C.R.S. § 40-6-109 — CO Code / Title 40 / Article 6 / Section 40-6-109
40-6-109. Hearings - orders - record - review - representation of entities in nonadjudicat
Status: in_force

40-6-109. Hearings - orders - record - review - representation of entities in nonadjudicatory proceedings. (1) (a) (I) At the time fixed for any hearing before the commission, any commissioner, or an administrative law judge or at the time to which the hearing may have been continued, the following persons are entitled to be heard, examine and cross-examine witnesses, and introduce evidence:

(A) The applicant;

(B) The petitioner;

(C) The complainant;

(D) The person, firm, or corporation complained of;

(E) Such persons, firms, or corporations as the commission may allow to intervene; and

(F) Such persons, firms, or corporations as will be interested in or affected by any order that may be made by the commission in such proceeding and who shall have become parties to the proceeding.

(II) All parties in interest are entitled to be heard in person or by attorney.

(b) In a proceeding before the commission that relates to an investor-owned utility's application for cost recovery, the commission shall permit a wholesale customer of the utility to intervene if the customer demonstrates a pecuniary or tangible interest in the proceeding.

(c) A reporter appointed by the commission, a commissioner if deemed appropriate by the commission, or, as applicable, an administrative law judge shall take down and record electronically a full and complete record of all proceedings had before the commission, any commissioner, or an administrative law judge in any formal hearing and all testimony.

(2) Whenever any hearing, investigation, or other proceeding is assigned to an administrative law judge or individual commissioner for hearing, the administrative law judge or individual commissioner, after the conclusion of said hearing, shall promptly transmit to the commission the record and exhibits of said proceeding together with a written recommended decision which shall contain his findings of fact and conclusions thereon, together with the recommended order or requirement. Copies thereof shall be served upon the parties, who may file exceptions thereto; but if no exceptions are filed within twenty days after service upon the parties, or within such extended period of time as the commission may authorize in writing (copies of any such extension to be served upon the parties), or unless such decision is stayed within such time by the commission upon its own motion, such recommended decision shall become the decision of the commission and subject to the provisions of section 40-6-115. The commission upon its own motion may and where exceptions are filed shall reconsider the matter, either upon the same record or after further hearing, and such recommended decision shall thereupon be stayed or postponed pending final determination thereof by the commission. The commission may adopt, reject, or modify the findings of fact and conclusions of such individual commissioner or administrative law judge or, after examination of the record of any such proceeding, enter its decision and order therein without regard to the findings of fact and conclusions of any individual commissioner or administrative law judge. Any commissioner to whom a proceeding may be so assigned shall not be disabled thereby from participating with the commission in the final decision.

(3) After the conclusion of any hearing, investigation, or proceeding before the commission, the commission shall make and file its decision. The decision shall be a report in writing in which the commission shall state its findings of fact and conclusions thereon together with its order or requirement. The decision, under the seal of the commission, shall be served upon all parties and made available to all participants in the proceeding.

(4) Unless otherwise provided in this title, all decisions of the commission shall become effective upon a day to be fixed by the commission in any such decision and shall continue in force either for a period which may be designated therein or until changed or abrogated by the commission. Decisions containing negative orders shall be effective on the date of entry thereof, unless otherwise provided in any such decision. If an order or requirement cannot, in the judgment of the commission, be complied with within the time prescribed therein, the commission, on application made within such time and for good cause shown, may extend the time for compliance fixed in its decision.

(5) The commission may by general rule or regulation provide for the taking of evidence in uncontested or unopposed proceedings by affidavit or otherwise, without the necessity of a formal oral hearing. Such shortened or informal proceedings shall otherwise be subject to all of the provisions of this title. Upon its own motion the commission may and upon request of a party timely made the commission shall assign any such uncontested or unopposed proceeding for hearing.

(6) The commission may make the initial decision in cases where it has not presided at the taking of evidence, and the recommended decision of the individual commissioner or administrative law judge may be omitted in any case in which the commission finds upon the record that due and timely execution of its functions imperatively and unavoidably so requires.

(7) The commission may by general rule or regulation provide for appearances pro se by, or for representation by authorized officers or regular employees of, the commission's staff, corporations, partnerships, limited liability companies, sole proprietorships, and other legal entities in certain nonadjudicatory matters before the commission.
C.R.S. § 40-2-127 — CO Code / Title 40 / Article 2 / Part 1 / Section 40-2-127
40-2-127. Community energy funds - community solar gardens - definitions - rules - legisla
Status: repealed

40-2-127. Community energy funds - community solar gardens - definitions - rules - legislative declaration - applicability - repeal. (1) Legislative declaration. The general assembly hereby finds and declares that:

(a) Local communities can benefit from the further development of renewable energy, energy efficiency, conservation, and environmental improvement projects, and the general assembly hereby encourages electric utilities to establish community energy funds for the development of such projects;

(b) It is in the public interest that broader participation in solar electric generation by Colorado residents and commercial entities be encouraged by the development and deployment of distributed solar electric generating facilities known as community solar gardens, in order to:

(I) Provide Colorado residents and commercial entities with the opportunity to participate in solar generation in addition to the opportunities available for rooftop solar generation on homes and businesses;

(II) Allow renters, low-income utility customers, and agricultural producers to own interests in solar generation facilities;

(III) Allow interests in solar generation facilities to be portable and transferrable; and

(IV) Leverage Colorado's solar generating capacity through economies of scale.

(2) Definitions. As used in this section, unless the context otherwise requires:

(a) The definitions in section 40-2-124 apply; and

(b) In addition:

(I) (A) "Community solar garden" means a solar electric generation facility with a nameplate rating within the range specified under subsection (2)(b)(I)(D) of this section that is located in or near a community served by a qualifying retail utility where the beneficial use of the electricity generated by the facility belongs to the subscribers to the community solar garden. There shall be at least ten subscribers. The owner of the community solar garden may be the qualifying retail utility or any other for-profit or nonprofit entity or organization, including a subscriber organization organized under this section, that contracts to sell the output from the community solar garden to the qualifying retail utility. A community solar garden shall be deemed to be "located on the site of customer facilities".

(B) A community solar garden shall constitute "retail distributed generation" within the meaning of section 40-2-124, as amended by House Bill 10-1001, enacted in 2010.

(C) Notwithstanding any provision of this section or section 40-2-124 to the contrary, a community solar garden constitutes retail distributed generation for purposes of a cooperative electric association's compliance with the applicable renewable energy standard under section 40-2-124.

(D) A community solar garden must have a nameplate rating of five megawatts or less; except that the commission may, in rules adopted pursuant to subsection (3)(b) of this section, approve the formation of a community solar garden with a nameplate rating of up to ten megawatts on or after July 1, 2023.

(II) "Subscriber" means a retail customer of a qualifying retail utility who owns a subscription and who has identified one or more physical locations to which the subscription is attributed. Such physical locations must be within the service territory of the same qualifying retail utility as the community solar garden. The subscriber may change from time to time the premises to which the community solar garden electricity generation shall be attributed, so long as the premises are within the same service territory.

(III) "Subscription" means a proportional interest in solar electric generation facilities installed at a community solar garden, together with the renewable energy credits associated with or attributable to such facilities under section 40-2-124. Each subscription shall be sized to represent at least one kilowatt of the community solar garden's generating capacity and to supply no more than one hundred twenty percent of the average annual consumption of electricity by each subscriber at the premises to which the subscription is attributed, with a deduction for the amount of any existing solar facilities at such premises. Subscriptions in a community solar garden may be transferred or assigned to a subscriber organization or to any person or entity who qualifies to be a subscriber under this section.

(3) Subscriber organization - subscriber qualifications - transferability of subscriptions. (a) The community solar garden may be owned by a subscriber organization, whose sole purpose shall be beneficially owning and operating a community solar garden. The subscriber organization may be any for-profit or nonprofit entity permitted by Colorado law. The community solar garden may also be built, owned, and operated by a third party under contract with the subscriber organization.

(b) The commission shall adopt rules as necessary to implement this section, including rules to facilitate the financing of subscriber-owned community solar gardens. The rules must include:

(I) Minimum capitalization;

(II) The share of a community solar garden's eligible solar electric generation facilities that a subscriber organization may at any time own in its own name; and

(III) Authorizing subscriber organizations to enter into leases, sale-and-leaseback transactions, operating agreements, and other ownership arrangements with third parties.

(c) If a subscriber ceases to be a customer at the premises on which the subscription is based but, within a reasonable period as determined by the commission, becomes a customer at another premises in the service territory of the qualifying retail utility and within the geographic area served by the community solar garden, the subscription shall continue in effect but the bill credit and other features of the subscription shall be adjusted as necessary to reflect any differences between the new and previous premises' customer classification and average annual consumption of electricity.

(3.5) Standards for construction and operation. The following requirements apply to any community solar garden exceeding two megawatts:

(a) The initial installation of any photovoltaic module or associated electrical equipment is subject to final inspection and approval in accordance with section 12-115-120.

(b) Following the development or acquisition by a qualifying retail utility of a community solar garden in which the qualifying retail utility retains ownership, the qualifying retail utility shall either use its own employees to operate and maintain the community solar garden or contract for operation and maintenance of the community solar garden by a contractor whose employees have access to an apprenticeship program registered with the United States department of labor's office of apprenticeship or with a state apprenticeship agency recognized by that office; except that this apprenticeship requirement does not apply to:

(I) The design, planning, or engineering of the infrastructure;

(II) Management functions to operate the infrastructure; or

(III) Any work included in a warranty.

(3.7) Energy sector public works projects. If the development of a community solar garden is an energy sector public works project, as defined in section 24-92-303 (5), then the project must comply with the applicable requirements of the "Colorado Energy Sector Public Works Project Craft Labor Requirements Act", part 3 of article 92 of title 24.

(4) Community solar gardens not subject to regulation. Neither the owners of nor the subscribers to a community solar garden shall be considered public utilities subject to regulation by the commission solely as a result of their interest in the community solar garden. Prices paid for subscriptions in community solar gardens shall not be subject to regulation by the commission.

(5) Purchases of the output from community solar gardens. (a) (I) Each qualifying retail utility shall set forth in its plan for acquisition of renewable resources a plan to purchase the electricity and renewable energy credits generated from one or more community solar gardens over the period covered by the plan.

(II) For the first three compliance years commencing with the 2011 compliance year, each qualifying retail utility shall issue one or more standard offers to purchase the output from community solar gardens of five hundred kilowatts or less at prices that are comparable to the prices offered by the qualifying retail utility under standard offers issued for on-site solar generation. During these three compliance years, the qualifying retail utility shall acquire, through these standard offers, one-half of the solar garden generation it plans to acquire, to the extent the qualifying retail utility receives responses to its standard offers. Notwithstanding any provision of this subparagraph (II) to the contrary, renewable energy credits generated from solar gardens shall not be used to achieve more than twenty percent of the retail distributed generation standard in years 2011 through 2013.

(III) For the first three compliance years commencing with the 2011 compliance year, a qualifying retail utility shall not be obligated to purchase the output from more than six megawatts of newly installed community solar garden generation.

(III.5) Subsections (5)(a)(II) and (5)(a)(III) of this section and this subsection (5)(a)(III.5) are repealed, effective July 1, 2043.

(IV) For each qualifying retail utility's compliance years commencing in 2014 through 2025, the commission shall determine the minimum and maximum purchases of electrical output from newly installed community solar gardens of different output capacity that the qualifying retail utility shall plan to acquire, without regard to the six-megawatt ceiling of the first three compliance years. In addition, as necessary, the commission shall formulate and implement policies consistent with this section that simultaneously encourage:

(A) The ownership by customers of subscriptions in community solar gardens and of other forms of distributed generation, to the extent the commission finds there to be customer demand for such ownership;

(B) Ownership in community solar gardens by residential retail customers and agricultural producers, including low-income customers, to the extent the commission finds there to be demand for such ownership;

(C) The development of community solar gardens with attributes that the commission finds result in lower overall total costs for the qualifying retail utility's customers;

(D) Successful financing and operation of community solar gardens owned by subscriber organizations; and

(E) The achievement of the goals and objectives of section 40-2-124.

(b) (I) (A) The output from a community solar garden shall be sold only to the qualifying retail utility serving the geographic area where the community solar garden is located.

(B) Once a community solar garden is part of a qualifying retail utility's plan for acquisition of renewable resources, as approved by the commission, the commission shall, by January 30, 2020, initiate a proceeding, or consider in an active proceeding, to determine whether the qualifying retail utility shall purchase all of the electricity and renewable energy credits generated by the community solar garden or whether a subscriber may, upon becoming a subscriber, choose to retain or sell to the qualifying retail utility the subscriber's renewable energy credits.

(C) The amount of electricity and renewable energy credits generated by each community solar garden shall be determined by a production meter installed by the qualifying retail utility or third-party system owner and paid for by the owner of the community solar garden.

(II) (A) The purchase of the output of a community solar garden by a qualifying retail utility must take the form of a net metering credit against the qualifying retail utility's electric bill to each community solar garden subscriber at the premises set forth in the subscriber's subscription.

(B) For a subscriber organization that directs the qualifying retail utility to provide the subscriber organization's subscribers with a bill credit that changes annually, the net metering credit is calculated by multiplying the subscriber's share of the electricity production from the community solar garden by the qualifying retail utility's total aggregate retail rate as charged to the subscriber, minus a reasonable charge as determined by the commission. The charge will be used to cover the utility's costs of delivering to the subscriber's premises the electricity generated by the community solar garden, integrating the solar generation with the utility's system, and administering the community solar garden's contracts and net metering credits.

(C) For a subscriber organization that directs the qualifying retail utility to provide the subscriber organization's subscribers with a fixed bill credit, the net metering credit is calculated by multiplying the subscriber's share of the electricity production from the community solar garden by the qualifying retail utility's total aggregate retail rate as charged to the subscriber at the time the subscriber organization applies for or bids capacity into a utility community solar garden program, minus a reasonable charge, as determined by the commission at the time the subscriber organization applies for or bids capacity into a utility community solar garden program. The charge will be used to cover the utility's costs related to: Delivering to the subscriber's premises the electricity generated by the community solar garden, integrating the solar generation with the utility's system, and administering contracts and net metering credits for the community solar garden.

(D) For community solar gardens eligible for a fixed bill credit, and solely for the purpose of applying the bill credit to a subscriber's bill, the bill credit shall not be applied toward the following rate rider charges, unless the rate rider charges are included in the reasonable charge: Rate rider charges that promote clean energy technologies, including beneficial electrification; rate rider charges that provide low-income bill assistance; or rate rider charges that provide other public benefits as determined by the commission.

(E) By June 30, 2024, the commission shall adopt rules to implement the fixed bill credit. The rules must consider the change of value to community solar garden customers of the fixed bill credit over time through rate adjustments or other mechanisms.

(F) The commission shall allow a qualifying retail utility to recover the costs incurred in implementing and maintaining billing systems for the various bill credit processes required pursuant to this subsection (5)(b)(II).

(G) The commission shall ensure that the reasonable charge that the commission determines pursuant to subsections (5)(b)(II)(B) and (5)(b)(II)(C) of this section does not reflect costs that are already recovered by the utility from the subscriber through other charges.

(H) If, and to the extent that, a subscriber's net metering credit exceeds the subscriber's electric bill in any billing period, the net metering credit shall be carried forward and applied against future bills.

(I) The qualifying retail utility and the owner of the community solar garden must agree on whether the purchase of the renewable energy credits from subscribers will be accomplished through a credit on each subscriber's electricity bill or by a payment to the owner of the community solar garden.

(c) The owner of the community solar garden shall provide real-time production data to the qualifying retail utility to facilitate incorporation of the community solar garden into the utility's operation of its electric system and to facilitate the provision of net metering credits.

(d) The owner of the community solar garden shall be responsible for providing to the qualifying retail utility, on a monthly basis and within reasonable periods set by the qualifying retail utility, the percentage shares that should be used to determine the net metering credit to each subscriber. If the electricity output of the community solar garden is not fully subscribed, the qualifying retail utility shall purchase the unsubscribed renewable energy and the renewable energy credits at a rate equal to the qualifying retail utility's average hourly incremental cost of electricity supply over the immediately preceding calendar year.

(e) Each qualifying retail utility shall set forth in its plan for acquisition of renewable resources a proposal for including low-income customers as subscribers to a community solar garden. The utility may give preference to community solar gardens that have low-income subscribers.

(f) Qualifying retail utilities shall be eligible for the incentives and subject to the ownership limitations set forth in section 40-2-124 (1)(f) for utility investments in community solar gardens and may recover through rates a margin, in an amount determined by the commission, on all energy and renewable energy credits purchased from community solar gardens. Such incentive payments shall be excluded from the cost analysis required by section 40-2-124 (1)(g).

