TITLE 170 INDIANA UTILITY REGULATORY COMMISSION
Final Rule
LSA Document #18-127(F)
DIGEST
Amends
170 IAC 4-7-1,
170 IAC 4-7-2,
170 IAC 4-7-3,
170 IAC 4-7-4,
170 IAC 4-7-5,
170 IAC 4-7-6,
170 IAC 4-7-7,
170 IAC 4-7-8, and
170 IAC 4-7-9, and adds
170 IAC 4-7-0.5,
170 IAC 4-7-2.1,
170 IAC 4-7-2.2,
170 IAC 4-7-2.3,
170 IAC 4-7-2.5,
170 IAC 4-7-2.6,
170 IAC 4-7-2.7, and
170 IAC 4-7-10 to update the commission's rule requiring electric utilities to prepare and submit integrated resource plans. Amends
170 IAC 4-8-1,
170 IAC 4-8-2,
170 IAC 4-8-3,
170 IAC 4-8-4,
170 IAC 4-8-5,
170 IAC 4-8-6,
170 IAC 4-8-7, and
170 IAC 4-8-8, and adds
170 IAC 4-8-0.5 and
170 IAC 4-8-7.5 to update the commission's rule regarding utilities' energy efficiency plans and demand response programs. Effective 30 days after filing with the Publisher.
Authority:
IC 8-1-1-3;
IC 8-1-8.5-3
Sec. 0.5. (a) The purpose of this rule is to provide the specific requirements for submission of utilities' integrated resource plans required by IC 8-1-8.5-3(e).
(b) This rule applies to a utility, as defined in this rule, unless otherwise noted.
(Indiana Utility Regulatory Commission; 170 IAC 4-7-0.5; filed Dec 5, 2018, 11:49 a.m.: 20190102-IR-170180127FRA)
Authority:
IC 8-1-1-3;
IC 8-1-8.5-3
Sec. 1. (a) As used in this rule, "allowance" or "emission allowance" means the authority to emit one (1) ton of sulfur dioxide (SO2), as defined under Section 7651 of the Clean Air Act Amendments of 1990, 42 U.S.C. 7401 to 7671q, effective November 15, 1990. The definitions in this section apply throughout this rule.
(b) As used in this rule, "Avoided cost" means the amount of fuel, operation, maintenance, purchased power, labor, capital, taxes, and other incremental or marginal cost to a utility of energy or capacity, or both, not incurred by a utility if an alternative supply supply-side resource or demand-side resource is included in the utility's integrated resource plan. IRP.
(c) As used in this rule, "Clean Air Act Amendments of 1990" or "CAAA" means Title IV, Acid Deposition Control, of the federal Clean Air Act Amendments of 1990, 42 U.S.C. 7401 to 42 U.S.C. 7671q, in effect November 15, 1990.
(c) "Candidate resource portfolio" means one (1) of multiple long term resource portfolios selected for further evaluation through the utility's portfolio screening process to determine the preferred resource portfolio.
(d)
As used in this rule, "Cogeneration facility" means the following:
(1) A facility that:
(A) simultaneously generates electricity and useful thermal energy; and
(B) meets the energy efficiency standards established for a cogeneration facility by the Federal Energy Regulatory Commission (FERC) under 16 U.S.C. 824a-3. in effect November 9, 1978.
(2) The land, system, building, or improvement
that is if:
(A) located at the project facility site; and is
(B) necessary or convenient to the:
(i) construction;
(ii) completion; or
(iii) operation;
of the facility.
(3) The transmission or distribution facility facilities necessary to conduct the energy produced by the facility to a user located at or near the project site.
(e) As used in this rule, "Commission" means the Indiana utility regulatory commission.
(f) As used in this rule, "conservation" means reducing the amount of energy consumed by a customer for a specific end-use. Conservation includes behavior changes such as thermostat setback. Conservation does not include changing the timing of energy use, switching to another fossil fuel source, or increasing off-peak usage.
