election.
   1. (Deleted by amendment, L. 2007, p. 257 , § 1, effective March 27, 2007.)
   2. The board of directors of each municipally owned electric utility not subject to this section may, at its option, submit the question of its inclusion in this section to its consumers on a one meter equals one vote basis. Approval by a majority of those voting in the election shall be required for such inclusion, providing that a minimum of twenty-five percent of eligible consumers participates in the election.
   (5.5) Each cooperative electric association that is a qualifying retail utility shall submit an annual compliance report to the commission no later than June 1 of each year in which the cooperative electric association is subject to the renewable energy standard requirements established in this section. The annual compliance report shall describe the steps taken by the cooperative electric association to comply with the renewable energy standards and shall include the same information set forth in the rules of the commission for jurisdictional utilities. Cooperative electric associations shall not be subject to any part of the compliance report review process as provided in the rules for jurisdictional utilities. Cooperative electric associations shall not be required to obtain commission approval of annual compliance reports, and no additional regulatory authority of the commission other than that specifically contained in this subsection (5.5) is created or implied by this subsection (5.5).
6. (Deleted by amendment, L. 2007, p. 257 , § 1, effective March 27, 2007.)
7. 1. Definitions. For purposes of this subsection (7), unless the context otherwise requires:
      1. "Customer-generator" means an end-use electricity customer that generates electricity on the customer's side of the meter using eligible energy resources.
      2. "Municipally owned utility" means a municipally owned utility that serves five thousand customers or more.
   2. 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:
      1. 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.
      2. 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.
      3. Nondiscriminatory rates. A municipally owned utility shall provide net metering service at nondiscriminatory rates.
      4. 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.
      5. 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:
         1. Residential customer-generators to generate electricity subject to net metering up to ten kilowatts; and
         2. 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.
   1. 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.
   2. 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.
   3. 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).
   4. 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).
   5. 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.
   6. 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.
   7. 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:
      1. Describe the steps it took during the immediately preceding twelve months to comply with the electric resource standard established in this subsection (8);
      2. 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
      3. 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.
   8. Nothing in this subsection (8) amends or waives any provision of subsections (1) to (7) of this section.

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

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.

Source: Initiated 2004: Entire section added, see L. 2005, p. 2337 , effective December 1, 2004, proclamation of the Governor issued December 1, 2004. L. 2005: Entire section amended, p. 238, § 2, effective August 8; (2) added by revision, see L. 2005, p. 2340 , § 3.

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:
   1. 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;
   2. 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;
   3. 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;
   4. 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
   5. 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:
   1. "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.
   2. "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).
   3. 1. "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.
      2. "Qualifying retail utility" does not include a municipally owned utility.
3. Clean energy targets.
   1. In addition to the other requirements of this section, a qualifying retail utility shall meet the following clean energy targets:
      1. 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.
      2. 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.
      3. 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.
   2. 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.
   1. 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:
      1. The electric resource plan containing the clean energy plan must utilize a resource acquisition period that extends through 2030.
      2. 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.
      3. 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.
      4. 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.
      5. 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.
      6. The clean energy plan must set forth the projected cost of its implementation and anticipated reductions in carbon dioxide and other emissions.
      7. 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:
         1. The number of workers employed by the utility or a contractor of the utility at the electric generating facility;
         2. 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;
         3. 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;
         4. 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.
      8. 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.
   2. 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.
   3. 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.
   4. 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:
      1. 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;
      2. 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.
      3. 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.
   5. 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.
   1. 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:

      1. Fuel and transmission costs;
      2. 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;
      3. The incremental costs of eligible energy resources recovered with funds collected under section 40-2-124 (1)(g); and
      4. 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

      5. 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.

   2. 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.
   3. 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.
   4. 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.
   5. 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.
   6. 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.
   7. 1. 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:
      2. 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.

      (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.

   8. 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.

Source: L. 2019: Entire section added, (SB 19-236), ch. 359, p. 3291, § 5, effective May 30. L. 2021: IP(4)(a)(VII) amended, (HB 21-1316), ch. 325, p. 2062, § 78, effective July 1.

40-2-126. Transmission facilities - biennial review - energy resource zones - definition - plans - approval - cost recovery.

1. As used in this section, "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.
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:
   1. Designate energy resource zones;
   2. 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;
   3. 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
   4. 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.
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:
   1. The construction or expansion:
      1. Is required to:
         1. 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
         2. 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;
      2. 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
   2. 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 council recognized by that office; except that this apprenticeship requirement does not apply to:
   1. The design, planning, or engineering of the transmission facilities;
   2. Management functions to operate the transmission facilities; or
   3. Any work performed in response to a warranty claim.

Source: L. 2007: Entire section added, p. 266, § 2, effective March 27. L. 2016: IP(2) and (2)(d) amended and (4) repealed, (HB 16-1091), ch. 48, p. 114, § 1, effective August 10. L. 2021: IP(3) and (3)(a) amended, (4) RC&RE, and (5) added, (SB 21-072), ch. 329, p. 2110, § 1, effective June 24.

Editor's note: Section 11 of chapter 329 (SB 21-072), Session Laws of Colorado 2021, provides that the act changing this section applies to conduct occurring on or after June 24, 2021.

Cross references: For the legislative declaration contained in the 2007 act enacting this section, see section 1 of chapter 61, Session Laws of Colorado 2007.

40-2-127. Community energy funds - community solar gardens - definitions - rules - legislative declaration - repeal.

1. Legislative declaration. The general assembly hereby finds and declares that:
   1. 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;
   2. 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:
      1. 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;
      2. Allow renters, low-income utility customers, and agricultural producers to own interests in solar generation facilities;
      3. Allow interests in solar generation facilities to be portable and transferrable; and
      4. Leverage Colorado's solar generating capacity through economies of scale.
2. Definitions. As used in this section, unless the context otherwise requires:
   1. The definitions in section 40-2-124 apply; and
   2. In addition:
      1. 1. "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".
         2. 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.
         3. 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.
         4. 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.
      2. "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.
      3. "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.
   1. 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.
   2. 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:
      1. Minimum capitalization;
      2. 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
      3. Authorizing subscriber organizations to enter into leases, sale-and-leaseback transactions, operating agreements, and other ownership arrangements with third parties.
   3. 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:

   1. 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.
   2. 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 council recognized by that office; except that this apprenticeship requirement does not apply to:
      1. The design, planning, or engineering of the infrastructure;
      2. Management functions to operate the infrastructure; or
      3. Any work included in a warranty.
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.
   1. 1. 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.
      2. 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.
      3. 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.

      4. For each qualifying retail utility's compliance years commencing in 2014 and thereafter, 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:
         1. 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;
         2. 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;
         3. 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;
         4. Successful financing and operation of community solar gardens owned by subscriber organizations; and
         5. The achievement of the goals and objectives of section 40-2-124.
   2. 1. 1. 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) (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.
         2. 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.
         3. 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.
      2. The purchase of the output of a community solar garden by a qualifying retail utility shall 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. The net metering credit shall be 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 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. 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 shall be carried forward and applied against future bills. The qualifying retail utility and the owner of the community solar garden shall 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.
   3. 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.
   4. 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.
   5. 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.
   6. 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.

Source: L. 2007: Entire section added, p. 265, § 2, effective March 27. L. 2010: Entire section amended, (HB 10-1342), ch. 344, p. 1592, § 1, effective June 5. L. 2015: (2)(b)(II) amended, (HB 15-1248), ch. 170, p. 519, § 1, effective May 8; (2)(b)(I)(C) added, (SB 15-046), ch. 142, p. 434, § 2, effective August 5. L. 2019: IP(3)(b) amended and (5)(a)(III.5) added, (SB 19-236), ch. 359, p. 3299, § 6, effective May 30; (2)(b)(I)(A), (2)(b)(II), and (5)(b)(I) amended and (2)(b)(I)(D) and (3.5) added, (HB 19-1003), ch. 360, p. 3336, § 2, effective August 2. L. 2020: IP(3.5)(b) amended, (HB 20-1402), ch. 216, p. 1058, § 70, effective June 30.

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:
   1. 1. 1. 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. (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.
         2. 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).
         3. 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).
         4. 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.
      2. 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.
   2. 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.
   3. Repealed.
   4. On a system with a direct current design capacity of less than three hundred kilowatts:
      1. 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:
         1. The installation of photovoltaic modules;
         2. The installation of photovoltaic module mounting equipment; and
         3. Any photovoltaic electrical work; and
      2. 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:
   1. 1. "Photovoltaic electrical work" means wiring, grounding, or repairing electrical apparatus and equipment in a photovoltaic distributed generation system.
      2. "Photovoltaic electrical work" includes the preinstallation assembly of photovoltaic modules to photovoltaic module mounting equipment for installation on-site.
      3. "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).
   2. "Photovoltaic module" means the module or panel that generates electricity through a photovoltaic process.
   3. "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.

Source: L. 2010: Entire section added, (HB 10-1001), ch. 37, p. 150, § 4, effective August 11. L. 2013: IP(1) and (1)(a)(I) amended, (SB 13-186), ch. 159, p. 513, § 2, effective May 3. L. 2019: IP(1), (1)(a)(I)(D), and IP(1)(d) amended and (1)(c) repealed, (HB 19-1003), ch. 360, p. 3338, § 3, effective August 2; (1)(a)(I)(A), (1)(a)(I)(C), and (1)(b) amended, (HB 19-1172), ch. 136, p. 1732, § 258, effective October 1.

40-2-129. New resource acquisitions - factors in determination - local employment - "best value" metrics - performance audit.

1. 1. 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: 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 councils recognized by that office; employment of Colorado labor as compared to importation of out-of-state workers; long-term career opportunities; and industry-standard wages, health care, and pension benefits. When a utility proposes to construct new facilities of its own, the utility shall supply similar information to the commission.
   2. 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:
      1. Provide the "best value" employment metrics documentation specified in the solicitation document; or
      2. In the alternative, certify compliance with objective "best value" employment metrics performance standards set forth in the solicitation document.
   3. 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 council recognized by that office; except that this apprenticeship requirement does not apply to:
   1. The design, planning, or engineering of the infrastructure;
   2. Management functions to operate the infrastructure; or
   3. 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) or 40-2-127 (2)(b)(I)(B).
4. 1. The state auditor shall conduct or cause to be conducted a performance audit of the commission's implementation of the "best value" employment metrics requirements of this section, including review of:
      1. The projects subject to subsection (1)(a) of this section that have been approved in the previous ten years;
      2. Whether the work done used contractors that met the criteria specified in this section;
      3. Any shortfalls in enforcement capacity or implementation by the commission;
      4. Current enforcement procedures for investor-owned utilities, independent power producers, and wholesale generation and transmission electric cooperatives; and
      5. Whether and how delayed rule-making proceedings have prevented the "best value" employment metrics requirements of this section from being implemented.
   2. The governor's office, the commission, and commission staff shall cooperate with stakeholders and the state auditor in conducting the audit and making recommendations for reforms of, or potential alternatives to, the implementation and enforcement of "best value" employment metrics.
   3. Upon completion of a performance audit, the state auditor shall submit a written report to the legislative audit committee, together with any findings and recommendations.

Source: L. 2010: Entire section added, (HB 10-1001), ch. 37, p. 150, § 4, effective August 11. L. 2013: Entire section amended, (HB 13-1292), ch. 266, p. 1406, § 16, effective May 24. L. 2019: Entire section amended, (SB 19-236), ch. 359, p. 3300, § 7, effective May 30. L. 2020: (1)(a) and IP(2) amended, (HB 20-1402), ch. 216, p. 1058, § 71, effective June 30. L. 2021: (4) added, (HB 21-1266), ch. 411, p. 2751, § 22, effective July 2.

Editor's note: Section 24 of chapter 411 (HB 21-1266), Session Laws of Colorado 2021, provides that the act changing this section applies to conduct occurring on or after July 2, 2021.

Cross references: (1) For the short title ("Keep Jobs In Colorado Act of 2013") in HB 13-1292, see section 1 of chapter 266, Session Laws of Colorado 2013.

(2) For the short title ("Environmental Justice Act") and the legislative declaration in HB 21-1266, see sections 1 and 2 of chapter 411, Session Laws of Colorado 2021.

40-2-130. Distributed resources - energy storage systems - definitions - legislative declaration - rules.

1. Legislative declaration.
   1. The general assembly finds and determines that:
      1. Colorado's economy, as well as the health and safety of its residents, depends on a reliable and efficient supply of electricity; and
      2. 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.
   2. Therefore, the general assembly declares that:
      1. It is in the public interest to limit barriers to the installation, interconnection, and use of customer-sited energy storage facilities in Colorado; and
      2. 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:
   1. "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.
   2. "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:
   1. It is in the public interest to limit barriers to the installation, interconnection, and use of customer-sited energy storage systems in Colorado;
   2. 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;
   3. Utility approval processes and any required interconnection reviews of energy storage systems shall be simple, streamlined, and affordable for customers; and
   4. 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:
   1. The principles of net metering as described in section 40-2-124; or
   2. Any existing electrical permit requirements or any licensing or certification requirements for installers, manufacturers, or equipment.

Source: L. 2018: Entire section added, (SB 18-009), ch. 45, p. 476, § 1, effective August 8.

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:
   1. 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;
   2. The current statewide structure, technology, and general operations of 911 service in Colorado;
   3. 911 network reliability and resiliency;
   4. Identified gaps, vulnerabilities, and needs related to 911 service in the state;
   5. The impact on and involvement of the state in federal activities and national trends affecting 911 service in Colorado;
   6. The state's planning for, transition to, and implementation of next generation 911, including a projected timeline for full statewide implementation; and
   7. 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.
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.

Source: L. 2018: Entire section added, (HB 18-1184), ch. 308, p. 1862, § 1, effective May 29. L. 2020: (2) amended, (HB 20-1293), ch. 267, p. 1298, § 16, effective July 10.

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:
   1. Define the following terms:
      1. Distributed energy resources that include:
         1. Distributed renewable electric generation;
         2. Energy storage systems connected to the distribution grid;
         3. Microgrids;
         4. Energy efficiency measures; and
         5. Demand response measures; and
      2. Non-wires alternatives;
   2. Develop a methodology for evaluating the costs and net benefits of using distributed energy resources as non-wires alternatives;
   3. 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;
   4. Direct each qualifying retail utility to file a distribution system plan;
   5. Determine what shall be included in a distribution system plan, which at a minimum must include the following:
      1. Information regarding:
         1. System and substation historical data;
         2. Peak demand;
         3. Adoption of distributed energy resources; and
         4. Distribution system investments;
      2. 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;
      3. An updated load forecast that includes any new load resulting from projected or forecasted growth from beneficial electrification programs;
      4. A forecast of the growth of distributed energy resources for the years covered by the plan;
      5. 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.
      6. A proposed cost-recovery method or mechanism for any non-wires alternative investments found to be outside the ordinary course of business;
      7. A description of the qualifying retail utility's anticipated new distribution system expansion investments for the years covered by the plan;
      8. A process to evaluate the plan's feasibility and the economic impacts of using non-wires alternatives for certain projects;
      9. 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
      10. 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. 1. 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.
   2. 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.

Source: L. 2019: Entire section added, (SB 19-236), ch. 359, p. 3301, § 8, effective May 30.

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:
   1. 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;
   2. The total number of workers whose existing jobs, as a result of the retirement of the electric generating facility:
      1. Will be retained; and
      2. Will be eliminated;
   3. 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:
      1. Whose employment will end without them being offered other employment;
      2. Who will retire as planned, be offered early retirement, or leave on their own;
      3. Who will be retained by being transferred to other electric generating facilities or offered other employment by the qualifying retail utility; and
      4. Who will be retained to continue to work for the qualifying retail utility in a new job classification; and
   4. If the qualifying retail utility is replacing the electric generating facility being retired with a new electric generating facility, the number of:
      1. Workers from the retired electric generating facility who will be employed at the new electric generating facility; and
      2. 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.

Source: L. 2019: Entire section added, (SB 19-236), ch. 359, p. 3303, § 8, effective May 30.

40-2-134. Wholesale electric cooperatives - electric resource planning - definition - rules.

1. 1. 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.
   2. In developing rules for a wholesale electric cooperative, the commission must consider, among other factors determined by the commission, whether each wholesale electric cooperative:
      1. Serves a multistate operational jurisdiction;
      2. Has a not-for-profit ownership structure; and
      3. 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.

Source: L. 2019: Entire section added, (SB 19-236), ch. 359, p. 3304, § 8, effective May 30.

40-2-135. Retail distributed generation - customers' rights - rules.

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.

Source: L. 2019: Entire section added, (SB 19-236), ch. 359, p. 3304, § 9, effective May 30.

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

1. 1. The general assembly finds and determines that:
      1. Cardinal principles of cooperative electric associations include democratic member control, autonomy, and independence; and
      2. 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.
   2. Therefore, the general assembly declares that:
      1. 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
      2. 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:
   1. "Cooperative electric association" means a nonprofit electric corporation or association other than a wholesale electric cooperative.
   2. "Energy storage system" has the meaning set forth in section 40-2-202 (2).
   3. "Wholesale electric cooperative" means any generation and transmission cooperative electric association that provides wholesale electric service directly to cooperative electric associations.

Source: L. 2020: Entire section added, (HB 20-1225), ch. 94, p. 372, § 3, effective March 27.

Cross references: For the legislative declaration in HB 20-1225, see section 1 of chapter 94, Session Laws of Colorado 2020.

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:
   1. 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
   2. 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.

Source: L. 2021: Entire section added, (SB 21-272), ch. 220, p. 1161, § 7, effective June 10.

Editor's note: Section 14 of chapter 220 (SB 21-272), Session Laws of Colorado 2021, provides that the act adding this section applies to conduct occurring on or after June 10, 2021.

40-2-201. Legislative declaration.

1. The general assembly finds, determines, and declares that:
   1. Energy storage systems provide potential opportunities to:
      1. Reduce system costs;
      2. Support diversification of energy resources; and
      3. Enhance grid safety and reliability;
   2. 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.

Source: L. 2018: Entire part added, (HB 18-1270), ch. 360, p. 2151, § 2, effective August 8.

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.

Source: L. 2018: Entire part added, (HB 18-1270), ch. 360, p. 2152, § 2, effective August 8.

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:
   1. Increased integration of energy into the grid of the electric utility;
   2. Improved reliability of the grid;
   3. A reduction in the need for the increased generation of electricity during periods of peak demand; and
   4. 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:
   1. Establishing mechanisms for the inclusion of benefits and costs associated with energy storage systems into the planning conducted by electric utilities;
   2. 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.
   3. 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;
   4. Establishing that an energy storage system may be owned by an electric utility or by any other person;
   5. 1. Establishing requirements for the filing by an electric utility of acquisition plans containing an analysis of the integration and use of electric storage systems.
      2. The requirements under this subsection (3)(e) must include the requirement that an electric utility provide in its acquisition plans:
         1. Modeling assumptions used to assess the costs and benefits of energy storage systems; and
         2. Model contracts for procurement of energy storage systems.
   6. 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: L. 2018: Entire part added, (HB 18-1270), ch. 360, p. 2152, § 2, effective August 8.

40-2.1-101 to 40-2.1-106. (Repealed)

Source: L. 89: Entire article repealed, p. 1640, § 6, effective July 1.

Editor's note: This article was added in 1979. For amendments to this article prior to its repeal in 1989, consult the Colorado statutory research explanatory note and the table itemizing the replacement volumes and supplements to the original volume of C.R.S. 1973 beginning on page vii in the front of this volume.

Cross references: For the "Hazardous Materials Transportation Act of 1987", see parts 1, 2, and 3 of article 20 of title 42.

40-2.2-101 to 40-2.2-213. (Repealed)

Source: L. 93: Entire article repealed, p. 1612, § 14, effective June 6.

Editor's note: This article was added in 1986. For amendments to this article prior to its repeal in 1993, consult the Colorado statutory research explanatory note and the table itemizing the replacement volumes and supplements to the original volume of C.R.S. 1973 beginning on page vii in the front of this volume.

Cross references: For the "Hazardous Materials Transportation Act of 1987", see parts 1, 2, and 3 of article 20 of title 42.

40-2.3-101. Definitions.

As used in this article 2.3, unless the context otherwise requires:

1. "Electric utility" means a public utility as defined in section 40-1-103.
2. "Energy imbalance market" means a real-time bulk power trading market that provides a means for participating electric utilities to purchase and sell unscheduled energy across a geographic region.
3. "Joint tariff" means a tariff that contains only joint rates, which are rates that apply for transmission service over the lines or routes of two or more transmission providers, made by an agreement between the transmission providers.
4. "Power pool" means a system of trading wholesale electricity that determines which generating sets or plants are called to meet demand for power at any particular time and sets the price of power for that period.
5. "Regional transmission organization" means an independent electric transmission operator that provides wholesale transmission services to more than one provider of electric service within a geographic region by pooling together a number of transmission assets into a single electricity transmission market from which participating electric utilities may purchase wholesale transmission services.

Source: L. 2019: Entire article added, (SB 19-236), ch. 359, p. 3307, § 12, effective May 30.

40-2.3-102. Commission proceeding - evaluate participation in energy imbalance market, regional transmission organization, power pool, or joint tariff.

1. On or before January 1, 2020, the commission shall open a proceeding to investigate the potential costs and benefits to electric utilities, other generators, and Colorado electric utility customers that would arise from electric utilities participating in any energy imbalance markets, regional transmission organizations, power pools, or joint tariffs. The proceeding must include an investigation of the potential advantages and disadvantages of these options, including the effect on:
   1. Both participating and nonparticipating retail and wholesale Colorado electric service providers;
   2. Wholesale electric energy rates;
   3. Transmission rates;
   4. Retail electric energy rates for both participating and nonparticipating Colorado retail electric service providers;
   5. Commitment and dispatch of generation and real-time dispatch optimization of energy and ancillary services;
   6. Reserve margin requirements;
   7. Short-term and long-term operational costs;
   8. Regional infrastructure investment in response to growth in demand for electric energy or changes in energy production;
   9. Operating reserve procurement; and
   10. Renewable energy resource interconnection and integration.
2. On or before July 1, 2021, the commission shall hold a hearing for public comment to consider the information received during the commission's investigation and deliberate on whether electric utilities should participate in an energy imbalance market, regional transmission organization, power pool, or joint tariff.
3. On or before December 1, 2021, the commission shall issue a decision determining whether electric utilities participating in an energy imbalance market, regional transmission organization, power pool, or joint tariff is in the public interest.
4. If the commission determines that electric utility participation in an energy imbalance market, regional transmission organization, power pool, or joint tariff is in the public interest, the commission, on or before July 1, 2022, shall direct electric utilities to take appropriate actions and conduct such proceedings as the commission deems appropriate to pursue participation in an energy imbalance market, regional transmission organization, power pool, or joint tariff.

Source: L. 2019: Entire article added, (SB 19-236), ch. 359, p. 3307, § 12, effective May 30.