(6) Nothing in this section shall be construed to waive or supersede the retail rate impact limitations in section 40-2-124 (1)(g). Utility expenditures for unsubscribed energy and renewable energy credits generated by community solar gardens shall be included in the calculations of retail rate impact required by that section.

(7) Applicability to cooperative electric associations and municipally owned utilities. This section shall not apply to cooperative electric associations or to municipally owned utilities.

(8) Applicability. (a) This section applies to community solar capacity that is allocated on or before December 31, 2025.

(b) Community solar capacity that is allocated on or after January 1, 2026, is allocated pursuant to section 40-2-127.2.
C.R.S. § 40-41-106 — CO Code / Title 40 / Article 41 / Section 40-41-106
40-41-106. Effect on commission jurisdiction - rules
Status: in_force

40-41-106. Effect on commission jurisdiction - rules. (1) Except as otherwise provided in subsection (2) of this section, if the commission issues a financing order to an electric utility, the commission shall not, in exercising its powers and carrying out its duties pursuant to this article 41:

(a) Consider the CO-EI bonds issued pursuant to the financing order to be debt of the electric utility other than for income tax purposes;

(b) Consider the CO-EI charges paid under the financing order to be revenue of the electric utility;

(c) Consider the CO-EI costs or financing costs specified in the financing order to be the regulated costs or assets of the electric utility; or

(d) Determine any prudent action taken by an electric utility that is consistent with the financing order to be unjust or unreasonable.

(2) Nothing in subsection (1) of this section:

(a) Prevents or precludes the commission from investigating the compliance of an electric utility with the terms and conditions of a financing order and requiring compliance with the financing order; or

(b) Prevents or precludes the commission from imposing regulatory sanctions against a regulated electric utility for failure to comply with the terms and conditions of a financing order or the requirements of this article 41.

(3) The commission may not refuse to allow the recovery of any costs associated with the retirement of electric generating facilities by an electric utility solely because the electric utility has elected to recover those costs through traditional rate-making methods or to finance those activities through a financing mechanism other than CO-EI bonds, whether or not a financing order with respect to such costs has been applied for by the utility or issued by the commission.

(4) The commission may adopt rules to implement this article 41.
C.R.S. § 40-10.1-405 — CO Code / Title 40 / Article 10.1 / Part 4 / Section 40-10.1-405
40-10.1-405. Nonconsensual tows - rights of owners, operators, and lienholders - rules
Status: repealed

40-10.1-405. Nonconsensual tows - rights of owners, operators, and lienholders - rules. (1) Towing fees. (a) Towing carriers shall prominently display at their place of business and on any website of the towing carrier the current maximum rates permitted by rule of the commission for each tow service provided by the towing carrier. The sign must include the following statement: "The maximum permitted rate is based upon rules of the public utilities commission, and if there are concerns or questions about these rates or the towing carrier, then call the public utilities commission consumer affairs hotline at 303-894-2070."

(b) (I) A towing carrier shall accept:

(A) Cash;

(B) Major credit cards; and

(C) Other forms of payment required by rule of the commission.

(II) The commission shall promulgate a rule defining what qualifies as a major credit card for the purposes of this subsection (1)(b).

(c) A towing carrier shall not:

(I) Charge storage fees for any twenty-four-hour period during which the towing carrier did not store the vehicle, but the towing carrier may charge, in accordance with section 42-4-2103 (3)(c), a prorated fee for any part of a twenty-four-hour period the towing carrier stored the vehicle; and

(II) Charge or retain any fees not identified in the rules of the commission for the nonconsensual tow of a vehicle from private property.

(2) Towing carrier document vehicle's condition and reason for tow - adequate illumination. (a) Before a towing carrier connects a towing vehicle to a vehicle without consent, the towing carrier shall document the vehicle's condition and the reason for the tow by:

(I) Taking at least four photographs of the vehicle, with at least one photograph taken from the front, one photograph taken from the rear, one photograph taken from the driver's side, and one photograph taken from the passenger's side. These photographs must:

(A) Show the entire vehicle from the required angle;

(B) Have the vehicle fill at least three-fourths of the photograph, measured from side to side; and

(C) Be rendered in a resolution of at least two thousand pixels by at least two thousand pixels.

(II) Taking a photograph that shows the reason for the vehicle being towed without consent. The photograph must:

(A) Show the position of the vehicle in relation to the reason, including any sign, that the vehicle was towed; and

(B) Be rendered in a resolution of at least two thousand pixels by at least two thousand pixels.

(b) Upon demand by an authorized or interested person, the towing carrier shall provide copies of the photographs required to be taken pursuant to subsection (2)(a)(I) or (2)(a)(II) of this section.

(c) (I) A rebuttable presumption that a towing carrier damaged a vehicle is created by evidence that:

(A) The towing carrier has failed to produce photographs of the vehicle's condition in compliance with subsection (2)(b) of this section; and

(B) A vehicle has suffered damage.

(II) A towing carrier's failure to produce a photograph of the reason for the tow in compliance with subsection (2)(b) of this section creates a rebuttable presumption that the towing carrier did not have authorization to tow a vehicle.

(d) During business hours or when a vehicle is being released, a towing carrier shall maintain an area at each storage facility with lighting that is adequate to allow a person to inspect a vehicle for damage prior to its release from storage.

(3) Authorization, signs, and notice required for tows from private property. (a) A towing carrier shall not nonconsensually tow a vehicle from private property unless:

(I) The vehicle is being repossessed by a creditor with a lien or security interest in the vehicle;

(II) The removal is expressly ordered or authorized by a court order, an administrative order, or a peace officer or by operation of law;

(III) The vehicle blocks a driveway or roadway enough to effectively obstruct a person's access to the driveway or roadway;

(IV) The towing carrier has received documented permission, which must not be automated or preapproved, for each individual tow of the vehicle, within the twenty-four hours immediately preceding the tow, from the following person that must document the permission by signing the form created in accordance with subsection (3)(d)(I) of this section:

(A) The owner of or leaseholder of the private property; except that, if the owner or leaseholder would earn income from the nonconsensual tow, the towing carrier shall not perform the nonconsensual tow but may authorize another towing carrier to perform the nonconsensual tow;

(B) A person subject to the "Colorado Common Interest Ownership Act", article 33.3 of title 38, if the private property is located within the boundaries of the person's area of operation; or

(C) An employee of a person described in subsection (3)(a)(IV)(A) or (3)(a)(IV)(B) of this section or an employee of a property management company retained to collect rent and perform residential services; except that the employee who has a financial interest in or relationship with the towing carrier or a parking lot management company that earns income from managing or controlling parking or permission to park or that earns income from nonconsensual tows shall not grant permission to authorize the tow; or

(V) The towing carrier has received permission for each individual tow.

(b) (I) Except as provided in subsection (3)(b)(IV) of this section, a towing carrier shall not nonconsensually tow a vehicle from a parking space or common parking area without the towing carrier or property owner giving the vehicle owner or operator twenty-four hours' written notice, unless:

(A) The vehicle owner or operator has received two previous notices for parking inappropriately in the same manner;

(B) The vehicle is being repossessed by a creditor with a lien or security interest in the vehicle;

(C) The removal is expressly ordered or authorized by a court order, an administrative order, or a peace officer or by operation of law;

(D) The vehicle blocks a driveway or roadway enough to effectively obstruct a person's access to the driveway or roadway;

(E) The vehicle is parked in violation of section 42-4-1208 (4) or in reserved parking for people with disabilities without displaying an identifying placard or an identifying plate, as those terms are defined in section 42-3-204 (1)(f) and (1)(g), that is currently valid or has been expired for no more than sixty days;

(F) The vehicle is parked in or effectively obstructing a designated and marked fire zone;

(G) The vehicle is occupying without permission or effectively obstructing access to or from an individually designated, rented, or purchased parking space of a resident; or

(H) The vehicle is parked without authorization in a parking lot marked for the exclusive use of residents or invited guests.

(II) The towing carrier or property owner shall provide the notice described in subsection (3)(b)(I) of this section by placing a written notice on the windshield of the vehicle at least twenty-four hours before towing the vehicle.

(III) The notice must state clearly:

(A) That the vehicle will be towed without consent if the vehicle remains parked inappropriately;

(B) A description of the inappropriate parking that has caused the notice to be given;

(C) The time the vehicle will be towed if it is not moved to appropriate parking or the inappropriate parking has been corrected; and

(D) That continuing to park inappropriately in the same manner may lead to the vehicle being towed without notice.

(IV) If the vehicle is parked a third or subsequent time in the same inappropriate manner that caused it to receive previous notices, the towing carrier or property owner need not give the notice required in subsection (3)(b)(I) of this section before towing the vehicle.

(V) For purposes of this subsection (3)(b), a vehicle is parked inappropriately when it is parked in a manner that:

(A) Violates the procedures necessary to obtain authorization to park in the lot or space;

(B) Fails to comply with the property owner's signs or the agreements of the tenants; or

(C) Violates a statute, rule, ordinance, or resolution of the state or a political subdivision of the state.

(c) In order for a towing carrier to conduct a nonconsensual tow, the property owner must have posted signage that:

(I) Is not less than two square feet in size;

(II) Has lettering not less than one inch in height;

(III) Has lettering that contrasts sharply in color with the background on which the letters are placed and contrasts sharply with the structure the signs are placed on;

(IV) Contains the following information in the order listed below:

(A) The restriction or prohibition on parking;

(B) The times of the day and days that the restriction is applicable, but, if the restriction applies twenty-four hours a day, seven days a week, the sign must say "Authorized Parking Only"; and

(C) The name and telephone number of the towing carrier authorized to perform tows from the private property;

(V) Is printed in English and Spanish;

(VI) Is permanently mounted both:

(A) At the entrance to the private property so that the sign faces outward toward the street and is visible before and upon entering the private property; and

(B) Inside the private property so that the sign faces outward toward the parking area;

(VII) Is not obstructed from view or placed in a manner that prevents direct visibility; and

(VIII) Is not placed higher than ten feet or lower than three feet from the surface closest to the sign's placement.

(d) (I) The commission shall create a form that implements subsection (3)(a)(IV) of this section.

(II) The towing carrier must retain for three years the signed form required by subsection (3)(a)(IV) of this section and, upon request, provide the signed form to the vehicle owner.

(e) A towing carrier shall not patrol or monitor property to enforce parking restrictions on behalf of the property owner.

(4) Notice, disclosures, and towing carrier signs. (a) In connection with a nonconsensual tow, the towing carrier shall provide, upon request, evidence of the towing carrier's commercial liability insurance coverage, including cargo liability coverage, garage keeper's liability coverage, if applicable, and motor vehicle liability coverage, to an authorized or interested person.

(b) A towing carrier shall maintain a clearly visible sign at the entrance to the storage facility holding a nonconsensually towed vehicle. The sign must:

(I) State the name of the business, telephone number, and hours of operation;

(II) State: "If a vehicle is nonconsensually towed from private property, the authorized or interested person may retrieve the contents of the vehicle even if the authorized or interested person does not pay the towing carrier's fees. If the authorized or interested person fills out the appropriate form, the authorized or interested person may retrieve the vehicle after paying a reduced fee, but the authorized or interested person still owes the towing carrier the balance of those fees."

(III) Be no less than two square feet in size;

(IV) Have lettering not less than two inches in height;

(V) Have lettering that contrasts sharply in color with the background on which the letters are placed; and

(VI) Be printed in English.

(c) Upon request, a towing carrier shall provide to an authorized or interested person an itemized bill showing each charge and the rate for each fee that the authorized or interested person has incurred as a result of a nonconsensual tow.

(d) Upon request, a towing carrier shall disclose accepted forms of payment, including those required to be accepted in accordance with subsection (1)(b) of this section.

(e) If a towing carrier has nonconsensually towed a vehicle from private property, the towing carrier shall give the authorized or interested person that is retrieving the vehicle a written notice of the person's ability to make a complaint to the commission. The notice:

(I) Must be written in a conspicuous typeface and font on the invoice, the receipt, and the bill for the tow; and

(II) Must not be in a typeface or font that is smaller than the other numbers or words on the receipt or bill, as applicable.

(f) (I) A towing carrier shall not perform a nonconsensual tow of a vehicle, other than an abandoned motor vehicle as defined in section 42-4-2102 (1), from private property normally used for parking unless:

(A) Notice of the parking regulations was provided to the vehicle operator when the vehicle entered the private property and parked; and

(B) Notice that any vehicle parked in violation of the regulations is subject to tow at the vehicle owner's expense was provided to the vehicle operator when the vehicle entered the private property and parked.

(II) A property owner with tenants shall provide the notice described in this subsection (4)(f) by issuing each tenant a written document containing any applicable parking regulations before the regulations are adopted or amended or before the person agrees to be a tenant.

(III) Repealed.

(g) The towing carrier shall retain evidence, including photographs of the relevant signs, of giving the notices and disclosures required in subsection (4)(f) of this section for three years after the date of completion of a nonconsensual tow and provide the evidence to the commission or an enforcement official upon request.

(5) No mechanic's liens on contents. (a) Notwithstanding section 38-20-105, a towing carrier that nonconsensually tows a vehicle does not have a mechanic's lien on the contents of the vehicle to cover the cost of towing the vehicle.

(b) If an authorized or interested person requests that a towing carrier return the contents of a vehicle that was towed without consent within thirty days after the postmarked date the notice was mailed in accordance with section 42-4-2103 (4) or the date the operator received notice that no record exists for the motor vehicle, the towing carrier shall allow the authorized or interested person to retrieve the vehicle's contents. This subsection (5)(b) does not apply to the contents of a vehicle if the contents of the vehicle are subject to a hold order issued by a court, district attorney, law enforcement agency, or peace officer.

(c) The towing carrier shall immediately retrieve a vehicle that has been nonconsensually towed or allow the authorized or interested person to retrieve the vehicle if:

(I) The owner pays fifteen percent of the fees, not to exceed sixty dollars, owed the towing carrier for the nonconsensual tow; and

(II) The authorized or interested person is not a lienholder or insurance company.

(d) For an authorized or interested person to retrieve a vehicle without paying the towing carrier the total amount owed to the towing carrier, the authorized or interested person must sign a form affirming that the authorized or interested person owes the towing carrier payment for fees that comply with this article 10.1, part 21 of article 4 of title 42, or article 20 of title 38. Knowingly providing false information on the form is unlawful. Signing this form does not prohibit a vehicle owner from filing a complaint with the commission or pursuing other remedies. The towing carrier may use the form to take reasonable actions to collect the debt, including initiating a court action or using a collection agency. The commission shall:

(I) Create the form;

(II) Give the form the following title: "Towed Vehicle Release Notice: Retrieval with Payment Owed"; and

(III) Provide the form on the public utilities commission website for towing carriers to retrieve and use.

(e) A towing carrier shall not require a person to undergo an approval process other than signing the form created pursuant to subsection (5)(d) of this section.

(6) Releasing the vehicle upon request. (a) A towing carrier shall release a nonconsensually towed vehicle in accordance with subsection (5)(c) of this section.

(b) A towing carrier shall not assess a drop charge to release the vehicle after the vehicle is hooked up to the tow truck but before the vehicle is removed from the property.

(c) If approached by an authorized or interested person before the vehicle is removed from private property, the towing carrier shall notify the authorized or interested person that the towing carrier is required to release the vehicle upon request of the authorized or interested person.

(d) Upon request by the authorized or interested person, the towing carrier shall stop any tow in progress before the vehicle is removed from private property.

(7) No towing for expired registration. Unless the tow is based on an order given by a peace officer, a towing carrier shall not tow a vehicle from private property because the rear license plate of the vehicle or the record obtained using the system described in section 42-4-2103 (3)(c)(III) indicates that the vehicle's registration has expired.

(8) Towing carrier responsibility. Repealed.

(9) Applicability. This section does not apply to:

(a) A tow ordered by a peace officer or technician directed by a peace officer in the course and scope of the officer's or technician's duties; or

(b) A tow from a parking space that serves a business if:

(I) Repealed.

