Indiana Administrative Code
Title 170 - INDIANA UTILITY REGULATORY COMMISSION
Article 4 - ELECTRIC UTILITIES
Rule 7 - Guidelines for Integrated Resource Planning by an Electric Utility
Section 7-4 - Integrated resource plan contents

Universal Citation: 170 IN Admin Code 7-4

Current through September 18, 2024

Authority: IC 8-1-1-3; IC 8-1-8.5-3

Affected: IC 8-1; IC 8-1.5

Sec. 4.

An IRP must include the following:

(1) At least a twenty (20) year future period for predicted or forecasted analyses.

(2) An analysis of historical and forecasted levels of peak demand and energy usage in compliance with section 5(a) of this rule.

(3) At least three (3) alternative forecasts of peak demand and energy usage in compliance with section 5(b) of this rule.

(4) A description of the utility's existing resources in compliance with section 6(a) of this rule.

(5) A description of the utility's process for selecting possible alternative future resources for meeting future demand for electric service, including a cost-benefit analysis, if performed.

(6) A description of the possible alternative future resources for meeting future demand for electric service in compliance with section 6(b) of this rule.

(7) The resource screening analysis and resource summary table required by section 7 of this rule.

(8) A description of the candidate resource portfolios and the process for developing candidate resource portfolios in compliance with section 8(a) and 8(b) of this rule.

(9) A description of the utility's preferred resource portfolio and the information required by section 8(c) of this rule.

(10) A short term action plan for the next three (3) year period to implement the utility's preferred resource portfolio and its workable strategy, pursuant to section 9 of this rule.

(11) A discussion of the:

(A) inputs;

(B) methods; and

(C) definitions; used by the utility in the IRP.

(12) Appendices of the data sets and data sources used to establish alternative forecasts in section 5(b) of this rule. If the IRP references a third-party data source, the IRP must include for the relevant data:

(A) source title;

(B) author;

(C) publishing address;

(D) date;

(E) page number; and

(F) an explanation of adjustments made to the data.

The data must be submitted within two (2) weeks of submitting the IRP in an editable format, such as a comma separated value or excel spreadsheet file.

(13) A description of the utility's effort to develop and maintain a database of electricity consumption patterns, disaggregated by:

(A) customer class;

(B) rate class;

(C) NAICS code;

(D) DSM program; and

(E) end-use.

(14) The database in subdivision (13) may be developed using, but not limited to, the following methods:

(A) Load research developed by the individual utility.

(B) Load research developed in conjunction with another utility.

(C) Load research developed by another utility and modified to meet the characteristics of that utility.

(D) Engineering estimates.

(E) Load data developed by a non-utility source.

(15) A proposed schedule for industrial, commercial, and residential customer surveys to obtain data on:

(A) end-use penetration;

(B) end-use saturation rates; and

(C) end-use electricity consumption patterns.

(16) A discussion detailing how information from advanced metering infrastructure and smart grid, where available, will be used to enhance usage data and improve load forecasts, DSM programs, and other aspects of planning.

(17) A discussion of the designated contemporary issues designated, if required by section 2.7(e) of this rule.

(18) A discussion of distributed generation within the service territory and its potential effects on:

(A) generation planning;

(B) transmission planning;

(C) distribution planning; and

(D) load forecasting.

(19) For models used in the IRP, including optimization and dispatch models, a description of the model's structure and applicability.

(20) A discussion of how the utility's fuel inventory and procurement planning practices have been taken into account and influenced the IRP development.

(21) A discussion of how the utility's emission allowance inventory and procurement practices for an air emission have been considered and influenced the IRP development.

(22) A description of the generation expansion planning criteria. The description must fully explain the basis for the criteria selected.

(23) A discussion of how compliance costs for existing or reasonably anticipated air, land, or water environmental regulations impacting generation assets have been taken into account and influenced the IRP development.

(24) A discussion of how the utilities' resource planning objectives, such as:

(A) cost effectiveness;

(B) rate impacts;

(C) risks; and

(D) uncertainty; were balanced in selecting its preferred resource portfolio.

(25) A description and analysis of the utility's base case scenario, sometimes referred to as a business as usual case or reference case. The base case scenario is the most likely future scenario and must meet the following criteria:

(A) Be an extension of the status quo, using the best estimate of forecasted electrical requirements, fuel price projections, and an objective analysis of the resources required over the planning horizon to reliably and economically satisfy electrical needs.

(B) Include:
(i) existing federal environmental laws;

(ii) existing state laws, such as renewable energy requirements and energy efficiency laws; and

(iii) existing policies, such as tax incentives for renewable resources.

(C) Existing laws or policies continuing throughout at least some portion of the planning horizon with a high probability of expiration or repeal must be eliminated or altered when applicable.

(D) Not include future resources, laws, or policies unless:
(i) a utility subject to section 2.6 of this rule solicits stakeholder input regarding the inclusion and describes the input received;

(ii) future resources have obtained the necessary regulatory approvals; and

(iii) future laws and policies have a high probability of being enacted. A base case scenario need not align with the utility's preferred resource portfolio.

(26) A description and analysis of alternative scenarios to the base case scenario, including comparison of the alternative scenarios to the base case scenario.

(27) A brief description of the models, focusing on the utility's Indiana jurisdictional facilities, of the following components of FERC Form 715:

(A) The most current power flow data models, studies, and sensitivity analysis.

(B) Dynamic simulation on its transmission system, including interconnections, focused on the determination of the performance and stability of its transmission system on various fault conditions. The description must state whether the simulation meets the standards of the North American Electric Reliability Corporation (NERC).

(C) Reliability criteria for transmission planning as well as the assessment practice used. This description must include the following:
(i) The limits of the utility's transmission use.

(ii) The utility's assessment practices developed through experience and study.

(iii) Operating restrictions and limitations particular to the utility.

(28) A list and description of the methods used by the utility in developing the IRP, including the following:

(A) For models used in the IRP, the model's structure and reasoning for its use.

(B) The utility's effort to develop and improve the methodology and inputs, including for its:
(i) load forecast;

(ii) forecasted impact from demand-side programs;

(iii) cost estimates; and

(iv) analysis of risk and uncertainty.

(29) An explanation, with supporting documentation, of the avoided cost calculation for each year in the forecast period, if the avoided cost calculation is used to screen demand-side resources. The avoided cost calculation must reflect timing factors specific to the resource under consideration such as project life and seasonal operation. The avoided cost calculation must include the following:

(A) The avoided generating capacity cost adjusted for transmission and distribution losses and the reserve margin requirement.

(B) The avoided transmission capacity cost.

(C) The avoided distribution capacity cost.

(D) The avoided operating cost, including:
(i) fuel cost;

(ii) plant operation and maintenance costs;

(iii) spinning reserve;

(iv) emission allowances;

(v) environmental compliance costs; and

(vi) transmission and distribution operation and maintenance costs.

(30) A summary of the utility's most recent public advisory process, including the following:

(A) Key issues discussed.

(B) How the utility responded to the issues.

(C) A description of how stakeholder input was used in developing the IRP.

(31) A detailed explanation of the assessment of demand-side and supply-side resources considered to meet future customer electricity service needs.

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