170 IAC 4-7-4 - Integrated resource plan contents
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.
Notes
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