(II) The parking space is on commercial real estate, as defined in section 38-22.5-102 (2).
C.R.S. § 40-3.2-108 — CO Code / Title 40 / Article 3.2 / Part 1 / Section 40-3.2-108
40-3.2-108. Clean heat targets - legislative declaration - definitions - plans - rules - rep
Status: in_force

40-3.2-108. Clean heat targets - legislative declaration - definitions - plans - rules - reports. (1) Legislative declaration. The general assembly hereby:

(a) Finds that:

(I) In order to achieve Colorado's science-based greenhouse gas emission reduction goals and maintain a healthy, livable climate for Coloradans, Colorado must reduce greenhouse gas pollution from all sectors of the economy, including the built environment;

(II) A significant source of greenhouse gas pollution from the built environment comes from the use of gas to heat Colorado's homes and businesses and to heat water in those buildings, from the use of gas in commercial and industrial processes, and from gas leaks in the supply chain;

(III) Improving the energy efficiency of Colorado's buildings will reduce pollution, improve comfort and safety, provide more resilience during weather extremes, and reduce consumer costs for heating and cooling homes and businesses; and

(IV) Reducing the carbon intensity of gas delivered by utilities and switching from gas space and water heating to high-efficiency electric heating will reduce greenhouse gas pollution and lead to improved indoor air quality;

(b) Determines that:

(I) There is significant potential to reduce emissions of methane from active and inactive coal mines, landfills, wastewater treatment plants, agricultural operations, and other sources of methane pollution through development of methane recovery and biomethane projects, and there are also significant economic development opportunities, especially in rural Colorado, from development of this resource;

(II) Green and blue hydrogen have the potential to be zero- or very low-carbon sources of energy for use in a variety of sectors, including high-heat industrial applications, zero-carbon electricity generation, and the gas distribution system; and

(III) The development of hydrogen projects in Colorado has the potential to lower costs, contribute to economies of scale, and bring economic development opportunities; and

(c) Declares that:

(I) The general assembly's intent in enacting this section is to implement a performance standard that will allow Colorado gas utilities to use available tools, including energy efficiency, biomethane, hydrogen, recovered methane, beneficial electrification of customer end uses, cost-effective leak reductions on the utility's distribution system as determined by the commission that exceed state and federal requirements, and other measures to achieve greenhouse gas emission reductions, cost-effectiveness, and equity;

(II) Colorado is focused on a transition to a decarbonized economy that recognizes the historic injustices that impact lower-income Coloradans and Black, Indigenous, and other people of color who have borne a disproportionate share of environmental risks while also enjoying fewer environmental benefits;

(III) The commission must maximize greenhouse gas emission reductions and benefits to customers, with particular attention to residential customers who participate in income-qualified programs, while managing costs and risks to customers, including stranded-asset cost risks, and in a manner that supports family-sustaining jobs; and

(IV) Decarbonizing Colorado's homes and businesses will require investments in building and equipment upgrades, clean fuel projects, and infrastructure upgrades.

(2) Definitions. As used in this section, unless the context otherwise requires:

(a) "Biomethane":

(I) Means a mixture of carbon dioxide and hydrocarbons released from the biological decomposition of organic materials that is primarily methane and provides a net reduction in greenhouse gas emissions; and

(II) Includes biomethane recovered from manure management systems or anaerobic digesters, including from operations for dairy cows, beef cattle, poultry, swine, or sheep, that has been processed to meet pipeline quality.

(b) "Clean heat plan" means a comprehensive plan submitted by a gas distribution utility or municipal gas distribution utility that demonstrates projected reductions in methane and carbon dioxide emissions that, together, meet the reductions required in this section at the lowest reasonable cost.

(c) "Clean heat resource" means any one or a combination of:

(I) Gas demand-side management programs as defined in section 40-1-102 (6);

(II) Recovered methane;

(III) Green hydrogen;

(IV) Beneficial electrification as defined in section 40-1-102 (1.2);

(V) Pyrolysis of tires if the pyrolysis meets a recovered methane protocol;

(V.5) Thermal energy; and

(V.8) Wastewater thermal energy; and

(VI) Any technology that the commission finds is cost-effective and that the division finds results in a reduction in carbon emissions from the combustion of gas in customer end uses or meets a recovered methane protocol approved by the air quality control commission. To qualify as a clean heat resource, all credits or severable, tradable mechanisms representing the emission reduction attributes of the clean heat resource must be retired in the year generated and may not be sold.

(d) "Cost cap" means a maximum cost impact established pursuant to subsection (6)(a)(I) of this section for compliance with a clean heat target.

(e) "Division" means the division of administration created by section 25-1-102 (2)(a) in the department of public health and environment.

(f) "Gas" means geological gas, hydrogen, and recovered methane.

(g) "Gas distribution utility" means a public utility providing gas service to more than ninety thousand retail customers. "Gas distribution utility" does not include a municipal gas distribution utility.

(h) "Geological gas" means methane and other hydrocarbons that occur underground without human intervention and are used as fuel.

(h.5) "Geothermal fluid" has the meaning set forth in section 37-90.5-103 (2).

(i) "Greenhouse gas" has the meaning set forth in section 25-7-140 (6), measured in terms of carbon dioxide equivalent.

(j) "Green hydrogen" means hydrogen derived from a clean energy resource as defined in section 40-2-125.5 (2)(b) that uses water as the source of the hydrogen. For purposes of a clean heat plan, a green hydrogen project may include associated clean energy generation, transmission, and other infrastructure, subject to commission approval.

(k) "Lowest reasonable cost" means a reasonable-cost mix of clean heat resources that meet clean heat targets established pursuant to this section as determined through a detailed analysis of available technologies and includes resource costs, market volatility risks, risks to ratepayers, systems operations costs, infrastructure costs, environmental justice goals, the social cost of carbon, and the social cost of methane in comparing the costs and benefits of alternatives, and other costs and benefits as determined by the commission.

(l) "Municipal gas distribution utility" means a municipally owned utility that provides gas service to more than ninety thousand customers.

(m) "Pyrolysis" has the meaning set forth in section 40-2-124 (1)(a)(V).

(n) "Recovered methane" means any of the following that are located in Colorado and meet a recovered methane protocol approved by the air quality control commission:

(I) Biomethane; and

(II) Methane derived from:

(A) Municipal solid waste;

(B) The pyrolysis of municipal solid waste;

(C) Biomass pyrolysis or enzymatic biomass; or

(D) Wastewater treatment;

(III) Coal mine methane, as defined in section 40-2-124 (1)(a)(II), the capture of which is not otherwise required by state or federal law; or

(IV) Methane that would have leaked without repairs of the gas distribution and service pipelines from the city gate to customer end use.

(o) "Recovered methane credit" means a tradable instrument that represents a greenhouse gas emission reduction or greenhouse gas removal enhancement of one metric ton of carbon dioxide equivalent. The greenhouse gas emission reduction or greenhouse gas removal enhancement must be real, additional, quantifiable, permanent, verifiable, and enforceable. No recovered methane credit may be issued if the greenhouse gas emission reduction or greenhouse gas removal enhancement that the credit would represent is required or accounted for by a proposed or final federal, state, or local rule or regulation.

(p) "Recovered methane protocol" means a documented set of procedures and requirements established by the air quality control commission to quantify ongoing greenhouse gas emission reductions or greenhouse gas removal enhancements achieved by a recovered methane project and to calculate the project baseline. A recovered methane protocol that the air quality control commission adopts for biomethane from manure management systems must allow for the use of manure from beef cattle operations. The air quality control commission may also adopt a recovered methane protocol that is specific to manure management from beef cattle operations. A recovered methane protocol must:

(I) Specify relevant data collection and monitoring procedures and emission factors;

(II) Conservatively account for uncertainty, activity-shifting leakage risks, and market-shifting leakage risks associated with a type of recovered methane project;

(III) Determine data verification requirements; and

(IV) Specify procedures pursuant to which the air quality control commission must approve an entity that the division proposes to accredit for verification of ongoing greenhouse gas emission reductions or greenhouse gas removal enhancements.

(q) "Small gas distribution utility" means a public utility providing gas service to ninety thousand retail customers or fewer. "Small gas distribution utility" does not include a municipal gas distribution utility.

(r) (I) "Thermal energy" means piped, noncombustible fluids used for adding or removing heat from buildings for the purpose of efficient building temperature control and domestic hot water, including space heating and cooling and refrigeration.

(II) "Thermal energy" includes methods of exchanging the piped, noncombustible fluids through the ground, wastewater treatment facilities, or other sources that achieve desired fluid temperatures; except that any source of thermal energy for this purpose must:

(A) Not cause incremental greenhouse gas emissions or rely on increased, long-term combustion of fossil fuels; and

(B) Be evaluated by the commission to protect against increased emissions of harmful co-pollutants, negative impacts to communities including to disproportionately impacted communities, as defined in section 24-4-109 (2)(b)(II), and the risk of stranded assets, if the thermal energy is from any industrial source including a system for which the primary purpose is to generate electricity, including any process involving engine-driven generation.

(s) "Thermal energy network":

(I) Means all real estate, fixtures, and personal property that are operated, owned, used, or intended to be used for, in connection with, or to facilitate a distribution infrastructure project that supplies thermal energy to two or more buildings that are not a campus, as defined in section 40-4-121 (1)(a), and that assists in reducing greenhouse gas emissions in the state;

(II) Consists of pipe loops between multiple buildings and energy sources carrying piped, noncombustible fluids at the desired thermal temperature;

(III) Includes a network that can be used for heating, cooling, and other building services; and

(IV) May also be known as a geothermal exchange district, networked geothermal system, geoexchange system, geogrid system, community geothermal heating and cooling district, or geothermal heating district.

(t) "Thermal energy system" includes a geothermal system or other method of exchanging the piped, noncombustible fluids through the ground, wastewater treatment facilities, or other sources of thermal energy that achieve desired fluid temperatures.

(u) "Wastewater thermal energy" means a system that uses thermal energy in wastewater, to heat or cool a space, or for any other useful thermal purpose that reduces greenhouse gas emissions from the combustion of gas in customer end uses.

(3) Clean heat targets. (a) The purpose of a clean heat plan is to achieve clean heat targets by reducing carbon dioxide and methane emissions from gas distribution utilities.

(b) (I) A clean heat plan under this section must demonstrate that the gas distribution utility submitting the clean heat plan will achieve a reduction of carbon dioxide and methane emissions from the distribution and end-use combustion of gas.

(II) A gas distribution utility shall demonstrate compliance with subsection (3)(b)(I) of this section by filing and obtaining commission approval of clean heat plans that meet clean heat targets calculated as follows: Consistent with subsection (3)(c) of this section and as compared to a 2015 baseline, a four percent reduction in greenhouse gas emissions in 2025, of which not more than one percent can be from recovered methane; and a twenty-two percent reduction in greenhouse gas emissions in 2030, of which not more than five percent can be from recovered methane.

(c) (I) In calculating the baseline and projected emissions covered under a clean heat plan, a gas distribution utility must include the following:

(A) Methane leaked from the transportation and delivery of gas from the gas distribution and service pipelines from the city gate to customer end use;

(B) Carbon dioxide emissions resulting from the combustion of gas by residential, commercial, and industrial customers not otherwise subject to federal greenhouse gas emission reporting and excluding all transport customers; and

(C) Emissions of methane resulting from leakage from delivery of gas to other local distribution companies.

(II) All emissions are metric tons of carbon dioxide equivalent as reported to the federal environmental protection agency pursuant to 40 CFR 98, either subpart W (methane) or subpart NN (carbon dioxide), or successor reporting requirements; except that the division shall use the AR-4 one-hundred-year global warming potential or any greater successor value determined by the federal environmental protection agency.

(d) In calculating its clean heat target, a utility must show its baseline carbon dioxide emissions and methane emissions separately and must show that the total emission reductions are projected to achieve the clean heat target. The final calculation demonstrating that the plan meets the clean heat target must be presented on a carbon dioxide equivalent basis.

(e) It is the policy of the state of Colorado to reduce the state's greenhouse gas emissions, and therefore to count toward a gas distribution utility's compliance with the emission reduction goals, recovered methane under a clean heat plan must be represented by a recovered methane credit, issued subject to an approved recovered methane protocol, and delivered:

(I) To or within Colorado through a dedicated pipeline; or

(II) Through a common carrier pipeline if the source of the recovered methane injects the recovered methane into a common carrier pipeline that physically flows within Colorado or toward the end user in Colorado for which the recovered methane was produced.

(f) To count toward a gas distribution utility's compliance with the clean heat targets, the utility must quantify the actual methane reductions achieved by any leak repairs and the commission must find that the leak reductions are cost-effective. The commission may require the utility to evaluate nonpipeline alternatives.

(4) Submission of clean heat plans. (a) No later than August 1, 2023, the largest gas distribution utility in Colorado, as determined by the volume of gas sold in Colorado, shall file with the commission an application for approval of a clean heat plan that demonstrates that the gas distribution utility will achieve the clean heat target established for 2025 in subsection (3)(b)(II) of this section by 2025. All other gas distribution utilities shall file applications for approval of clean heat plans no later than January 1, 2024, that demonstrate, for each such gas distribution utility, that it will achieve the clean heat target established for 2025 in subsection (3)(b)(II) of this section by 2025.

(b) After complying with subsection (4)(a) of this section, each gas distribution utility shall, as directed by the commission but not less often than every four years, file an additional clean heat plan that covers, at minimum, five years after the date of the filing.

(c) A clean heat plan filed pursuant to this subsection (4) must:

(I) Demonstrate that the gas distribution utility will meet the applicable clean heat targets specified in this section for the applicable plan period;

(II) Set forth portfolios that the gas distribution utility will use to demonstrate alternative compliance approaches for reducing carbon dioxide and methane emissions to meet the clean heat target in the applicable plan period, including its preferred option. The utility shall present:

(A) A portfolio of resources that uses clean heat resources to the maximum practicable extent, that complies with the cost cap, that may include leak reductions approved by the commission, and that may or may not meet the clean heat target in the applicable plan period but that demonstrates reductions in methane emissions;

(B) A portfolio that meets the clean heat targets in the applicable plan period using only clean heat resources but that need not meet the cost cap;

(C) Other portfolios at the utility's discretion; and

(D) Other portfolios as directed by the commission.

(III) Quantify annual projected greenhouse gas emission reductions during the applicable plan period resulting from each portfolio;

(IV) Propose program budgets to meet the emission reduction targets;

(V) Prioritize investments that ensure that disproportionately impacted communities or customers who meet requirements for income-qualified programs benefit from the investments made to implement the clean heat plan;

(VI) Project annual greenhouse gas emission reductions that would result if each proposed portfolio were extended through 2050;

(VII) Forecast carbon dioxide and methane emission reductions that are consistent with the recovered methane protocol rules adopted by the air quality control commission pursuant to section 25-7-105 (1)(e)(X.4);

(VIII) Quantify additional air quality, environmental, and health benefits of the plan in addition to the greenhouse gas emission reductions;

(IX) Include a forecast of potential new customers and system growth or expansion of the gas system for the applicable plan period, including projected greenhouse gas emissions related to that growth;

(X) Describe the effects of the actions and investments in the clean heat plan on the safety, reliability, and resilience of the gas distribution utility's gas service;

(XI) Quantify the cost of implementing the preferred portfolio of clean heat resources used to meet the clean heat targets through the clean heat plan, net of the avoided cost of any new delivery infrastructure avoided through implementing the plan;

(XII) Identify potential changes to depreciation schedules or other actions to align the gas distribution utility's cost recovery with statewide policy goals, including reducing carbon dioxide and methane emissions, minimizing costs, and minimizing risks to customers;

(XIII) Explain the gas distribution utility's analysis of the costs and benefits of an array of compliance alternatives, including the social cost of carbon and the social cost of methane in the cost-benefit calculations;

(XIV) Describe the monitoring and verification methodology to be used in annual reporting;

(XIV.5) Demonstrate that, with respect to any thermal energy network that will be used as a clean heat resource, any geothermal fluid associated with the thermal energy system or thermal energy network is used in compliance with the permitting requirements for production of geothermal fluid set forth in article 90.5 of title 37; and

(XV) Include any other information required by the commission.

(d) (I) To demonstrate compliance with the applicable clean heat target in a clean heat plan, a gas distribution utility must utilize clean heat resources to the maximum extent practicable and count greenhouse gas emission reductions resulting from its use of those resources. For compliance with the 2030 target, a utility shall not propose and the commission shall not approve recovered methane resources achieving more than five percent of the target of twenty-two percent.

(II) Notwithstanding any other provision of this section, and unless the commission finds that a clean heat plan is not cost-effective in meeting the following targets, of the emission reductions required in a clean heat plan that a gas distribution utility must achieve, reductions from recovered methane projects may be in the following maximum amounts:

(A) Five percent of the total reduction for the period 2026 through 2030; and

(B) An amount specified by the commission by rule for clean heat plans covering years after 2030 if the commission determines that the requirements further investment in Colorado communities, reduce greenhouse gas emissions, are cost-effective, and are in the public interest.

(e) A clean heat plan may be filed as part of a demand-side management plan or any other plan as determined by the commission.

(f) A gas distribution utility may include proposals to make investments in green or blue hydrogen projects that will reduce greenhouse gas emissions. If a gas distribution utility proposes to make an investment pursuant to this subsection (4)(f), it must also include a proposal for competitive solicitation.

(g) (I) The commission shall consult with the division to estimate reductions of emissions of greenhouse gases and other air pollutants under the portfolios.