40-2.3-103. Repeal of article.

This article 2.3 is repealed, effective September 1, 2022.

Source: L. 2019: Entire article added, (SB 19-236), ch. 359, p. 3309, § 12, effective May 30.

40-3-101. Reasonable charges - adequate service.

1. All charges made, demanded, or received by any public utility for any rate, fare, product, or commodity furnished or to be furnished or any service rendered or to be rendered shall be just and reasonable. Every unjust or unreasonable charge made, demanded, or received for such rate, fare, product or commodity, or service is prohibited and declared unlawful. Rates and charges demanded or received by any public utility for gas transportation service furnished or to be furnished shall not be deemed to be unjust or unreasonable so long as said rate or charge is no greater than a maximum rate and no lower than a minimum rate determined by the commission (or, in the case of a municipal utility, by the governing body of the municipal utility in accordance with sections 40-3-102 and 40-3.5-102) to be just and reasonable, and the provision of such gas transportation service at such rates or charges shall not constitute per se unjust discrimination or the granting of a preference. Nothing in this subsection (1) shall limit or restrict the commission's authority to regulate rates and charges, correct abuses, or prevent unjust discrimination.
2. Every public utility shall furnish, provide, and maintain such service, instrumentalities, equipment, and facilities as shall promote the safety, health, comfort, and convenience of its patrons, employees, and the public, and as shall in all respects be adequate, efficient, just, and reasonable.
3. 1. If a retail cooperative electric association, in conjunction with the payment of an applicable charge, withdraws from membership in a wholesale electric cooperative, as defined in section 40-2-136 (3)(c), that withdrawal is deemed to be a matter of statewide concern, and, in relation to such withdrawal:
      1. The wholesale electric cooperative will act in accordance with the obligation of good faith and fair dealing in implementing the withdrawal and shall not require or impose commercially unreasonable contractual terms on the retail cooperative electric association in relation to the withdrawal; and
      2. The wholesale electric cooperative shall, upon request from the withdrawing retail cooperative electric association, facilitate the retail cooperative electric association's transition from native load to a firm service transmission customer without diminishing the withdrawing retail cooperative electric association's native electric load priority for accessing firm transmission capacity.
   2. The commission has the authority to adjudicate complaints about the terms on which a wholesale electric cooperative implements withdrawal pursuant to this subsection (3).

Source: L. 13: p. 468, § 13. C.L. § 2924. CSA: C. 137, § 14. CRS 53: § 115-3-1. C.R.S. 1963: § 115-3-1. L. 91: (1) amended, p. 1417, § 9, effective April 19. L. 2020: (3) added, (HB 20-1225), ch. 94, p. 373, § 4, effective March 27.

Cross references: (1) For hearings on rate schedules, see § 40-6-111; for reparation for excessive charges, see § 40-6-119.

(2) For the legislative declaration in HB 20-1225, see section 1 of chapter 94, Session Laws of Colorado 2020.

40-3-102. Regulation of rates - correction of abuses.

The power and authority is hereby vested in the public utilities commission of the state of Colorado and it is hereby made its duty to adopt all necessary rates, charges, and regulations to govern and regulate all rates, charges, and tariffs of every public utility of this state to correct abuses; to prevent unjust discriminations and extortions in the rates, charges, and tariffs of such public utilities of this state; to generally supervise and regulate every public utility in this state; and to do all things, whether specifically designated in articles 1 to 7 of this title or in addition thereto, which are necessary or convenient in the exercise of such power, and to enforce the same by the penalties provided in said articles through proper courts having jurisdiction; except that nothing in this article shall apply to municipal natural gas or electric utilities for which an exemption is provided in the constitution of the state of Colorado, within the authorized service area of each such municipal utility except as specifically provided in section 40-3.5-102.

Source: L. 13: p. 469, § 14. C.L. § 2925. CSA: C. 137, § 15. CRS 53: § 115-3-2. C.R.S. 1963: § 115-3-2. L. 83: Entire section amended, p. 1552, § 1, effective June 17.

Cross references: For definition of a public utility, see § 40-1-103; for penalties for violation, see article 7 of this title.

40-3-103. Utilities to file rate schedules - rules.

1. Under the rules prescribed by the commission, each public utility shall file with the commission, within the time and in the form designated by the commission, and shall print and keep open to public inspection, schedules showing all rates, tolls, rentals, charges, and classifications collected or enforced, or to be collected and enforced, together with all rules, regulations, contracts, privileges, and facilities that in any manner affect or relate to rates, tolls, rentals, classifications, or service.
2. 1. On or after January 1, 2018, on a schedule determined by the commission, each investor-owned electric utility shall file for the commission's review a comprehensive billing format that the investor-owned electric utility has developed for its monthly billing of customers. The comprehensive billing format must include the following components of a customer's monthly bill:
      1. A line-item representation of all monthly charges and credits applied to the customer and an indication of whether the charges have changed from the prior month as a result of changes in fuel costs;
      2. For months in which tiered rates are applied, a breakdown of the tiered rates and the amount of usage to which each rate was applied for the month;
      3. The daily average cost for the current month compared to the same month in the previous calendar year;
      4. A glossary of terms used by the utility in the monthly bill;
      5. A description of each of the monthly fees that the utility may charge the customer;
      6. The usage for the current month and each of the previous twelve months, as shown in a bar graph or similar visual format; and
      7. For customers to which demand rates apply, a listing of the applicable demand charge, the peak demand during the billing period, and, provided the utility can reasonably ascertain such data, the date and time at which the peak demand occurred.
   2. Each investor-owned electric utility shall provide its customers, on a biannual basis, with either an onsert or an insert that indicates, as a percentage, each fuel source used in power generation and purchased for that utility, including renewable energy sources, natural gas, and coal.
   3. 1. The commission shall review a filing submitted pursuant to subsection (2)(a) of this section within thirty days after the filing. If the commission determines that the filing does not meet the comprehensive billing format requirements set forth in subsection (2)(a) of this section, the commission may require the investor-owned electric utility to resubmit a comprehensive billing format in compliance with the requirements. The commission shall notify the investor-owned electric utility in writing of the reasons for the deficiency, and the investor-owned electric utility shall resubmit a comprehensive billing format in compliance with the requirements of subsection (2)(a) of this section within sixty days after the date of the commission's notice of deficiency; except that the commission may, upon request, extend the deadline.
      2. After the commission has approved a comprehensive billing format submitted by an investor-owned electric utility pursuant to subsection (2)(a) of this section, the investor-owned electric utility need not resubmit a comprehensive billing format unless the investor-owned electric utility makes changes to its comprehensive billing format.

Source: L. 13: p. 469, § 15. C.L. § 2926. CSA: C. 137, § 16. CRS 53: § 115-3-3. C.R.S. 1963: § 115-3-3. L. 69: p. 964, § 75. L. 91: Entire section amended, p. 2427, § 1, effective June 8. L. 2006: Entire section amended, p. 1103, § 26, effective August 7. L. 2007: Entire section amended, p. 1244, § 1, effective May 24. L. 2017: Entire section amended, (SB 17-105), ch. 224, p. 862, § 1, effective May 22.

40-3-103.5. Medical exemption - tiered electricity rates - rules.

1. Notwithstanding any provision of articles 1 to 7 of this title 40 to the contrary, the commission shall adopt rules to create an exemption from any tiered electricity rate plan based on a customer's medical condition. The commission's rules must provide a mechanism for the recovery of costs associated with implementing and providing the medical exemption.
2. The commission may determine the definition of "medical condition"; except that the definition must include multiple sclerosis, epilepsy, quadriplegia, and paraplegia. The medical exemption is for individuals who have the verification of a physician licensed in Colorado of a heat-sensitive medical condition or the need for the use of an essential life support device.
3. If the commission determines that a means test is necessary for the medical exemption, the commission shall use no less than four hundred percent of the federal poverty level for the customer's household as the maximum income to be eligible for the medical exemption.
4. If the low-income energy assistance program is used to certify eligibility, the medical exemption under this section must be distinguishable from the heat assistance benefits offered under the low-income energy assistance program because these programs may have different eligibility requirements.
5. On and after September 1, 2020, the commission shall require utilities periodically to report, pursuant to section 40-3-110, the number of their customers who receive the medical exemption under this section and to describe the efforts the utilities have made during each reporting period to facilitate the enrollment of qualified persons in their medical exemption programs.

Source: L. 2011: Entire section added, (SB 11-087), ch. 80, p. 218, § 1, effective March 29. L. 2013: Entire section amended, (SB 13-282), ch. 292, p. 1562, § 1, effective May 28. L. 2020: (1) and (3) amended and (5) added, (SB 20-030), ch. 148, p. 637, § 1, effective June 29.

40-3-103.6. Disconnection due to nonpayment - connection and reconnection fees - deposits - standard practices - rules.

1. On or before September 1, 2020, the commission shall commence a rule-making proceeding to adopt standard practices for gas and electric utilities to use when disconnecting service due to nonpayment. At a minimum, the rules must address the following subjects:
   1. Resources to support customers in multiple languages, as appropriate to the geographic areas served;
   2. Limiting shut-off times to reasonable hours of the day Monday through Friday, excluding holidays, so that customers can attempt to reconnect on the same day;
   3. Prescribed terms and conditions for payment plans to cure delinquency;
   4. Referral of delinquent customers to energy payment assistance resources such as Energy Outreach Colorado, charities, nonprofits, and state agencies that provide, or that administer federal funds for, low-income energy assistance;
   5. For each utility, standardized methodology to be used in determining reconnection fees and deposit requirements for reconnection;
   6. Protection policies for customers for whom electricity is medically necessary;
   7. Prohibitions on the disconnection of service during periods of extreme heat or cold, as appropriate to the geographic area served;
   8. A prohibition on the remote disconnection of service for nonpayment, through advanced metering infrastructure or otherwise, without a reasonable attempt to make contact with the customer of record by telephone or engaging in a personal, physical visit to the premises; and
   9. Reporting requirements, no less frequently than annually, to provide the commission with standardized information from all utilities about disconnections and delinquencies. For the purpose of trend analysis, utilities may disaggregate data by month or by quarter, as the commission deems appropriate. Reporting requirements must take into consideration existing utility reporting and must allow the utilities a reasonable ability to ascertain data.
2. The commission shall publish on its website, or require utilities to publish on their websites:
   1. Information regarding the standard practices and fees specified in rules adopted pursuant to subsection (1) of this section; and
   2. The information periodically reported in accordance with subsection (1)(i) of this section.

Source: L. 2020: Entire section added, (SB 20-030), ch. 148, p. 638, § 2, effective June 29.

40-3-104. Changes in rates - notice.

1. 1. In the case of a public utility other than a rail carrier, subject to the provisions of paragraph (c) of this subsection (1), no change shall be made by any public utility in any rate, fare, toll, rental, charge, or classification or in any rule, regulation, or contract relating to or affecting any rate, fare, toll, rental, charge, classification, or service or in any privilege or facility, except after thirty days' notice to the commission and the public. Notwithstanding the provisions of this paragraph (a), changes in intrastate telecommunications services which have been determined by the commission to be competitive in nature, pursuant to the provisions of article 15 of this title, shall not be subject to any notice requirement, including, but not limited to, any requirement in this section whether or not denoted as a notice requirement.
   2. Repealed.
   3. 1. A public utility shall provide the notice required under subsection (1)(a) of this section by filing with the commission and keeping open for public inspection new schedules stating plainly the changes to be made in the schedules then in force and the time when the changes will go into effect. At the time of the public utility's filing with the commission, the public utility shall post the notice on its public website, including a reference to the docket numbers of relevant rules or adjudicatory matters, which posting must be conspicuously displayed on the website for at least thirty days. The commission may require transportation and water utilities to give additional notice in a manner set forth by order or rule. For public utilities other than transportation and water utilities, the commission shall require additional notice prior to an increase or other change in any rate, fare, toll, rental, charge, classification, or service, which additional notice may be made, at the option of the public utility, by any of the following methods:
         1. Publication of a notice in each newspaper of general circulation in each county in which the public utility provides service, which notice shall be four columns wide and eleven inches high stating plainly the changes and shall be published once each week for two successive weeks during the first twenty days of the thirty-day period prior to the effective date of the increase or change. If notice is given by publication, public utilities other than those providing intrastate telecommunications services pursuant to section 40-15-104 (1) shall also be required to include, with each regular billing statement mailed to affected customers during the first regular billing cycle following the filing of the application for an increase or other change, a bill insert containing the same information contained in the notice by newspaper publication.
         2. Mailing of a notice to each affected customer of the public utility during the first twenty days of the thirty-day period prior to the effective date of the increase or change;
         3. Inclusion of an insert in, or a clear and conspicuous statement on, the bill mailed to each affected customer of the public utility during a regular billing cycle not later than the twentieth day of the thirty-day period prior to the effective date of the increase or change;
         4. Subject to subsection (1)(c)(VII) of this section, not later than the twentieth day of the thirty-day period before the effective date of the increase or change, sending an e-mail or text message to each affected customer of the public utility for whom the utility has an e-mail address or a mobile telephone number; or
         5. At the request of the public utility, such other manner as the commission may prescribe.
      2. Such additional notice shall be sufficient if it states the total dollar amount sought to be raised by such increased rates or other changes and, if determinable at the time of filing, the average monthly increase, by dollar amount or percentage, to customers served under residential and small business tariffs; states the effective date or dates thereof; contains a general description of the types of services to be affected thereby; informs affected customers, other than residential and small business customers, where they may call to obtain information during the thirty-day period prior to the effective date of the proposed increases or changes concerning how such increases or changes will affect them; and includes the telephone number and address of the commission with instructions regarding the registration of a protest to the proposed increases or changes. Proof of additional notice shall be filed by the public utility with the commission.
      3. Increases in rates, fares, tolls, rentals, or charges associated with electric and gas utility adjustment clauses are subject only to the provisions of subsection (2) of this section.
      4. For public utilities other than transportation and water utilities, where increases or changes in any rate, fare, toll, rental, charge, classification, or service result from requested increases in revenue requirements and rate restructuring and are contained in a single advice letter or application, the additional notice required under subparagraphs (I) and (II) of this paragraph (c) shall be deemed sufficient if a single notice is given even if more than one proceeding is established by the commission with respect to the increases or changes.
      5. In the case of a public utility that provides regulated intrastate telecommunications services:
         1. Notice of a decrease in a rate or charge for any regulated telecommunications service shall be given by filing with the commission and keeping open for public inspection for a period of fourteen days the new schedule stating plainly the decrease to be made and the time that the decrease will become effective. Such decreases shall not be subject to any additional notice requirements.
         2. Notice of changes in terms and conditions for any regulated telecommunications service shall be given by filing with the commission and keeping open for public inspection for a period of fourteen days the new schedule stating plainly the changes to be made in the terms and conditions and the time that the changes will become effective. Such changes in the terms and conditions shall not be subject to any additional notice requirements unless the commission determines that such additional notice is in the public interest. Any such additional notice shall be given in a manner specified by the commission.
      6. A public utility that provides additional notice pursuant to subsection (1)(c)(I) of this section must include in the additional notice:
         1. The public utility's public website address; and
         2. A toll-free telephone number associated with the public utility that a customer may call for additional information or assistance. If a public utility sends additional notice by e-mail or text message pursuant to subsection (1)(c)(I)(D) of this section, the e-mail or text message need not include all information required by this subsection (1)(c)(VI); however, the e-mail or text message must include a link to the portion of the public utility's public website where that information is posted.
      7. A public utility may provide additional notice pursuant to subsection (1)(c)(I)(D) of this section only if the public utility provides its customers with a mechanism by which a customer may opt out of receiving e-mail or text message notifications. For any customer that opts out, the public utility shall provide an alternate method of additional notice authorized under subsection (1)(c)(I) of this section.
2. The commission, for good cause shown, may allow changes with less notice than is required by subsection (1) of this section by an order specifying the changes so to be made and the time when they shall take effect and the manner in which they shall be filed and published.
3. When any change is proposed in any rate, fare, toll, rental, charge, or classification or in any form of contract or agreement or in any rule, regulation, or contract relating to or affecting any rate, fare, toll, rental, charge, classification, or service or in any privilege or facility, attention shall be directed to such change on the schedule filed with the commission immediately preceding or following the item.
4. and (5) Repealed.

Source: L. 13: p. 470, § 16. C.L. § 2927. CSA: C. 137, § 17. CRS 53: § 115-3-4. C.R.S. 1963: § 115-3-4. L. 84: Entire section amended, p. 1036, § 2, effective July 1. L. 85: (1)(a) and (1)(c) amended, p. 1296, § 1, effective May 19. L. 2000: (1)(b), (4), and (5) repealed, p. 215, § 1, effective March 29. L. 2002: (1)(c)(V) added, p. 200, § 2, effective August 7. L. 2015: IP(1)(c)(I) and (1)(c)(I)(D) amended, (SB 15-261), ch. 291, p. 1188, § 1, effective August 5. L. 2019: IP(1)(c)(I), (1)(c)(I)(C), and (1)(c)(I)(D) amended and (1)(c)(I)(E), (1)(c)(VI), and (1)(c)(VII) added, (SB 19-236), ch. 359, p. 3304, § 10, effective May 30.

Cross references: For the legislative declaration contained in the 2002 act enacting subsection (1)(c)(V), see section 1 of chapter 74, Session Laws of Colorado 2002.

40-3-104.3. Manner of regulation - competitive responses - definitions - repeal.

1. 1. Upon application by any public utility providing electric, natural gas, or steam service, the commission shall authorize such public utility to provide utility services to a specific customer or potential customer by contract without reference to its tariffs on file with the commission if the commission finds that:
      1. For contracts with a specific customer or potential customer involving electric and steam service:
         1. The price of any such service is not below that service's variable cost;
         2. The customer, or potential customer, has expressed its intention to decline or discontinue, or partially discontinue, service, to provide its own service, or to pursue the purchase of alternate services from another provider;
         3. The approval of the application will not adversely affect the remaining customers of the public utility; and
         4. The approval of the application is in the public interest;
      2. For contracts with existing customers involving natural gas service:
         1. The customer has the ability to provide its own service or has competitive alternatives available from other providers of the same or substitutable service, except from another public utility providing or proposing to provide the same type of service;
         2. The customer will discontinue using the services of the public utility if the authorization is not granted;
         3. Approval of the application will not as adversely affect the remaining customers of the public utility as would the alternative;
         4. The price of any such service provided pursuant to this subparagraph (II) shall be justified and shall not be less than the marginal cost of the service to the public utility. If the price is less than marginal cost, this shall be deemed to be an illegal restraint of trade subject to the provisions of article 4 of title 6, C.R.S.; and
         5. The approval of the application is in the public interest.
   2. 1. Following a notice period of five days after the filing of an application under this section, the commission shall approve or deny the application within thirty days. All applications filed with the commission pursuant to this section shall be placed at the head of the commission's docket and shall be disposed of promptly within the time periods set forth in this subsection (1)(b)(I); except that, for good cause shown, the commission may extend the period in which it must act for an additional fifteen days, or, in extraordinary circumstances, including the existence of numerous pending applications under this section, the commission may extend the period in which it must act for an additional thirty days beyond the fifteen days provided for in this subsection (1)(b)(I).
      2. Whenever the application is continued as provided in subsection (1)(b)(I) of this section, the commission shall enter an order making the continuance and stating fully the facts necessitating the continuance. If the commission has not approved or denied an application within the time periods set forth in subsection (1)(b)(I) of this section, the application shall be deemed approved. If the commission denies an application for approval within the permitted period, the subject contract does not become effective.
      3. Any contract submitted pursuant to this section shall be filed under seal and treated as confidential by the commission; except that, at the time the applicant files an application or contract with the commission, the applicant shall also furnish a copy of the application to any public utility then providing electric, gas, or steam service in the state of Colorado to the customer, and also furnish a copy to the office of the utility consumer advocate, which office shall also treat the contract as confidential.
   3. An application filed by a public utility pursuant to this section shall contain the name of the customer, a description of the services proposed to be provided under contract, evidence that the requirements of paragraph (a) of this subsection (1) have been met, and any additional information required by the commission. The commission may dismiss an application if the applicant fails to provide information necessary to enable the commission to make the findings required by paragraph (a) of this subsection (1).
   4. (Deleted by amendment, L. 92, p. 2138 , § 1, effective April 23, 1992.)
   5. Within ten days after the execution of the contract, the public utility shall file with the commission under seal and as a confidential document the final contract or other description of the price and terms of service, together with any additional information required by the commission. The applicant shall also furnish a copy of the information to the office of the utility consumer advocate, which office shall treat the information as confidential. The commission has no authority to disapprove the contract if the contract complies with the conditions contained in subsection (1)(a) of this section, but the commission may consider the contract for general regulatory purposes and to ensure compliance with the requirements of this section.
2. 1. For contracts involving electric and steam service, at the time of any proceeding in which a utility's overall rate levels are determined, the commission shall specify a fully distributed cost methodology to be used to segregate rate base, expenses, and revenues associated with utility service provided by contract pursuant to this section from other regulated utility operations. For contracts involving electric and steam service, if revenues from a service provided pursuant to this section are less than the cost of service as determined by the fully distributed cost methodology specified by the commission, the rates of other regulated utility operations may not be increased to recover such difference between costs and revenues.
   2. For contracts involving natural gas service, the commission may require a public utility to segregate investments, expenses, and revenues associated with utility service provided pursuant to subparagraph (II) of paragraph (a) of subsection (1) of this section to ensure that such services are not subsidized by revenues from other utility operations. If the commission requires such segregation of such investment and expenses, it shall specify a fully distributed cost allocation methodology.
3. 1. This section shall neither enlarge nor diminish the rights and obligations of a public utility operating under a certificate issued by the commission to serve customers within a territory pursuant to the provisions of article 3.5, 5, or 9.5 of this title.
   2. Nothing in this section shall be construed to permit any public utility to provide electric, natural gas, or steam service to a customer of another public utility located in or for use in the service territory of such other public utility providing or proposing to provide the same type of service.
4. 1. The commission has the right to inspect the books and records of any affiliate of a public utility to the extent that the affiliate uses any plant, or incurs any cost, or provides any service or product which is joint and common to the provision of public utility services and products subject to the jurisdiction of the commission. Upon application and for good cause shown, the commission may enter an appropriate protective order which directs the manner in which proprietary information shall be treated.
   2. For purposes of this subsection (4), unless the context otherwise requires, "affiliate of a public utility" means a subsidiary of a public utility, a parent corporation of a public utility, a joint venture organized as a separate corporation or partnership to the extent of the individual public utility's involvement with the joint venture, or a subsidiary of a parent corporation of a public utility.
5. Nothing in this section limits or restricts the commission's authority to regulate rates and charges, correct abuses, or prevent unjust discrimination except as specifically provided in this section.
6. 1. Notwithstanding any other provision of this section, an investor-owned electric utility subject to rate regulation by the commission may offer economic development rates to a qualifying commercial or industrial customer.
   2. 1. An economic development rate approved pursuant to this section must be lower than the rate or rates that the qualifying commercial or industrial customer would be or currently is subject to under the utility's tariffs in effect at the time the qualifying commercial or industrial customer seeks to qualify for the economic development rate; except that an economic development rate must not be lower than the utility's marginal cost of providing service to the qualifying commercial or industrial customer.
      2. 1. The commission may approve investor-owned utility tariffs that provide for implementation of an economic development rate and set a minimum and maximum amount for the rate consistent with subsection (6)(b)(I) of this section.
         2. Notwithstanding subsection (6)(b)(II)(A) of this section, the utility may negotiate and enter into agreements related to economic development rates with individual qualifying commercial or industrial customers without commission approval so long as the agreed-upon economic development rate complies with the commission-approved tariff and the addition or expansion of existing load at a single location is less than or equal to twenty megawatts. Any addition or expansion of existing load at a single location that is greater than twenty megawatts requires separate commission approval based upon a finding that the addition or expansion is consistent with this section.
      3. An investor-owned utility may offer an economic development rate to a qualifying commercial or industrial customer for up to ten years.
   3. 1. An authorization granted by the commission pursuant to this section must include such terms and conditions as the commission determines are necessary to ensure that the economic development rates or charges assessed to other customers do not subsidize the cost of providing service to qualifying commercial and industrial customers consistent with subsection (6)(b)(I) of this section, and that there is no other subsidization of such service. In developing the terms and conditions, the commission shall consider, among other things, the rates and charges assessed to the utility's wholesale customers and the effects on other transmission system owners and users resulting from new transmission facilities constructed in connection with the utility's expansion of an existing voluntary renewable energy program or service offering.
      2. In a commission proceeding related to economic development rates authorized pursuant to subsection (6)(b) of this section, the utility bears the burden of proof to establish that:
         1. The rates or charges assessed to other customers do not subsidize the cost of providing economic development rates to qualifying commercial or industrial customers;
         2. The rates of other regulated utility operations do not increase; and
         3. Other customers on the utility's system do not experience a rate increase due to a rate or rates offered to a qualifying commercial or industrial customer pursuant to this section.
      3. The commission shall not impute to the utility revenues that would have been received from the qualifying commercial or industrial customer if the customer were being provided service under the corresponding rate for which it would have otherwise qualified under the utility's tariffs.
   4. 1. An investor-owned utility may seek commission approval to expand any voluntary renewable energy program or service offering, except those covered by valid agreements to the contrary executed and approved by the commission as of January 1, 2019, through the acquisition of additional renewable generation capacity and energy to meet the current and projected demand of:
         1. Any commercial or industrial customer making a capital investment of two hundred fifty million dollars or more;
         2. Any commercial or industrial customer that requires such expansion to remain as a customer of that utility; or
         3. Any qualifying commercial or industrial customer entering the service territory of the utility.
      2. The commission may approve, within one hundred twenty days, an expansion of an existing voluntary renewable energy program or service offering upon a showing by the utility that:
         1. There is not sufficient capacity and energy in the existing voluntary renewable energy program or service offering to satisfy the needs of the customer and the customer meets the requirements of subsection (6)(d)(I) of this section; and
         2. The availability of the program or service, either on its own or in combination with other incentives, is a substantial factor in the customer's decision to locate new or expand or retain existing business operations in Colorado.
7. As used in subsection (6) of this section and this subsection (7):
   1. "Qualifying commercial or industrial customer":
      1. Means a utility customer that:
         1. Agrees to: Locate commercial or industrial operations in Colorado and add at least three megawatts of new load at a single location; or expand existing commercial or industrial operations in Colorado and add at least three megawatts of new load at a single location; and
         2. Demonstrates, to the satisfaction of the investor-owned utility, subject to review by the commission, that: The cost of electricity is a critical consideration in deciding where to locate new or expand existing operations; and the availability of economic development rates, either on their own or in combination with other economic development incentives, is a substantial factor in the customer's decision to locate new or expand existing business operations in Colorado;
      2. Does not include a customer that agrees to relocate or otherwise transfer its existing load of at least three megawatts from the service territory of another public utility, as defined in section 40-1-103, into the service territory of the utility offering economic development rates.
   2. "Voluntary renewable energy program or service offering" means a program or other service offering approved by the commission that allows a commercial or industrial customer access to eligible energy resources, as that term is defined in section 40-2-124 (1)(a), on a voluntary basis, on terms and conditions deemed necessary by the commission. For a voluntary renewable energy program or service offering to be expanded, it must have been approved by the commission prior to the expansion request of a commercial or industrial customer pursuant to subsection (6)(d)(I) of this section.
8. This subsection (8) and subsections (6) and (7) of this section are repealed, effective January 1, 2028.

