4 Colo. Code Regs. § 723-4-4553

Current through Register Vol. 48, No. 1, January 10, 2025

Section 4 CCR 723-4-4553 - Contents of a Gas Infrastructure Plan

(a) General.

(I) The utility shall describe in each gas infrastructure plan the methodology, criteria, and assumptions used to develop the gas infrastructure plan. The utility shall specifically describe its system planning and infrastructure modeling process including the assumptions and variables that are inputs into the process.

(II) The utility shall describe its budget planning processes and the expected level of accuracy in its cost projections.

(III) The utility shall categorize planned projects, or explain any deviation of project categorization, based on the categories set forth below. A planned project may be included in more than one category or subcategory. The utility shall also explain the inter-relationship of planned projects, to the extent applicable.

(A) "System safety and integrity projects" shall include but are not limited to pipeline and storage integrity management programs; exposed pipe inspection and remediation; pipe or compressor station upgrades; projects undertaken to meet U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration requirements; and Supervisory Control and Data Acquisition (SCADA) upgrades.

(B) "New business projects" shall include utility investment and spending needed to provide gas service to new customers or customers requiring new gas service.

(C) "Capacity expansion projects" shall include both individual projects and sets of inter-related facilities needed to maintain system reliability and meet a specified capacity expansion need. Within the category of capacity expansion projects, the utility shall further separate appropriate projects into the following sub-categories:

(i) capacity expansion projects needed for reliability or growth in sales by existing customers, structures, and facilities; and

(ii) capacity expansion projects needed for growth in sales due to new customers, structures, and facilities, that are not otherwise new business planned projects.

(D) "Mandatory relocation projects" as defined in paragraph 4001(gg).

(E) "Defined programmatic expenses" as defined in paragraph 4551(b), means the following, or as otherwise ordered by the Commission:

(i) "relocation or replacement of meters" shall include the utility's investment and expenditure to replace or relocate customer meters, including at-risk meters, not otherwise covered by other projects; and

(ii) "replacement of customer-owned yard lines" shall include the investment and expenditure to replace customer-owned yard lines and associated infrastructure with utility-owned pipelines and associated infrastructure.

(IV) The utility shall provide, for each year of the gas infrastructure plan total period, and for each project category defined above in subparagraph 4553(a)(III), the following information:

(A) the total number of projects; and

(B) the total annual capital investment.

(V) The utility shall provide one or more maps indicating locations of individual planned projects, pressure district or geographic area served by the individual planned projects or that would otherwise lead to a foreseeable lack of system reliability, if applicable, and other distinct zones identified for planning purposes in the utility's most recently approved clean heat plan pursuant to subparagraph 4731(a)(I)(B) with sufficient geographical detail such that the Commission can evaluate and fully comprehend the extent and purpose of the overall gas infrastructure plan. The utility shall also indicate whether the planned projects are located within disproportionately impacted communities.

(VI) The utility shall provide a copy of its prior year's United States Department of Transportation Gas Distribution Annual Report, Form F7100.

(VII) The utility shall provide a summary of stakeholder participation and input and explain how this input was incorporated into the gas infrastructure plan. For each recommendation received by the utility prior to filing its plan, a utility shall summarize the recommendation and respond to it. If a project or projects are located in a disproportionately impacted community, the utility shall further provide a description of outreach to members of that community, including a description of the nature of the outreach as appropriate to the filing, including descriptions of communications and materials, and findings from those efforts. The utility shall also provide a summary of the public workshops on alternatives analyses as required by subparagraph 4552(d)(IV).

(VIII) The utility shall provide project-level information consistent with the requirements in paragraph 4553(c) for all projects with an expected construction start date during the gas infrastructure plan action period and the gas infrastructure plan informational period, where available. For planned projects in the gas infrastructure plan informational period where project-level information is not available, category-level specificity consistent with subparagraph 4553(a)(III) is acceptable.

(IX) The utility shall provide the then-current peak design temperature assigned to unique segments of the utility system used for capacity planning, and data to support such design temperature(s).

(b) Forecast requirements.

(I) The utility shall present reference, low, and high forecasts of design peak demand, customer count, sales and capacity requirements, gas content including expected mixtures by volume of hydrogen and recovered methane, and system-wide greenhouse gas emissions, consistent with the utility's approved portfolio of clean heat resources and in accordance with subparagraph 4731(b)(I), or any appropriate interim-year update to such forecasts in accordance with subparagraph 4733(a)(VI).

(II) If a utility filed a small utility clean heat plan in accordance with rule 4734, the utility shall justify and document the data, assumptions, models, and other inputs upon which it relied to develop this gas infrastructure plan. A utility filing under this rule shall indicate how its forecast incorporates, to the extent practicable, relevant external factors including, but not limited to:

(A) the effect of current or enacted state and local building codes;

(B) changes in the utility's line extension policies, and the associated impact on gas customer growth;

(C) building electrification programs or incentives offered by the local electric utility or local or federal entities that overlap with the utility's gas service territory; and

(D) the price elasticity of demand (e.g., the impact of reduced throughput and rate increases on sales and peak demand requirements and impacts of commodity prices).

(c) Planned project information.