(II) The division may participate as a party in any proceeding before the commission in which a gas distribution utility is seeking approval of a clean heat plan the gas distribution utility developed pursuant to this section.

(h) A gas distribution utility's first clean heat plan must use a planning period that extends through 2025. The second clean heat plan must use a planning period that extends through 2030. Subsequent clean heat plans must use a planning period as determined by the commission.

(5) Commission rules. (a) No later than October 1, 2021, the commission shall undertake a rule-making proceeding to update electric and gas demand-side management rules consistent with the clean heat targets established in this section. In the rule-making, the commission shall remove any prohibition on customer incentives to help customers replace gas appliances with highly efficient electric alternatives. As part of this rule-making process, the commission shall convene at least four workshops or public meetings to solicit input on the contents and evaluation of gas distribution utilities' clean heat plans, two of which must be located in disproportionately impacted communities served by the utility that is required to submit a clean heat plan. Participation must be open to the public and shall not be limited to parties represented by an attorney.

(b) The commission shall adopt rules necessary for gas distribution utilities to implement clean heat plans by December 1, 2022.

(6) Approval of clean heat plans - recovery. (a) (I) For each gas distribution utility, the commission shall establish a cost cap that is two and one-half percent of annual gas bills for all full-service customers as a whole.

(II) The commission shall calculate the annual retail cost impact net of the utility's approved gas demand-side management program budgets but shall include any incentive adopted or approved by the commission. If a gas distribution utility includes a beneficial electrification plan as part of a filing with a clean heat plan, the commission shall calculate the retail cost impact cap net of the utility's approved beneficial electrification plan program budget.

(b) The commission shall consider allowing current recovery for clean heat plan costs through a rate adjustment clause or structure that allows for current recovery, and a gas distribution utility may recover the prudently incurred costs associated with actions under an approved clean heat plan or actions to meet any additional emission reduction requirements imposed pursuant to section 25-7-105 (1)(e)(X.7).

(c) (I) In approving a clean heat plan, the commission shall consider a cost test that includes both the social cost of carbon and the social cost of methane.

(II) In evaluating a clean heat plan, the commission shall consider whether the plan will achieve the applicable clean heat targets.

(d) (I) The commission shall approve a clean heat plan if the commission finds it to be in the public interest. The commission may modify the plan if the modifications are necessary to ensure that the plan is in the public interest. In evaluating whether the clean heat plan submitted to the commission is in the public interest, the commission shall take into account the following factors:

(A) Whether the clean heat plan achieves the clean heat targets through maximizing the use of clean heat resources;

(B) The additional air quality, environmental, and health benefits of the plan in addition to the greenhouse gas emission reductions;

(C) Whether investments in a clean heat plan prioritize serving customers participating in income-qualified programs and communities historically impacted by air pollution and other energy-related pollution;

(D) Whether the clean heat plan results in a reasonable cost to customers, including savings to customer bills resulting from investments made pursuant to the plan; and

(E) Whether the clean heat plan ensures system reliability.

(II) In approving a clean heat plan:

(A) If the commission determines that it is possible to achieve larger greenhouse gas emission reductions than the required clean heat targets using clean heat resources at or below the cost cap, the commission shall require the maximum level of emission reductions above the clean heat targets that can be achieved at or below the cost cap using clean heat resources, with the proportion of greenhouse gas emission reductions from recovered methane not exceeding the proportion allowed in meeting the clean heat target for the applicable plan period.

(B) The commission must require the gas distribution utility to achieve the maximum level of greenhouse gas emission reductions practicable using clean heat resources at or below the cost cap, with the proportion of greenhouse gas emission reductions from recovered methane not exceeding the proportion allowed in meeting the clean heat target for the applicable plan period.

(III) The commission may approve, or amend and approve, a clean heat plan with costs greater than the cost cap only if it finds that the plan is in the public interest, costs to customers are reasonable, the plan includes mitigation of rate increases for income-qualified customers, and the benefits of the plan, including the social costs of methane and carbon dioxide, exceed the costs.

(IV) Notwithstanding subsection (6)(a)(I) of this section, the commission shall not require a utility with fewer than two hundred fifty thousand meters to spend more than an amount equal to two percent of the utility's total annual revenues from full-service customers to comply with the 2025 emission reductions requirements of subsection (3)(b)(II) of this section, net of costs associated with a commission-approved demand-side management plan, avoided fuel costs, and avoided capital infrastructure costs. Notwithstanding subsection (6)(d)(III) of this section, a utility subject to this subsection (6)(d)(IV) may voluntarily request to spend a higher amount to comply with the 2025 clean heat targets, and the commission may approve the requested amount if the commission finds that the spending comes at a reasonable cost and rate impact and is in the public interest.

(7) Annual reporting. (a) Each gas distribution utility shall submit to the commission an annual report that shows the amount of money that it has spent under each program in the clean heat plan, the amount spent on income-qualified programs or programs that serve communities historically impacted by air pollution and other energy-related pollution, a calculation of emissions reduced or avoided pursuant to its approved clean heat plan, and any other information required by the commission.

(b) In addition to any other greenhouse gas reporting requirements, each gas distribution utility shall submit an annual report to the commission providing a calculation of emissions reduced or avoided pursuant to its approved clean heat plan. The report must include separate quantifications of the reductions in carbon dioxide and methane emissions. Carbon dioxide emission reductions must be calculated based on emissions reported pursuant to the air quality control commission's rules. If a utility includes recovered methane, the utility shall quantify actual emission reductions achieved on a project basis for each project for which it claims reductions in that year, based on any recovered methane credits generated.

(8) Employment and utility workforce. (a) For any utility-owned project that is part of a clean heat plan, the gas distribution utility shall, where practicable, use its own employees to complete the work.

(b) For a utility project that is part of a competitive solicitation and with a cost of more than one million dollars, the gas distribution utility shall require all bidders to provide detailed information about the use of Colorado-based labor and out-of-state labor. The utility shall provide this information to the commission.

(c) If a clean heat plan includes gas demand-side management programs as defined in section 40-1-102 (6), all requirements specified in this article 3.2 relating to labor standards for gas demand-side management programs or projects apply. If a clean heat plan includes beneficial electrification, all requirements specified in this article 3.2 relating to beneficial electrification labor standards, beneficial electrification plans, recovery of costs, and reporting apply.

(d) In all decisions approving clean heat resources to be acquired as part of a clean heat plan, the commission shall consider the long-term impacts on Colorado's utility workforce as part of a just transition and shall give additional weight to a project that includes:

(I) Training programs, including training through the division of employment and training in the department of labor and employment created in section 8-83-102, or apprenticeship programs registered with the United States department of labor's office of apprenticeship or a state apprenticeship agency recognized by the United States department of labor;

(II) Employment of Colorado-based labor; and

(III) Long-term career opportunities and industry-standard wages, health care, and pension benefits.

(e) If a project in connection with a clean heat plan is an energy sector public works project, as defined in section 24-92-303 (5), the project must comply with the applicable requirements of the "Colorado Energy Sector Public Works Project Craft Labor Requirements Act", part 3 of article 92 of title 24.

(9) Small gas distribution utilities. (a) A small gas distribution utility may file a clean heat plan with the commission pursuant to subsections (3) to (7) of this section or it may submit a small utility emission reduction plan pursuant to this subsection (9).

(b) The small gas distribution utility, as part of its small utility emission reduction plan:

(I) Must propose greenhouse gas emission reduction targets for 2025 and 2030;

(II) Is subject to the cost cap;

(III) Must identify the clean heat resources the small gas distribution utility will use to reduce emissions on its system and quantify the annual emission reductions expected during the plan period;

(IV) Must propose program budgets to meet the emission reduction targets proposed by the small gas distribution utility;

(V) Must forecast carbon dioxide and methane emission reductions reasonably expected to be achieved through the actions taken in the preferred plan;

(VI) Must quantify the cost of implementation of the preferred portfolio of resources used in the plan; and

(VII) Must include an implementation plan of at least three years during which the small gas distribution utility proposes to acquire clean heat resources to reduce emissions.

(c) The commission shall approve a clean heat plan filed under this subsection (9) if the commission finds it to be in the public interest. The commission may modify the clean heat plan if the modifications are necessary to ensure that the plan is in the public interest. In evaluating whether the clean heat plan submitted to the commission is in the public interest, the commission shall take into account the factors set forth in subsection (6)(d)(I) of this section. In approving a clean heat plan under this subsection (9), the commission shall carry out the duties set forth in subsection (6)(d)(II) of this section. The commission may approve a clean heat plan that exceeds the cost cap under this subsection (9) only pursuant to subsection (6)(d)(III) of this section.

(d) Small gas distribution utilities with approved clean heat plans are subject to the reporting provisions of subsection (7) of this section.

(10) No later than December 1, 2025, the commission, in consultation with the division, shall determine mass-based greenhouse gas emission reduction targets for clean heat plans for 2035. In establishing these targets, the commission shall:

(a) Ensure that gas distribution utilities' greenhouse gas emissions will be in line with the residential, commercial, and industrial sectors' contribution to statewide greenhouse gas pollution; and

(b) Determine whether recovered methane may be used to meet the mass-based greenhouse gas emissions reduction targets established pursuant to this subsection (10).

(11) No later than December 1, 2032, the commission, in consultation with the division, shall determine the mass-based greenhouse gas emission reduction goals for clean heat plans for 2040, 2045, and 2050 using a 2015 baseline that, at minimum, ensure that gas distribution utilities' greenhouse gas emission reductions will be proportionate to the residential, commercial, and industrial sectors' contribution to the greenhouse gas emission reduction goals, excluding transportation gas service customers or customers that report their own greenhouse gas emissions to the federal environmental protection agency under applicable federal law, including 40 CFR 98, subpart NN. In determining these goals, the commission shall consider savings achieved or projected to be achieved in other sectors of the state's economy, as well as the commercial availability of technologies to achieve emission reductions in this sector.
C.R.S. § 40-20-304 — CO Code / Title 40 / Article 20 / Part 3 / Section 40-20-304
40-20-304. Emergency operations
Status: in_force

40-20-304. Emergency operations. (1) State emergency response authorities may recommend actions necessary to protect railroads, rail workers, and public safety in the event of an emergency such as wildfire, flood, earth movement, or civil disorder, including stopping or rerouting rail traffic if deemed necessary.

(2) A railroad shall respond to a state emergency response authority promptly and work closely with state and local officials during emergencies to coordinate response efforts and ensure the safety of rail personnel and the public.
C.R.S. § 40-10.1-304 — CO Code / Title 40 / Article 10.1 / Part 3 / Section 40-10.1-304
40-10.1-304. Revocation of permit for failure to pay fine
Status: in_force

40-10.1-304. Revocation of permit for failure to pay fine. (1) If a carrier that holds a permit under this part 3 fails to pay a fine or civil penalty imposed under this article 10.1 or a rule issued under this article 10.1 within the time prescribed for payment, and not before the decision imposing the fine or civil penalty becomes a final decision by the commission, the carrier's permit is revoked immediately. Any of the following are disqualified from applying for a permit for thirty-six months after the date the fine or civil penalty is due:

(a) The carrier;

(b) Any owner, principal, officer, member, partner, or director of the carrier; and

(c) Any other entity owned or operated by that owner, principal, officer, member, partner, or director.

(2) This disqualification is in addition to and not in lieu of any other penalty or disqualification, including the period of disqualification specified in section 40-10.1-112 (4).
C.R.S. § 40-8.5-102 — CO Code / Title 40 / Article 8.5 / Section 40-8.5-102
40-8.5-102. Applicability
Status: in_force

40-8.5-102. Applicability. This article shall apply to any electric or gas utility, as defined by section 40-8.5-103; except that this article shall apply only to those cooperative electric associations, as defined by section 40-9.5-102, which notify the commission that they elect to come under this article.
C.R.S. § 40-15-108 — CO Code / Title 40 / Article 15 / Part 1 / Section 40-15-108
40-15-108. Cost methodologies
Status: in_force

40-15-108. Cost methodologies. (1) Any local exchange provider which provides facilities or equipment for use by interstate users or providers of telecommunications services shall separate all investments and expenses associated therewith according to applicable federal separations procedures and agreements.

(2) Any provider of telecommunications service which offers both regulated and deregulated telecommunications service shall segregate its intrastate investments and expenses in accordance with allocation methodologies as prescribed by the commission to ensure that deregulated telecommunications services are not subsidized by regulated telecommunications services.
C.R.S. § 40-3-110 — CO Code / Title 40 / Article 3 / Section 40-3-110
40-3-110. Information furnished commission - reports
Status: in_force

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.
C.R.S. § 40-2-132.5 — CO Code / Title 40 / Article 2 / Part 1 / Section 40-2-132.5
40-2-132.5. Distribution system planning - grant program - cash fund - requirements - study
Status: repealed

40-2-132.5. Distribution system planning - grant program - cash fund - requirements - study - staffing - labor - cost recovery - virtual power plant program - undergrounding of power lines - report - rules - legislative declaration - definitions - repeal. (1) Legislative declaration. (a) The general assembly finds that:

(I) Distribution system planning requirements for investor-owned utilities were established by Senate Bill 19-236, enacted in 2019;

(II) The commission's distribution system planning rules and plans established pursuant to Senate Bill 19-236, enacted in 2019, have provided a forum for planning the distribution system in order to support state policy goals based on current information about utility systems and proactive planning, although considerable work remains and customers are increasingly challenged by distribution system constraints;

(III) Colorado has goals of cost-effectively and reliably reducing greenhouse gas emissions from transportation, electricity generation, building heating and cooling, water heating, and industrial fuel uses. To affordably and reliably reduce emissions from these uses as well as to meet federal, state, regional, and local air quality and decarbonization targets, standards, plans, and regulations, the state will need to rapidly shift customer end uses from fossil fuels to a cleaner electrical grid, which will drive a large increase in electricity demand.

(IV) Consumer demand for distributed energy resources, electric vehicles, and beneficial electrification measures is expected to increase dramatically given state incentives and new rebates and incentives in the federal "Inflation Reduction Act of 2022", Pub.L. 117-169;

(V) Customer demand for electric power may start exceeding qualifying retail utility capacity on the distribution system in certain locations;

(VI) To affordably and reliably meet federal, state, regional, and local air quality and decarbonization targets, standards, plans, and regulations, the state's electricity distribution systems must be substantially and strategically upgraded, new customers must be able to connect to the electrical distribution system, and existing customers must have their service levels promptly upgraded;

(VII) The state has an urgent need to increase its supply of affordable and infill housing, requiring both new electrical distribution capacity and the prompt connection of new affordable housing to the distribution system;

(VIII) Improved and proactive distribution system planning to reduce delays and meet building, affordable housing, and transportation electrification needs in an affordable and reliable manner is critical to protect Coloradans from the worst impacts of climate change, including extreme heat or cold, drought, and wildfires;

(IX) Electrifying transportation and buildings may put downward pressure on rates by spreading fixed costs over more kilowatt-hours of usage so long as demand and supply can be dynamically integrated in ways that encourage utility investment in an affordable and reliable system that optimizes the use of grid assets;

(X) Constraints in the capacity of the electrical distribution system can limit the ability of an individual customer to cost-effectively and reliably interconnect distributed energy resources and energize beneficial electrification and transportation electrification resources; and

(XI) Virtual power plants can offer the potential to cost-effectively and reliably increase the grid value of distributed energy resources, limit costs for incorporating distributed energy resources, and increase the operational efficiency of the distribution system.

(b) The general assembly further finds that:

(I) A modern electric distribution system should take into account the need for improved resilience and safety due to the increased occurrence of extreme weather events and climate-related wildfire risk;

(II) Undergrounding power lines can significantly help in avoiding the risk of wildfires and power outages due to strong winds, severe storms, and dry conditions; and

(III) It is in the public interest that all ratepayers of a qualifying retail utility, including those who do not live in a jurisdiction with a franchise agreement, have nondiscriminatory and equal access to the opportunity to benefit from investments in undergrounding power lines.

(c) The general assembly therefore determines and declares that:

(I) It is a matter of state urgency to ensure that there is sufficient capacity on the distribution system to affordably and reliably meet Colorado's decarbonization goals and support consumer demand for retail distributed generation and beneficial electrification measures consistent with their benefit to the electrical grid;

(II) When determining where to make undergrounding conversion expenditures, a qualifying retail utility should not, as a policy or course of business, discriminate against jurisdictions that do not have franchise agreements with the qualifying retail utility; and

(III) A qualifying retail utility should establish programs for nonfranchised areas to have the same benefit under the same or similar terms as offered to areas that have franchise agreements with the qualifying retail utility.