Source: L. 89: Entire section added, p. 1535, § 1, effective July 1. L. 92: Entire section amended, p. 2138, § 1, effective April 23. L. 2018: (5) amended and (6) to (8) added, (HB 18-1271), ch. 362, p. 2159, § 2, effective January 1, 2019. L. 2021: (1)(b) and (1)(e) amended, (SB 21-103), ch. 477, p. 3414, § 13, effective September 1.

Cross references: For the legislative declaration in HB 18-1271, see section 1 of chapter 362, Session Laws of Colorado 2018.

40-3-104.4. Simplified regulatory treatment for small or nonprofit water companies.

1. The commission, with due consideration to public interest, quality of service, financial condition, and just and reasonable rates, shall grant regulatory treatment that is less comprehensive than otherwise provided for under this article 3 to small, privately owned water companies that serve fewer than one thousand five hundred customers. The commission, when considering policy statements and rules, shall balance reasonable regulatory oversight with the cost of regulation in relation to the benefit derived from the regulation.
2. 1. Except as otherwise provided in subsection (2)(b) of this section, a water company registered as a nonprofit organization under section 501 (c) of the federal "Internal Revenue Code of 1986", as amended, 26 U.S.C. sec. 501 (c), is exempt from regulation under the "Public Utilities Law", articles 1 to 7 of this title 40.
   2. Notwithstanding subsection (2)(a) of this section, all rates, charges, and terms and conditions of service between a water company described in subsection (2)(a) of this section and its customers must be just and reasonable. The commission shall resolve any complaint alleging a violation of this subsection (2)(b) in accordance with articles 6 and 7 of this title 40 if the complaint is signed by:
      1. The mayor, the president of the board of trustees, or a majority of the council, commission, or other governing body of an affected city, county, city and county, or town;
      2. The chief executive officer of an affected public utility; or
      3. The lesser of:
         1. At least twenty-five customers or prospective customers of the water company complained of; or
         2. At least twenty-five percent of the current customers of the water company complained of.

Source: L. 2001: Entire section added, p. 1469, § 1, effective August 8. L. 2018: Entire section amended, (SB 18-134), ch. 91, p. 729, § 1, effective August 8.

40-3-104.5. Special provisions for rail carrier rate increases.

Notwithstanding section 40-3-105 and any other provision of this title to the contrary, the commission shall not exercise any jurisdiction over rates with respect to intrastate rail carriers.

Source: L. 84: Entire section added, p. 1037, § 3, effective July 1. L. 2000: Entire section amended, p. 215, § 2, effective March 29.

40-3-105. Free and reduced service or transportation prohibited - exceptions.

1. No public utility shall, directly or indirectly, issue, give, or tender any free service, ticket, frank, free pass, or other gratuity of services or any free or reduced rate transportation for passengers or property between points within this state unless a tariff so providing is first filed with and approved by the commission.
2. Except as otherwise provided in this section, no public utility shall charge, demand, collect, or receive a greater or lesser or different compensation for any product or commodity furnished or to be furnished, or for any service rendered or to be rendered, than the rates, tolls, rentals, and charges applicable to such product or commodity or service as specified in its schedules on file and in effect at the time, nor shall any such public utility refund or remit, directly or indirectly, in any manner or by any device, any portion of the rates, tolls, rentals, and charges so specified, nor extend to any corporation or person any form of contract or agreement or rule or regulation or any facility or privilege except those which are regularly and uniformly extended to all corporations and persons; but the commission may by rule or order establish such exceptions from the operation of this prohibition as it may consider just and reasonable as to each public utility.
3. 1. Nothing in this article shall prohibit or restrict any public utility from furnishing its service, product, or commodity to, or the receiving of its service, product, or commodity by, its employees, pensioners, officers, directors, or board members at no charge or at charges less than those prescribed in the utility's published schedules or tariffs.
   2. No revenue shall accrue or be credited in the accounts of such utility with respect to such service, product, or commodity furnished at no charge nor with respect to any amounts by which charges for such service, product, or commodity are less than those prescribed in the utility's published schedules or tariffs.

Source: L. 13: p. 470, § 17. C.L. § 2928. L. 27: p. 249, § 1. CSA: C. 137, § 18. L. 41: p. 599, § 1. CRS 53: § 115-3-5. C.R.S. 1963: § 115-3-5. L. 69: p. 931, § 14. L. 73: p. 1143, § 1. L. 84: (2) amended, p. 1039, § 4, effective July 1. L. 2002: (2) amended, p. 1033, § 69, effective June 1.

Cross references: For penalties for violations, see article 7 of this title.

40-3-106. Advantages prohibited - graduated schedules - consideration of household income and other factors - definitions.

1. 1. Except when operating under paragraph (c) or (d) of this subsection (1), a public utility, as to rates, charges, service, or facilities, or in any other respect, shall not make or grant any preference or advantage to a corporation or person or subject a corporation or person to any prejudice or disadvantage. A public utility shall not establish or maintain any unreasonable difference as to rates, charges, service, facilities, or between localities or class of service. The commission may determine any question of fact arising under this section.
   2. Repealed.
   3. A local exchange provider, as defined in section 40-15-102 (18), may enter into a contract, when necessary, specifying non-cost-based rates and conditions particular to that contract with one or more purchasers of services for applications of interactive video technology for purposes of distance learning, video arraignment of defendants in criminal cases, or examination, diagnosis, or treatment of patients in the course of medical practice. When an application is subject to a bidding process by the end user of the service, the local exchange providers offering component elements of interactive video technology pursuant to this paragraph (c) shall offer the component elements relating to a specific application to a specific end user to all bidders, including themselves, if bidding, at the same rates, terms, and conditions. This exception shall not apply to any other regulated service. A provider other than a local exchange provider may offer such interactive video services if such services are provided under the same terms and conditions as specified in this paragraph (c). Each contract entered into under this paragraph (c) shall be filed with the commission for information only.
   4. 1. Notwithstanding any provision of articles 1 to 7 of this title to the contrary, the commission may approve any rate, charge, service, classification, or facility of a gas or electric utility that makes or grants a reasonable preference or advantage to low-income customers, and the implementation of such commission-approved rate, charge, service, classification, or facility by a public utility shall not be deemed to subject any person or corporation to any prejudice, disadvantage, or undue discrimination.
      2. As used in this subsection (1)(d), a "low-income utility customer" means a utility customer who:
         1. Has a household income at or below one hundred eighty-five percent of the current federal poverty line; or
         2. Otherwise meets the income eligibility criteria set forth in rules of the department of human services adopted pursuant to section 40-8.5-105.
      3. When considering whether to approve a rate that makes or grants a reasonable preference or advantage to low-income utility customers, the commission shall take into account the potential impact on, and cost-shifting to, utility customers other than low-income utility customers.
2. Nothing in articles 1 to 7 of this title 40 prohibits a public utility engaged in the production, generation, transmission, or furnishing of heat, light, gas, water, power, or telephone service from establishing a graduated scale of charges subject to this title 40; except that, for rates resulting from a rate design change approved by the commission on or after September 1, 2020, the commission shall require utility revenue or billing adjustment mechanisms to ensure that a utility's change in rate design results in a revenue-neutral outcome. In adopting new rate designs for residential customers, the commission shall evaluate the potential for higher bills due to changes in rate design. Rate designs that disproportionately negatively impact low-income residential customers compared to other residential customers of the utility are presumed to be contrary to the public interest.
3. Nothing in this section shall prevent the commission from revoking its approval at any time and fixing other rates and charges for the product or commodity or service as authorized by articles 1 to 7 of this title.
4. The commission shall order a fixed public utility, except a municipally owned utility, to increase its rates only to its customers in a municipality by adding a surcharge to recover the amount such fixed public utility pays to that municipality as a cost of doing business within that municipality under a franchise or pursuant to a license or occupation tax levied by the municipality, so long as the increase in rates by such fixed public utility is pursuant to a method of surcharge approved by the commission. Occupation tax as used in this subsection (4) does not include the employer and employee tax imposed by a municipality for the privilege of employment within that municipality.
5. Repealed.

Source: L. 13: p. 473, § 18. C.L. § 2929. CSA: C. 137, § 19. CRS 53: § 115-3-6. C.R.S. 1963: § 115-3-6. L. 69: p. 932, § 15. L. 81: (4) and (5) added, p. 1912, § 1, effective July 1. L. 83: (5) repealed, p. 1555, § 3, effective June 17. L. 84: (1) amended, p. 1039, § 5, effective July 1. L. 86: (1)(a) amended, p. 1155, § 2, effective September 1. L. 89: (2) amended, p. 1526, § 8, effective April 12. L. 90: (1)(a) amended, p. 1849, § 51, effective May 31. L. 91: (1)(a) amended, p. 1925, § 57, effective June 1. L. 95: (1)(a) amended and (1)(c) added, p. 245, § 1, effective April 17. L. 2000: (1)(b) repealed, p. 217, § 3, effective March 29. L. 2002: (1)(a) amended, p. 1033, § 70, effective June 1. L. 2007: (1)(a) amended and (1)(d) added, p. 319, § 1, effective April 2. L. 2008: (2) amended, p. 1792, § 6, effective July 1. L. 2010: (1)(d)(II)(A) amended, (HB 10-1422), ch. 419, p. 2124, § 181, effective August 11. L. 2013: (1)(a) amended, (SB 13-194), ch. 89, p. 289, § 2, effective April 1. L. 2020: (2) amended, (SB 20-030), ch. 148, p. 639, § 3, effective June 29. L. 2021: (1)(d)(II) amended, (HB 21-1105), ch. 488, p. 3496, § 3, effective September 7.

40-3-107. Transmission of business of other companies.

Every telephone public utility operating in this state shall receive, transmit, and deliver, without discrimination or delay, the conversations and messages of every other telephone public utility with whose line a physical connection may have been made.

Source: L. 13: p. 473, § 19. C.L. § 2930. CSA: C. 137, § 20. CRS 53: § 115-3-7. C.R.S. 1963: § 115-3-7. L. 69: p. 932, § 16. L. 2008: Entire section amended, p. 1792, § 7, effective July 1.

Cross references: For fixing of joint rates, see § 40-4-104.

40-3-107.5. Interconnection with renewable energy cooperatives.

Electric utilities shall interconnect with renewable energy cooperatives organized pursuant to section 7-56-210, C.R.S. Every renewable energy cooperative that desires to interconnect its system with any facilities owned or operated by a public utility shall comply with applicable interconnection rules and with reasonable standards and policies related to the reliability of the public utility system. All such standards and policies, as well as all costs for the interconnection, shall be fair, reasonable, and nondiscriminatory to each renewable energy cooperative.

Source: L. 2004: Entire section added, p. 1123, § 4, effective May 27.

40-3-108. Rates for long and short distances.

No telephone public utility subject to articles 1 to 7 of this title shall charge or receive any greater compensation in the aggregate for the transmission of any long distance message or conversation for a shorter than for a longer distance over the same line or route in the same direction within this state, the shorter being included within the longer distance, or charge any greater compensation for a through service than the aggregate of the intermediate rates or tolls subject to articles 1 to 7 of this title. Upon application to the commission, a telephone public utility may be authorized by the commission to charge less for a longer than a shorter distance service for the transmission of messages or conversations in special cases, after investigation; and the commission may from time to time prescribe the extent to which such telephone public utility may be relieved from the operation and requirements of this section.

Source: L. 13: p. 473, § 20. C.L. § 2931. CSA: C. 137, § 21. CRS 53: § 115-3-8. C.R.S. 1963: § 115-3-8. L. 69: p. 932, § 17. L. 2008: Entire section amended, p. 1793, § 8, effective July 1.

40-3-109. Street transportation public utility - transfers.

Every street transportation public utility shall, upon such terms as the commission finds to be just and reasonable, furnish to its passengers transfers entitling them to one continuous trip in the same general direction over and upon the portions of its lines within the same city and county, city, or town not reached by the originating vehicle.

Source: L. 13: p. 474, § 21. C.L. § 2932. CSA: C. 137, § 22. CRS 53: § 115-3-9. C.R.S. 1963: § 115-3-9. L. 69: p. 933, § 18.

40-3-110. Information furnished commission - reports.

1. Every public utility shall furnish to the commission, at such time and in such form as the commission may require, one or more reports in which the utility shall specifically answer all questions propounded by the commission upon or concerning which the commission may desire information. All reports must be made under oath or affirmation.
2. The commission may require a public utility to file monthly reports of earnings and expenses and to file periodic or special reports, or both periodic and special reports, concerning any matter about which the commission is authorized by articles 1 to 7 of this title 40 or in any other law to inquire or to keep itself informed or which it is required to enforce.
3. The commission shall require every public utility that reports information on disconnections and delinquencies pursuant to section 40-3-103.6 (1)(i) to also file an annual narrative containing the utility's analysis of any trends or inconsistencies revealed by the data.

Source: L. 13: p. 474, § 22. C.L. § 2933. CSA: C. 137, § 23. CRS 53: § 115-3-10. C.R.S. 1963: § 115-3-10. L. 2020: Entire section amended, (SB 20-030), ch. 148, p. 639, § 4, effective June 29.

Cross references: For duty of common carriers to report accidents, see § 40-9-108.

40-3-111. Rates determined after hearing.

1. Whenever the commission, after a hearing upon its own motion or upon complaint, finds that the rates, tolls, fares, rentals, charges, or classifications demanded, observed, charged, or collected by any public utility for any service, product, or commodity, or in connection therewith, including the rates or fares for excursion or commutation tickets, or that the rules, regulations, practices, or contracts affecting such rates, fares, tolls, rentals, charges, or classifications are unjust, unreasonable, discriminatory, or preferential, or in any way violate any provision of law, or that such rates, fares, tolls, rentals, charges, or classifications are insufficient, the commission shall determine the just, reasonable, or sufficient rates, fares, tolls, rentals, charges, rules, regulations, practices, or contracts to be thereafter observed and in force and shall fix the same by order. In making such determination, the commission may consider current, future, or past test periods or any reasonable combination thereof and any other factors which may affect the sufficiency or insufficiency of such rates, fares, tolls, rentals, charges, or classifications during the period the same may be in effect, and may consider any factors which influence an adequate supply of energy, encourage energy conservation, or encourage renewable energy development.
   1. (1.5) (a) If the commission considers environmental effects when comparing the costs and benefits of potential utility resources, it shall also make findings and give due consideration to the effect that acquiring such resources will have on the state's economy and employment, including, but not limited to, the effect on the mining, electric, natural gas, energy efficiency, and renewable resource industries.
   2. If the commission considers factors which encourage renewable energy development, it shall also make findings and give due consideration to the effect of such factors on the utility's ability to recover its capital and operating costs.
2. 1. The commission has the power, after a hearing upon its own motion or upon complaint, to investigate a single rate, fare, toll, rental, charge, classification, rule, contract, or practice, or the entire schedule of rates, fares, tolls, rentals, charges, classifications, rules, contracts, and practices of any public utility; and to establish new rates, fares, tolls, rentals, charges, classifications, rules, contracts, practices, or schedules, in lieu thereof.
   2. As part of any inquiry or investigation into rate structures of regulated electric utilities undertaken on or before July 1, 2009, the commission shall consider whether to adopt retail rate structures that enable the use of solar or other renewable energy resources in agricultural applications, including, but not limited to, irrigation pumping.

Source: L. 13: p. 475, § 23. C.L. § 2934. CSA: C. 137, § 24. CRS 53: § 115-3-11. C.R.S. 1963: § 115-3-11. L. 81: (1) amended, p. 1914, § 1, effective July 1. L. 93: (1.5) added, p. 202, § 1, effective March 31. L. 94: (1) and (1.5) amended, p. 611, § 3, effective April 8. L. 2008: (2) amended, p. 1793, § 9, effective July 1.

Cross references: For the legislative declaration contained in the 1994 act amending subsections (1) and (1.5), see section 1 of chapter 102, Session Laws of Colorado 1994.

40-3-112. Commission to provide local government with avoided cost information.

1. The general assembly hereby finds that it is in the interest of the people of this state to promote the production of energy and the disposal of solid waste in a manner designed to protect the environment; therefore, the general assembly hereby declares that it is the policy of this state to promote the development of systems which generate energy through the burning of solid waste in a manner designed to insure the maintenance of clean air standards.
2. Prior to the construction of a solid waste-to-energy incineration facility, any unit of local government contemplating construction of such a facility may, by written request, require the commission to calculate the avoided cost to a specified electric utility for the purchase of energy and capacity by said utility from said contemplated facility. Pursuant to such request the utility shall provide the commission with all data necessary to calculate said cost.
3. As used in this section, "solid waste-to-energy incineration facility" means a facility where flammable waste material is used as a primary fuel for the production of electrical power the total output of which exceeds one hundred kilowatts.

Source: L. 83: Entire section added, p. 1556, § 1, effective June 1.

Cross references: For the authority of counties and municipalities relating to solid waste-to-energy incineration systems, see part 9 of article 20 of title 30 and part 10 of article 15 of title 31.

40-3-113. Rail rates for transportation of recyclable or recycled materials. (Repealed)

Source: L. 84: Entire section added, p. 1040, § 6, effective July 1. L. 2000: Entire section repealed, p. 217, § 4, effective March 29.

40-3-114. Cost allocation - effect on competitive markets.

The commission shall ensure that regulated electric and gas utilities do not use ratepayer funds to subsidize nonregulated activities.

Source: L. 93: Entire section added, p. 2062, § 13, effective July 1.

40-3-115. Recovery of utility relocation costs.

1. As used in this section, unless the context otherwise requires:
   1. "Political subdivision" means a county, city and county, city, town, home rule city, home rule town, service authority, school district, local improvement district, law enforcement authority, water, sanitation, fire protection, metropolitan, irrigation, drainage, or other special district, or any other kind of municipal, quasi-municipal, or public organization organized pursuant to law.
   2. "State" means the state government, any state agency, state department, state institution, or state-level authority.
2. 1. Notwithstanding the provisions of section 40-15-502 (3)(b)(I) to (3)(b)(V), local exchange providers of basic local exchange service subject to regulation pursuant to part 2, part 3, or part 5 of article 15 of this title may request authorization from the commission to recover the actual costs incurred for the relocation of infrastructure or facilities requested by the state or a political subdivision. Actual costs are the nonfacility costs incurred in the relocation plus the undepreciated amount of the facilities being replaced. Recovery of actual costs incurred for relocation is intended for those state and political subdivision requests that are determined by the commission to be beyond the normal course of business.
   2. The commission shall verify the actual costs that may be recovered, determine the allocation of costs to various customers and services, and prescribe the method of such recovery. In no event shall the period of recovery of the relocation costs exceed three years.
   3. In determining the allocation of the costs to be recovered, the commission shall consider the jurisdiction requiring the relocation and the geographic area that most directly benefits from the required relocation to determine the customers or services that will bear the costs.

