(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.
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