(2) Definitions. As used in this section, unless the context otherwise requires:

(a) "Affordable housing" means affordable housing that:

(I) Has received loans, grants, equity, bonds, or tax credits from any source to support the creation, preservation, or rehabilitation of affordable housing that, as a condition of funding, encumbers the property with a restricted use covenant or similar recorded agreement to ensure affordability; or has been income-restricted under a local inclusionary zoning ordinance or other regulation or program;

(II) Restricts or limits maximum rental or sale price for households of a given size at a given area median income, as established annually by the United States department of housing and urban development; and

(III) Ensures occupancy by low- to moderate-income households for a specified period detailed in a restrictive use covenant or similar recorded agreement.

(b) "Apprentice" has the meaning set forth in section 8-15.7-101 (1).

(c) "Automated distributed resource management system" means a category of technologies that manage distributed generation or load and that may be used to reduce or eliminate the need for system upgrades to the distribution system, customer service connection, or electrical infrastructure on the customer side of the service meter. These technologies include:

(I) Automated load management technologies;

(II) Certified power control systems; and

(III) Smart inverters.

(d) "Certified power control system" means software or hardware serving as the interface of an automated distributed resource management system that can curtail the import and export of electricity, that has electricity import and export control set points, and that has been certified by a nationally recognized testing laboratory.

(e) "Department" means the department of labor and employment.

(f) "DER aggregator" means a company or an organization that controls, monitors, and manages aggregated distributed energy resources to ensure performance of the aggregated distributed energy resources in a qualifying virtual power plant.

(g) "Distributed energy resources" or "DER" includes distributed generation, energy storage systems, electric vehicles, microgrids, fuel cells, and demand-side management measures, including energy efficiency, demand response, and demand flexibility that are deployed at the distribution grid level on either the customer or utility side of the meter.

(h) "Distribution activities" means:

(I) Capital investment and operations and maintenance expenses associated with equipment upgrades, repair and replacement programs, conductor replacements, conductor installations, pole repair and replacement, overhead rebuilds, inspection, modeling, asset data gathering, defect corrections, and major line rebuilds; and

(II) Similar activities and investments, including information and operational technology investments, with the objective of enhancing the distribution system to meet state decarbonization goals and federal, state, regional, and local air quality and decarbonization targets, standards, plans, and regulations.

(i) (I) "Energization" or "energize" means connecting new customer load to the electrical grid or upgrading electrical capacity to provide upgraded service to an existing customer, including establishing adequate electrical capacity to provide for the required service.

(II) "Energization" or "energize" does not include activities related to interconnecting distributed generation.

(j) "Energization time period" means the elapsed time period beginning when the qualifying retail utility receives a substantially complete energization project application and ending when the electrical service is installed and energized.

(k) "Flexible interconnection or energization tariff" means a set of rules and requirements for expeditiously energizing new load or interconnecting a distributed energy resource to a qualifying retail utility's distribution system and includes an agreement for curtailing the import or export of electricity from and to the distribution system.

(l) "Fund" means the Colorado lineworker apprenticeship grant program cash fund created in subsection (3)(h)(I) of this section.

(m) "Grant program" means the grant program created pursuant to subsection (3)(a) of this section.

(n) "Hosting capacity" means the amount of distributed energy resources or transportation or beneficial electrification that can be interconnected or energized to the qualifying retail utility's distribution system at a given time and at a given location under existing electrical grid conditions and that can operate without adversely impacting safety, power quality, reliability, or other operational criteria and without requiring system upgrades. Hosting capacity may be expressed in terms of a load or generation profile.

(o) "Hybrid facility" means a facility that has more than one device of different technology types for the production, storage, or consumption of electricity that are located on the same site and have a single point of interconnection to the utility distribution system.

(p) "Infill housing" means the development of housing within existing development patterns, as delineated by census urban areas established by the most recent federal decennial census.

(q) "Non-wires alternatives" means the strategic deployment of distributed energy resources by a qualifying retail utility or a third party and associated control or aggregation of systems and technologies intended to cost-effectively defer or avoid the need for major distribution grid projects.

(r) "Office" means the Colorado energy office created in section 24-38.5-101 (1).

(s) "Office of future of work" means the office of future of work created in section 8-15.8-103.

(t) "Performance-based compensation" means a financial payment that is made to a qualified DER aggregator or passed through a DER aggregator to eligible customers participating in a VPP operated by that DER aggregator and that is provided based on the performance of a qualified virtual power plant during a qualified virtual power plant event.

(u) "Phased interconnection or energization agreement" means an agreement between a qualifying retail utility and a customer to provide certain levels of electrical service capacity on a guaranteed timeline in exchange for the customer participating in the qualifying retail utility's flexible interconnection or energization tariff while necessary grid upgrades are being completed.

(v) "Prosumer" means a customer of a qualifying retail utility that participates in a commission-approved virtual power plant program.

(w) "Qualified aggregator" means a DER aggregator that has control over prosumer resources and has the demonstrated technical capability to dispatch distributed energy resources at required capacity levels when called upon by a qualifying retail utility using available technology, such as metering, telemetry, control software measurement and verification, and financial settlements.

(x) "Qualifying distribution activity recovery" means distribution activities for which the commission approves recovery through the grid modernization adjustment clause.

(y) "Qualifying retail utility" means an investor-owned electric utility serving five hundred thousand customers or more.

(z) "State apprenticeship agency" has the meaning set forth in section 8-15.7-101 (16).

(aa) "System upgrades" means the additions, modifications, and system upgrades to a qualifying retail utility's distribution or commission-jurisdictional transmission system, including customer-driven upgrades necessary to interconnect distributed energy resources, energize or service-connect transportation and beneficial electrification measures, or facilitate service connections to affordable housing or infill housing.

(bb) "Virtual power plant" or "VPP" means a commission-approved program that achieves the collective management of dispatchable demand or distributed energy resources connected to the utility distribution grid.

(3) Grant program - report - cash fund - repeal. (a) The office of future of work, in coordination with the office, shall create a grant program for lineworker apprenticeship programs to expand apprenticeship programs registered with the United States department of labor's office of apprenticeship or the state apprenticeship agency.

(b) The office of future of work shall create a competitive application process through which the office of future of work selects eligible registered apprenticeship programs as grant recipients.

(c) A grant recipient must satisfy, at a minimum, the following criteria:

(I) The grant recipient must train apprentices as transmission or distribution lineworkers on construction projects and related installations; and

(II) The grant recipient must match the grant award with actual or in-kind resources.

(d) The office of future of work shall offer grants for the following purposes:

(I) Funding for training materials or software, apprenticeship tools and supplies, and hands-on training equipment or technology upgrades to expand registered apprenticeship programs that instruct transmission or distribution lineworkers; and

(II) Additional staffing to expand instruction capacity of registered apprenticeship programs to instruct transmission or distribution lineworkers.

(e) The office of future of work shall reserve at least fifty percent of the grant funding for grants that are directed toward programs that are organized as a multiemployer registered apprenticeship program organized through a joint apprenticeship training committee.

(f) The office of future of work shall encourage the primary applicant for a grant to include a diverse set of co-applicants, which may include trade associations, employers, labor union organizations, public utilities, accredited institutions of higher education, state-accredited community colleges, or other co-applicants that can advance the goals of allowing apprentices to reach full journeyworker status as a utility transmission or distribution lineworker.

(g) The office of future of work shall:

(I) Publish the grant application no later than January 1, 2025;

(II) Develop performance expectations for grant recipients, which may contemplate the termination of a grant recipient's participation in the grant program if the grant recipient fails to satisfy the performance expectations;

(III) Require grant recipients to annually report data to the office of future of work, which must include, at a minimum, a detailed statement of the grant recipient's allocation of grant money received pursuant to the grant program, including administration costs; and

(IV) Beginning in 2026, and in each year thereafter, submit a report compiling the data received pursuant to subsection (3)(g)(III) of this section to the business, labor, and technology committee of the senate and the business affairs and labor committee of the house of representatives, or any successor committees.

(h) (I) The Colorado lineworker apprenticeship grant program cash fund is created in the state treasury. The fund consists of gifts, grants, and donations and any money that the general assembly may appropriate or transfer to the fund. The state treasurer shall credit all interest and income derived from the deposit and investment of money in the fund to the fund. Money in the fund is continuously appropriated to the department for allocation to the office of future of work for the purposes of administering the grant program pursuant to this subsection (3). The office of future of work may seek, accept, and expend gifts, grants, or donations from private or public sources for the purposes of administering the grant program pursuant to this subsection (3).

(II) (A) On July 1, 2024, the state treasurer shall transfer eight hundred thousand dollars from the general fund to the fund.

(B) This subsection (3)(h)(II) is repealed, effective July 1, 2026.

(i) This subsection (3) is repealed, effective July 1, 2028.

(4) Near-term actions - interconnection and energization backlogs - identification of hosting capacity - cost recovery. (a) Qualifying retail utilities shall upgrade the state's electrical distribution systems as needed and in time to affordably and reliably support the achievement of the state's beneficial and transportation electrification and decarbonization goals and support implementation of federal, state, regional, and local air quality and decarbonization targets, standards, plans, and regulations.

(b) To promptly, affordably, and reliably interconnect and energize new customers and comply with the obligation to serve without substantial delay, a qualifying retail utility shall:

(I) Commence a data collection process to inform future energization timelines. The commission may open or use an existing miscellaneous proceeding to accept information collected by the qualifying retail utility and from other stakeholders.

(II) Meet the interconnection deadlines specified in section 40-2-135 and commission rules;

(III) Adopt the following cost caps, which cost caps must remain in effect until the commission completes the rule-making described in subsection (6) of this section:

(A) For distributed generation systems that are twenty-five kilowatts or less, adopt a cap of no more than three hundred dollars for an individual customer's responsibility for interconnection costs for a customer-caused upgrade of the qualifying retail utility's distribution system, so long as the costs above the cap remain recoverable by the qualifying retail utility;

(B) For residential customers energizing transportation electrification or beneficial electrification, not require the customer to pay for the costs of associated distribution system upgrades, so long as the costs remain recoverable by the qualifying retail utility; and

(C) For affordable housing developments, cap the costs for interconnection or energization for a project-caused upgrade of the qualifying retail utility's distribution system at a level of three hundred dollars per residential unit of affordable housing, so long as costs above the cap remain recoverable by the qualifying retail utility;

(IV) Propose, and the commission shall authorize, modify, or deny in a manner consistent with the public interest, the use of an optional flexible interconnection or energization tariff or phased interconnection or energization agreement by a customer as an alternative to a system upgrade that would otherwise be required by the qualifying retail utility in response to the customer's request to interconnect or energize a distributed energy resource; and

(V) Establish a procedure for customers with a hybrid facility to complete the interconnection and energization processes through a single application.

(c) A qualifying retail utility shall identify interconnection and load hosting capacity for DERs, including beneficial electrification and transportation electrification, for disproportionately impacted communities within its service territory.

(d) (I) Prior to the establishment of the grid modernization adjustment clause, a qualifying retail utility shall recover the forecasted investments placed in service and expenses incurred for distribution activities during the period beginning on May 22, 2024, and ending on December 31, 2025, consistent with this section.

(II) Cost recovery must occur through the transmission cost adjustment clause or another existing adjustment clause, subject to:

(A) A one-half percent retail rate impact cap on an annualized basis for 2024; and

(B) A one and one-fourth percent retail rate impact cap on an annualized basis for 2025.

(III) Within thirty days after May 22, 2024, a qualifying retail utility shall file an advice letter with the commission identifying the distribution activities for recovery, including the revenue requirement for the distribution activities and a return at the qualifying retail utility's most recently approved weighted average cost of capital, for the period beginning on May 22, 2024, and ending on December 31, 2024, to be included in the transmission cost adjustment clause or an existing adjustment clause with an effective date within sixty days after May 22, 2024.

(IV) On or before November 1, 2024, a qualifying retail utility shall file an advice letter with the commission identifying the distribution activities for recovery, including the revenue requirement for the distribution activities and a return at the qualifying retail utility's most recently approved weighted average cost of capital, for the period beginning January 1, 2025, and ending December 31, 2025, to be included in the transmission cost adjustment clause or an existing adjustment clause with an effective date of January 1, 2025.

(V) The amounts recovered pursuant to this subsection (4)(d) are subject to a true-up with any positive or negative balance credited to customers or recovered by the qualifying retail utility in the subsequent year and with the financing cost for the transmission cost adjustment clause or the applicable existing adjustment clause applied to the positive or negative balances. All amounts recovered are subject to a prudence review by the commission through either a standalone prudence review proceeding or in a base rate proceeding.

(VI) In addition to the amounts recovered pursuant to this subsection (4)(d), a qualifying retail utility may spend and recover through the transmission cost adjustment clause or another existing adjustment clause the revenue requirement associated with up to an additional one hundred fifty million dollars in investment to order equipment to advance distribution activities, such as power transformers, service transformers, capacitor banks, switch cabinets, and feeder cables, as long as the investments are prudently incurred for the purposes of achieving economies of scale, addressing supply chain concerns, or other similar purposes.

(5) Long-term actions - distribution system plan requirements - approval by commission - staffing requirements - labor requirements - report. (a) A qualifying retail utility shall file distribution system plans pursuant to section 40-2-132, subject to review, approval, modification, or denial by the commission, to create sufficient hosting capacity across its electrical distribution system to affordably and reliably support the implementation of the following:

(I) Federal, state, regional, and local air quality and decarbonization targets, standards, plans, and regulations;

(II) The transportation, affordable housing, new infill housing, and building electrification policies of state and local law, including:

(A) The rules adopted by the air quality control commission related to greenhouse gas emission reductions from light-duty and heavy-duty motor vehicles; and

(B) The rules adopted by the air quality control commission pursuant to section 25-7-142 or local building performance standards;

(III) State agency, local agency, and local government plans and requirements related to housing, economic development, critical facilities, transportation, and building electrification;

(IV) Enforceable and funded federal, state, regional, and local policies, plans, goals, incentives, or requirements designed to increase access to distributed energy resources, electrified transportation, and building electrification in disproportionately impacted communities; and

(V) The qualifying retail utility's approved renewable energy standard plan, clean heat plan, beneficial electrification plan, demand-side management plan, gas infrastructure plan, and transportation electrification plan required by this title 40.

(b) In developing distribution system plans pursuant to section 40-2-132, consistent with state-level recognized best practices for community outreach, a qualifying retail utility shall consult with and provide opportunities for meaningful engagement and education through multilingual and culturally relevant outreach to disproportionately impacted communities.

(c) (I) As part of a distribution system plan proceeding, a qualifying retail utility shall present at least two future planning scenarios with corresponding investments to show different future states of the distribution system.

(II) In determining the distribution capacity necessary to meet projected load growth and distributed energy resource expansion, including to affordably and reliably support implementation of applicable targets, standards, plans, and regulations described in subsection (5)(a) of this section, a qualifying retail utility shall incorporate a scenario that incorporates load and managed generation flexibility that may increase system capacity utilization, reduce the need for system upgrades, and lower system costs.

(III) In determining to which portions of the distribution system to propose system upgrades to affordably and reliably support the implementation of the applicable targets, standards, plans, and regulations described in subsection (5)(a) of this section, a qualifying retail utility shall prioritize capacity investments in areas of its distribution system that are at or near their hosting capacity limits or that are projected to have energization loads that cannot be met without a system upgrade. A qualifying retail utility shall prioritize system upgrades targeted at improving infrastructure for income-qualified or disproportionately impacted communities with residential capacity constraints.

(IV) Specific to reliability investments, a qualifying retail utility shall prioritize investments for disproportionately impacted communities based on reliability information provided in the qualifying retail utility's quality of service plan.

(d) In evaluating a qualifying retail utility's distribution system plans, the commission shall evaluate whether the distribution system plan:

(I) Establishes a long-term distribution system plan, which must cover at least five years, that includes timelines and budgets to create sufficient hosting capacity across the qualifying retail utility's electrical distribution system to affordably and reliably support the implementation of the applicable targets, standards, plans, and regulations described in subsection (5)(a) of this section;

(II) Includes the identification of specific distribution investments needed to strategically support the applicable targets, standards, plans, and regulations described in subsection (5)(a) of this section over the planning period, which must cover at least five years, with increased specificity in the first two years of the planning period;

(III) Includes detailed mapping of distribution hosting capacity with appropriate safeguards to protect critical infrastructure, as determined by the commission;

(IV) Includes a process to identify and evaluate infill housing loads;

(V) Includes proposed, unless already informed or satisfied by commission rules, standardized, quantifiable, and transparent processes and timelines within the planning period for formal load and generation interconnection and energization requests, so long as the qualifying retail utility is not required to include energization timelines as part of its first distribution system plan filed after May 22, 2024;

(VI) Includes proposed actions to facilitate programs for:

(A) The competitive acquisition of cost-effective non-wires alternatives to defer or avoid identified system distribution infrastructure projects, subject to investment thresholds in commission rules;

(B) Load and generation flexibility, including interruptible programs, with due consideration given to programs proposed or approved in other commission proceedings; and

(C) Other alternatives to system upgrades, which may include automated distributed resource management systems;

(VII) Includes adequate reporting and system mapping to implement the proposed plan and programs, as well as:

(A) To the extent available at the time of the distribution system plan filing, the average, median, and standard deviation time between receiving a formal application for interconnection or energization and energizing the electrical service; constraints and obstacles to each type of interconnection or energization, such as funding limitations, qualified staffing availability, or equipment availability; and any other information required by the commission; and

(B) If the interconnection and energization time periods exceed any established, commission-approved average target energization time periods, as determined in a qualifying retail utility's distribution system plan proceeding, or if the qualifying retail utility has a substantial number of interconnection or energization applications that exceed any established commission-approved maximum target energization time periods, a strategy for meeting the target energization time periods in the future; and

(VIII) Includes documentation demonstrating progress toward implementation of previously approved distribution system plans.