Source: L. 2003: Entire section added, p. 2640, § 1, effective August 6.

40-3-116. Electric vehicle programs - rates.

1. The rates and charges schedule for services provided by a program created under section 40-5-107 may allow:
   1. A return on any investment made under section 40-5-107 by an electric public utility at the electric public utility's weighted average cost of capital, including the most recent rate of return on equity, approved by the commission, including by allowing a utility to earn a rate of return on rebates provided to customers through a transportation electrification program;
   2. Rate recovery mechanisms that allow earlier, as determined by the commission, recovery of costs, including the use of rate adjustment clauses; and
   3. Performance-based incentive returns or similar investment incentives.
2. By May 15, 2020, an electric public utility shall submit to the commission a proposal for a specific rate or rates for electricity supplied to commercial and industrial facilities used to charge electric vehicles that encourage vehicle charging and that support the operation of the electric grid.

Source: L. 2019: Entire section added, (SB 19-077), ch. 383, p. 3434, § 3, effective May 31.

Cross references: For the legislative declaration in SB 19-077, see section 1 of chapter 383, Session Laws of Colorado 2019.

40-3-117. Performance-based rate-making - investigation - report - repeal. (Repealed)

Source: L. 2019: Entire section added, (SB 19-236), ch. 359, p. 3306, § 11, effective May 30.

Editor's note: Subsection (3) provided for the repeal of this section, effective September 1, 2021. (See L. 2019, p. 3306 .)

40-3-118. Electric utility retail rates survey - nonadjudicatory proceeding - definition - report - repeal. (Repealed)

Source: L. 2019: Entire section added, (SB 19-236), ch. 359, p. 3306, § 11, effective May 30.

Editor's note: Subsection (3) provided for the repeal of this section, effective September 1, 2021. (See L. 2019, p. 3306 .)

40-3.2-101. Legislative declaration.

The general assembly hereby finds, determines, and declares that cost-effective natural gas and electricity demand-side management programs will save money for consumers and utilities and protect Colorado's environment. The general assembly further finds, determines, and declares that providing funding mechanisms to encourage Colorado's public utilities to reduce emissions or air pollutants and to increase energy efficiency are matters of statewide concern and that the public interest is served by providing such funding mechanisms. Such efforts will result in an improvement in the quality of life and health of Colorado citizens and an increase in the attractiveness of Colorado as a place to live and conduct business.

Source: L. 98: Entire article added, p. 1050, § 3, effective July 1. L. 2007: Entire section amended, p. 984, § 2, effective May 22.

40-3.2-102. Recovery of air quality improvement costs.

1. A public utility shall be entitled to fully recover from its retail customers the air quality improvement costs that it prudently incurs as a result of a voluntary agreement entered into pursuant to part 12 of article 7 of title 25, C.R.S., after July 1, 1998, except as provided in subsection (7) of this section.
2. For the purposes of this article, "air quality improvement costs" means the incremental life-cycle costs including capital, operating, maintenance, fuel, and financing costs incurred or to be incurred by a public utility at electric generating facilities located in Colorado. To account for the timing differences between various costs and revenue recovery, life-cycle costs shall be calculated using net present value analysis.
3. Upon application by a public utility for cost recovery, the commission shall determine an appropriate method of cost recovery that assures full cost recovery for the public utility. The air quality improvement costs recovered by the public utility shall not cause an average rate impact greater than the equivalent of one and one-half mills per kilowatt hour in any period, nor shall such costs exceed a total of two hundred eleven million dollars calculated using 1998 net present value dollars. The air quality improvement costs for a generating facility shall be recovered over a period of fifteen years or less.
4. Any revenues a public utility receives from transferring, selling, banking, or otherwise using allowances established under Title IV of the federal "Clean Air Act" or under any other trading program of regional or national applicability shall be credited to the public utility's customers to offset air quality improvement costs if such revenues are a result of a voluntary agreement entered into under part 12 of article 7 of title 25, C.R.S.
5. To the extent that a voluntary agreement entered into under part 12 of article 7 of title 25, C.R.S., does not increase the public utility's electric generating capacity, the voluntary agreement shall not be subject to any restrictions that arise from the commission's integrated resources planning rules.
6. The commission shall assure that any future industry restructuring does not adversely affect the ability of the public utility to recover its air quality improvement costs. Nothing in this section shall prevent the commission from considering the appropriate value, including market value, of a public utility's generation assets in any future industry restructuring proceeding.
7. 1. If a public utility's wholesale sales are subject to regulation by the federal energy regulatory commission and the public utility sells power on the wholesale market from generating facilities that are subject to a voluntary agreement under part 12 of article 7 of title 25, C.R.S., the public utilities commission shall determine whether to assign a portion of the air quality improvement costs to be recovered from the public utility's wholesale customers. The public utilities commission may assign a portion of the air quality improvement costs to the public utility's wholesale customers to the extent that such portion of such cost recovery does not conflict with the public utility's wholesale contracts entered into prior to April 1, 1998.
   2. If the public utilities commission assigns a portion of the public utility's air quality improvement costs to be recovered from the public utility's wholesale customers, the public utility may apply to the federal energy regulatory commission for recovery, effective on the date of filing, of the portion of costs assigned to the public utility's wholesale customers. The public utilities commission shall permit the public utility to recover the portion of costs assigned to the public utility's wholesale customers from its retail customers pending the federal energy regulatory commission's approval of recovery from the public utility's wholesale customers.
   3. Notwithstanding paragraph (b) of this subsection (7), if the public utility fails to apply to the federal energy regulatory commission within six months after the public utilities commission's final order assigning a portion of the air quality improvement costs to the public utility's wholesale customers or fails to make a diligent, good faith effort to persuade the federal energy regulatory commission to approve the cost recovery from the public utility's wholesale customers, the public utility shall not be entitled to recover said portion of the costs from its retail customers.
   4. All revenues that a public utility receives from its wholesale customers for air quality improvement costs shall be credited as an offset to the air quality improvement costs charged to the public utility's retail customers.

Source: L. 98: Entire article added, p. 1050, § 3, effective July 1.

40-3.2-103. Gas distribution utility demand-side management programs - recovery of costs - reports.

1. Commencing in 2022 and no less frequently than every four years thereafter, each investor-owned gas distribution utility, also referred to in this section as a "gas utility", shall file an application to open a DSM strategic issues proceeding to develop energy savings targets to be achieved by the gas utility, taking into account its potential for cost-effective demand-side management as well as Colorado's greenhouse gas reduction goals. The commission shall, as part of approving a gas utility's gas DSM strategic issues application, also develop an estimated DSM budget commensurate with natural gas savings targets, funding and cost-recovery mechanisms, and a financial bonus structure for DSM programs implemented by a gas utility.
2. As part of the development of targets, mechanisms, and a bonus structure required by subsection (1) of this section, the commission shall:
   1. Adopt an estimated budget for DSM program expenditures commensurate with the energy savings targets established by the commission;
   2. Establish DSM program energy savings targets that are consistent with achieving the greenhouse gas reduction targets in section 25-7-102 (2)(g), take into consideration new clean energy technologies as contemplated by section 40-2-123, and reflect the maximum cost-effective and achievable natural gas savings potential for the gas utility consistent with the needs of its full-service customers;
   3. 1. 1. Adopt procedures for allowing gas utilities to recover their prudently incurred costs of DSM programs without having to file a rate case. Such costs shall include, but are not limited to, facility investments; rebates; interest rate buy-downs; incremental labor costs, employee benefits, carrying costs, and employee-related administrative costs; and other administrative costs. All such costs shall be recovered through a cost adjustment mechanism that is set on an annual basis, or more frequently if deemed appropriate. (c) (I) (A) Adopt procedures for allowing gas utilities to recover their prudently incurred costs of DSM programs without having to file a rate case. Such costs shall include, but are not limited to, facility investments; rebates; interest rate buy-downs; incremental labor costs, employee benefits, carrying costs, and employee-related administrative costs; and other administrative costs. All such costs shall be recovered through a cost adjustment mechanism that is set on an annual basis, or more frequently if deemed appropriate.
         2. Labor costs shall reflect, and the commission shall require, compliance with all applicable labor standards set forth in section 40-3.2-105.5.
      2. Cost adjustment procedures shall give gas utilities the option of obtaining cost recovery either through expensing DSM program expenditures or adding them to base rates, with an amortization period to be determined by the commission. In addition, such procedures shall provide that cost recovery for programs directed at residential customers are to be collected from residential customers only and that cost recovery for programs directed at nonresidential customers are to be collected from nonresidential customers only.
   4. Adopt a bonus structure to reward gas utilities for investments in cost-effective DSM programs. For each year of operation, the bonus shall be capped at twenty-five percent of the expenditures or twenty percent of the net economic benefits of the DSM programs, whichever amount is lower. The amount of the bonus awarded each year shall be determined based on the extent to which the gas utility has achieved the targets established by the commission in accordance with paragraphs (a) and (b) of this subsection (2). The bonus shall not count against a gas utility's authorized rate of return or be considered in rate proceedings.
   5. Consider the fact that implementing the new DSM programs may require a phase-in period before a gas utility is able to achieve the funding level determined by the commission pursuant to paragraph (a) of this subsection (2). A gas utility that implements a new DSM program in phases shall be eligible to receive a bonus under the bonus structure adopted pursuant to paragraph (d) of this subsection (2) during its phase-in period.
   6. Not adopt any measure authorizing a financial penalty against a gas utility that fails to meet the targets in any particular year.

   (2.5) For gas utilities with fewer than two hundred fifty thousand full-service customers, the commission may establish energy savings targets, a budget for gas DSM program expenditures, funding and cost-recovery mechanisms, and a financial bonus structure in the same proceeding in which the utility's gas DSM program plan is submitted for approval.

3. After the development of the targets, mechanisms, and bonus structure as described in subsection (1) of this section, each gas utility shall:
   1. 1. Develop gas DSM program plans designed to meet or exceed the energy savings targets established by the commission.
      2. Gas DSM program plans may be combined with electric DSM program plans, beneficial electrification plans, or other plans that reduce energy consumption or greenhouse gas emissions. Except as otherwise provided in subsections (3)(a)(III) and (3)(a)(IV) of this section, one or more of the gas DSM programs or measures, representing an aggregate total of at least twenty-five percent of overall residential gas DSM program expenditures, including expenditures serving income-qualified households, must be targeted to residential customers in income-qualified households.
      3. In the case of a gas utility with fewer than fifty thousand full-service customers, and except as otherwise provided in subsection (3)(a)(IV) of this section, one or more of the gas DSM programs or measures, representing an aggregate total of at least fifteen percent of overall residential gas DSM program expenditures, including expenditures serving income-qualified households, must be targeted to residential customers in income-qualified households.
      4. On or after January 1, 2026, the commission may commence proceedings to adjust the percentage specified in subsection (3)(a)(II) or (3)(a)(III) of this section in light of changed circumstances, so long as the resulting percentages represent a significant portion of gas DSM program expenditures and continue to make progress toward achievement of Colorado's energy efficiency and greenhouse gas emission reduction goals.
   2. In implementing approved DSM programs, use reasonable efforts to maximize energy savings consistent with the annual energy efficiency budget.
   1. (3.5) (a) To meet the energy savings targets established by the commission in accordance with this section, gas utilities shall consider including incentives for customers to utilize behind-the-meter thermal renewable sources. The commission shall not prohibit gas utilities from offering programs or incentives that encourage customers to replace gas-fueled appliances with efficient electric appliances.
   2. The commission shall not require the removal of gas-fueled appliances or equipment from an existing structure nor ban the installation of gas service lines to any new structure.
4. In implementing DSM programs, gas utilities may spend a disproportionate share of total expenditures on one or more classes of customers.
5. 1. The commission shall authorize each gas utility to recover money spent for education programs, impact and process evaluations, and program planning related to natural gas DSM programs offered by the gas utility without having to show that such expenditures, on an independent basis, are cost-effective. The commission may limit the amount spent for these activities.
   2. 1. Upon petition by a regulated gas utility, the commission shall remove disincentives to the implementation of effective gas DSM programs through the adoption of a rate adjustment mechanism that ensures that the revenue per customer approved by the commission in a general rate case proceeding is recovered by the gas utility without regard to the quantity of natural gas actually sold by the gas utility after the date the rate took effect. The commission shall separately calculate, for the rate class or classes to which a rate adjustment mechanism applies, the regulatory disincentives removed through that mechanism and collected or refunded by the gas utility through a tariff rider.
      2. Removing disincentives through a rate adjustment mechanism adopted pursuant to subsection (5)(b)(I) of this section does not preclude a gas utility from receiving a bonus pursuant to subsection (2)(d) of this section.
      3. The commission shall not reduce a gas utility's return on equity based solely on approval of a rate adjustment mechanism adopted pursuant to subsection (5)(b)(I) of this section.
6. 1. Gas utilities shall submit annual reports to the commission, as determined by the commission by rule. The annual report shall describe the gas utility's DSM programs and shall document program expenditures, energy savings impacts and the techniques used to estimate these impacts, the estimated cost-effectiveness of program expenditures, and any other information the commission may require.
   2. The commission shall review each report submitted pursuant to paragraph (a) of this subsection (6) and shall determine the level of bonus, if any, that the gas utility is eligible to collect on the basis of the information included in the report. The commission's determination shall be made within three months after receiving the report. Any such bonus shall be authorized as a supplement to the cost adjustment mechanism or alternative mechanism approved by the commission and shall be applied over a twelve-month period after approval of the bonus.
7. Gas utilities may continue DSM programs that were in existence on or before May 22, 2007, and shall not be required to obtain approval from the commission for such programs.
8. This section shall not be construed to extend the commission's authority to any nonregulated utility businesses or affiliates of a gas utility.

Source: L. 2007: Entire section added, p. 984, § 3, effective May 22. L. 2021: (1), IP(2), (2)(a), (2)(b), (2)(c)(I), (3), and (5) amended and (2.5) and (3.5) added, (HB 21-1238), ch. 330, p. 2133, § 4, effective September 7.

Editor's note: Section 8 of chapter 330 (HB 21-1238), Session Laws of Colorado 2021, provides that the act changing this section applies to plans, applications, or other documents reviewed by the public utilities commission on or after September 7, 2021.

Cross references: (1) For the definition of DSM programs, see § 40-1-102.

(2) For the legislative declaration in HB 21-1238, see section 1 of chapter 330, Session Laws of Colorado 2021.

40-3.2-104. Electricity utility demand-side management programs - rules - annual report - definition.

1. It is the policy of the state of Colorado that a primary goal of electric utility least-cost resource planning is to minimize the net present value of revenue requirements. The commission may adopt rules as necessary to implement this policy.
2. 1. The commission shall establish energy savings and peak demand reduction goals to be achieved by an investor-owned electric utility, taking into account the utility's cost-effective demand-side management potential, the need for electricity resources, the benefits of demand-side management investments, and other factors as determined by the commission.
   2. The energy savings and peak demand reduction goals must be at least five percent of the utility's retail system peak demand, measured in megawatts, in the base year and at least five percent of the utility's retail energy sales, measured in megawatt-hours, in the base year. The base year is 2006. The goals shall be met in 2018, counting savings in 2018 from demand-side management measures installed starting in 2006. The commission may establish interim goals and may revise the goals as it deems appropriate.
   3. Commencing January 1, 2019, the energy savings and peak demand reduction goals must be at least five percent of the utility's retail system peak demand, measured in megawatts, in the base year and at least five percent of the utility's retail energy sales, measured in megawatt-hours, in the base year. The base year is 2018. The goals shall be met in 2028, counting savings in 2028 from demand-side management measures installed starting in 2019. The commission may establish interim goals and may revise the goals as it deems appropriate.
3. The commission shall permit electric utilities to implement cost-effective electricity DSM programs to reduce the need for additional resources that would otherwise be met through a competitive acquisition process.
4. The commission shall ensure that utilities develop and implement DSM programs that give all classes of customers an opportunity to participate and shall give due consideration to the impact of DSM programs on nonparticipants and on low-income customers.
5. The commission shall allow an opportunity for a utility's investments in cost-effective DSM programs to be more profitable to the utility than any other utility investment that is not already subject to special incentives. In complying with this subsection (5), the commission shall consider, without limitation, the following incentive mechanisms, which shall take into consideration the performance of the DSM program:
   1. An incentive to allow a rate of return on demand-side management investments that is higher than the utility's rate of return on other investments;
   2. An incentive to allow the utility to accelerate the depreciation or amortization period for demand-side management investments;
   3. An incentive to allow the utility to retain a portion of the net economic benefits associated with a DSM program for its shareholders;
   4. An incentive to allow the utility to collect the costs of DSM programs through a cost adjustment clause;
   5. Other incentive mechanisms that the commission deems appropriate.
6. Each investor-owned electric utility shall submit an annual report to the commission describing the DSM programs implemented by the electric utility in the previous year. The report shall document the following:
   1. Program expenditures, including incentive payments;
   2. Peak demand and energy savings impacts and the techniques used to estimate those impacts;
   3. Avoided costs and the techniques used to estimate those costs;
   4. The estimated cost-effectiveness of the DSM programs;
   5. The net economic benefits of the DSM programs; and
   6. Any other information required by the commission.
7. For purposes of this section, "electric utility" or "utility" means "investor-owned utility".

Source: L. 2007: Entire section added, p. 984, § 3, effective May 22; (7) added, p. 1172, § 3, effective May 23. L. 2017: (2) amended, (HB 17-1227), ch. 209, p. 813, § 1, effective August 9. L. 2020: (5)(a) and (5)(b) amended, (HB 20-1402), ch. 216, p. 1059, § 72, effective June 30.

Cross references: For the definition of DSM programs, see § 40-1-102.

40-3.2-105. Reporting requirement. (Repealed)

Source: L. 2007: Entire section added, p. 984, § 3, effective May 22. L. 2017: Entire section repealed, (SB 17-044), ch. 4, p. 8, § 6, effective August 9.

40-3.2-105.5. Labor standards for gas DSM projects.

1. This section applies to all necessary plumbing, mechanical, and electrical work performed in connection with a project undertaken pursuant to a gas DSM program under this article 3.2 and for which a customer of an investor-owned utility applies for a rebate directly from the utility.
2. When practicable, the utility may assign its own employees to perform the work, subject to state licensing requirements and all applicable state and local rules, codes, and standards.
3. 1. The utility shall make use of a list, referred to in this section as the "certified contractor list", containing the names and contact information of:
      1. Qualified contractors that participate in apprenticeship programs that:
         1. Are registered with the United States department of labor's employment and training administration or with a state apprenticeship council recognized by the United States department of labor; and
         2. Have been providing training for at least six months; and
      2. Qualified mechanical, electrical, and plumbing contractors that participate in apprenticeship programs meeting the standards specified in section 24-92-115 (1)(a)(II).
   2. The Colorado department of labor and employment shall oversee the compilation of the certified contractor list through one of the following methods:
      1. Directing the state apprenticeship council, if available, to assemble the information; or
      2. Establish an application process whereby contractors would apply for inclusion in the list and provide evidence, in a form satisfactory to the department, that each applicant meets the criteria set forth in subsection (3)(a) of this section.
   3. The utility shall publish the certified contractor list on its website and include or reference the list in all of the utility's relevant marketing material for gas DSM programs.
   4. In addition to the certified contractor list, each investor-owned gas utility shall require its residential customers to use licensed plumbing and electrical contractors that perform the type of work appropriate to residential gas DSM installations for participation in gas DSM programs where a rebate is paid directly to the customer after the installation is complete and the customer uses a contractor.
4. The following requirements apply to gas DSM projects in new or existing buildings:
   1. For plumbing, mechanical, or electrical projects undertaken by a commercial or industrial customer in a building that contains twenty thousand square feet or more of conditioned floor space and for which a rebate is to be provided directly to the customer as part of a gas DSM program, the utility shall condition payment of the rebate on the customer's exclusive use of contractors from the certified contractor list unless the work is done by employees of the utility.
   2. 1. For plumbing, mechanical, or electrical projects that involve energy efficiency improvements to central building systems in a multifamily building that contains twenty thousand square feet or more of conditioned floor space and for which a rebate is to be provided directly to the building owner as part of a gas DSM program, the utility shall condition payment of the rebate on the building owner's exclusive use of contractors that participate in apprenticeship programs registered with the United States department of labor's employment and training administration or with a state apprenticeship council recognized by the United States department of labor for any necessary plumbing or electrical work. If the contractor chosen by the customer is not on the certified contractor list, the utility shall require another method of verifying compliance with this subsection (4)(b).
      2. This subsection (4)(b) does not apply to a gas DSM project that is limited to in-unit work in a multifamily building, as undertaken by the owner or tenant of the multifamily building or unit.

Source: L. 2021: Entire section added, (HB 21-1238), ch. 330, p. 2135, § 5, effective September 7.

Editor's note: Section 8 of chapter 330 (HB 21-1238), Session Laws of Colorado 2021, provides that the act adding this section applies to plans, applications, or other documents reviewed by the public utilities commission on or after September 7, 2021.

Cross references: For the legislative declaration in HB 21-1238, see section 1 of chapter 330, Session Laws of Colorado 2021.

40-3.2-105.6. Labor standards for beneficial electrification projects.

