{"operation":"document","citation":"4 CCR 723-4 Rule 4553","title":"Contents of a Gas Infrastructure Plan","source_type":"regulation","agency":"Colorado Public Utilities Commission","status":"current","official":true,"published_on":null,"effective_on":null,"summary":"(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 ","machine_formats":{"json":"https://regulus.evalyn.ai/document/co-ccr-4-723-4-4553.json","markdown":"https://regulus.evalyn.ai/document/co-ccr-4-723-4-4553.md"},"app_url":"https://regulus.evalyn.ai/document/co-ccr-4-723-4-4553","source_url":"https://www.sos.state.co.us/CCR/DisplayRule.do?action=ruleinfo&ruleId=2260&deptID=18&agencyID=96&deptName=Department%20of%20Regulatory%20Agencies&agencyName=Public%20Utilities%20Commission&seriesNum=4%20CCR%20723-4","body":"(a) General.\n(I) The utility shall describe in each gas infrastructure plan the methodology,\ncriteria, and assumptions used to develop the gas infrastructure plan. The\n\nutility shall specifically describe its system planning and infrastructure\nmodeling process including the assumptions and variables that are inputs\ninto the process.\n(II) The utility shall describe its budget planning processes and the expected\nlevel of accuracy in its cost projections.\n(III) The utility shall categorize planned projects, or explain any deviation of\nproject categorization, based on the categories set forth below. A planned\nproject may be included in more than one category or subcategory. The\nutility shall also explain the inter-relationship of planned projects, to the\nextent applicable.\n(A) “System safety and integrity projects” shall include but are not\nlimited to pipeline and storage integrity management programs;\nexposed pipe inspection and remediation; pipe or compressor\nstation upgrades; projects undertaken to meet U.S. Department of\nTransportation Pipeline and Hazardous Materials Safety\nAdministration requirements; and Supervisory Control and Data\nAcquisition (SCADA) upgrades.\n(B) “New business projects” shall include utility investment and\nspending needed to provide gas service to new customers or\ncustomers requiring new gas service.\n(C) “Capacity expansion projects” shall include both individual projects\nand sets of inter-related facilities needed to maintain system\nreliability and meet a specified capacity expansion need. Within the\ncategory of capacity expansion projects, the utility shall further\nseparate appropriate projects into the following sub-categories:\n(i) capacity expansion projects needed for reliability or growth\nin sales by existing customers, structures, and facilities; and\n(ii) capacity expansion projects needed for growth in sales due\nto new customers, structures, and facilities, that are not\notherwise new business planned projects.\n(D) “Mandatory relocation projects” as defined in paragraph 4001(gg).\n(E) “Defined programmatic expenses” as defined in paragraph 4551(b),\nmeans the following, or as otherwise ordered by the Commission:\n(i) “relocation or replacement of meters” shall include the\nutility’s investment and expenditure to replace or relocate\ncustomer meters, including at-risk meters, not otherwise\ncovered by other projects; and\n\n(ii) “replacement of customer-owned yard lines” shall include the\ninvestment and expenditure to replace customer-owned yard\nlines and associated infrastructure with utility-owned\npipelines and associated infrastructure.\n(IV) The utility shall provide, for each year of the gas infrastructure plan total\nperiod, and for each project category defined above in subparagraph\n4553(a)(III), the following information:\n(A) the total number of projects; and\n(B) the total annual capital investment.\n(V) The utility shall provide one or more maps indicating locations of individual\nplanned projects, pressure district or geographic area served by the\nindividual planned projects or that would otherwise lead to a foreseeable\nlack of system reliability, if applicable, and other distinct zones identified\nfor planning purposes in the utility’s most recently approved clean heat\nplan pursuant to subparagraph 4731(a)(I)(B) with sufficient geographical\ndetail such that the Commission can evaluate and fully comprehend the\nextent and purpose of the overall gas infrastructure plan. The utility shall\nalso indicate whether the planned projects are located within\ndisproportionately impacted communities.\n(VI) The utility shall provide a copy of its prior year’s United States Department\nof Transportation Gas Distribution Annual Report, Form F7100.\n(VII) The utility shall provide a summary of stakeholder participation and input\nand explain how this input was incorporated into the gas infrastructure\nplan. For each recommendation received by the utility prior to filing its\nplan, a utility shall summarize the recommendation and respond to it. If a\nproject or projects are located in a disproportionately impacted community,\nthe utility shall further provide a description of outreach to members of that\ncommunity, including a description of the nature of the outreach as\nappropriate to the filing, including descriptions of communications and\nmaterials, and findings from those efforts. The utility shall also provide a\nsummary of the public workshops on alternatives analyses as required by\nsubparagraph 4552(d)(IV).