(g) As used in this rule, "demand-side management" or "DSM" means the planning, implementation, and monitoring of a utility activity designed to influence customer use of electricity that produces a desired change in a utility's load shape. DSM includes only an activity that involves deliberate intervention by a utility to alter load shape.
(h) As used in this rule, "demand-side measure" means a particular end-use device, technology, service, or rate design at a targeted customer's premises or a utility's energy delivery system for a specific DSM program.
(i) As used in this rule, "demand-side program" means a utility program designed to implement a demand-side measure.
(f) "Commission analysis" means the required state energy analysis developed by the commission under IC 8-1-8.5-3.
(g) "Contemporary issue" means a topic that may affect an IRP's inputs, methods, or judgment factors, and is common to the utilities. Topics may include, but are not limited to, those relevant to the following considerations:
(1) Economic.
(2) Financial.
(3) Environmental.
(4) Energy.
(5) Demographic.
(6) Customer.
(7) Methodological.
(8) Regulatory.
(9) Technological.
(h) "Demand-side management program" or "DSM program" means a utility program designed to implement:
(1) demand response; or
(2) energy efficiency.
(i) "Demand response" means a reduction in electricity usage for limited intervals of time, such as during peak electricity usage or emergency conditions.
(j) As used in this rule, "Demand-side resource" means a resource that reduces the demand for electrical power or energy by applying a demand-side program to implement one (1) or more demand-side measures. management programs.
(k)
As used in this rule, "discount rate" "Director" means
an employee of the
interest rate used in determining commission designated as the
present value of future cash flows. IRP director by the commission's agency head appointed under IC 8-1-1-2(d).
(l) As used in this rule, "dispersed "Distributed generation" means electric generation technology that is relatively small in size, and its implementation favors installation an electrical generating facility located at or near a load center or remote location on the subtransmission or distribution customer's point of use, which may be connected in parallel operation to the utility system.
(m) "DSM costs" refers to the expenses incurred by a utility in a given year for operation of a DSM program, whether the cost is capitalized or expensed. Expenses include, but are not limited to, the following:
(1) Administration.
(2) Equipment.
(3) Incentives paid to program participants.
(4) Marketing and advertising.
(5) Evaluation, measurement, and verification.
(n) "Emission allowance" means the authority to emit one (1) unit of an air pollutant as specified by a federal or state regulatory system.
(m) As used in this rule, (o) "End-use" means the:
(1) light;
(2) heat;
(3) cooling;
(4) refrigeration;
(5) motor drive;
(6) microwave energy;
(7) video or audio signal;
(8) computer processing;
(9) electrolytic process; or other
(10) useful work;
produced by equipment using electricity.
(n) As used in this rule, (p) "Energy efficiency" improvement" means reduced energy use for a comparable or improved level of energy service.
(o) As used in this rule, (q) "Energy service" means the:
(1) light;
(2) heat;
(3) motor drive; and
(4) other service;
for which a customer purchases electricity from the utility.
(r) "Energy storage" means a:
(1) technology; or
(2) set of technologies;
capable of storing generated energy and discharging that energy as electricity at a later time.
(p) As used in this rule, (s) "Engineering estimate" means an a calculated estimate of the change in energy (kWh) and demand (kW) impact resulting from a demand-side measure based on an engineering calculation procedure. An engineering estimate addresses change in energy use of a building or system resulting from installation of a DSM measure. If multiple DSM measures are installed, an engineering estimate accounts for the interactive effect program, accounting for dynamic interactions between or among the DSM measures. programs.
(t) "FERC Form 715" means the annual transmission planning and evaluation report required by the FERC, as adopted in 58 FR 52436, Oct. 8, 1993, and as amended by Order 643, 68 FR 52095, Sep. 2, 2003.
(q) As used in this rule, (u) "Firm wholesale power sale" means a power sale intended to be available to the purchaser at all times, including under adverse conditions, during the period covered by the commitment.