1. This section applies to all necessary mechanical, plumbing, and electrical work performed in connection with a project undertaken pursuant to a beneficial electrification program under this article 3.2 and for which a customer of an investor-owned electric utility applies for a rebate directly from the utility.
2. When practicable, the utility may assign its own employees to perform the work, subject to state licensing requirements and all applicable state and local rules, codes, and standards.
3. 1. The utility shall obtain from the Colorado department of labor and employment and shall make use of a list, referred to in this section as the "certified contractor list", containing the names and contact information of:
      1. Qualified contractors that participate in apprenticeship programs that are registered with the United States department of labor's employment and training administration or with a state apprenticeship council recognized by the United States department of labor; and
      2. Qualified mechanical, electrical, and plumbing contractors that meet the graduation standards specified in section 24-92-115 (1)(a)(II).
   2. The utility shall publish the certified contractor list on its website and include or reference the list in all of the utility's relevant marketing material for beneficial electrification programs.
   3. As a condition for customer participation in beneficial electrification programs where a rebate is paid directly to the customer after installation is complete, each investor-owned electric utility shall require its residential customers to verify that they used licensed electricians and plumbers or properly supervised apprentices on all plumbing and electrical work performed by a contractor on residential installations that qualify for a beneficial electrification rebate.
4. The following requirements apply to beneficial electrification projects in new or existing industrial, commercial, or multifamily residential buildings:
   1. For plumbing, mechanical, or electrical projects undertaken by a commercial or industrial customer in a building that contains twenty thousand square feet or more of conditioned floor space and for which a rebate is to be provided directly to the customer as part of a beneficial electrification program, the utility shall condition payment of the rebate on the customer's exclusive use of contractors from the certified contractor list unless the work is done by employees of the utility.
   2. 1. For plumbing, mechanical, or electrical projects that involve the beneficial electrification of central building systems in a multifamily building that contains twenty thousand square feet or more of conditioned floor space and for which a rebate is to be provided directly to the building owner as part of a beneficial electrification program, the utility shall condition payment of the rebate on the building owner's exclusive use of contractors that participate in apprenticeship programs registered with the United States department of labor's employment and training administration or with a state apprenticeship council recognized by the United States department of labor for any necessary plumbing or electrical work. If the contractor chosen by the building owner is not on the certified contractor list, the utility shall require another method of verifying compliance with this subsection (4)(b).
      2. This subsection (4)(b) does not apply to a beneficial electrification project that is limited to in-unit work in a multifamily building, as undertaken by the owner or tenant of the multifamily building or unit.

Source: L. 2021: Entire section added, (SB 21-246), ch. 283, p. 1677, § 5, effective September 7.

Cross references: For the legislative declaration in SB 21-246, see section 1 of chapter 283, Session Laws of Colorado 2021.

40-3.2-106. Costs of pollution in utility planning - rules.

1. The commission shall require an electric or gas public utility subject to commission jurisdiction to consider the social cost of carbon dioxide emissions and the social cost of methane emissions, as set forth in subsections (4) and (5) of this section, when determining the cost, benefit, or net present value of any plan or proposal submitted in one of the following proceedings:
   1. Electric resource plans or any utility plan or application that considers or proposes the acquisition of new electric generating resources or the retirement of existing utility generation;
   2. Applications related to section 40-2-124;
   3. Applications related to, or the commission's evaluation of, programs adopted under section 40-3.2-103;
   4. Applications related to, or the commission's evaluation of, programs adopted under section 40-3.2-104; or
   5. A plan or application for transportation electrification under section 40-5-107 or any other form of beneficial electrification, including beneficial electrification in buildings.
2. In a proceeding listed in subsection (1)(a) of this section, a utility shall:
   1. At a minimum, model an optimization of a base case portfolio of resources using the cost of carbon dioxide emissions, as set forth pursuant to subsection (4) of this section. The cost of carbon dioxide emissions must apply to the evaluation of all existing electric generation resources and to any new resources evaluated or proposed as part of the resource modeling. The commission may require a utility to file or propose additional base cases. The utility may propose, and the commission shall consider, alternative optimized portfolios of resources in addition to the base case, utilizing different levels of costs for carbon dioxide.
   2. 1. Present a calculation of the net present value of revenue requirement for the resources in each optimized portfolio. To show the net present value of revenue requirement that would be incurred by the utility for implementing the portfolio, in addition to presenting the full net present value of revenue requirement through a calculation using the cost of carbon dioxide emissions set forth pursuant to subsection (4) of this section, the utility shall also present the full net present value of revenue requirement through a calculation without using the cost of carbon dioxide emissions set forth pursuant to subsection (4) of this section.
      2. In addition to the net present value of revenue requirement calculations required in subsection (2)(b)(I) of this section, for each optimized model run, the utility must provide a present value calculation showing the net present value of the total cost of carbon dioxide emissions of each portfolio, calculated by multiplying the total emissions of that portfolio by the cost of carbon dioxide set forth pursuant to subsection (4) of this section.
3. In approving a resource plan, either with generic resources or in the analysis of bids in a competitive solicitation, the commission shall require a comparison of the portfolios' net present value of revenue requirements inclusive of the social cost of carbon dioxide. The commission shall also consider:
   1. The net present value of revenue requirements of the cost of carbon dioxide or carbon dioxide equivalent emissions;
   2. The net present value of revenue requirements that would be incurred by the utility for implementing the portfolio; and
   3. Other relevant factors, as determined by the commission.
4. The commission shall base the cost of carbon dioxide emissions on the most recent assessment of the social cost of carbon dioxide developed by the federal government using a discount rate of two and one-half percent or less. Starting in 2020, the commission shall use a social cost of carbon dioxide of not less than sixty-eight dollars per short ton. The commission shall modify the cost of carbon dioxide emissions based on escalation rates of the 2020 base cost by an amount that is equal to or greater than the escalation rates established in the technical support document. When calculating the cost of carbon dioxide emissions for any proceeding listed in subsection (1) of this section, the commission shall use a discount rate for the social cost of carbon dioxide that does not exceed the lesser of two and one-half percent or any lower value established by the most recent available successor to the technical support document. Notwithstanding the discount rate used to develop the social cost of carbon dioxide value over the planning period, the commission shall continue to discount any net present value analysis of any optimized resource portfolio in the electric resource planning process using discount rates that the commission deems appropriate.
5. In the base case analysis of cost effectiveness as described in section 40-1-102 (5)(b), the commission shall apply the social cost of carbon dioxide and the social cost of methane emissions to the benefit-cost calculation for programs that are defined to be energy efficiency or beneficial electrification programs or that incorporate behind-the-meter thermal renewable sources.
6. Repealed.

Source: L. 2019: Entire section added, (SB 19-236), ch. 359, p. 3309, § 13, effective May 30. L. 2021: IP(3) and (3)(a) amended, (SB 21-272), ch. 220, p. 1161, § 8, effective June 10; IP(1), (1)(c), (4), and (5) amended and (1)(c.5) added, (HB 21-1238), ch. 330, p. 2137, § 6, effective September 7; IP(1), (1)(d), and (5) amended and (6) repealed, (SB 21-246), ch. 283, p. 1676, § 4, effective September 7.

40-3.2-107. Costs of methane pollution in gas DSM program planning - rules - definitions.

1. The commission shall require a gas public utility subject to commission jurisdiction to consider the social cost of methane emissions, as set forth in subsection (2) of this section, when determining the cost, benefit, or net present value of revenue requirements of any plan or proposal submitted in an application related to, or the commission's evaluation of, programs adopted under section 40-3.2-103.
2. 1. The commission shall base the social cost of methane emissions on the most recent assessment of the global social cost of methane developed by the federal government, using a discount rate of two and one-half percent or less as updated to reflect the latest available figures derived from peer-reviewed, published studies; except that, beginning on September 7, 2021, the commission shall use a social cost of methane of not less than one thousand seven hundred fifty-six dollars per short ton. The commission shall modify the social cost of methane emissions based on escalation rates of the 2020 base cost by an amount that is equal to or greater than the escalation rates established in the addendum to the technical support document and shall use a discount rate that does not exceed the lesser of two and one-half percent or any lower value established by the most recent available successor to the technical support document.
   2. When calculating the cost of methane emissions for any purpose listed in subsection (1) of this section, the commission shall obtain and apply the best available values for natural gas leakage during the extraction, processing, transportation, and delivery of natural gas by the gas public utility as well as leakage from piping or other equipment on customer premises. The commission shall take into account any relevant data and emissions accounting methodologies developed by the air quality control commission pursuant to section 25-7-140 regarding methane leakage rates and the appropriate global warming potential of methane. The commission shall use the same discount rate as that used to develop the federal social cost of methane, as set forth in the addendum to the technical support document.
   3. Notwithstanding the discount rate used for the cost of methane emissions, the commission shall discount other future cost streams into the net present value analysis of any resource portfolio in the gas DSM program planning process using a discount rate that the commission deems relevant to the parties responsible for financing or paying these future costs. When ratepayers are covering costs without investment from gas public utilities, such as environmental costs or pass-through fuel costs, the commission shall give consideration to discounting those costs with a stable long-term inflation rate that, in the commission's judgment, accurately represents the net present value of future cash flows experienced by ratepayers.
3. As used in this section:
   1. "Addendum to the technical support document" means the 2016 addendum of the federal interagency working group on social cost of greenhouse gases, entitled "Addendum to Technical Support Document on Social Cost of Carbon for Regulatory Impact Analysis under Executive Order 12866: Application of the Methodology to Estimate the Social Cost of Methane and the Social Cost of Nitrous Oxide".
   2. "Technical support document" means the 2016 technical support document of the federal interagency working group on social cost of greenhouse gases, entitled "Technical Update of the Social Cost of Carbon for Regulatory Impact Analysis Under Executive Order 12866".

Source: L. 2021: Entire section added, (HB 21-1238), ch. 330, p. 2138, § 7, effective September 7.

Editor's note: Section 8 of chapter 330 (HB 21-1238), Session Laws of Colorado 2021, provides that the act adding this section applies to plans, applications, or other documents reviewed by the public utilities commission on or after September 7, 2021.

Cross references: For the legislative declaration in HB 21-1238, see section 1 of chapter 330, Session Laws of Colorado 2021.

40-3.2-108. Clean heat targets - legislative declaration - definitions - plans - rules - reports.

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

Source: L. 2021: Entire section added, (SB 21-264), ch. 328, p. 2093, § 1, effective June 24.

Editor's note: Section 5 of chapter 328 (SB 21-264), Session Laws of Colorado 2021, provides that the act adding this section applies to conduct occurring on or after June 24, 2021.

40-3.2-109. Beneficial electrification plans for electric utilities - definition - rules - recovery of costs - report.

1. Definition. As used in this section, "beneficial electrification plan" or "plan" means an electric utility's plan to increase beneficial electrification in the residential, commercial, and industrial sectors for purposes other than transportation.
2. 1. The commission shall allow an investor-owned electric utility to implement cost-effective beneficial electrification plans that support voluntary customer adoption of beneficial electrification measures.
   2. On or before July 1, 2022, and thereafter as directed by the commission, but no less frequently than every three years, an investor-owned electric utility shall file with the commission an application for a beneficial electrification plan for regulated activities to support beneficial electrification. Beneficial electrification plans may be combined with other demand-side management strategic issues or transportation electrification plans, as applicable, but a beneficial electrification plan must, at a minimum:
      1. Include proposed programs to advance beneficial electrification for residential and commercial customers. Plans may also include programs to advance beneficial electrification for industrial customers.
      2. Include programs targeted to low-income households or disproportionately impacted communities, with at least twenty percent of the total beneficial electrification program funding targeted to programs that serve low-income households or disproportionately impacted communities;
      3. Include budgets; targeted numbers of installations; projected fuel savings; projected cost-effectiveness calculations, including the social cost of methane and carbon dioxide emissions and an appropriate social discount rate in the cost-benefit analysis; projected reductions in greenhouse gas emissions; and other information deemed relevant by the commission for the plan as a whole and for each program included in the plan;
      4. Demonstrate that the utility will, to the greatest extent practicable, serve incremental load attributable to beneficial electrification with generation that can be reasonably expected to have a carbon intensity no higher than the average carbon intensity for all generation in the utility's portfolio;
      5. Include incentives to facilitate beneficial electrification, with programs targeted toward new and existing building markets. Products eligible for incentives must be certified under the federal Energy Star program, as defined in section 6-7.5-102 (15), or a successor program if that certification is available, in product categories for which such certification exists.
      6. Include an outreach plan for engagement with customers in low-income households and disproportionately impacted communities to develop programs to support those customers in every phase of the utility's beneficial electrification programs, including through incentives offered to multifamily buildings occupied in full or in part by low-income households; and
      7. Include documentation and data to show that the utility's beneficial electrification plan is consistent with maintaining the reliability of the electric grid.
3. The commission and investor-owned electric utilities subject to commission jurisdiction shall:
   1. Incorporate into the cost-benefit analysis of beneficial electrification plans and programs:
      1. The social costs of carbon dioxide and methane emissions, including the avoided carbon dioxide emissions from the direct combustion of fossil fuel in appliances or industrial equipment that is replaced with electricity;
      2. The avoided upstream emissions of methane from the production and delivery of fossil fuel to the appliance or equipment;
      3. The incremental carbon dioxide emissions from generation of electricity; and
      4. The incremental load attributable to beneficial electrification;
   2. Use the methodology defined in section 40-3.2-106 (4) to determine the cost of carbon dioxide emissions;
   3. Base the cost of methane emissions on the most recent assessment of the global social cost of methane developed by the federal government, using a discount rate of two and one-half percent or less; except that, beginning on September 7, 2021, the commission shall use a social cost of methane of not less than one thousand seven hundred fifty-six dollars per short ton. The commission shall modify the social cost of methane based on escalation rates of the 2020 base cost by an amount that is equal to or greater than the escalation rates established in the addendum to the technical support document and shall use a discount rate that does not exceed the lesser of two and one-half percent or any lower value established by the most recent available successor to the technical support document.
   4. Include upstream leakage of methane emissions in the extraction, production, and transportation of fossil gas in the cost-benefit analysis if the air quality control commission determines an estimate for upstream methane leakage.
4. Notwithstanding any other provision of law, the commission shall allow an electric utility to offer incentives to its customers to replace gas appliances with high-efficiency electric appliances.
5. 1. The commission shall allow an electric utility to recover its prudently incurred costs, on a current basis, for implementation of approved beneficial electrification programs.
   2. The commission may provide an electric utility an opportunity to earn incentives for exceeding beneficial electrification targets or emission-reduction performance targets that the commission has established for the beneficial electrification plan. For purposes of implementing this subsection (5)(b), the commission may consider incentive mechanisms to promote the advancement of the utility's beneficial electrification programs, which may include:
      1. An incentive rate of return on beneficial electrification investments;
      2. An incentive to allow the utility to accelerate depreciation;
      3. An incentive to allow the utility to retain a portion of the net economic benefits of beneficial electrification;
      4. An incentive to allow the utility to collect the cost of beneficial electrification programs through a rider or cost adjustment clause; or
      5. Any other incentive mechanism the commission deems appropriate.
6. 1. By April 1, 2024, and thereafter as determined by the commission but no less frequently than every six years, an investor-owned electric utility shall file an application for a beneficial electrification strategic issues filing that proposes a ten-year beneficial electrification target and objective criteria for measuring progress toward attainment of the target, which criteria may include the level of substitution of renewable sources for fossil fuel or the level of reduction in greenhouse gas emissions. The commission shall approve or amend and approve the utility's application, taking into account the utility's potential for cost-effective beneficial electrification, the state's greenhouse gas pollution reduction targets, and the potential for beneficial electrification to reduce greenhouse gas emissions.
   2. The beneficial electrification strategic issues filing may be combined with other demand-side management strategic issues or related filings as appropriate, and an investor-owned gas utility may file with the commission an application for a beneficial electrification plan for regulated activities to support beneficial electrification as part of such a proceeding or as a separate application. A beneficial electrification plan filed by an investor-owned gas utility is eligible for the same treatment as a beneficial electrification plan filed by an investor-owned electric utility pursuant to this section.
7. The electric utility or other entity commissioning a beneficial electrification project shall ensure compliance with the labor standards set forth in section 40-3.2-105.6.
8. Each electric utility that implements a beneficial electrification plan shall submit to the commission an annual report describing the beneficial electrification programs implemented under the plan and documenting:
   1. Program expenditures, energy savings, incremental additional electric load attributable to approved beneficial electrification programs, and incremental additional greenhouse gas emissions associated with beneficial electric load attributable to approved beneficial electrification programs;
   2. Assumed avoided greenhouse gas emissions from other sectors resulting from approved beneficial electrification programs;
   3. Societal costs and benefits of approved beneficial electrification programs as well as the techniques used to calculate those impacts;
   4. Compliance with the labor standards set forth in section 40-3.2-105.6; and
   5. Any other information that the commission requests.
9. Municipally owned electric utilities, cooperative electric associations, and wholesale electric cooperatives, as defined in section 40-2-134, in Colorado are encouraged to:
   1. Develop beneficial electrification plans as addressed in this section and transportation electrification programs pursuant to section 40-5-107 that help their customers invest in beneficial electrification in buildings and transportation;
   2. Account for the social cost of carbon dioxide and methane emissions, set total energy savings and greenhouse-gas-emission-reduction goals, and implement beneficial electrification programs for their customers;
   3. Include a beneficial electrification plan or transportation electrification program as part of a clean energy plan; and
   4. Participate in statewide or regional initiatives to increase the availability of, develop the market for, and support contractor training on high-efficiency electric technologies.
10. In implementing this section, the commission shall not require the removal of gas-fueled appliances or equipment from any existing structure or ban the installation of gas service lines to any new structure.

Source: L. 2021: Entire section added, (SB 21-246), ch. 283, p. 1677, § 5, effective September 7.

Cross references: For the legislative declaration in SB 21-246, see section 1 of chapter 283, Session Laws of Colorado 2021.

40-3.2-201. Short title.

This part 2 shall be known and may be cited as the "Clean Air - Clean Jobs Act".

Source: L. 2010: Entire part added, (HB 10-1365), ch. 140, p. 466, § 1, effective April 19.

40-3.2-202. Legislative declaration.

1. The general assembly hereby finds, determines, and declares that the federal "Clean Air Act", 42 U.S.C. sec. 7401 et seq., will likely require reductions in emissions from coal-fired power plants operated by rate-regulated utilities in Colorado. A coordinated plan of emission reductions from these coal-fired power plants will enable Colorado rate-regulated utilities to meet the requirements of the federal act and protect public health and the environment at a lower cost than a piecemeal approach. A coordinated plan of reduction of emissions for Colorado's rate-regulated utilities will also result in reductions in many air pollutants and promote the use of natural gas and other low-emitting resources to meet Colorado's electricity needs, which will in turn promote development of Colorado's economy and industry.
2. The general assembly further finds that the use of natural gas to reduce coal-fired emissions may require rate-regulated utilities to enter into long-term contracts for natural gas in a manner that protects electricity consumers. Even though such long-term contracts might be beneficial to consumers, financial rating agencies could find that such long-term contracts increase the financial risk to rate-regulated utilities, which in turn could increase the cost of capital to these utilities. The general assembly finds that it is important to give financial markets confidence that utilities will be able to recover the costs of long-term gas contracts without the risk of future regulators disallowing contracts.
3. The general assembly further finds and declares that Colorado rate-regulated utilities require timely and forward-looking reviews of their costs of providing utility service in order to undertake the comprehensive and extensive planning and changes to their business operations contemplated by this part 2. In order to allow these utilities to continue to provide reliable electric service, alter their operations in the manner described by this part 2, and meet other state public policy goals, it is imperative that Colorado rate-regulated utilities continue in sound financial condition and remain attractive investments so that sufficient capital is provided to achieve the state's goals. To that end, the general assembly finds that the commission should have additional tools and more flexibility in its regulatory authority to ensure the continued financial health of these utilities. The general assembly also finds and declares that the actions provided for in this part 2 be implemented in a manner to address the sound economic, health, and environmental conditions of energy producing communities.

Source: L. 2010: Entire part added, (HB 10-1365), ch. 140, p. 466, § 1, effective April 19.

40-3.2-203. Definitions.

As used in this part 2, unless the context otherwise requires:

1. "Air quality control commission" means the commission created in section 25-7-104, C.R.S.
2. "Department" means the department of public health and environment.
3. "Federal act" means the federal "Clean Air Act", 42 U.S.C. sec. 7401 et seq., as amended.
4. "State act" means the "Colorado Air Pollution Prevention and Control Act", article 7 of title 25, C.R.S.
5. "State implementation plan" means the plan required by and described in section 110 (a) and other provisions of the federal act.

Source: L. 2010: Entire part added, (HB 10-1365), ch. 140, p. 467, § 1, effective April 19.

40-3.2-204. Emission control plans - role of the department of public health and environment - timing of emission reductions - approval.

1. On or before August 15, 2010, and in coordination with current or expected requirements of the federal act and the state act, all rate-regulated utilities that own or operate coal-fired electric generating units located in Colorado shall submit to the commission an emission reduction plan for emissions from those units.
2. 1. The plan filed under this section shall cover a minimum of nine hundred megawatts or fifty percent of the utility's coal-fired electric generating units in Colorado, whichever is smaller. Except as set forth in section 40-3.2-206, the coal-fired capacity covered under the plan filed under this section shall not include any coal-fired capacity that the utility has already announced that it plans to retire prior to January 1, 2015. At the utility's discretion, the plan may include some or all of the following elements:
      1. New emission control equipment for oxides of nitrogen and other pollutants;
      2. Retirement of coal-fired units, if the retired coal-fired units are replaced by natural gas-fired electric generation or other low-emitting resources as defined in section 40-3.2-206, including energy efficiency;
      3. Conversion of coal-fired generation to run on natural gas;
      4. Long-term fuel supply agreements;
      5. New natural gas pipelines and other supporting gas infrastructure;
      6. Increased utilization of existing gas-fired generating capacity;
      7. New transmission lines and other supporting transmission infrastructure;
      8. Emission control equipment that is required to be installed at affected units prior to or in conjunction with any retirement, conversion, or emission control equipment retrofit set forth under the plan in order to limit any pollutant other than oxides of nitrogen; and
      9. Any other capital, fuel, and operations and maintenance expenditures appropriate to support the implementation of the plan.
   2. 1. Prior to filing the plan, the utility shall consult with the department and shall work with the department in good faith to design a plan to meet the current and reasonably foreseeable requirements of the federal act and state law in a cost-effective and flexible manner.
      2. The commission shall provide the department an opportunity to:
         1. Comment on the air quality, all other air pollutants, and other emission reductions of the plan; and
         2. Evaluate and determine whether the plan is consistent with the current and reasonably foreseeable requirements of the federal act.
      3. In commenting upon the utility's plan, the department shall determine whether any new or repowered electric generating unit proposed under the plan, other than a peaking facility utilized less than twenty percent on an annual basis or a facility that captures and sequesters more than seventy percent of emissions not subject to a national ambient air quality standard or a hazardous air pollutant standard, will achieve emission rates equivalent to or less than a combined-cycle natural gas generating unit.
      4. The commission shall not approve a plan except after an evidentiary hearing and unless the department has determined that the plan is consistent with the current and reasonably foreseeable requirements of the federal act.
   3. The plan shall include a schedule that would result in full implementation of the plan on or before December 31, 2017. The schedule may include interim milestones. The utility shall design the schedule to protect system reliability, control overall cost, and assure consistency with the requirements of the federal act.
   4. The plan shall set forth the costs associated with activities identified in the plan, including the planning, development, construction, and operation of elements identified pursuant to subparagraphs (I) to (IX) of paragraph (a) of this subsection (2), as well as the costs of any shutdown, decommissioning, or repowering of existing coal-fired electric generating units that are set forth in the plan.

Source: L. 2010: Entire part added, (HB 10-1365), ch. 140, p. 468, § 1, effective April 19.