\n(VIII) The utility shall provide project-level information consistent with the\nrequirements in paragraph 4553(c) for all projects with an expected\nconstruction start date during the gas infrastructure plan action period and\nthe gas infrastructure plan informational period, where available. For\nplanned projects in the gas infrastructure plan informational period where\nproject-level information is not available, category-level specificity\nconsistent with subparagraph 4553(a)(III) is acceptable.\n\n(IX) The utility shall provide the then-current peak design temperature\nassigned to unique segments of the utility system used for capacity\nplanning, and data to support such design temperature(s).\n(b) Forecast requirements.\n(I) The utility shall present reference, low, and high forecasts of design peak\ndemand, customer count, sales and capacity requirements, gas content\nincluding expected mixtures by volume of hydrogen and recovered\nmethane, and system-wide greenhouse gas emissions, consistent with the\nutility’s approved portfolio of clean heat resources and in accordance with\nsubparagraph 4731(b)(I), or any appropriate interim-year update to such\nforecasts in accordance with subparagraph 4733(a)(VI).\n(II) If a utility filed a small utility clean heat plan in accordance with rule 4734,\nthe utility shall justify and document the data, assumptions, models, and\nother inputs upon which it relied to develop this gas infrastructure plan. A\nutility filing under this rule shall indicate how its forecast incorporates, to\nthe extent practicable, relevant external factors including, but not limited\nto:\n(A) the effect of current or enacted state and local building codes;\n(B) changes in the utility’s line extension policies, and the associated\nimpact on gas customer growth;\n(C) building electrification programs or incentives offered by the local\nelectric utility or local or federal entities that overlap with the utility’s\ngas service territory; and\n(D) the price elasticity of demand (e.g., the impact of reduced\nthroughput and rate increases on sales and peak demand\nrequirements and impacts of commodity prices).\n(c) Planned project information.\n(I) The utility shall present the following project-specific information for all\nplanned projects in the gas infrastructure plan total period, with\ninformation provided to the extent practicable for projects in the gas\ninfrastructure plan informational period:\n(A) project name;\n(B) project category, consistent with the categories defined in\nsubparagraph 4553(a)(III), or otherwise identified and justified by\nthe utility;\n\n(C) general scope of work and explanation of need for the project,\nincluding any applicable U.S. Department of Transportation\nPipeline and Hazardous Materials Safety Administration code\nrequirements for the project;\n(D) projected life of the project;\n(E) if the project is presented as a gas infrastructure plan action period\nproject or a gas infrastructure plan informational period project;\n(F) anticipated construction start date, construction period, with any\nphases indicated, and expected in-service date;\n(G) the cost estimate classification using the utility’s or an industry-\naccepted cost estimate classification index, and support of the\nmethodology;\n(H) project technical details, such as physical equipment characteristics\nof proposed facilities, pipeline length, pipeline diameter, project\nmaterial(s), and maximum allowable operating pressure;\n(I) total project cost estimate and a presentation of the associated\nannual revenue requirements for the project during the gas\ninfrastructure plan total period, assuming both conventional\ndepreciation and accelerated depreciation in accordance with the\nforecasts submitted or developed pursuant to paragraph 4553(b);\n(J) the project location and an illustrative map of the facilities (subject\nto necessary and appropriate confidentiality provisions) including:\n(i) the pressure district or geographic area that requires the\nproposed facilities;\n(ii) the existing and proposed regulator stations and existing and\nproposed distribution piping and higher capacity pipelines\nserved by or representing the proposed facilities;\n(iii) the locations of any disproportionately impacted community;\n(iv) identification of the electric utility service provider(s) at that\nlocation; and\n(v) any other information necessary to allow the Commission to\nmake a thorough evaluation.\n(K) to the extent practicable, the number of customers, annual sales,\nand design peak demand requirements, by customer class, directly\nimpacted or served by the project;\n\n(L) permit(s) required to begin work, if any;\n(M) environmental requirements associated with completion of project,\nif any;\n(N) the change in projected greenhouse gas emissions due to the\nplanned project;\n(O) the status of the planned projects as addressed in previous plans,\nas well as changes, additions or deletions in the current plan when\ncompared with prior plans; and\n(P) for a quantity of new business and capacity expansion projects,\ngiven the criteria established by the Commission in accordance\nwith subparagraph 4552(b)(I)(A) through (C), the utility shall\npresent an analysis of alternatives, including non-pipeline\nalternatives, costs for those alternatives, and criteria used to rank\nor eliminate such alternatives.