(e) The distribution system plan must include a performance-based framework, which must consist of:

(I) Applicable interconnection timelines;

(II) Applicable energization timelines, so long as:

(A) The energization timelines are not applicable to the first distribution system plan filed after May 22, 2024;

(B) In the second distribution system plan filed after May 22, 2024, measurement of any energization timelines must commence upon submission by the customer of a formal load request, and any performance-based framework must only include the steps in the energization process that are the sole responsibility of the qualifying retail utility;

(C) Any energization timelines in a performance-based framework must account for extenuating circumstances, as demonstrated by the qualifying retail utility, that do not result in any finding of noncompliance by the commission for the qualifying retail utility;

(D) Any energization timelines and performance requirements do not include conceptual capacity checks or other informational evaluations that may precede a formal load request; and

(E) The qualifying retail utility must be required to track and collect data on steps and outcomes that may precede the formal energization process, and the commission may consider this data in updating any performance-based energization timeline requirements in the third distribution system plan filed after May 22, 2024; and

(III) Reasonable and cost-effective targets measured in megawatts for flexible load and demand management, so long as:

(A) A general target-setting framework must be evaluated in the first distribution system plan filed after May 22, 2024, and further developed through other planning processes, including subsequent distribution system plans, electric resource plans, and demand-side management plans; and

(B) The targets are applicable in the second distribution system plan filed after May 22, 2024, and subsequent distribution system plans.

(f) (I) A qualifying retail utility shall include in its distribution system plan a detailed analysis of its current qualified staffing level and future required qualified staffing level for each job classification needed to achieve the policies and requirements of this section. The analysis of workforce needs must include review of both the anticipated needs of future utility employees as well as the anticipated needs for workforce acquired through third-party utility and construction contractors. Adequate staffing includes engineering and programming staff necessary to oversee the timely interconnection of distributed energy resources, energization of electrified end uses, and energization of new service connections to the qualifying retail utility's distribution system.

(II) The commission shall review whether each qualifying retail utility has adequate qualified staffing needed to achieve the policies and requirements of this section. The analysis of adequate staffing must be considered in a qualifying retail utility's distribution system plan proceeding.

(g) A qualifying retail utility shall ensure that, in any construction, expansion, or maintenance of distribution projects undertaken as a part of the distribution system plan, all labor is performed either by the employees of the qualifying retail utility or by qualified contractors, or both, and that, except as otherwise provided in subsection (5)(i) of this section, a qualifying retail utility shall not use a contractor unless:

(I) The contractor is chosen from a list of qualified contractors prepared and updated at least annually by the department; and

(II) The contractor's employees have access to an apprenticeship program registered with the United States department of labor's office of apprenticeship or the state apprenticeship agency; except that this apprenticeship program requirement does not apply to:

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

(B) Management functions to operate the facilities; or

(C) Any work performed in response to a warranty claim.

(h) To qualify pursuant to subsection (5)(g)(I) of this section, an apprenticeship program must certify to the qualifying retail utility that:

(I) Its curriculum includes requirements for the completion of:

(A) At least seven thousand hours of on-the-job training to achieve journeyman lineman status, with at least six hundred fifty of those hours spent working on energized power lines at voltages of at least six hundred volts; and

(B) A class in electric transmission and distribution offered by the federal occupational safety and health administration known as the "OSHA ET&D ten-hour training" and comprising content substantially equivalent to that of the "OSHA 10" class offered during calendar year 2021; and

(II) Supervision of apprentices meets the following standards:

(A) Apprentices must work under the supervision of a journeyman-level worker at all times; and

(B) The ratio of apprentices to journeymen linemen does not exceed two to one when working on distribution projects for both energized and nonenergized work.

(i) The request for proposal for any contract work on facilities subject to this section must be submitted to the list of qualified contractors described in subsection (5)(g)(I) of this section for at least sixty days. If none of the contractors on the list submits a qualifying bid within sixty days, then the entity procuring the work may solicit bids from contractors that are not on the list but otherwise qualify under the terms of the request for proposal so long as those terms include compliance with all applicable laws and regulations related to safety.

(j) Notwithstanding section 24-1-136 (11)(a)(I), two years after the approval of any distribution system plan, and every two years thereafter, a qualifying retail utility shall prepare a report and submit the report to the general assembly and the commission outlining progress toward the objectives set forth in this section, including progress toward meeting the hosting capacity needs in disproportionately impacted communities identified pursuant to subsection (4)(c) of this section. The progress reports must be posted on the qualifying retail utility's website and the commission's website.

(6) Longer-term requirements - rules. (a) Following the adjudication and final commission decision on a qualifying retail utility's first distribution system plan filing after May 22, 2024, the commission shall open a rule-making, for a qualifying retail utility, to consider and establish:

(I) Target average and maximum energization timelines;

(II) Any necessary updates to existing interconnection rules;

(III) Rules for interconnection, energization, and electrification of end uses in new construction homes, particularly regarding time frames for responding to cost projection requests, the reliability of utility cost estimates, and reasonable construction schedules; and

(IV) Maximum individual customer cost caps or fees for interconnection or energization of resources of all sizes to help defray or eliminate the costs of interconnecting new distributed generation or energizing transportation or beneficial electrification load to the electrical grid. The rules, where appropriate, should specifically exempt income-qualified customers from payment of system upgrade fees.

(b) The rule-making described in subsection (6)(a) of this section may set different fees based on the inclusion of technologies or agreements to reduce system costs, including flexible interconnection or energization tariffs and automated distributed resource management systems.

(c) The commission's consideration of the rule-making proceeding described in subsections (6)(a) and (6)(b) of this section must conclude in a time that is sufficient to allow the qualifying retail utility to file its second distribution system plan after May 22, 2024.

(7) Cost recovery - grid modernization adjustment clause. (a) A qualifying retail utility shall recover, on an annual basis, projected distribution activities through a grid modernization adjustment clause established as part of the qualifying retail utility's first distribution system plan application after May 22, 2024, so long as the grid modernization adjustment clause continues in effect through subsequent distribution system plans.

(b) (I) Within the distribution system plan, a qualifying retail utility shall propose, and the commission shall evaluate, whether the projected distribution activities and corresponding budgets strategically benefit or advance the applicable targets, standards, plans, and regulations described in subsection (5)(a) of this section or state energy policy goals, including greenhouse gas emission reductions, beneficial electrification, increased reliability, and increased resiliency, and the commission shall allow grid modernization adjustment clause recovery for such approved distribution activities.

(II) If the commission finds that the projected distribution activities and corresponding budgets affordably and strategically benefit or advance the goals described in subsection (7)(b)(I) of this section, the distribution activities are qualifying distribution activity recovery and recovery must occur through the grid modernization adjustment clause in a manner consistent with this section.

(III) For projected distribution activities and corresponding budgets that the commission finds do not benefit or advance the goals described in subsection (7)(b)(I) of this section, recovery may occur through the grid modernization adjustment clause if the qualifying retail utility meets the criteria established in the performance-based framework approved by the commission pursuant to subsection (5)(e) of this section through the distribution system planning process.

(c) (I) The grid modernization adjustment clause is subject to annual adjustments, which are effective on January 1 of each year.

(II) A qualifying retail utility shall make a grid modernization adjustment clause advice letter filing with the commission annually, and no later than November 1 of each year, with an effective date of January 1 of the subsequent year, which must include the qualifying distribution activity recovery and other distribution activities approved pursuant to subsection (7)(b) of this section for the next twelve months, including a return at the qualifying retail utility's most recently approved weighted average cost of capital.

(III) The grid modernization adjustment clause must be reduced to the extent that any prudently incurred costs being recovered through the grid modernization adjustment clause have already been included in the qualifying retail utility's base rates as a result of the commission's final order in a rate case, and recovered qualifying distribution activity recovery is subject to a true-up with any positive or negative balance credited to customers or recovered by the qualifying retail utility in the subsequent year and an appropriate financing cost applied to the positive or negative balances.

(d) Recovery through the grid modernization adjustment clause must not apply to wholesale customers with rates under federal jurisdiction or customers that do not take distribution service from the qualifying retail utility.

(8) Virtual power plant program. (a) No later than February 1, 2025, a qualifying retail utility shall create and file with the commission an application to implement a virtual power plant program, including a tariff for performance-based compensation for a qualified virtual power plant.

(b) A virtual power plant program implemented pursuant to subsection (8)(a) of this section:

(I) Must define the goals of the virtual power plant program and consider the role that virtual power plants can play in modeling and meeting system needs in the resource planning process and eligibility requirements for DER aggregators and technologies;

(II) Must establish a requirement for a DER aggregator to participate in a virtual power plant as a qualified aggregator, including communication, dispatch, measurement and verification, and settlement of performance-based compensation;

(III) May set a cap for individual resource capacity and minimum aggregation capacity for participation in the virtual power plant program;

(IV) Must have provisions for the enrollment of prosumers by DER aggregators;

(V) Must have requirements for a DER aggregator to participate in a virtual power plant tariff, including requirements for the measurements of distributed energy resources associated with the virtual power plant;

(VI) Must have requirements for a standard tariff or tariffs to set performance requirements and performance-based compensation for the DER aggregator, which requirements must include:

(A) A requirement that otherwise eligible customers must participate in the tariff or tariffs through a DER aggregator, regardless of the customer's electricity service rate; and

(B) A requirement to explore the costs and benefits of setting the tariff requirements and compensation for a period of five years, after which DER aggregators may be required to transition to different tariff requirements and compensation;

(VII) Must have streamlined and reasonable data requirements for the participation of qualified aggregators, prosumers, or otherwise eligible customers in the virtual power plant program;

(VIII) Must provide that prosumers or otherwise eligible customers must not be disqualified from participation in a commission-approved virtual power plant program or performance-based compensation due to receipt of other incentives, including up-front incentives or performance payments for energy, capacity, or other grid services that are distinct from the virtual power plant;

(IX) Must provide that prosumers or otherwise eligible customers are not compensated for the provision of the same service more than once;

(X) Must require that DER aggregators adhere to all relevant interconnection rules, tariffs, and applicable qualifying retail utility procedures to ensure the safe operation of virtual power plants within the distribution system;

(XI) Must prescribe the method for setting performance-based compensation. The virtual power plant program may make use of tariff riders to reflect standard and additional values provided by certain resources, locations, times, or grid conditions. To the extent applicable, the performance-based compensation methodology must reflect the full value of services, which may include:

(A) Local and system peak demand reduction;

(B) Clean peak service;

(C) Voltage support and other ancillary services;

(D) The avoidance or deferral of electric or gas transmission or distribution upgrades or capacity expansion;

(E) Locational value as revealed by a grid needs assessment or participation in non-wires alternatives identified in the qualifying retail utility's distribution system plan;

(F) The use of telemetry for settlement; and

(G) Other functions that the commission determines are supportive of efficient planning and operation of the electrical grid; and

(XII) Must allow a qualifying retail utility to serve as a DER aggregator so long as the tariff or access to necessary data does not provide the utility a competitive advantage over third-party aggregators.

(c) As part of the tariff application, the commission shall consider whether it is appropriate to set different performance-based compensation and requirements for different technologies or services.

(d) Any tariff filed by a qualifying retail utility pursuant to subsection (8)(a) of this section must include, at a minimum, the following terms for the commission to approve, modify, or deny the tariff:

(I) Minimum and maximum numbers of grid events for which the qualifying retail utility may dispatch the virtual power plant;

(II) Months of the year that grid events can occur;

(III) Days of the week that grid events can occur;

(IV) Times of day that grid events can occur;

(V) The maximum duration of grid events; and

(VI) Minimum advance notification requirements of grid events.

(e) Nothing in this section affects a qualifying retail utility's net metering program required by section 40-2-124 for energy that is exported outside of a commission-approved virtual power plant program.

(f) A qualifying retail utility shall recover costs to facilitate a virtual power plant program, including foundational technology costs or investments, operations and maintenance expenses, operating technology costs or investments, and information technology costs or investments, through the grid modernization adjustment clause.

(g) (I) In order to participate in a virtual power plant program under this section, an individual energy storage project put out to bid by the project owner after June 30, 2024, with a usable energy capacity of one megawatt or higher is subject to the requirements of sections 24-92-304, 24-92-305, 24-92-306, and 24-92-307.

(II) The DER aggregator administering the VPP shall file an affidavit under penalty of perjury with the commission stating that all energy storage systems with a usable energy capacity of one megawatt or higher participating in the VPP are in compliance with this section.

(III) The commission may ask the qualifying retail utility to get additional information or documentation from the DER aggregator if the commission deems it necessary to ensure compliance with this section.

(IV) After the initial filing of the affidavit with the commission, if a DER aggregator adds an individual additional storage system capacity of one megawatt or higher, the DER aggregator shall file another affidavit with the commission.

(h) Unless implemented in another proceeding, the commission shall determine whether to direct a qualifying retail utility to propose a competitive solicitation for virtual power plants that may operate in conjunction with the tariff-based virtual power plant program in evaluating the approval of the tariff.

(9) Underground conversion and community benefit programs - plans - definition. (a) By January 1, 2025, a qualifying retail utility shall file with the commission a plan to implement community-directed underground conversion and community benefit programs for the undergrounding of utility distribution infrastructure and other community benefit investments in nonfranchised areas of the qualifying retail utility in the state using one percent of the area's gross electric revenues from the prior year.

(b) As part of a qualifying retail utility's distribution system plans, the qualifying retail utility shall consider the public benefit of undergrounding existing and new distribution system infrastructure and other community benefit investments. A qualifying retail utility shall include in its distribution system plans a description of how such public benefit has been considered in its distribution system planning.

(c) In order to account for the fact that undergrounding significant portions of utility distribution infrastructure may not be feasible or efficient in some areas, as used in this subsection (9), "community benefit investments" means community-directed projects such as microgrids, customer-sited energy storage, and other similar projects aimed at community energy resiliency.
C.R.S. § 40-2-130.5 — CO Code / Title 40 / Article 2 / Part 1 / Section 40-2-130.5
40-2-130.5. Dispatchable distributed generation - energy storage - definitions - program cap
Status: in_force

40-2-130.5. Dispatchable distributed generation - energy storage - definitions - program capacity - program administration - rules. (1) Definitions. As used in this section, unless the context otherwise requires:

(a) "Dispatchable distributed generation" means distributed generation paired with a co-located energy storage system that is:

(I) Directly interconnected to an investor-owned electric utility's distribution system and is not behind a customer meter; and

(II) Measured by the capacity of the distributed generation in alternating current.

(b) "Distributed generation" means a renewable energy resource as defined in section 40-2-124 (1)(a)(VII) that interconnects to a utility's distribution system.

(c) "Energy storage system" has the same meaning as set forth in section 40-2-130 (2)(a).

(d) "Investor-owned electric utility" or "utility" means a retail electric utility in the state that is not a cooperative electric association or a municipally owned electric utility.

(2) Program capacity. (a) On or before June 1, 2026, an investor-owned electric utility with more than five hundred thousand customers shall acquire at least fifty megawatts of dispatchable distributed generation.

(b) On or after January 1, 2027, but before June 1, 2027, an investor-owned electric utility with more than five hundred thousand customers shall acquire at least fifty megawatts of dispatchable distributed generation.

(c) To ensure that an investor-owned electric utility with more than five hundred thousand customers acquires dispatchable distributed generation in accordance with subsections (2)(a) and (2)(b) of this section, the commission shall:

(I) Determine the procedures for a utility to acquire dispatchable distributed generation;

(II) Establish a methodology that ascribes value to dispatchable distributed generation located in specific areas of the electric grid in order to direct the development of dispatchable distributed generation resources in optimal locations; and

(III) Adopt any other program- or project-specific requirements the commission deems necessary to facilitate the acquisition of dispatchable distributed generation, including all applicable requirements of the "Colorado Energy Sector Public Works Project Craft Labor Requirements Act", part 3 of article 92 of title 24, for dispatchable distributed generation projects that qualify as an "energy sector public works project" as defined in section 24-92-303 (5).