40-3.2-205. Review - approval.

1. In evaluating the plan, the commission shall consider the following factors:
   1. Whether the department reports that the plan is likely to achieve at least a seventy to eighty percent reduction, or greater, in annual emissions of oxides of nitrogen as necessary to comply with current and reasonably foreseeable requirements of the federal act and the state act. The reduction in emissions under this paragraph (a) shall be measured from 2008 levels at coal-fired power plants identified in the plan. In determining the reduction in emissions under this paragraph (a), the department shall include:
      1. Emissions from coal-fired power plants identified in the plan and continuing to operate after retrofit with emission control equipment; and
      2. Emissions from any facilities constructed to replace any retired coal-fired power plants identified in the plan.
   2. Whether the department has made the determination under section 40-3.2-204 (2)(b)(III);
   3. The degree to which the plan will result in reductions in other air pollutant emissions;
   4. The degree to which the plan will increase utilization of existing natural gas-fired generating capacity;
   5. The degree to which the plan enhances the ability of the utility to meet state or federal clean energy requirements, relies on energy efficiency, or relies on other low-emitting resources;
   6. Whether the plan promotes Colorado economic development;
   7. Whether the plan preserves reliable electric service for Colorado consumers;
   8. Whether the plan is likely to help protect Colorado customers from future cost increases, including costs associated with reasonably foreseeable emission reduction requirements; and
   9. Whether the cost of the plan results in reasonable rate impacts. In evaluating the rate impacts of the plan, the commission shall examine the impact of the rates on low-income customers.
2. The commission shall review the plan and enter an order approving, denying, or modifying the plan by December 15, 2010. Any modifications required by the commission shall result in a plan that the department determines is likely to meet current and reasonably foreseeable federal and state act requirements.
3. All actions taken by the utility in furtherance of, and in compliance with, an approved plan are presumed to be prudent actions, the costs of which are recoverable in rates as provided in section 40-3.2-207.
4. If the utility disagrees with the commission's modifications to its proposed plan with respect to resource selection, the utility may withdraw its application.

Source: L. 2010: Entire part added, (HB 10-1365), ch. 140, p. 469, § 1, effective April 19.

40-3.2-206. Coal plant retirements - replacement resources.

1. 1. The general assembly finds that, in designing a coordinated emission reduction plan as described in section 40-3.2-204 and to expeditiously accelerate coal plant retirements, it is in the public interest for utilities to give primary consideration to replacing or repowering their coal generation with natural gas generation and that utilities shall also consider other low-emitting resources, including energy efficiency, if this replacement or repowering can be accomplished prudently and for reasonable rate impacts compared with placing additional emission controls on coal-fired generating units, and if electric system reliability can be preserved. To that end, in the plan required under section 40-3.2-204, each utility shall include an evaluation of the following proposals:
      1. The cost and system reliability impacts of retiring a minimum of nine hundred megawatts of coal-fired electric generating capacity, or fifty percent of the utility's coal-fired generating units in Colorado, whichever is less, by January 1, 2015, and repowering the affected coal-fired facilities with natural gas or replacing them with natural gas-fired generation or other low-emitting resources, including energy efficiency. The coal-fired capacity evaluated under this subparagraph (I) shall not include any coal-fired capacity that the utility has already announced that it plans to retire prior to January 1, 2015. The utility may also prepare evaluations of additional scenarios, including scenarios that result in the retirement of less than nine hundred megawatts of coal-fired electric generating capacity or the retirement of some portion of the nine hundred megawatts of capacity after January 1, 2015, but before January 1, 2018.
      2. Retirements of a portion of its coal-fired generating capacity in the period after April 19, 2010, but prior to January 1, 2015. At a minimum, the utility shall evaluate whether to retire a portion of its coal-fired capacity on or before January 1, 2013, or whether the retirements of coal-fired generating facilities that have already been announced could be advanced to an earlier retirement date.
   2. 1. For all evaluations required by this subsection (1), the utility shall report:
         1. The estimated overall impacts on the utility's emissions of oxides of nitrogen and other pollutants;
         2. The feasibility of the retirement, repowering, or replacement on the schedule proposed in the evaluation;
         3. The costs and impact on electric rates from these proposals; and
         4. The impact of the retirements on the reliability of the utility's electric service.
      2. All evaluations required by this subsection (1) shall contrast the costs of replacing coal generation with natural gas generation and other low-emitting resources, including energy efficiency, with the costs of installing additional emission controls on the coal plants.
2. The utility shall set forth in its plan the utility's proposal for the best way of timely meeting the emission reduction requirements required by federal and state law, given the need to preserve electric system reliability, to avoid unreasonable rate increases, and the economic and environmental benefits of coordinated emission reductions.
3. In reviewing the reasonableness of the utility's proposed plan, the commission shall:
   1. Compare the relative costs of repowering or replacing coal facilities with natural gas generation or other low-emitting resources, including energy efficiency, to an alternative that incorporates emission controls on the existing coal-fired units;
   2. Use reasonable projections of future coal and natural gas costs;
   3. Incorporate a reasonable estimate for the cost of reasonably foreseeable emission regulation consistent with the commission's existing practice;
   4. Consider the degree to which the plan will increase utilization of existing natural gas-fired generating resources available to the utility, together with increased utilization of other low-emitting resources including energy efficiency; and
   5. Consider the economic and environmental benefits of a coordinated emissions reduction strategy.
4. The utility may enter into long-term gas supply agreements to implement the requirements of this part 2. A long-term gas supply agreement is an agreement with a term of not less than three years or more than twenty years. All long-term gas supply agreements may be filed with the commission for review and approval. The commission shall determine whether the utility acted prudently by entering into the specific agreement, whether the proposed agreement appears to be beneficial to consumers, and whether the agreement is in the public interest. If an agreement is approved, the utility is entitled to recover through rates the costs it incurs under the approved agreement, and any approved amendments to the agreement, notwithstanding any change in the market price of natural gas during the term of the agreement. The commission shall not reverse its approval of the long-term gas agreement even if the agreement price is higher than a future market price of natural gas.

Source: L. 2010: Entire part added, (HB 10-1365), ch. 140, p. 470, § 1, effective April 19.

40-3.2-207. Cost recovery - legislative declaration.

1. 1. A utility is entitled to fully recover the costs that it prudently incurs in executing an approved emission reduction plan, including the costs of planning, developing, constructing, operating, and maintaining any emission control or replacement capacity constructed pursuant to the plan, as well as any interim air quality emission control costs the utility incurs while the plan is being implemented.
   2. The general assembly finds that the emissions reductions under this part 2 are being made to assist the state of Colorado to comply with current and reasonably foreseeable emission restrictions under federal law. To provide this assistance, the utility is being asked to make substantial capital investments and to enter into substantial contractual commitments in an expedited time period outside of the normal resource planning process.
2. 1. If a public utility's wholesale sales are subject to regulation by the federal energy regulatory commission, and if the public utility sells power on the wholesale market from a project developed pursuant to the plan, the commission shall determine whether to assign a portion of the plan cost to be recovered from the public utility's wholesale customers. The commission may make such assignment to the extent that it does not conflict with the public utility's wholesale contracts entered into before April 19, 2010.
   2. Except as specified in paragraph (c) of this subsection (2), if the commission makes an assignment of costs pursuant to paragraph (a) of this subsection (2) and if the utility applies to the federal energy regulatory commission for recovery and pursues that application in good faith, then:
      1. To the extent that the federal energy regulatory commission does not permit recovery of the allocated wholesale portion of plan-related investment, the commission shall approve retail rates sufficient to recover such disallowed wholesale portion of the investment through the recovery mechanism detailed in this section; and
      2. The public utility may not recover any revenue shortfall caused by a delay in making any filing with the federal energy regulatory commission or due to any rate suspension period employed by the federal energy regulatory commission or because the public utility failed to pursue recovery of the amounts at the federal energy regulatory commission in good faith.
   3. If the public utility fails to apply to the federal energy regulatory commission within six months after the commission's final order assigning a portion of the plan's costs to the public utility's wholesale customers, the public utility is not entitled to recover the assigned portion of the costs from its retail customers.
3. Current recovery shall be allowed on construction work in progress at the utility's weighted average cost of capital, including its most recently authorized rate of return on equity, for expenditures on projects associated with the plan during the construction, startup, and preservice implementation phases of the projects.
4. To the extent that an approved plan includes the early conversion or closure of coal-based generation capacity by January 1, 2015, and to the extent that the utility demonstrates that a lag in the recovery of the costs of the plan related to the investment required by such plan contributes to a utility earning less than its authorized return on equity, the commission shall employ rate-making mechanisms, in addition to allowing a current return on construction work in progress, that permit rate adjustments, no less frequently than once per year, without requiring the utility to file a general rate case to allow recovery of the approved plan's costs. Such rate-making mechanisms may include a separate rate adjustment clause, regular make-whole rate increases, or other appropriate mechanisms as determined by the commission.
5. During the time any special regulatory practice is in effect, the utility shall file a new rate case at least every two years or file a base rate recovery plan that spans more than one year.
6. The commission shall allow, but not require, the utility to develop and own as utility rate-based property any new electric generating plant constructed primarily to replace any coal-fired electric generating unit retired pursuant to the plan filed under this part 2.

Source: L. 2010: Entire part added, (HB 10-1365), ch. 140, p. 472, § 1, effective April 19.

40-3.2-208. Air quality planning.

1. The air quality provisions of the emission reduction plan filed under this part 2 are intended to fulfill the requirements of the state and federal acts and shall be proposed by the department to the air quality control commission after the utility files the plan with the commission to be considered for incorporation into the regional haze element of the state implementation plan.
2. 1. Upon the utility's filing of the utility plan with the commission pursuant to section 40-3.2-204, the air quality control commission, in response to the proposal by the department, shall initiate a proceeding to incorporate the air quality provisions of the utility plan into the regional haze element of the state implementation plan. Except as set forth in this subsection (2), the air quality control commission shall not act on the utility plan or the provisions of the regional haze element of the state implementation plan that would establish controls for those units covered by the utility plan until after the commission's approval of the utility plan.
   2. The air quality control commission shall vacate the entire proceeding related to the utility plan and shall initiate a new proceeding for the consideration of alternative proposals for the appropriate controls for those units covered by the utility plan for inclusion in the regional haze element of the state implementation plan if:
      1. The commission does not approve the utility plan by December 15, 2010;
      2. The utility withdraws its application pursuant to section 40-3.2-205 (4); or
      3. The air quality control commission rejects any portion of the utility plan as approved by the commission.
   3. The air quality control commission shall conduct the proceedings specified in this subsection (2) after public notice and an opportunity for the public to participate in accordance with the air quality control commission's procedures.
3. If the final approved provisions of the state implementation plan are not consistent with the air quality provisions of the utility plan, the utility may file a revised utility plan with the commission that modifies the original plan to be consistent with the final approved state implementation plan. The revised utility plan is subject to all of the review and cost recovery provisions contained in this part 2. Notwithstanding any revision required to the utility plan, the utility is entitled to fully recover any costs it prudently incurred or contracted to incur under the originally approved plan prior to the plan's revision and any costs incurred as a result of any enforceable state implementation plan or other air quality requirements.

Source: L. 2010: Entire part added, (HB 10-1365), ch. 140, p. 474, § 1, effective April 19.

40-3.2-209. Early reductions.

Reductions in emissions achieved pursuant to this part 2 through a compliance strategy before such reductions are mandated under federal law are voluntary for purposes of determining early reduction credits under federal law.

Source: L. 2010: Entire part added, (HB 10-1365), ch. 140, p. 475, § 1, effective April 19.

40-3.2-210. Exemption from limits on voluntary emission reductions.

The limits on utility expenditures on voluntary emission reductions in section 40-3.2-102 do not apply to utility expenditures under a plan approved by the commission under this part 2.

Source: L. 2010: Entire part added, (HB 10-1365), ch. 140, p. 475, § 1, effective April 19.

40-3.4-101 to 40-3.4-111. (Repealed)

Source: L. 2013: Entire article repealed, (SB 13-194), ch. 89, p. 289, § 1, effective April 1.

Editor's note: This article was added in 1986. For amendments to this article prior to its repeal in 2013, consult the 2012 Colorado Revised Statutes and the Colorado statutory research explanatory note beginning on page vii in the front of this volume.

Cross references: For the wind up of the low-income telephone assistance fund and the satisfying of obligations, see section 5 of chapter 89, Session Laws of Colorado 2013.

40-3.5-101. Application - reasonable charges - adequate service.

1. This article shall be applicable within the authorized electric and natural gas service areas of each municipal utility that lie outside the jurisdictional limits of such municipality. Insofar as municipal utilities establish rates, charges, and tariffs and any regulations pertaining thereto in accordance with the provisions of this article, the provisions of section 40-1-104 and articles 4, 6, and 7 of this title shall not apply; except that section 40-4-105 shall apply with respect to the crossing of railroad rights-of-way. Nothing in this article shall be construed as limiting the applicability of article 5 of this title.
2. All charges made, demanded, or received by any municipal utility for any rate, product, or commodity furnished or to be furnished or any service rendered or to be rendered shall be just, reasonable, and sufficient.
3. Every municipal utility shall furnish, provide, and maintain such service, instrumentalities, equipment, and facilities as shall promote the safety, health, comfort, and convenience of its patrons, its employees, and the public, and as shall in all respects be adequate, efficient, just, and reasonable.
4. For the purposes of this article, "municipal utility" means a municipal natural gas or electric utility.

Source: L. 83: Entire article added, p. 1553, § 2, effective June 17. L. 2002: (1) amended, p. 1947, § 3, effective June 8.

Cross references: For the legislative declaration contained in the 2002 act amending this section, see section 1 of chapter 350, Session Laws of Colorado 2002.

40-3.5-102. Regulation of rates.

The power and authority is hereby vested in the governing body of each municipal utility and it is hereby made the duty of each such governing body to adopt all necessary rates, charges, and regulations to govern and regulate all rates, charges, and tariffs of its municipal utility within its authorized electric and natural gas service areas which lie outside the jurisdictional limits of the municipality. No rate, charge, tariff, or voluntary plan approved pursuant to section 40-2-122 shall unjustly discriminate between or among those customers or recipients of any commodity, service, or product of the municipal utility within the authorized service area. In the event that any rate, charge, tariff, or voluntary plan established within the authorized service area which lies outside the jurisdictional limits of the municipality varies from the rate, charge, tariff, or voluntary plan established for the same class of customers or recipients of any such service within the authorized service area which lies inside the jurisdictional limits of the municipality, such rate, charge, tariff, or voluntary plan shall not become effective until reviewed and approved by the commission. Such review and approval shall be in accordance with the provisions of article 3 of this title; except that in no event shall the commission modify or establish such rate, charge, or tariff to an amount lower than that established by the municipality, or approve a voluntary plan that differs from the voluntary plan, for the same class of customers or recipients of any utility service within the authorized service area which lies inside the jurisdictional limits of the municipality.

Source: L. 83: Entire article added, p. 1553, § 2, effective June 17. L. 99: Entire section amended, p. 964, § 2, effective August 4.

40-3.5-103. Rate schedules.

Municipal utilities shall print and keep open for public inspection schedules showing all rates and charges collected or enforced, or to be collected or enforced, together with all rules, regulations, contracts, privileges, and facilities which in any manner affect or relate to rates and service within the authorized electric and natural gas service areas of the municipal utility which lie outside the jurisdictional limits of the municipality.

Source: L. 83: Entire article added, p. 1553, § 2, effective June 17.

40-3.5-104. Changes in rates - notice and public hearing.

1. 1. No change shall be made by any municipal utility in any rate or charge or in any rule, regulation, or contract relating to or affecting any base rate, charge, or service, or in any privilege or facility, except after thirty days' notice to the public. Such notice shall be given by keeping open for public inspection new schedules stating plainly the changes to be made in the schedules then in force and the time when the changes will go into effect. In addition, such notice shall be given by publishing the proposed new schedule, or if that is impractical due to the size or bulk of the proposed new schedule, by publishing a notice of the availability of the proposed new schedule for public inspection, at least once in at least one newspaper of general circulation in the authorized service area at least thirty days and no more than sixty days prior to the date set for public hearing on and adoption of the new schedule.
   2. In addition to the notice provided for in paragraph (a) of this subsection (1), if a municipal utility serves customers who live outside the municipal corporate boundaries, notice of any change in any rate or charge or in any rule, regulation, or contract relating to or affecting any base rate, charge, or service or any change in any privilege or facility shall be given by mailing to such customer notification of any such change.
2. The notice required by subsection (1) of this section shall also specify the date, time, and place at which the public hearing shall be held by the governing body of the municipal utility to consider the proposed new schedule. The notice shall specify that each municipal utility customer shall have the right to appear, personally or through counsel, at such hearing for the purpose of providing testimony regarding the proposed new schedule. Said public hearing shall be held on the date and time and at the place set forth in the notice; except that the governing body of the municipal utility may adjourn and reconvene said hearing as it deems necessary.
3. The governing body of the municipal utility, for good cause shown, may allow changes without requiring the thirty days' notice and public hearing by an order specifying the changes to be made, the circumstances necessitating the change without requiring the thirty days' notice and public hearing, the time when the changes shall take effect, and the manner in which the changes shall be published.
4. Insofar as municipal utilities establish rates, charges, and tariffs and any regulations pertaining thereto in accordance with the provisions of this article, any conflict shall be resolved by the commission in accordance with the procedures contained in article 6 of this title upon the filing of a complaint by no less than five percent of the affected electric or natural gas customers outside the corporate limits of the municipality or by five such customers, whichever number is greater. Any such complaint shall be filed with the commission within thirty days after the final decision by the governing body of the municipality to change a rate, charge, or tariff or any regulation pertaining thereto. If such complaint is heard by the commission and is deemed not frivolous, all reasonable costs as determined by the commission, including reasonable attorney fees, shall be paid by the utility. In any hearing conducted pursuant to the provisions of this section, the burden of proof shall be sustained by the municipal utility.

Source: L. 83: Entire article added, p. 1554, § 2, effective June 17.

40-3.5-105. Free and reduced service prohibited - exceptions.

Except as otherwise provided in this section, no municipal utility shall charge, demand, collect, or receive a greater or lesser or different compensation for any product or commodity furnished or to be furnished, or for any service rendered or to be rendered, than the rates and charges applicable to such product, commodity, or service as specified in its schedules on file and in effect at the time, nor shall any such municipal utility refund or remit, directly or indirectly or in any manner or by any device, any portion of the rates and charges so specified nor extend to any corporation or person any form of contract or agreement or rule or regulation or any facility or privilege except one which is regularly and uniformly extended to all corporations and persons. The governing body of the municipal utility may by rule or order establish such exceptions from the operation of this prohibition as it may consider just and reasonable.

Source: L. 83: Entire article added, p. 1555, § 2, effective June 17.

40-3.5-106. Advantages prohibited - graduated schedules.

1. No municipal utility, as to rates, charges, service, facilities, or in any other respect, shall make or grant any preference or advantage to any corporation or person or subject any corporation or person to any prejudice or disadvantage. No municipal utility shall establish or maintain any unreasonable difference as to rates, charges, service, facilities, or in any other respect, either between localities or between any class of service. The governing body of each municipal utility shall determine the reasonableness of any such difference.
2. Nothing in this article shall prohibit a municipal utility engaged in the production, generation, transmission, distribution, or furnishing of heat, light, gas, or power from establishing a graduated scale of charges subject to the provisions of this article.
3. Nothing contained in this article shall exempt from the public utilities commission of the state of Colorado the power and authority to regulate the rates, charges, tariffs and any regulations pertaining thereto of the sale of natural gas by a municipal utility to another public utility.

Source: L. 83: Entire article added, p. 1555, § 2, effective June 17.

40-3.5-107. Fees.

Municipal utilities authorized to serve areas which lie outside their municipal corporate limits shall be subject to providing annual reports of gross operating revenues, computation of fees, and payment of such fees relating to those areas.

Source: L. 83: Entire article added, p. 1555, § 2, effective June 17.

40-4-101. Regulations, service, and facilities prescribed.

1. Whenever the commission, after a hearing upon its own motion or upon complaint, finds that the rules, regulations, practices, equipment, facilities, or service of any public utility or the methods of manufacture, distribution, transmission, storage, or supply employed by it are unjust, unreasonable, unsafe, improper, inadequate, or insufficient, the commission shall determine the just, reasonable, safe, proper, adequate, or sufficient rules, regulations, practices, equipment, facilities, service, or methods to be observed, furnished, constructed, enforced, or employed and shall fix the same by its order, rule, or regulation.
2. The commission shall prescribe rules and regulations for the performance of any service or the furnishing of any commodity of the character furnished or supplied by any public utility, and upon proper tender of rates, such public utility shall furnish such commodity or render such service within the time and upon the conditions provided in such rules.
3. The commission shall prescribe rules and regulations for the termination of gas and electric service to residential customers. Said rules and regulations shall require that the customer be given reasonable notice and an opportunity to be heard by the terminating utility company before termination of gas or electric service and that such service may not be terminated during certain periods if the customer establishes that termination of the service would be especially dangerous to the health or safety of the customer and that he is unable to pay for the service as regularly billed by the utility, or that he is able to pay but only in reasonable installments.

Source: L. 13: p. 475, § 24. C.L. § 2935. CSA: C. 137, § 25. CRS 53: § 115-4-1. C.R.S. 1963: § 115-4-1. L. 69: p. 933, § 19. L. 80: Entire section amended, p. 748, § 1, effective April 13.

40-4-102. Extensions and improvements prescribed - when.

1. Whenever the commission, after a hearing upon its own motion, upon appeal by a public utility or power authority from a local government action pursuant to section 29-20-108 (5), C.R.S., or upon complaint, finds that the additions, extensions, repairs, or improvements to or change in the existing plant, equipment, facilities, or other physical property of any public utility or of any two or more public utilities ought reasonably to be made, that a new structure should be erected to promote the security or convenience of its employees or the public or in any other way to secure adequate service or facilities, or that the conditions imposed by a local government action unreasonably impair the ability of a public utility or power authority to provide safe, reliable, and economical service, the commission shall make and serve an order directing that such additions, extensions, repairs, improvements, or changes be made or such structure be erected in the manner and within the time specified in such order. If the commission orders the erection of a new structure, the selection of the site for such structure shall be subject to the approval of the commission. If a public utility or power authority appeals an order from a local government action under section 29-20-108, C.R.S., the commission may require that the public utility or power authority reimburse the commission for the reasonable expenses, attorney fees, and expert witness fees the commission incurs in reviewing the appeal. Any fee collected pursuant to this section shall be remitted to the state treasurer, who shall credit such fee to the public utilities commission fixed utility fund created pursuant to section 40-2-114.
2. If any additions, extensions, repairs, improvements, or changes or any new structures which the commission has ordered to be erected require joint action of two or more public utilities, the commission shall notify the public utilities that such additions, repairs, improvements, or changes or new structures have been ordered and that the same shall be made at their joint cost, whereupon the public utilities shall have such reasonable time as the commission may grant within which to agree upon the portion or division of cost of such additions, repairs, extensions, improvements, or changes or new structures which each shall bear. If, at the expiration of such time, such public utilities fail to file with the commission a statement that an agreement has been made for a division or apportionment of the cost or expense of such additions, extensions, repairs, improvements, or changes or new structures, the commission has the authority, after further hearing, to make an order fixing the proportion of such expense to be borne by each public utility and the manner in which the same shall be paid or secured.