\n(i) An analysis of alternatives shall consider, at a minimum:\n(1) one or more applicable clean heat resources\nconsistent with the utility’s most recently approved\nclean heat plan, pursuant to rule 4732, demand side\nmanagement plan, pursuant to rule 4753, or beneficial\nelectrification plan, as applicable;\n\n(2) a cost-benefit analysis including the costs of direct\ninvestment and the social costs of carbon and\nmethane for emissions due to or avoided by the\nalternative, and other costs determined appropriate by\nthe Commission; and\n(3) available Best Value Employment metrics associated\nwith each alternative, as defined in paragraph\n4211(a), including a projection of gas distribution jobs\naffected by the alternative and jobs made available\nthrough the alternative, opportunities to transition any\naffected gas distribution jobs to the alternative, pay\nand benefit levels of the affected gas distribution jobs\nand the jobs available through a transition\nopportunity, and how employment impacts associated\nwith each alternative could affect disproportionately\nimpacted communities.\n(ii) An analysis of alternatives shall include, at a minimum:\n(1) the technologies or approaches evaluated;\n(2) the technologies or approaches proposed, if\napplicable;\n(3) the projected timeline and annual implementation rate\nfor the technology or approaches evaluated;\n(4) the technical feasibility of the alternative assuming full\nadoption of the technologies and approaches\nevaluated;\n(5) the utility’s strategy to facilitate the technologies or\napproaches evaluated; and\n(6) an explanation of the methodology used to select\nwhich projects are presented with an alternative\nanalysis, including discussion of the public review\nprocess required pursuant to subparagraph\n4552(d)(IV).\n\n(Q) For new business and capacity expansion projects, a utility shall\nprovide an alternative analysis as set forth in subparagraph (c)(I)(P)\nabove or justify why the new business and capacity expansion\nproject is not suitable for an alternative analysis for which the utility\nseeks a certificate of public convenience and necessity or other\nrelief, in accordance with subparagraph 4552(d)(II).\n(R) For system safety and integrity projects, the utility shall provide the\napplicable federal regulation, the planned project’s risk ranking and\nthe utility’s risk ranking methodology including but not limited to the\nmaterial, age, maximum allowable operating pressure, density of\nsurrounding residences and businesses, and any other physical\nand operating characteristics relevant to the risk ranking of the\nplanned project and the risk ranking methodology. The utility should\nalso identify, discuss in detail, and provide the output to any risk-\nrelated models developed or employed by the utility in conducting\nrisk analyses to support planned system safety and integrity\nprojects or other projects.\n(II) With respect to the reference, low and high forecasts conducted pursuant\nto subparagraph 4553(b)(I):\n(A) the total incremental investment that may be needed over the gas\ninfrastructure plan action period and gas infrastructure plan\ninformational period; and\n(B) an identification of the primary individual new projects avoided in\nthe low design peak demand forecast and an identification of the\nprimary individual new projects and capital spend added in the high\ndesign peak demand forecast.\n(d) Existing infrastructure assessment reporting. The utility shall report on the\nfollowing in the gas infrastructure plan.\n(I) The utility shall report the following information regarding customer-owned\nyard lines attached to its distribution system, if applicable:\n(A) an estimate of the number of customer-owned yard lines by\nmunicipality served;\n(B) the number of customer-owned yard lines replaced by the utility to\ndate and capital investment incurred to do so; and\n(C) the estimated gross and net rate-based investment needed to\nreplace all customer-owned yard lines in present dollars through\nyear 2030, through year 2040, and through year 2050.\n\n(II) The utility shall report the following information regarding hydrogen\ncompatibility throughout its distribution system, to the extent known:\n(A) estimate the percentage of distribution system components known\nto be compatible with safely carrying varying concentrations of\nhydrogen, including but not limited to:\n(i) piping;\n(ii) fittings; and\n(iii) non-pipe system components.\n(B) The utility shall identify any areas of the system with unknown\nmaterials or materials known to be not compatible with hydrogen\nmixtures up to 20 percent by volume.\n(III) The utility shall report the following information regarding advanced leak\ndetection:\n(A) identification of equipment, survey method, percentage of system\nsurveyed in each year, and interval in which additional advanced\nleak detection occurred on the same areas of the system;\n(B) any updates to anticipated system-wide methane emissions based\non most recent advanced leak detection surveys; and\n(C) extent to which leakage sources identified are within\ndisproportionately impacted communities.","truncated":false,"body_characters":14877}