(d) On or before June 1, 2028, and periodically thereafter, the commission shall determine the procedure and capacity amounts for future acquisitions of dispatchable distributed generation by an investor-owned electric utility.

(3) Program administration. The commission shall:

(a) Adopt and enforce all rules required under this section;

(b) Require all applicable investor-owned electric utilities to file the tariffs, agreements, or other forms and documents necessary for the implementation of this section; and

(c) Consult with the Colorado electric transmission authority, created in section 40-42-103, as necessary to plan for and optimize the use of dispatchable distributed generation that is acquired and developed in accordance with this section.
C.R.S. § 40-6.5-108 — CO Code / Title 40 / Article 6.5 / Section 40-6.5-108
40-6.5-108. Repeal of article - office of the utility consumer advocate subject to terminati
Status: repealed

40-6.5-108. Repeal of article - office of the utility consumer advocate subject to termination. This article 6.5 is repealed, effective September 1, 2028. Before the repeal, this article 6.5 is scheduled for review in accordance with section 24-34-104.
C.R.S. § 40-18-104 — CO Code / Title 40 / Article 18 / Section 40-18-104
40-18-104. Confidential investigative reports
Status: in_force

40-18-104. Confidential investigative reports. Investigative reports of the commission compiled under this article shall be confidential and shall not be discoverable nor used as evidence in any court or administrative action.
C.R.S. § 40-10.1-102 — CO Code / Title 40 / Article 10.1 / Part 1 / Section 40-10.1-102
40-10.1-102. Powers of commission
Status: in_force

40-10.1-102. Powers of commission. (1) The commission has the power to and shall administer and enforce this article 10.1, including:

(a) The right to inspect the motor vehicles, facilities, and records and documents, regardless of the format, of the motor carriers and persons involved;

(b) The authority to administratively set the application, filing, annual operating, and other fees for motor carriers pursuant to section 40-10.1-111; and

(c) The authority to administratively set permit fees for each transportation network company pursuant to section 40-10.1-606 (2).

(2) The Colorado state patrol has the power to monitor and enforce compliance with the certificate and permit requirements of this article and article 10.5 of this title.
C.R.S. § 40-23-101 — CO Code / Title 40 / Article 23 / Section 40-23-101
40-23-101. Right to reorganize
Status: in_force

40-23-101. Right to reorganize. Whenever the railroads, property, and franchises of any railroad company, organized and existing under the laws of this state, are sold and conveyed under or by virtue of any power contained in any trust deed or mortgage or pursuant to the judgment or decree of any court of competent jurisdiction, it is lawful to organize a railroad company under the laws of this state for the purpose of purchasing, maintaining, operating, extending, or completing the railroads, property, and franchises so sold and conveyed.
C.R.S. § 40-6-104 — CO Code / Title 40 / Article 6 / Section 40-6-104
40-6-104. Certified copies - evidence - orders
Status: in_force

40-6-104. Certified copies - evidence - orders. (1) Copies of all official documents, commission decisions, and orders on file with the commission, or documents filed or deposited according to law in the office of the commission, certified by a commissioner or by the director under the official seal of the commission to be true copies of the originals, shall be evidence in like manner as the originals and shall be treated and recognized as such by all courts of the state of Colorado.

(2) Any order, decision, authorization, certificate, or entry, or a copy thereof, certified by a commissioner or by the director under the official seal of the commission to be a true copy of the original order, decision, authorization, certificate, or entry, may be filed for record in the office of the county clerk and recorder of any county or city and county in which is located the principal place of business of any public utility affected thereby or in which is situated any property of any such public utility, and such record shall impart notice of its provisions to all persons. A certificate under the seal of the commission that any such order, decision, authorization, or certificate has not been modified, stayed, suspended, or revoked may also be recorded in the same offices in the same manner and with like effect.
C.R.S. § 40-20-313 — CO Code / Title 40 / Article 20 / Part 3 / Section 40-20-313
40-20-313. Rail industry safety advisory committee - membership - duties - rail safety plan
Status: repealed

40-20-313. Rail industry safety advisory committee - membership - duties - rail safety plan - repeal. (1) The rail industry safety advisory committee is created.

(2) (a) The rail industry safety advisory committee consists of the following nine members, each to be appointed by the governor:

(I) Two members who represent operators of class I railroads operating freight rail lines;

(II) One member who represents a class II or class III railroad in the state;

(III) One member who represents a railroad that operates a passenger rail line;

(IV) Two members who represent first responder organizations; and

(V) Three members with expertise concerning rail safety, rail operations, emergency response, or transportation regulation.

(b) The governor shall make the initial appointments on or before August 1, 2024.

(c) The members of the rail industry safety advisory committee each serve terms of three years; except that:

(I) The members of the rail industry safety advisory committee initially appointed pursuant to subsections (2)(a)(I) and (2)(a)(II) of this section shall each serve an initial term of one year; and

(II) The members of the rail industry safety advisory committee initially appointed pursuant to subsections (2)(a)(III) and (2)(a)(IV) of this section shall each serve an initial term of two years.

(d) Members of the rail industry safety advisory committee serve at the pleasure of the governor.

(e) Members of the rail industry safety advisory committee may serve an unlimited number of terms.

(3) Members of the rail industry safety advisory committee serve without compensation but must be reimbursed from money in the fund for actual and necessary expenses incurred in the performance of the members' duties pursuant to this section.

(4) The rail industry safety advisory committee is repealed, effective September 1, 2034. Before the repeal, the rail industry safety advisory committee is scheduled for review in accordance with section 2-3-1203.
C.R.S. § 40-4-120 — CO Code / Title 40 / Article 4 / Section 40-4-120
40-4-120. Study of community choice in wholesale electric supply - duties of commission -
Status: repealed

40-4-120. Study of community choice in wholesale electric supply - duties of commission - report - legislative declaration - definition - repeal. (Repealed)
C.R.S. § 40-3.2-104.4 — CO Code / Title 40 / Article 3.2 / Part 1 / Section 40-3.2-104.4
40-3.2-104.4. Colorado energy office gas investment asset depreciation study - third-party eva
Status: in_force

40-3.2-104.4. Colorado energy office gas investment asset depreciation study - third-party evaluation - commission rules. (1) (a) On or before July 1, 2024, the Colorado energy office created in section 24-38.5-101 (1) shall contract with an independent third party to evaluate the risk of stranded or underutilized natural gas infrastructure investments and the annual projected rate impact on ratepayers.

(b) The evaluation must take into account:

(I) Any projected decline in gas sales;

(II) The decline in the number of gas customers; and

(III) Measures to achieve the greenhouse gas emission reduction goals set forth in section 25-7-102 (2)(g).

(c) The independent third party shall conduct an analysis of, and include policy recommendations related to, the potential impacts of stranded or underutilized natural gas infrastructure on utility employees who work for, or contract workers who perform work for, investor-owned gas utilities. In conducting the study, the independent third party shall consult with appropriate labor organizations that represent utility employees who work for, and contract workers who perform work for, investor-owned gas utilities and other relevant stakeholders.

(2) After the independent third-party evaluation described in subsection (1) of this section is completed, the Colorado energy office shall submit a written copy of the findings and conclusions of the evaluation to the commission. The commission shall review the evaluation and consider whether any changes to rules or depreciation schedules are warranted.

(3) (a) An investor-owned gas utility shall provide as part of any gas infrastructure plan, or as otherwise directed by the commission, a map showing system-wide locations, ages, and materials or types of gas distribution system pipes, consistent with 49 CFR 191 and section 40-2-115 (1)(d).

(b) As part of the filing, the investor-owned gas utility shall also provide information about pipes that may need to be upgraded or replaced within ten years after the date that the utility files the plan, unless otherwise directed by the commission.

(c) The commission shall ensure that the content of the map provided to the commission and sharing procedures are in compliance with the parameters related to critical infrastructure reporting standards of the California Institute for Energy and Environment, or its successor organization, and the safety and system integrity standards of the American Petroleum Institute, or its successor organization.

(d) (I) An investor-owned gas utility may designate any map or associated information provided pursuant to this subsection (3) as containing critical infrastructure information. If the commission determines that the designated map or associated information does not contain critical infrastructure information, the investor-owned gas utility may appeal the commission's determination in a court of competent jurisdiction by filing the appeal within ten days after the commission's determination.

(II) If the commission determines that the disclosure of the designated map or associated information may expose or create vulnerability to critical infrastructure facilities or systems, the commission:

(A) Shall limit access to the designated map or associated information to individuals at state agencies that are parties to the proceeding in which the map or associated information was provided; and

(B) Except as provided in subsection (3)(d)(II)(A) of this section, shall not provide the designated map or associated information to any persons and may order the investor-owned gas utility to provide a public redacted version of the map or associated information that includes a general description of the information without detailed location information.

(III) A custodian, as defined in section 24-72-202 (1.1), shall not release a map or associated information for which the commission has limited access pursuant to subsection (3)(d)(II) of this section in response to any request to inspect public records pursuant to the "Colorado Open Records Act", part 2 of article 72 of title 24.
C.R.S. § 40-8.7-108.5 — CO Code / Title 40 / Article 8.7 / Section 40-8.7-108.5
40-8.7-108.5. Energy outreach Colorado - administration of water assistance contributions
Status: in_force

40-8.7-108.5. Energy outreach Colorado - administration of water assistance contributions. (1) The organization shall hold and administer all money collected for water assistance pursuant to this article 8.7 delivered to it by water utilities pursuant to section 40-8.7-107 in a separately identifiable account, which shall be restricted to the purposes set forth in this article 8.7. The organization shall maintain its books and records pertaining to the water assistance contributions in accordance with generally accepted accounting principles and, in addition, shall maintain records adequate to identify the money collected by each water utility. If the organization commingles the money collected and delivered with other assets of the organization for investment purposes, the organization shall maintain accurate accounts of the investment money and shall credit or charge a pro rata portion of all investment earnings, gains, or losses to the account that holds the water assistance collections.

(2) The organization shall use the water assistance contributions to provide low-income water assistance. The organization shall pay the financial assistance money to each participating water utility as vendor payments. The organization shall not use the money for water assistance for customers whose water utility does not participate in the program. The organization may use up to five percent of the money collected for administration of the water assistance program in accordance with generally accepted accounting principles.

(3) The organization shall, on an annual basis, develop a budget for the water assistance program to determine the allocation of the water assistance contributions collected under this article 8.7.
C.R.S. § 40-15-401 — CO Code / Title 40 / Article 15 / Part 4 / Section 40-15-401
40-15-401. Services, products, and providers exempt from regulation - definition
Status: repealed

40-15-401. Services, products, and providers exempt from regulation - definition. (1) The following products, services, and providers are exempt from regulation under this article 15 or under the "Public Utilities Law" of the state of Colorado:

(a) Cable services as defined by section 602 (5) of the federal "Cable Communications Policy Act of 1984";

(b) Basic service; except that:

(I) The high cost support mechanism, as described in sections 40-15-208 and 40-15-502, remains effective to support basic service regardless of the classification of basic service or voice-over-internet protocol service in this part 4;

(II) (A) Until July 1, 2016, each incumbent local exchange carrier shall charge a uniform price for basic service throughout its service territory; except that an incumbent local exchange carrier shall not charge a price for basic service that is more than the price that the carrier charged on December 31, 2013, unless the price charged is lower than the urban rate floor prescribed by the federal communications commission. If a carrier charges less than the urban rate floor, the carrier may increase the price to equal but not exceed the urban rate floor; except that, if the commission orders reductions in intercarrier compensation rates, an incumbent local exchange carrier may increase local rates to recover some or all of the lost revenues associated with the commission's action.

(B) As used in this subparagraph (II), "urban rate floor" means the basic local exchange service rate required to be charged in order to prevent a reduction in federal high cost support.

(III) Until July 1, 2016, each incumbent local exchange carrier remains subject to any obligations as provider of last resort, as established by the commission under section 40-15-502 (6), throughout its service territory;

(IV) On and after July 1, 2016, throughout each geographic area for which the commission provides high cost support mechanism distributions for basic service under sections 40-15-208 and 40-15-502 (5), the commission retains the authority to:

(A) Designate providers of last resort under section 40-15-502 (6);

(B) Determine a maximum price for basic service under section 40-15-502 (3)(b);

(C) Prohibit providers from discontinuing basic service, notwithstanding section 40-15-111; and

(D) Audit, investigate, and enforce compliance with regulation permitted in this section and sections 40-15-208 and 40-15-502 (5);

(V) Providers of basic service remain subject to the following fees and surcharges:

(A) High cost support mechanism assessments calculated under section 40-15-502 (5)(a);

(B) Emergency service surcharges assessed under part 1 of article 11 of title 29, C.R.S., to support 911 service; and

(C) Telecommunications relay service charges assessed under article 17 of this title; and

(VI) If, after July 1, 2018, the commission finds that re-regulation of basic local exchange service is necessary to protect the public interest following a hearing and upon findings of fact and conclusions of law, the commission may regulate basic local exchange service under part 3 of this article.

(c) Commercial mobile radio services;

(d) Repealed.

(e) New products and services other than those included in the definition of basic local exchange service;

(f) Centron and centron-like services;

(g) Special arrangements;

(h) Special assemblies;

(i) Information services;

(j) Optional operator services;

(k) Advanced features;

(l) Special access;

(m) Public coin telephone service;

(n) Retail digital private line service;

(o) Retail private line service with a capacity of at least twenty-four voice grade circuits;

(p) Retail directory assistance;

(p.5) Private telecommunications networks;

(q) Internet-protocol-enabled services;

(r) Voice-over-internet protocol service;

(s) InterLATA toll, except with respect to interexchange provider registration under section 40-15-302.5, complaints of unauthorized charges on a subscriber's bill, or complaints of changing a subscriber's service without the subscriber's consent;

(t) IntraLATA toll, except with respect to interexchange provider registration under section 40-15-302.5, complaints of unauthorized charges on a subscriber's bill, or complaints of changing a subscriber's service without the subscriber's consent; and

(u) Nonoptional operator services.

(2) Nothing in this section affects, modifies, or expands:

(a) An entity's obligations under sections 251 and 252 of the federal "Communications Act of 1934", as amended, and codified in 47 U.S.C. secs. 251 and 252;

(b) Any commission authority over wholesale telecommunications rates, services, agreements, providers, or tariffs;

(c) Any commission authority addressing or affecting the resolution of disputes regarding intercarrier compensation; or

(d) The requirements for the receipt of state or federal financial assistance through a high cost support mechanism.

(3) If a telecommunications service or product is not defined in part 1 of this article and is not classified under part 2 or 3 of this article, the telecommunications service or product is classified as a deregulated telecommunications service under this part 4.

(4) Nothing in this part 4 shall be construed to affect, modify, limit, or expand the commission's authority to regulate basic emergency service.

(5) This section does not affect the establishment or enforcement of standards, requirements, procedures, or procurement policies, applicable to any department, agency, commission, or political subdivision of the state, or to the employees, agents, or contractors of a department, agency, commission, or political subdivision of the state, relating to the protection of intellectual property.
C.R.S. § 40-9.5-108 — CO Code / Title 40 / Article 9.5 / Part 1 / Section 40-9.5-108
40-9.5-108. Public meetings - definition
Status: in_force

40-9.5-108. Public meetings - definition. (1) All meetings of a cooperative electric association are declared to be open meetings and open to the members, consumers, and news media at all times; but such association, by a two-thirds affirmative vote of the board members present, may go into executive session for consideration of documents or testimony given in confidence, but such association shall not make final policy decisions or adopt or approve any resolution, rule, regulation, or formal action, any contract, or any action calling for the payment of money at any session which is closed to the members, consumers, and news media.

(1.5) All meetings of a generation and transmission association are declared to be open meetings and open to the members, consumers, and news media at all times; but such association, by a two-thirds affirmative vote of the board members present, may go into executive session for consideration of documents or testimony given in confidence.

(2) (a) Before a board of directors convenes in executive session pursuant to subsection (1) or (1.5) of this section, the board shall announce the general topic of the executive session.

(b) At every regular meeting of the board of directors of an association or a generation and transmission association, members of the association shall be given an opportunity to address the board on any matter concerning the policies and business of the association. The board may place reasonable, viewpoint-neutral restrictions on the amount and duration of public comment.

(c) Written minutes shall be made of all meetings of the board of directors of an association or a generation and transmission association. The minutes shall be posted on the website of the association or generation and transmission association as soon as they have been approved and shall remain posted until at least six months after the date of the meeting. Upon request by a member of the board, that member's own vote on any issue shall be noted in the minutes.

(3) Any action taken contrary to the provisions of this section shall be null and void and without force or effect.