(I) The utility shall present the following project-specific information for all planned projects in the gas infrastructure plan total period, with information provided to the extent practicable for projects in the gas infrastructure plan informational period:

(A) project name;

(B) project category, consistent with the categories defined in subparagraph 4553(a)(III), or otherwise identified and justified by the utility;

(C) general scope of work and explanation of need for the project, including any applicable U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration code requirements for the project;

(D) projected life of the project;

(E) if the project is presented as a gas infrastructure plan action period project or a gas infrastructure plan informational period project;

(F) anticipated construction start date, construction period, with any phases indicated, and expected in-service date;

(G) the cost estimate classification using the utility's or an industry-accepted cost estimate classification index, and support of the methodology;

(H) project technical details, such as physical equipment characteristics of proposed facilities, pipeline length, pipeline diameter, project material(s), and maximum allowable operating pressure;

(I) total project cost estimate and a presentation of the associated annual revenue requirements for the project during the gas infrastructure plan total period, assuming both conventional depreciation and accelerated depreciation in accordance with the forecasts submitted or developed pursuant to paragraph 4553(b);

(J) the project location and an illustrative map of the facilities (subject to necessary and appropriate confidentiality provisions) including:

(i) the pressure district or geographic area that requires the proposed facilities;

(ii) the existing and proposed regulator stations and existing and proposed distribution piping and higher capacity pipelines served by or representing the proposed facilities;

(iii) the locations of any disproportionately impacted community;

(iv) identification of the electric utility service provider(s) at that location; and

(v) any other information necessary to allow the Commission to make a thorough evaluation.

(K) to the extent practicable, the number of customers, annual sales, and design peak demand requirements, by customer class, directly impacted or served by the project;

(L) permit(s) required to begin work, if any;

(M) environmental requirements associated with completion of project, if any;

(N) the change in projected greenhouse gas emissions due to the planned project;

(O) the status of the planned projects as addressed in previous plans, as well as changes, additions or deletions in the current plan when compared with prior plans; and

(P) for a quantity of new business and capacity expansion projects, given the criteria established by the Commission in accordance with subparagraph 4552(b)(I)(A) through (C), the utility shall present an analysis of alternatives, including non-pipeline alternatives, costs for those alternatives, and criteria used to rank or eliminate such alternatives.

(i) An analysis of alternatives shall consider, at a minimum:

(1) one or more applicable clean heat resources consistent with the utility's most recently approved clean heat plan, pursuant to rule 4732, demand side management plan, pursuant to rule 4753, or beneficial electrification plan, as applicable;

(2) a cost-benefit analysis including the costs of direct investment and the social costs of carbon and methane for emissions due to or avoided by the alternative, and other costs determined appropriate by the Commission; and

(3) available best value employment metrics associated with each alternative, as defined in paragraph 4001(j), including a projection of gas distribution jobs affected by the alternative and jobs made available through the alternative, opportunities to transition any affected gas distribution jobs to the alternative, pay and benefit levels of the affected gas distribution jobs and the jobs available through a transition opportunity, and how employment impacts associated with each alternative could affect disproportionately impacted communities.

(ii) An analysis of alternatives shall include, at a minimum:

(1) the technologies or approaches evaluated;

(2) the technologies or approaches proposed, if applicable;

(3) the projected timeline and annual implementation rate for the technology or approaches evaluated;

(4) the technical feasibility of the alternative assuming full adoption of the technologies and approaches evaluated;

(5) the utility's strategy to facilitate the technologies or approaches evaluated; and

(6) an explanation of the methodology used to select which projects are presented with an alternative analysis, including discussion of the public review process required pursuant to subparagraph 4552(d)(IV).

(Q) For new business and capacity expansion projects, a utility shall provide an alternative analysis as set forth in subparagraph (c)(I)(P) above or justify why the new business and capacity expansion project is not suitable for an alternative analysis for which the utility seeks a certificate of public convenience and necessity or other relief, in accordance with subparagraph 4552(d)(II).

(R) For system safety and integrity projects, the utility shall provide the applicable federal regulation, the planned project's risk ranking and the utility's risk ranking methodology including but not limited to the material, age, maximum allowable operating pressure, density of surrounding residences and businesses, and any other physical and operating characteristics relevant to the risk ranking of the planned project and the risk ranking methodology. The utility should also identify, discuss in detail, and provide the output to any risk-related models developed or employed by the utility in conducting risk analyses to support planned system safety and integrity projects or other projects.

(II) With respect to the reference, low and high forecasts conducted pursuant to subparagraph 4553(b)(I):

(A) the total incremental investment that may be needed over the gas infrastructure plan action period and gas infrastructure plan informational period; and

(B) an identification of the primary individual new projects avoided in the low design peak demand forecast and an identification of the primary individual new projects and capital spend added in the high design peak demand forecast.

(d) Existing infrastructure assessment reporting. The utility shall report on the following in the gas infrastructure plan.

(I) The utility shall report the following information regarding customer-owned yard lines attached to its distribution system, if applicable:

(A) an estimate of the number of customer-owned yard lines by municipality served;

(B) the number of customer-owned yard lines replaced by the utility to date and capital investment incurred to do so; and

(C) the estimated gross and net rate-based investment needed to replace all customer-owned yard lines in present dollars through year 2030, through year 2040, and through year 2050.

(II) The utility shall report the following information regarding hydrogen compatibility throughout its distribution system, to the extent known:

(A) estimate the percentage of distribution system components known to be compatible with safely carrying varying concentrations of hydrogen, including but not limited to:

(i) piping;

(ii) fittings; and

(iii) non-pipe system components.

(B) The utility shall identify any areas of the system with unknown materials or materials known to be not compatible with hydrogen mixtures up to 20 percent by volume.

(III) The utility shall report the following information regarding advanced leak detection:

(A) identification of equipment, survey method, percentage of system surveyed in each year, and interval in which additional advanced leak detection occurred on the same areas of the system;

(B) any updates to anticipated system-wide methane emissions based on most recent advanced leak detection surveys; and

(C) extent to which leakage sources identified are within disproportionately impacted communities.

4 CCR 723-4-4553

47 CR 08, April 25, 2024, effective 5/15/2024