Source: L. 13: p. 476, § 25. C.L. § 2936. CSA: C. 137, § 26. CRS 53: § 115-4-2. C.R.S. 1963: § 115-4-2. L. 69: p. 933, § 20. L. 2001: (1) amended, p. 597, § 4, effective May 30.

Cross references: For the legislative declaration contained in the 2001 act amending subsection (1), see section 1 of chapter 183, Session Laws of Colorado 2001.

40-4-103. Increased transportation facilities prescribed.

Whenever the commission, after a hearing upon its own motion or upon complaint, finds that any common carrier does not run a sufficient number of trains or vehicles or does not possess or operate sufficient motive power to reasonably accommodate the traffic, whether passenger or freight, or both, transported by or offered to it for transportation, or does not run its trains or vehicles with sufficient frequency or at a reasonable or proper time having regard to safety, or does not stop the same at proper places or does not run any train or vehicle upon a reasonable time schedule for the run, the commission has the power to make an order directing any such common carrier to increase the number of its trains or of its vehicles or its motive power or to change the time of starting its train or vehicle or to change the time schedule for the run of any train or vehicle, or to change the stopping places thereof, or to make any other change the commission may determine to be reasonably necessary to accommodate and transport the traffic, whether passenger or freight, or both, transported or offered to it for transportation.

Source: L. 13: p. 477, § 26. C.L. § 2937. CSA: C. 137, § 27. CRS 53: § 115-4-3. C.R.S. 1963: § 115-4-3. L. 69: p. 933, § 21.

40-4-104. Connection of noncompetitive lines - costs and rates apportioned.

Whenever the commission, after a hearing upon its own motion or upon complaint, finds that a physical connection can reasonably be made between the lines of two or more noncompetitive telephone public utilities whose lines can be made to form a continuous line of communication by the construction and maintenance of suitable connections for the transmission of messages or conversations and that the public convenience and necessity will be served or finds that two or more telephone public utilities have failed to establish joint rates, tolls, or charges for service by or over said lines and that joint rates, tolls, or charges ought to be established, the commission may by its order require that such connections be made and that conversations be transmitted and messages transferred over such connection under such rules as the commission may establish and prescribe through lines and joint rates, tolls, and charges to be made and used, observed, and in force in the future. If such telephone public utilities do not agree upon the division between them of the joint cost of the physical connection or connections or the division of the joint rates, tolls, or charges established by the commission over such through lines, the commission has authority, after further hearing, to establish the division by supplemental order.

Source: L. 13: p. 477, § 27. C.L. § 2938. CSA: C. 137, § 28. CRS 53: § 115-4-4. C.R.S. 1963: § 115-4-4. L. 69: p. 934, § 22. L. 2008: Entire section amended, p. 1794, § 11, effective July 1.

Cross references: For duty of telephone company to transmit messages of another company, see § 40-3-107.

40-4-105. Joint use of equipment and facilities.

1. Whenever the commission, after a hearing upon its own motion or upon complaint of a public utility affected, finds that the public convenience and necessity require the use by one public utility of the conduits, subways, tracks, wires, poles, pipes, or other equipment, or any part thereof on, over, or under any street or highway that belongs to another public utility, or the crossing of a railroad right-of-way by a public utility for installation of its own facilities in a manner and in a location that is compatible with the use for railroad purposes, and that such use will not result in irreparable injury to the owners or other users of such conduits, subways, wires, tracks, poles, pipes, or other equipment or to the railroad's use of the right-of-way, or in any substantial detriment to the service, and that such public utilities have failed to agree upon such use or the terms and conditions or compensation for the same, the commission by order may direct that such use be permitted and prescribe reasonable compensation and reasonable terms and conditions for the joint use. If such use is directed, the public utility to whom the use is permitted shall be liable to the owner or other users of such conduits, subways, tracks, wires, poles, pipes, other equipment, or railroad right-of-way, for such damage as may result therefrom to the property of such owners or other users thereof.
2. In proceedings arising out of a complaint requesting the commission to authorize and determine appropriate compensation to be paid by a public utility to install its own facilities across a railroad right-of-way in a manner and location compatible with railroad use of the right-of-way, the commission may require the parties involved in the proceeding to reimburse the commission for the reasonable expenses, attorney fees, and expert witness fees the commission incurs in making its determination. Any fee collected pursuant to this section shall be remitted to the state treasurer, who shall credit such fee to the public utilities commission fixed utility fund created pursuant to section 40-2-114.
3. Nothing in this section shall be construed to limit the right of a public utility to exercise the power of eminent domain to acquire property pursuant to applicable law.
4. For purposes of this section, with respect to crossing of railroad rights-of-way by a public utility, the term "public utility" shall include power authorities organized under section 29-1-204, C.R.S. The term "public utility" shall also include municipal utilities and cooperative electric associations otherwise exempt from this article.

Source: L. 13: p. 478, § 28. C.L. § 2939. CSA: C. 137, § 29. CRS 53: § 115-4-5. C.R.S. 1963: § 115-4-5. L. 69: p. 934, § 23. L. 2002: Entire section amended, p. 1946, § 2, effective June 8.

Cross references: (1) For compensation ascertained by jury in eminent domain proceedings when demanded by owner, see § 15 of article II of the Colorado Constitution.

(2) For the legislative declaration contained in the 2002 act amending this section, see section 1 of chapter 350, Session Laws of Colorado 2002.

40-4-106. Rules for public safety - crossings - civil fines - allocation of expenses.

1. 1. The commission may, after a hearing on its own motion or upon complaint, make general or special orders, promulgate rules, or act by other means to require each public utility to maintain and operate its lines, plant, system, equipment, electrical wires, apparatus, tracks, and premises in such a manner as to promote and safeguard the health and safety of its employees, passengers, customers, subscribers, and the public and to require the performance of any other act that the health or safety of its employees, passengers, customers, subscribers, or the public may demand.
   2. If, pursuant to this subsection (1), the commission issues an order or promulgates a rule requiring a railroad company to comply with railroad crossing safety regulations, the commission may impose a civil penalty pursuant to article 7 of this title 40, in an amount not to exceed the maximum amount set forth in section 40-7-105 (1), against a railroad company that fails to comply with the order or rule.
2. 1. The commission has the power to determine, order, and prescribe, in accordance with the plans and specifications to be approved by it, the just and reasonable manner including the particular point of crossing at which the tracks or other facilities of any public utility may be constructed across the facilities of any other public utility at grade, or above or below grade, or at the same or different levels, or at which the tracks or other facilities of any railroad corporation may be constructed across any public highway at grade, or above or below grade, or at which any public highway may be constructed across the tracks or other facilities of any railroad corporation at grade, or above or below grade and to determine, order, and prescribe the terms and conditions of installation and operation, maintenance, and warning at all such crossings that may be constructed, including the posting of personnel or the installation and regulation of lights, block, interlocking, or other system of signaling, safety appliance devices, or such other means or instrumentalities as may to the commission appear reasonable and necessary to the end, intent, and purpose that accidents may be prevented and the safety of the public promoted.
   2. Whenever the commission orders in any proceeding before it, regardless of by whom or how such proceeding was commenced, that automatic or other safety appliance signals or devices be installed, reconstructed, or improved and operated at any crossing at grade of any public highway or road over the tracks of any railroad corporation, the commission shall also determine and order, after notice and hearing, how the cost of installing, reconstructing, or improving such signals or devices shall be divided between and paid by the interested railroad corporation whose tracks are located at the crossing on the one hand and the chief engineer and the interested city, city and county, town, county, or other political subdivision of the state on the other hand. In determining how much of the cost shall be paid by the railroad corporation, consideration shall be given to the benefit, if any, that will accrue from the signals or devices to the railroad corporation, but in every case the part to be paid by the railroad corporation shall be not less than twenty percent of the total cost of the signals or devices at any crossing, and the orders shall provide that every signal or device installed will be maintained by the railroad corporation for the life of the crossing to be so signalized. In order to compensate for the use of the crossings by the public generally, the commission shall also order that such part of the cost of installing, reconstructing, or improving the signals or devices as will not be paid by the railroad corporation be divided between the highway-rail crossing signalization fund and the city, town, city and county, county, or other political subdivision in which the crossing is located, and the commission shall fix in each case the amount to be paid from the highway-rail crossing signalization fund and the amount to be paid by the city, town, city and county, county, or other political subdivision. Any order of the commission under this section for the payment of any part of any such costs from the highway-rail crossing signalization fund is authority for the state treasurer to pay out of said fund to the person, firm, or corporation entitled thereto under the commission's order the amount so determined to be paid from said fund. The requirement of notice and hearing in this section is deemed to have been complied with by the commission's giving notice of and holding a hearing upon the question of whether any such signals or devices are required at any crossing; but in such cases the notice shall state that the question of how the costs will be borne and paid will be considered at and determined as a result of the hearing for which the notice is given. This paragraph (b) shall not apply to any grade crossing when all or any part of the cost of the installation, reconstruction, or improvement of the signals or devices at the crossing will be paid from funds available under any federal or federal-aid highway act.
3. 1. 1. The commission also has power upon its own motion or upon complaint and after hearing, of which all the parties in interest including the owners of adjacent property shall have due notice, to order any crossing constructed at grade or at the same or different levels to be relocated, altered, or abolished, according to plans and specifications to be approved and upon just and reasonable terms and conditions to be prescribed by the commission, and to prescribe the terms upon which the separation should be made and the proportion in which the expense of the alteration or abolition of the crossing or the separation of the grade should be divided between the railroad corporations affected or between the corporation and the state, county, municipality, or public authority in interest. (3) (a) (I) The commission also has power upon its own motion or upon complaint and after hearing, of which all the parties in interest including the owners of adjacent property shall have due notice, to order any crossing constructed at grade or at the same or different levels to be relocated, altered, or abolished, according to plans and specifications to be approved and upon just and reasonable terms and conditions to be prescribed by the commission, and to prescribe the terms upon which the separation should be made and the proportion in which the expense of the alteration or abolition of the crossing or the separation of the grade should be divided between the railroad corporations affected or between the corporation and the state, county, municipality, or public authority in interest.
      2. Notwithstanding the provisions of subparagraph (I) of this paragraph (a), the affected railroad corporation, the commission, the department of transportation, or the local government responsible for supervising and maintaining the intersecting public highway or road may abolish any crossing at grade of any public highway or road over the tracks of a corporation if:
         1. The crossing is without gates, signals, alarm bells, or warning personnel and is located within one-quarter mile of a crossing with gates, signals, alarm bells, or warning personnel or a separated grade crossing;
         2. The crossing is not the only crossing that provides access to property;
         3. No less than sixty days prior to the proposed abolition date, the railroad corporation, commission, department of transportation, or local government posts conspicuous notice of the proposed abolition at the crossing and gives written notice of the proposed abolition to all other entities authorized to initiate abolition of the crossing pursuant to this subparagraph (II); and
         4. Neither any entity given notice nor any other interested party files an objection to the abolition pursuant to subparagraph (III) of this paragraph (a).
      3. A crossing shall not be abolished pursuant to subparagraph (II) of this paragraph (a) if an entity given notice pursuant to sub-subparagraph (C) of subparagraph (II) of this paragraph (a) or any other interested party, within sixty days of receiving such notice, files with the commission and provides to the entity that gave notice of the proposed abolition a written objection to the abolition. The written objection shall include a statement by a professional engineer licensed to practice in Colorado that indicates that the engineer is familiar with the requirements of subparagraph (II) of this paragraph (a) and all relevant aspects of the crossing and has examined the crossing and believes that it is safe as designed. However, nothing in this subparagraph (III) shall preclude the abolition of the crossing pursuant to subparagraph (I) of this paragraph (a).
   2. 1. 1. The commission is authorized to approve individual projects wherein the allocation of the total expenses of the separation of grades to be paid by the railroad corporation or railroad corporations may exceed two million five hundred thousand dollars. The commission may approve more than one project, the sum totals of which may exceed the two-million-five-hundred-thousand-dollar cap set forth in this subparagraph (I), but in no event shall an individual class I railroad corporation pay more than two million five hundred thousand dollars of the cost of a single project or the cost of more than one project in any calendar year. Nothing in this subparagraph (I) shall preclude any railroad corporation from voluntarily contributing more than its allotted share for grade separation construction in one year, and, in such event, all amounts contributed by such railroad exceeding its allotted share in any one year shall be credited to and shall serve to reduce any payment for grade separation construction expenses by that railroad in subsequent years. (b) (I) (A) The commission is authorized to approve individual projects wherein the allocation of the total expenses of the separation of grades to be paid by the railroad corporation or railroad corporations may exceed two million five hundred thousand dollars. The commission may approve more than one project, the sum totals of which may exceed the two-million-five-hundred-thousand-dollar cap set forth in this subparagraph (I), but in no event shall an individual class I railroad corporation pay more than two million five hundred thousand dollars of the cost of a single project or the cost of more than one project in any calendar year. Nothing in this subparagraph (I) shall preclude any railroad corporation from voluntarily contributing more than its allotted share for grade separation construction in one year, and, in such event, all amounts contributed by such railroad exceeding its allotted share in any one year shall be credited to and shall serve to reduce any payment for grade separation construction expenses by that railroad in subsequent years.
         2. Repealed.
      2. If the cost of a project is such that it calls for payment by a railroad corporation in more than one calendar year or if the amount due from the railroad corporation exceeds two million five hundred thousand dollars and thus must be made in consecutive calendar years, nothing in this section shall be construed to require that the approved project must be subjected to reapplication or rereview by the commission.
      3. In determining how much of the total expense of the separation of grades shall be paid by the railroad corporation or railroad corporations and by the state, county, municipality, or public authority in interest, consideration shall be given to the benefits, if any, which accrue from the grade separation project and the responsibility for need, if any, for such project. The railroad corporation or railroad corporations and the state, county, municipality, or public authority in interest shall share the costs for that portion of the project which separates the grades and constructs the approaches thereto. The commission shall consider the costs of obtaining rights-of-way, the costs of construction, and the costs of engineering. To the extent that the requirements of the railroad corporation or railroad corporations and the state, county, municipality, or public authority in interest generate additional costs beyond that necessary to provide the grade separation, such costs shall be borne by the responsible entity.
      4. This paragraph (b) shall not apply to any project for the elimination of hazards at any railway-highway crossing when all or any part of the cost of such project will be paid from moneys made available for expenditure under title 23, U.S.C.; except that any amount paid by a railroad corporation for such an exempt project shall be credited against the two-million-five-hundred-thousand-dollar cap set forth in subparagraph (I) of this paragraph (b).
   3. 1. The state, county, municipality, or public authority, at its discretion, may withdraw its request for allocation determination at any time prior to the issue of the final order of the commission.
      2. The state, county, municipality, or public authority, at its discretion, after the hearing and prior to final order of the commission, may make a motion for a declaratory ruling on the cost allocation. In response to such a request, the commission shall make a declaratory ruling and shall provide the movant reasonable time to withdraw the request for allocation determination.
      3. After the final order is issued, the project shall proceed, unless the commission revises the order after consideration of a request for change by the state, county, municipality, or public authority in interest.
   4. The commission shall not order the abolition of any crossing for which a grade separation is determined to be necessary until this separation is constructed.
   6. Repealed.
4. Repealed.

Source: L. 13: p. 478, § 29. L. 17: p. 415, § 1. C.L. § 2940. CSA: C. 137, § 30. L. 41: p. 602, § 1. L. 43: p. 476, § 1. CRS 53: § 115-4-6. L. 55: p. 698, § 1. L. 63: p. 758, § 1. C.R.S. 1963: § 115-4-6. L. 65: p. 926, § 1. L. 69: pp. 935, 964, §§ 24, 75. L. 72: p. 615, § 144. L. 80: (4) added, p. 750, § 1, effective April 16. L. 81: (1) amended, p. 1918, § 1, effective June 19. L. 83: (3) amended, p. 1558, § 1, effective July 1. L. 86: (3)(b) and (3)(c) R&RE and (3)(e) and (3)(f) repealed, pp. 1157, 1158, §§ 1, 2, effective July 1. L. 91: (2)(b) amended, p. 1075, § 62, effective July 1. L. 93: (3)(b)(I)(B) repealed, p. 2063, § 15, effective July 1. L. 99: (3)(b)(I), (3)(b)(II), and (3)(b)(IV) amended, p. 140, § 1, effective August 4. L. 2003: (2)(b) amended, p. 1702, § 11, effective May 14. L. 2007: (3)(a) amended, p. 313, § 1, effective August 3. L. 2008: (2) amended, p. 1794, § 12, effective July 1. L. 2015: (2)(b) amended, (HB 15-1209), ch. 64, p. 173, § 2, effective March 30. L. 2019: (1) amended, (SB 19-236), ch. 359, p. 3311, § 14, effective May 30.

Editor's note: Subsection (4)(b) provided for the repeal of subsection (4), effective July 1, 1982. (See L. 80, p. 750 .)

Cross references: For liability under provisions of subsection (2) of this section, see § 43-4-216; for rule-making procedures, see article 4 of title 24.

40-4-107. Time limit regulations. (Repealed)

Source: L. 13: p. 479, § 30. C.L. § 2941. CSA: C. 137, § 31. CRS 53: § 115-4-7. C.R.S. 1963: § 115-4-7. L. 69: p. 936, § 25. L. 2008: Entire section repealed, p. 1796, § 13, effective July 1.

40-4-108. Standards for electricity, gas, and water.

The commission has power, after hearing upon its own motion or upon complaint, to ascertain and fix just and reasonable standards, classifications, regulations, practices, measurements, or service to be furnished, imposed, observed, and followed by all electric, gas, and water public utilities; to ascertain and fix adequate and serviceable standards for the measurement of quantity, quality, pressure, initial voltage, or other condition pertaining to the supply of the product, commodity, or service furnished or rendered by any such public utility; to prescribe reasonable regulations for the examination and testing of such product, commodity, or service and for the measurement thereof; to establish reasonable rules, regulations, specifications, and standards to secure the accuracy of all meters and equipment for measurement and weighing; and to provide for the examination and testing of any and all equipment used for the measurement or weighing of any product, commodity, or service of any such public utility.

Source: L. 13: p. 479, § 31. C.L. § 2942. CSA: C. 137, § 32. CRS 53: § 115-4-8. C.R.S. 1963: § 115-4-8. L. 69: p. 936, § 26.

40-4-109. Entry to premises - testing meters.

1. The commissioners and their officers and employees have power to enter upon any premises occupied by any public utility for the purpose of making the examination and tests and exercising any of the other powers provided for in articles 1 to 7 of this title and to set up and use on such premises any equipment necessary therefor. The agents and employees of such public utility have the right to be present at the making of such examinations and tests.
2. Any consumer or user of any product, commodity, or service of a public utility may have any equipment used in the measurement thereof tested upon paying the fees fixed by the commission. The commission shall establish and fix reasonable fees to be paid for testing such equipment on the request of the consumer or user, the fee to be paid by the consumer or user at the time of his request but to be paid by the public utility and repaid to the consumer or user if the equipment is found defective or incorrect to the disadvantage of the consumer or user under such rules and regulations as may be prescribed by the commission.

Source: L. 13: p. 479, § 31. C.L. § 2942. CSA: C. 137, § 32. CRS 53: § 115-4-9. C.R.S. 1963: § 115-4-9. L. 69: p. 937, § 27.

Cross references: For standards for and the testing of weights and measures generally, see article 14 of title 35.

40-4-110. Valuations of property.

The commission has power to ascertain the value of the property of every public utility in this state and the facts which in its judgment have or may have any bearing on such value. The commission has power to make revaluations from time to time and to ascertain all new construction, extensions, and additions to the property of every public utility.

Source: L. 13: p. 480, § 32. C.L. § 2943. CSA: C. 137, § 33. CRS 53: § 115-4-10. C.R.S. 1963: § 115-4-10.

Cross references: For hearings in valuation matters, see § 40-6-118.

40-4-111. Uniform system of accounts prescribed.

The commission has power to establish a system of accounts to be kept by all public utilities, or to classify said public utilities and to establish a system of accounts for each class, and to prescribe the manner in which such accounts shall be kept. It may also in its discretion prescribe the forms of accounts, records, and memoranda to be kept by such public utilities, including the accounts, records, and memoranda of the movement of traffic as well as the receipts and expenditures of moneys and any other forms, records, and memoranda that in the judgment of the commission may be necessary to carry out the provisions of articles 1 to 7 of this title. The system of accounts established by the commission and the forms of accounts, records, and memoranda prescribed by it shall not be inconsistent in the case of corporations subject to the provisions of the federal "Interstate Commerce Act", Part I, 49 U.S.C., sec. 1 et seq., with the systems and forms from time to time established for such corporations by the surface transportation board; but nothing contained in this section shall affect the power of the commission to prescribe forms of accounts, records, and memoranda covering information in addition to that required by the surface transportation board. The commission, after hearing upon its own motion or upon complaint, may prescribe by order the accounts in which particular outlays and receipts shall be entered, charged, or credited. Where the commission has prescribed the forms of accounts, records, or memoranda to be kept by any public utility for any of its business, it shall thereafter be unlawful for such public utility to keep any accounts, records, or memoranda for such business other than those so prescribed, or those prescribed by or under the authority of any other state or of the United States, excepting such accounts, records, or memoranda as are explanatory of and supplemental to the accounts, records, or memoranda prescribed by the commission.

Source: L. 13: p. 480, § 33. C.L. § 2944. CSA: C. 137, § 34. CRS 53: § 115-4-11. C.R.S. 1963: § 115-4-11. L. 2001: Entire section amended, p. 1281, § 60, effective June 5.

40-4-112. Depreciation account - rules.

The commission has power, after hearing, to require any or all public utilities to carry a proper and adequate depreciation account in accordance with such rules, regulations, and forms of accounts as the commission may prescribe. The commission, from time to time, may determine and by order fix the proper and adequate rates of depreciation of the several classes of property of each public utility, and each public utility shall conform its depreciation accounts to the rates so determined.

Source: L. 13: p. 481, § 34. C.L. § 2945. CSA: C. 137, § 35. CRS 53: § 115-4-12. C.R.S. 1963: § 115-4-12. L. 69: p. 937, § 28.

40-4-113. Evaluation of retail electric industry structure - study - repeal. (Repealed)

Source: L. 98: Entire section added, p. 860, § 1, effective May 26. L. 99: (4)(d) amended, p. 657, § 1, effective May 18.