(4) As used in this section, "generation and transmission association" means a nonprofit generation and transmission electric association that provides wholesale electric service directly to Colorado cooperative electric associations that are its members.
C.R.S. § 40-3.2-101 — CO Code / Title 40 / Article 3.2 / Part 1 / Section 40-3.2-101
40-3.2-101. Legislative declaration
Status: in_force

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.
C.R.S. § 40-22-104 — CO Code / Title 40 / Article 22 / Section 40-22-104
40-22-104. Property of each transferred
Status: in_force

40-22-104. Property of each transferred. (1) Upon the consummation of said act of consolidation, all the rights, privileges, and franchises of each of said corporations, parties to the same, and all the property, real, personal, and mixed, and all debts due on whatever account, as well as stock subscriptions and other things in action, belonging to each of such corporations shall be deemed to be transferred to and vested in such new corporation without further act or deed. All property, all rights-of-way, and every other interest shall be as effectually the property of the new corporation as they were of the former corporations.

(2) The title to real estate, either by deed or otherwise, under the laws of this state or of the United States, vested in any of such corporations, shall not be deemed to revert or be in any way impaired by reason of this article, nor shall the lien, operation, or effect of any trust deed or mortgage executed by any of the corporations so consolidating be in any way divested, impaired, or affected. The new corporation shall have the right to execute any future trust deed or mortgage upon its property, as shall be provided in the agreement of consolidation, not inconsistent with the laws of this state, and all debts, liabilities, and duties of either of said companies shall attach to said new corporation, and be enforced against it, to the same extent as if said debts, liabilities, and duties had been incurred or contracted by it.
C.R.S. § 40-3-104.3 — CO Code / Title 40 / Article 3 / Section 40-3-104.3
40-3-104.3. Manner of regulation - competitive responses - definitions - repeal
Status: repealed

40-3-104.3. Manner of regulation - competitive responses - definitions - repeal. (1) (a) 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:

(I) For contracts with a specific customer or potential customer involving electric and steam service:

(A) The price of any such service is not below that service's variable cost;

(B) 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;

(C) The approval of the application will not adversely affect the remaining customers of the public utility; and

(D) The approval of the application is in the public interest;

(II) For contracts with existing customers involving natural gas service:

(A) 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;

(B) The customer will discontinue using the services of the public utility if the authorization is not granted;

(C) Approval of the application will not as adversely affect the remaining customers of the public utility as would the alternative;

(D) 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

(E) The approval of the application is in the public interest.

(b) (I) 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).

(II) 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.

(III) 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.

(c) 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).

(d) (Deleted by amendment, L. 92, p. 2138, § 1, effective April 23, 1992.)

(e) 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) (a) 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.

(b) 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) (a) 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.

(b) 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) (a) 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.

(b) 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) (a) 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.

(b) (I) 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.

(II) (A) 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.

(B) 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.

(III) An investor-owned utility may offer an economic development rate to a qualifying commercial or industrial customer for up to ten years.

(c) (I) 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.

(II) 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:

(A) The rates or charges assessed to other customers do not subsidize the cost of providing economic development rates to qualifying commercial or industrial customers;

(B) The rates of other regulated utility operations do not increase; and

(C) 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.

(III) 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.

(d) (I) 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:

(A) Any commercial or industrial customer making a capital investment of two hundred fifty million dollars or more;

(B) Any commercial or industrial customer that requires such expansion to remain as a customer of that utility; or

(C) Any qualifying commercial or industrial customer entering the service territory of the utility.

(II) 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:

(A) 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

(B) 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):

(a) "Qualifying commercial or industrial customer":

(I) Means a utility customer that:

(A) 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

(B) 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;

(II) 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.

(b) "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.
C.R.S. § 40-42-109 — CO Code / Title 40 / Article 42 / Section 40-42-109
40-42-109. Study on expanding transmission capacity - reporting - repeal
Status: repealed

40-42-109. Study on expanding transmission capacity - reporting - repeal. (1) The authority shall expend money from the operational fund created in section 40-42-106 to study the need for expanded transmission capacity in the state, including:

(a) The ability to expand capacity through the construction of new transmission lines, improvements to existing transmission lines, and connections to organized wholesale markets, as defined in section 40-5-108 (1)(a);

(b) Whether and how expanded transmission capacity will:

(I) Improve the system reliability of the electric grid and provide optimal utilization of electricity flows in the state;

(II) Support the state's emission reduction goals set forth in section 25-7-102 (2)(g);

(III) Support the state's forecasted electricity needs; and

(IV) Reduce land impacts by using existing rights-of-way, including for large capacity transmission lines; co-locating multiple transmission lines; reconductoring transmission lines; and strategically siting new transmission corridors.

(2) The authority shall prepare:

(a) An initial report of the study, including any recommendations, and present the initial report to the commission on or before September 1, 2024; and

(b) A final report of the study, including any recommendations, and present the final report to the joint committee of the house of representatives energy and environment committee and the senate transportation and energy committee, or their successor committees, on or before January 31, 2025.

(3) This section is repealed, effective September 1, 2025.
C.R.S. § 40-15-403 — CO Code / Title 40 / Article 15 / Part 4 / Section 40-15-403
40-15-403. General assembly may reregulate
Status: in_force

40-15-403. General assembly may reregulate. Any telecommunications service or product deregulated pursuant to this part 4 may be reregulated by action of the general assembly.
C.R.S. § 40-2-127.5 — CO Code / Title 40 / Article 2 / Part 1 / Section 40-2-127.5
40-2-127.5. Community energy funds - community geothermal gardens - rules - legislative decl
Status: in_force

40-2-127.5. Community energy funds - community geothermal gardens - rules - legislative declaration - definitions - repeal. (1) Legislative declaration. The general assembly hereby finds and declares that:

(a) Local communities can benefit from the further development of renewable energy, energy efficiency, conservation, and environmental improvement projects, and the general assembly hereby encourages electric utilities to establish community energy funds for the development of such projects;

(b) It is in the public interest that broader participation in geothermal electric generation by Colorado residents and commercial entities be encouraged by the development and deployment of distributed geothermal electric generating facilities known as community geothermal gardens in order to:

(I) Provide Colorado residents and commercial entities with the opportunity to participate in geothermal electricity generation;

(II) Allow renters, low-income utility customers, and agricultural producers to own interests in such geothermal generation facilities;

(III) Allow interests in such geothermal generation facilities to be portable and transferrable; and

(IV) Leverage Colorado's geothermal electricity generating capacity through economies of scale.

(2) Definitions. As used in this section, unless the context otherwise requires, the definitions in section 40-2-124 apply, and:

(a) (I) "Community geothermal garden" means a geothermal facility that produces electricity from the earth's heat with a nameplate rating within the range specified under subsection (2)(a)(IV) of this section that is located in or near a community served by a qualifying retail utility where the beneficial use of the electricity generated by the facility belongs to the subscribers to the community geothermal garden. There must be at least ten subscribers. The owner of the community geothermal garden may be the qualifying retail utility or any other for-profit or nonprofit entity or organization, including a subscriber organization organized under this section, that contracts to sell the output from the community geothermal garden to the qualifying retail utility. A community geothermal garden is deemed to be "located on the site of customer facilities".

(II) A community geothermal garden constitutes "retail distributed generation" within the meaning of section 40-2-124.

(III) Notwithstanding any provision of this section or section 40-2-124 to the contrary, a community geothermal garden constitutes retail distributed generation for purposes of a cooperative electric association's compliance with the applicable renewable energy standard under section 40-2-124.

(IV) A community geothermal garden must have a nameplate rating of five megawatts or less; except that the commission may, in rules adopted pursuant to subsection (3)(b) of this section, approve the formation of a community geothermal garden with a nameplate rating of up to ten megawatts.

(b) "Subscriber" means a retail customer of a qualifying retail utility who owns a subscription and who has identified one or more physical locations to which the subscription is attributed. Such physical locations must be within the service territory of the same qualifying retail utility as the community geothermal garden. The subscriber may change from time to time the premises to which the community geothermal garden electricity generation is attributed, so long as the premises are within the same service territory.

(c) "Subscription" means a proportional interest in geothermal electric generation facilities installed at a community geothermal garden, together with the renewable energy credits associated with or attributable to such facilities under section 40-2-124. Each subscription must be sized to represent at least one kilowatt of the community geothermal garden's generating capacity and to supply no more than one hundred twenty percent of the average annual consumption of electricity by each subscriber at the premises to which the subscription is attributed, with a deduction for the amount of any existing geothermal facilities at such premises. Subscriptions in a community geothermal garden may be transferred or assigned to a subscriber organization or to any person or entity who qualifies to be a subscriber under this section.

(3) Subscriber organization - subscriber qualifications - transferability of subscriptions. (a) The community geothermal garden may be owned by a subscriber organization whose sole purpose is beneficially owning and operating a community geothermal garden. The subscriber organization may be any for-profit or nonprofit entity permitted by Colorado law. The community geothermal garden may also be built, owned, and operated by a third party under contract with the subscriber organization.

(b) The commission shall adopt rules as necessary to implement this section, including rules to facilitate the financing of subscriber-owned community geothermal gardens. The rules must include:

(I) Minimum capitalization;

(II) The share of a community geothermal garden's geothermal electric generation facilities that a subscriber organization may at any time own in its own name; and

(III) Authorizing subscriber organizations to enter into leases, sale-and-leaseback transactions, operating agreements, and other ownership arrangements with third parties.

(c) If a subscriber ceases to be a customer at the premises on which the subscription is based but, within a reasonable period as determined by the commission, becomes a customer at another premises in the service territory of the qualifying retail utility and within the geographic area served by the community geothermal garden, the subscription continues in effect but the bill credit and other features of the subscription are adjusted as necessary to reflect any differences between the new and previous premises' customer classification and average annual consumption of electricity.

(4) Standards for construction and operation. The following requirements apply to any community geothermal garden exceeding two megawatts:

(a) The initial installation of any electrical equipment associated with the community geothermal garden is subject to final inspection and approval in accordance with section 12-115-120.

(b) Following the development or acquisition by a qualifying retail utility of a community geothermal garden in which the qualifying retail utility retains ownership, the qualifying retail utility shall either use its own employees to operate and maintain the community geothermal garden or contract for operation and maintenance of the community geothermal garden by a contractor whose employees have access to an apprenticeship program registered with the United States department of labor's office of apprenticeship or with a state apprenticeship agency recognized by that office; except that this apprenticeship requirement does not apply to:

(I) The design, planning, or engineering of the infrastructure;

(II) Management functions to operate the infrastructure; or

(III) Any work included in a warranty.

(5) Community geothermal gardens not subject to regulation. Neither the owners of nor the subscribers to a community geothermal garden are considered public utilities subject to regulation by the commission solely as a result of their interest in the community geothermal garden. Prices paid for subscriptions in community geothermal gardens shall not be subject to regulation by the commission.

(6) Purchases of the output from community geothermal gardens. (a) (I) Each qualifying retail utility may set forth in its plan for acquisition of renewable resources a plan to purchase the electricity and renewable energy credits generated from one or more community geothermal gardens over the period covered by the plan.

(II) For each qualifying retail utility's compliance years commencing in 2026 and thereafter, the commission shall determine the minimum and maximum purchases of electrical output from newly installed community geothermal gardens of different output capacity that the qualifying retail utility may plan to acquire. In addition, as necessary and appropriate, the commission shall formulate and implement policies consistent with this section that simultaneously encourage:

(A) The ownership by customers of subscriptions in community geothermal gardens and of other forms of distributed generation, to the extent the commission finds there to be customer demand for such ownership;

(B) Ownership in community geothermal gardens by residential retail customers and agricultural producers, including low-income customers, to the extent the commission finds there to be demand for such ownership;

(C) The development of community geothermal gardens with attributes that the commission finds result in lower overall total costs for the qualifying retail utility's customers;

(D) Successful financing and operation of community geothermal gardens owned by subscriber organizations; and

(E) The achievement of the goals and objectives of section 40-2-124.

(b) (I) (A) The output from a community geothermal garden must be sold only to the qualifying retail utility serving the geographic area where the community geothermal garden is located.

(B) Once a community geothermal garden is part of a qualifying retail utility's plan for acquisition of renewable resources, as approved by the commission, the commission shall initiate a proceeding, or consider in an active proceeding, to determine whether the qualifying retail utility must purchase all of the electricity and renewable energy credits generated by the community geothermal garden or whether a subscriber may, upon becoming a subscriber, choose to retain or sell to the qualifying retail utility the subscriber's renewable energy credits.

(C) The amount of electricity and renewable energy credits generated by each community geothermal garden is determined by a production meter installed by the qualifying retail utility or third-party system owner and paid for by the owner of the community geothermal garden.

(II) The purchase of the output of a community geothermal garden by a qualifying retail utility takes the form of a net metering credit against the qualifying retail utility's electric bill to each community geothermal garden subscriber at the premises set forth in the subscriber's subscription. The net metering credit is calculated by multiplying the subscriber's share of the electricity production from the community geothermal garden by the qualifying retail utility's total aggregate retail rate as charged to the subscriber, minus a reasonable charge as determined by the commission to cover the utility's costs of delivering to the subscriber's premises the electricity generated by the community geothermal garden, integrating the geothermal generation with the utility's system, and administering the community geothermal garden's contracts and net metering credits. The commission shall ensure that this charge does not reflect costs that are already recovered by the utility from the subscriber through other charges. If, and to the extent that, a subscriber's net metering credit exceeds the subscriber's electric bill in any billing period, the net metering credit is carried forward and applied against future bills. The qualifying retail utility and the owner of the community geothermal garden must agree on whether the purchase of the renewable energy credits from subscribers will be accomplished through a credit on each subscriber's electricity bill or by a payment to the owner of the community geothermal garden.

(c) The owner of the community geothermal garden must provide real-time production data to the qualifying retail utility to facilitate incorporation of the community geothermal garden into the utility's operation of its electric system and to facilitate the provision of net metering credits.

(d) The owner of the community geothermal garden is responsible for providing to the qualifying retail utility, on a monthly basis and within reasonable periods set by the qualifying retail utility, the percentage shares that should be used to determine the net metering credit to each subscriber. If the electricity output of the community geothermal garden is not fully subscribed, the qualifying retail utility shall purchase the unsubscribed renewable energy and the renewable energy credits at a rate equal to the qualifying retail utility's average hourly incremental cost of electricity supply over the immediately preceding calendar year.

(e) If a qualifying retail utility includes a plan to purchase the electricity and renewable energy credits generated by one or more community geothermal gardens, then the qualifying retail utility shall set forth in its plan for acquisition of renewable resources a proposal for including low-income customers as subscribers to a community geothermal garden, if possible. The utility may give preference to community geothermal gardens that have low-income subscribers.

(f) Qualifying retail utilities are eligible for the incentives and subject to the ownership limitations set forth in section 40-2-124 (1)(f) for utility investments in community geothermal gardens and may recover through rates a margin, in an amount determined by the commission, on all energy and renewable energy credits purchased from community geothermal gardens. Such incentive payments are excluded from the cost analysis required by section 40-2-124 (1)(g).

(7) Nothing in this section waives or supersedes the retail rate impact limitations in section 40-2-124 (1)(g). Utility expenditures for unsubscribed energy and renewable energy credits generated by community geothermal gardens must be included in the calculations of retail rate impact required by that section.

(8) Applicability to cooperative electric associations and municipally owned utilities. This section shall not apply to cooperative electric associations or to municipally owned utilities.
C.R.S. § 40-7.5-104 — CO Code / Title 40 / Article 7.5 / Section 40-7.5-104
40-7.5-104. Remedies cumulative
Status: in_force

40-7.5-104. Remedies cumulative. It is the purpose of this article to provide additional remedies to avoid the wrongful use of the facilities of utilities, and nothing in this article shall abridge or alter rights of action or remedies existing prior to July 1, 1983, or created on or after said date.
C.R.S. § 40-9-107 — CO Code / Title 40 / Article 9 / Section 40-9-107
40-9-107. Damages for failure to comply
Status: in_force

40-9-107. Damages for failure to comply. For failure of any common carrier to transport any such shipment within the time required by section 40-9-106, the common carrier issuing the receipt or bill of lading shall pay to the owner, consignee, or other interested party whose interest may appear such actual damages as the owner, consignee, or other interested party may sustain, together with exemplary damages in a sum of not less than one hundred dollars nor more than one thousand dollars, to be fixed by the jury or by the court if the cause is tried without a jury, and such actual and exemplary damages may be sued for and recovered in any court of competent jurisdiction in the district in which the plaintiff resides.
C.R.S. § 40-3.5-103 — CO Code / Title 40 / Article 3.5 / Section 40-3.5-103
40-3.5-103. Rate schedules
Status: in_force

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.