Editor's note: Subsection (6) provided for the repeal of this section, effective December 31, 2000. (See L. 98, p. 860 .)

40-4-114. Funding and appropriations - retail electricity policy development fund - creation - repeal. (Repealed)

Source: L. 98: Entire section added, p. 867, § 1, effective May 26.

Editor's note: Subsection (2) provided for the repeal of this section, effective December 31, 2000. (See L. 98, p. 867 .)

40-4-115. Reliable electricity infrastructure - task force - repeal. (Repealed)

Source: L. 2006: Entire section added, p. 831, § 2, effective May 4.

Editor's note: Subsection (5) provided for the repeal of this section, effective December 31, 2006. (See L. 2006, p. 831 .)

40-4-116. Renewable resource generation development areas - task force - fund - definitions - repeal. (Repealed)

Source: L. 2007: Entire section added, p. 1340, § 1, effective May 29.

Editor's note: Subsection (7) provided for the repeal of this section, effective December 31, 2007. (See L. 2007, p. 1340 .)

40-4-117. Integrated transmission facility planning - review by commission - report - repeal. (Repealed)

Source: L. 2009: Entire section added, (HB 09-1345), ch. 356, p. 1858, § 2, effective June 1.

Editor's note: Subsection (6) provided for the repeal of this section, effective July 1, 2011. (See L. 2009, p. 1858 .)

40-4-118. Colorado smart grid task force - fund - definition - reports - repeal. (Repealed)

Source: L. 2010: Entire section added, (SB 10-180), ch. 428, p. 2231, § 1, effective June 11. L. 2012: (2)(a)(I) and (5) amended, (HB 12-1315), ch. 224, p. 980, § 49, effective July 1.

Editor's note: Subsection (7) provided for the repeal of this section, effective July 1, 2015. (See L. 2010, p. 2231 .)

40-4-119. Siting of electric transmission facilities - task force - repeal. (Repealed)

Source: L. 2011: Entire section added, (SB 11-045), ch. 288, p. 1338, § 1, effective June 3.

Editor's note: Subsection (6) provided for the repeal of this section, effective December 31, 2011. (See L. 2011, p. 1338 .)

40-4-120. Study of community choice in wholesale electric supply - duties of commission - report - legislative declaration - definition - repeal.

1. Legislative declaration.
   1. The general assembly finds and determines that:
      1. Fourteen communities in Colorado, known as the "Ready for 100" communities, have committed to obtaining one hundred percent renewable energy by 2025 to 2035. In addition, thirty-five communities, known as "Colorado Communities for Climate Action", have organized to advocate for stronger climate change policies. These communities, which represent more than one million Coloradans, are exploring ways to reach their energy and climate goals within their desired time periods.
      2. A key element of the governor's policy initiative, entitled "Roadmap to 100% Renewable Energy by 2040 and Bold Climate Action", prioritizes supporting local commitments to one hundred percent renewable energy.
      3. The ability of a community to achieve its energy goals is currently limited by the energy supply and the decarbonization timeline of the electric utility that serves that community's geographic area. The ability to procure electricity from alternative wholesale suppliers may enable communities to achieve their energy goals faster and more cost-effectively.
      4. Community choice energy or CCE, also commonly known as community choice aggregation or CCA, is a local energy model that a number of states have adopted and that has proven to be effective in helping communities achieve their renewable energy goals, cost-containment goals, or both. A robust study of CCE would answer key questions and illuminate the possible benefits and challenges of adapting the CCE model as an option for Colorado communities.
      5. In the CCE model, communities that are served by an investor-owned electric utility may choose their wholesale electricity suppliers, while the electricity continues to be delivered by the incumbent investor-owned electric utility. In states that have enabled CCE to date, CCE is not permitted in communities that are served by a cooperative electric association or a municipally owned electric utility.
      6. In the CCE model, an investor-owned electric utility continues to own and operate its transmission and distribution system to serve both CCE customers and its own customers, and the utility continues to provide metering and billing services, manage customer service, and implement demand-side management programs. The utility continues to own and operate its power generation assets to serve its own customers. If a community chooses to adopt CCE, the utility would deliver the electricity, with appropriate compensation, from one or more alternative suppliers to CCE customers.
      7. This section concerns the "wholesale, opt-out" model of CCE, pursuant to which individual customers are automatically enrolled in and retain the right to opt out of their community's CCE offerings and purchase their electricity from the utility under its traditional bundled service. By contrast, the retail model of CCE, in which individuals in deregulated retail choice states can shop for their electricity from among many competing suppliers, does not promote the stable revenue conditions needed for development of high levels of renewable energy. The retail CCE model is explicitly not the subject of this section.
      8. A well-designed wholesale, opt-out CCE program would introduce an element of wholesale competition and community-level choice into the supply of electricity and could provide communities that have ambitious renewable energy goals, cost-containment goals, or both, with a means to reach those goals more quickly and cost-effectively.
      9. This section pertains only to the study of CCE, not to its implementation. While CCE in other states shows the potential for communities to make local energy decisions, reach their energy goals, reduce energy costs, and foster local economic development and local employment, it is prudent to first study the feasibility and the regulatory, legal, and environmental implications of CCE in Colorado before considering the implementation of CCE as an option for communities in Colorado that are served by an investor-owned electric utility.
      10. The study of CCE as described in this section will answer key questions about the potential viability of CCE in Colorado and will identify best practices and lessons learned from the experiences of states that have already implemented CCE. The study will provide the information needed to determine whether CCE could provide net benefits to Colorado communities.
      11. CCE, if enabled in Colorado in the future, could promote a more vibrant and competitive wholesale electricity market and could enhance efforts to form or join a regional transmission organization, which could increase the footprint of energy trading in the west and thereby reduce costs through market efficiency, lower required reserve capacities, increased integration of cost-effective renewable energy, and decreased curtailment of excess renewable energy. A regional transmission organization could also potentially benefit cooperative electric associations and municipal electric utilities.
   2. Therefore, the general assembly declares that it is in the public interest to direct the commission to evaluate the viability of the wholesale, opt-out model of CCE in Colorado and to answer key questions about CCE in Colorado by conducting an investigatory docket that considers at least the topics outlined in subsection (3) of this section.
2. Definition. As used in this section, "community choice energy" or "CCE" means a mechanism that allows cities, including a city and county, counties, or groups of cities and counties to combine their purchasing power and choose one or more alternative wholesale electricity suppliers on behalf of the residents, businesses, and municipal facilities in the jurisdiction while the incumbent investor-owned electric utility maintains its existing generation and continues to own and operate its transmission and distribution system and deliver the electricity to both its own customers and CCE customers.
3. Investigatory docket.
   1. On or before January 15, 2022, and in accordance with this subsection (3), the commission shall open an investigatory docket to accept testimony and documentation from stakeholders, independent energy and utility experts, regulators from states in which CCE has been implemented or is under consideration, representatives of operational CCE authorities, and other interested parties. The goal of the proceeding is to consider the regulatory implications and legal impacts of possible future CCE-enabling legislation and provide recommendations to the general assembly. Conclusions should include best practices and lessons learned from states that have enabled CCE at the wholesale level. The commission shall employ procedures that promote a productive, effective, and evidence-based process, including one or more commissioners' informational meetings with presentations by subject-matter experts.
   2. The commission shall solicit input from a broad and inclusive range of stakeholders and presenters to ensure that the process is not dominated by any one group or viewpoint. Stakeholders and presenters may include:
      1. Local governments with declared goals regarding carbon emissions or energy supply choices;
      2. Business groups;
      3. Environmental advocates;
      4. Consumer advocates;
      5. Electric utilities, including investor-owned electric utilities, municipally owned electric utilities, and cooperative electric associations;
      6. Independent power producers;
      7. Power marketers;
      8. Renewable energy developers;
      9. Consultants or other experts in energy project financing;
      10. Consultants or other experts in energy efficiency and distributed energy resources;
      11. Representatives of operational CCE authorities that use the wholesale CCE model; and
      12. Members of the general public.
   3. The topics and questions to be explored in the docket shall include:
      1. Whether the commission would require additional statutory authority to conduct a rule-making proceeding concerning the creation of CCE authorities in Colorado; except that the commission's determination that additional statutory authority is not required does not preclude the general assembly from increasing or amending the commission's statutory authority;
      2. The appropriate scope of regulatory oversight of CCE operations, on a scale ranging from comprehensive, as with investor-owned electric utilities, to minimal, as with municipally owned electric utilities;
      3. Which aspects, if any, of current or anticipated investor-owned electric utility regulation by the commission should apply to CCE authorities as well, and to what extent, including regulation in the areas of:
         1. Resource adequacy planning;
         2. Assurance of reliability and how this is paid for;
         3. Compliance with renewable energy standards and emissions reduction targets;
         4. Supplemental demand-side management programs offered by CCE authorities;
         5. Time-of-use rates or other rate requirements if mandated for investor-owned electric utilities; and
         6. Standards for requests for proposals;
      4. The appropriate principles and considerations for calculating the amount and duration of reasonable transition fees, also known as exit fees, that communities forming a CCE authority would pay to the incumbent investor-owned electric utility to offset their fair share of the costs of utility assets and contracts that were procured on their behalf and previously approved, in amounts sufficient to provide cost recovery for stranded investor-owned electric utility assets and contracts and direct transition costs while protecting non-CCE customers but without unduly burdening CCE customers. The principles and considerations shall include:
         1. The age or the date of initial service of generation assets and existing contracts;
         2. The potential for exit fees to vary over time or by location;
         3. The establishment of a specific expiration period for exit fees;
         4. Measures to mitigate exit fees through potential contract transfer or resale to CCE authorities or other buyers, and appropriate forecasting of departing load to avoid over-procurement; and
         5. Pitfalls encountered in other states related to exit fees and how those pitfalls could be avoided or mitigated by up-front consideration.
      5. The appropriate conditions, limitations, and procedures under which customers may opt out of CCE and receive bundled service from the incumbent investor-owned electric utility;
      6. Whether any additional consumer protections would be required and the means of providing those protections;
      7. Potential challenges for CCE start-up or continuing operations, including the availability of financing and credit rating considerations, and strategies to overcome those challenges;
      8. What regulatory and legal issues have arisen in other states that have adopted the wholesale, opt-out model of CCE and possible solutions for those issues;
      9. Whether an investor-owned electric utility that remains the sole provider of distribution, transmission, and other services traditionally provided by the utility, such as metering and billing, should also be the provider of last resort for supplying electricity to customers who opt out of CCE;
      10. The appropriate process for approval of CCE on behalf of customers within a jurisdiction, whether by ordinance, by vote of the people, or otherwise;
      11. Whether CCE authorities should be allowed to offer demand-side management programs that either expand upon or replace such programs offered by the incumbent investor-owned electric utility;
      12. Regulatory and policy considerations related to forming CCE authorities in a state that does not currently belong to a regional transmission organization or participate in a wholesale electricity market, and possible solutions, including considerations in the areas of:
          1. Whether legislation should be adopted to guarantee open access and fair prices for transmission services;
          2. Recommendations for legislative or administrative measures, or both, concerning wholesale market access and development in Colorado; and
          3. Whether other legislative and regulatory modifications are necessary to successfully implement CCE in Colorado;
      13. What, if any, minimum requirements and standards should apply to independent power producers and power marketers who wish to supply energy to a CCE authority;
      14. What, if any, data-sharing requirements should be imposed on investor-owned electric utilities to help ensure that a CCE authority or a jurisdiction investigating whether to form or join a CCE authority can reasonably evaluate its financial and technical viability and implement its CCE program;
      15. How CCE might facilitate or impede:
          1. Increased integration of distributed energy resources, such as rooftop solar, community solar, and battery energy storage into distribution systems;
          2. Increased investment in beneficial electrification, including electrification of transport; and
          3. Resource adequacy and reliability, and what regulatory approaches would be needed to maximize positive impacts and mitigate negative impacts;
      16. The appropriate considerations for ensuring that the implementation of CCE does not include customers in the certificated territories of municipally owned electric utilities or cooperative electric associations;
      17. The impact of allowing CCE in Colorado on the ability of Colorado to reach its clean energy and greenhouse gas reduction goals and what legislative and regulatory requirements for CCE would be needed to facilitate reaching those goals;
      18. The impact, both positive and negative, of CCE in communities that have formed or joined a CCE authority in states that have enabled the wholesale, opt-out model of CCE;
      19. The impact of CCE on low-income households and communities disproportionately impacted by electricity generation, including the availability of low-income programs offered through the investor-owned electric utility to CCE customers and the ability of CCE authorities to establish additional programs to assist low-income households and communities disproportionately impacted by electricity generation;
      20. The risks a CCE authority might face that merit consideration, such as resource price risks, contract risks, or load defection, and the significance of those risks;
      21. The impact of CCE on jobs in the electricity sector, including the number and classification of jobs lost or gained at investor-owned utilities and CCA authorities in California;
      22. What options, including project labor agreements, would ensure that new energy projects built to supply CCE authorities are constructed using union labor; and
      23. How the procurement process works and how it varies from one CCE or CCA authority to another, especially in California.
   4. The commission shall summarize its findings, conclusions, and recommendations from the investigatory docket in a final report submitted to the transportation and energy committee of the senate and the energy and environment committee of the house of representatives, or their successor committees, and posted on the commission's public website. The commission shall submit the report on or before December 15, 2022. Recommendations may be split into majority views and dissenting views if necessary.
   5. The implementation of any option determined from the study cannot have a negative impact on other ratepayers outside of the municipality that is the focus of the study.
4. Repeal. This section is repealed, effective September 1, 2024.

Source: L. 2021: Entire section added, (HB 21-1269), ch. 338, p. 2187, § 1, effective June 25.

40-5-101. New construction - extension - compliance with local zoning rules.

1. 1. A public utility shall not begin the construction of a new facility, plant, or system or the extension of its facility, plant, or system without first obtaining from the commission a certificate that the present or future public convenience and necessity require, or will require, the construction or extension. For purposes of this subsection (1), the present or future public convenience and necessity does not include the consideration of land use rights or siting issues related to the location or alignment of the proposed electric transmission lines or associated facilities, which issues are under the jurisdiction of a local government's land use regulation. Sections 40-5-101 to 40-5-104 do not require a corporation to secure a certificate for the following:
      1. An extension within any city and county, city, or town within which it has already lawfully commenced operations;
      2. An extension into territory, either within or outside of a city and county, city, or town, contiguous to its facility, line, plant, or system and not already served by a public utility providing the same commodity or service; or
      3. An extension within or to territory already served by the corporation, as is necessary in the ordinary course of its business.
   2. If a public utility, in constructing or extending its line, plant, or system, interferes, or is about to interfere, with the operation of the line, plant, or system of any other public utility already constructed, the commission, upon complaint of the public utility claiming to be injuriously affected, after hearing, may prohibit the construction or extension or prescribe just and reasonable terms and conditions for the location of the lines, plants, or systems affected.
2. Whenever the commission, after a hearing upon its own motion or upon complaint, finds that there is or will be a duplication of service by public utilities in any area, the commission may issue a certificate of public convenience and necessity assigning specific territories to one or to each of said utilities or, by certificate of public convenience and necessity, otherwise define the conditions of rendering service and constructing extensions within those territories and may order the elimination of the duplication upon such terms as are just and reasonable, having due regard to due process of law and to all the rights of the respective parties and to public convenience and necessity.
3. Except as otherwise provided in section 29-20-108, C.R.S., a public utility shall not construct or install a new facility, plant, or system within the territorial boundaries of a local government unless the construction or installation complies with the local government's zoning rules, resolutions, or ordinances. Nothing in this subsection (3) prohibits a local government from granting a variance from its zoning rules, resolutions, or ordinances for such uses of the property. Nothing in this subsection (3) grants the commission any additional authority to restrict a siting application. For purposes of this section, "local government" means a county, home rule or statutory city, town, territorial charter city, or city and county. Nothing in this subsection (3) restricts the right of a public utility or power authority to appeal to the public utilities commission a local government action under section 29-20-108, C.R.S.
4. 1. A public utility is entitled to recover, through a separate rate adjustment clause, the costs that it prudently incurs in planning, developing, and completing the construction or expansion of transmission facilities for which the utility has been granted a certificate of public convenience and necessity, or for which the commission has determined that no certificate of public convenience and necessity is required. The transmission rate adjustment clause is subject to annual changes, which are effective on January 1 of each year.
   2. To provide additional encouragement to utilities to pursue the construction and expansion of transmission facilities, the commission shall approve current recovery by the utility through the annual rate adjustment clause of the utility's weighted average cost of capital, including its most recently authorized rate of return on equity, on the total balance of construction work in progress related to such transmission facilities as of the end of the immediately preceding year. The rate adjustment clause shall be reduced to the extent that the prudently incurred costs being recovered through the adjustment clause have been included in the public utility's base rates as a result of the commission's final order in a rate case.

Source: L. 13: p. 481, § 35. L. 17: p. 418, § 1. C.L. § 2946. CSA: C. 137, § 36. CRS 53: § 115-5-1. L. 61: p. 628, § 2. C.R.S. 1963: § 115-5-1. L. 2005: (3) added, p. 1355, § 1, effective August 8. L. 2007: (4) added, p. 267, § 3, effective March 27. L. 2012: Entire section amended, (HB 12-1312), ch. 101, p. 339, § 2, effective April 12.

Cross references: (1) For the acquisition of public utilities by cities and towns, see § 40-5-104.

(2) For the legislative declaration contained in the 2007 act enacting subsection (4), see section 1 of chapter 61, Session Laws of Colorado 2007. For the legislative declaration in the 2012 act amending this section, see section 1 of chapter 101, Session Laws of Colorado 2012.

40-5-101.5. Investor-owned utilities' service extension policies - commission review - rules.

1. Within one hundred eighty days after August 9, 2017, the commission shall open a nonadjudicatory proceeding to evaluate investor-owned utilities' current service extension policies for serving new load applications; except that gas-only, investor-owned utilities are not subject to the commission's nonadjudicatory proceeding. Based on the commission's evaluation, the commission shall issue a decision containing recommendations to investor-owned utilities for potential implementation.
2. In the commission's nonadjudicatory proceeding, the commission shall consider, without limitation, the following information from investor-owned utilities:
   1. The utilities' general load extension procedures used by the utility and requesting customers, including:
      1. The use of construction agreements, revenue assurance agreements, assignment of estimated costs, predevelopment system investment protocols, and options for cost and schedule transparency; and
      2. Potential system automation benefits to enhance clarity of the requirements and process;
   2. Equitable allocation of costs associated with an extension of facilities and any other factors affecting the cost of an extension of facilities; and
   3. Variables that affect time lines for construction and implementation of an extension of facilities.
3. Within ninety days after the conclusion of the nonadjudicatory proceeding, the commission may promulgate rules consistent with the findings of the nonadjudicatory proceeding.

Source: L. 2017: Entire section added, (SB 17-271), ch. 310, p. 1673, § 1, effective August 9.

40-5-102. Certificate of public convenience and necessity.

No public utility shall exercise any right or privilege under any franchise, permit, ordinance, vote, or other authority granted after April 12, 1913, or under any franchise, permit, ordinance, vote, or other authority granted before April 12, 1913, but not actually exercised before said date or the exercise of which has been suspended for more than one year without first having obtained from the commission a certificate that public convenience and necessity require the exercise of such right or privilege. When the commission finds, after hearing, that a public utility has, before April 12, 1913, begun actual construction work and is prosecuting such work, in good faith, uninterruptedly, and with reasonable diligence in proportion to the magnitude of the undertaking, under any franchise, permit, ordinance, vote, or other authority granted before April 12, 1913, but not actually exercised before said date, such public utility may proceed, under such rules and regulations as the commission may prescribe, to the completion of such work and after such completion, may exercise such right or privilege. Sections 40-5-101 to 40-5-104 shall not be construed to validate any right or privilege invalid on April 12, 1913, or becoming invalid after said date under any law of this state.

Source: L. 13: p. 481, § 35. L. 17: p. 418, § 1. C.L. § 2946. CSA: C. 137, § 36. CRS 53: § 115-5-2. C.R.S. 1963: § 115-5-2.

40-5-103. Certificate - application for - issuance.

1. Before any certificate may issue under sections 40-5-101 to 40-5-104, a certified copy of its articles of incorporation or charter, if the applicant is a corporation, shall be filed in the office of the commission. Every applicant for a certificate to exercise franchise rights under section 40-5-102 shall file in the office of the commission such evidence as shall be required by the commission to show that such applicant has received the required consent, franchise, permit, ordinance, vote, or other authority of the proper county, city and county, or municipal or other public authority. The commission has the power to issue a certificate to exercise franchise rights after hearing, to refuse to issue the same, or to issue it for the partial exercise only of said right or privilege and may attach to the exercise of the rights granted by such certificate such terms and conditions as in its judgment the public convenience and necessity may require. Nothing contained in this subsection (1) shall be construed to limit or restrict the power and authority of the commission: To regulate, issue, or refuse to issue certificates of public convenience and necessity for construction of a new facility, plant, or system or of any extension thereof as provided in section 40-5-101; and to attach to the exercise of the rights granted by such certificate such terms and conditions as in the commission's judgment may be required by the public convenience and necessity.
2. If such public utility desires to exercise a right or privilege under a franchise, permit, ordinance, vote, or other authority which it contemplates securing but which has not yet been granted to it, such public utility may apply to the commission for an order preliminary to the issue of the certificate. The commission may thereupon make an order declaring that it will thereafter, upon application, under such rules and regulations as it may prescribe issue the desired certificate upon such terms and conditions as it may designate after such public utility has obtained the contemplated franchise, permit, ordinance, vote, or other authority. Upon the presentation to the commission of evidence satisfactory to it that such franchise, permit, ordinance, vote, or other authority has been secured by such public utility, the commission shall thereupon issue such certificate.

Source: L. 13: p. 418, § 35. L. 17: p. 418, § 1. C.L. § 2946. CSA: C. 137, § 36. CRS 53: § 115-5-3. C.R.S. 1963: § 115-5-3. L. 69: p. 937, § 29. L. 81: (1) amended, p. 1918, § 1, effective June 19. L. 82: (1) amended, p. 629, § 43, effective April 2.

40-5-104. Acquisition by municipality.

1. Any municipality which has acquired or constructed any public utility plant, property, or facility has the power to contract with a public utility for the operation of any part or the whole thereof, subject to the provisions of articles 1 to 7 of this title and to exercise, in respect to such public utility, the powers of regulation and supervision conferred upon it by the commission.
2. Sections 40-5-101 to 40-5-104 shall not apply to railroads.

Source: L. 17: p. 417, § 1. C.L. § 2946. CSA: C. 137, § 36. CRS 53: § 115-5-4. C.R.S. 1963: § 115-5-4. L. 69: p. 938, § 30.

40-5-105. Certificate or assets may be sold, assigned, or lease