(r) As used in this rule, "hourly system lambda" means the change in a utility's total cost associated with a marginal change in hourly load. The hourly system lambda is a short run measure that reflects the change in fuel cost and includes incremental (or decremental) operation and maintenance expenses.
(s) As used in this rule, (v) "Integrated resource
planning", plan" or "IRP" means a utility's
assessment of a variety of demand-side and supply-side resources document or documents submitted to
cost-effectively the commission to meet
customer electricity service needs. The IRP may also include, but is not limited to, the following: the requirements of this rule.
(1) A public participation procedure.
(2) An analysis of the uncertainty and risk posed by different resources and external factors.
(t) As used in this rule, "load building" means a program intended to increase electricity consumption without regard to the timing of the increased usage.
(u) As used in this rule, (w) "Load research" means the collection of electricity usage data through a metering device associated with an end-use, a circuit, or a building. The metered data is used to better understand the characteristics of electric loads, the timing of their use, and the amount of electricity consumed by users. The data may be collected over a variety of time intervals, usually sixty (60) minutes or less.
(v) As used in this rule, (x) "Load shape" means the time pattern of customer electricity use and the relationship of the level of energy use to a specific time during the day, month, and year.
(w) As used in this rule, "lost opportunity" means a situation where a cost-effective demand-side measure could have been installed at a site during construction, renovation, or replacement of equipment, but was not, rendering a subsequent equal or more extensive modification to the site not cost-effective.
(x) As used in this rule, "non-utility generator" or "NUG" means a facility for generating electricity that:
(1) is not exclusively owned by a public utility;
(2) operates connected to an electric utility system; and
(3) sells electricity to a utility for resale to retail customers.
(y) As used in this rule, "participant" means a utility customer participating in a utility-sponsored DSM program.
(z) As used in this rule, "participant test" means a cost-effectiveness test that measures the difference between the cost incurred by a participant in a demand-side program and the value received by the participant. A participant's cost includes all costs borne by the participant. A participant's value from a DSM program consists of only the direct economic benefit received by the participant.
(y) "North American Industrial Classification System" or "NAICS" refers to the system developed by the United States Department of Commerce for use in the classification of establishments by type of activity in which a business is engaged.
(z) "OUCC" means the Indiana office of utility consumer counselor.
(aa) As used in this rule, "Penetration" means the ratio of the number of a specific type of new units appliances or end-use equipment installed to the total number of new units installed during a given time.
(bb) As used in this rule, "present value" means today's value of a future payment, or stream of payments, discounted at some appropriate compound interest or discount rate.
(cc) As used in this rule, "program cost" means all expenses incurred by a utility in a given year for operation of a DSM program whether the cost is capitalized or expensed. An expense includes, but is not limited to, the following:
(1) Administration.
(2) Equipment.
(3) Incentives paid to program participants.
(4) Marketing and advertising.
(5) Monitoring and evaluation.
(dd) As used in this rule, "public participation" means a procedure where a customer or interested party is provided the opportunity to comment on a utility's integrated resource plan prior to the submission of the IRP to the commission.
(ee) As used in this rule, "ratepayer impact measure" or "RIM" test means a cost-effectiveness test which analyzes how a rate for electricity is altered by implementing a DSM program. This test measures the change in a revenue requirement expressed on a per unit of sale basis.
(ff) As used in this rule, "renewable resource" means a generation facility or technology utilizing a fuel source such as, but not limited to, the following:
(1) Wind.
(2) Solar.
(3) Geothermal.
(4) Waste.
(5) Biomass.
(6) Small hydro.
(bb) "Power transfer capability" means the amount of power that can be transferred from one (1) point or part of the bulk electric system to another without exceeding a reliability criteria pertinent to the utility.
(gg) As used in this rule, (cc) "Preferred resource portfolio" means a facility, project, contract, or other mechanism used by a utility to provide the utility's selected long term supply-side and demand-side resource mix that safely, reliably, efficiently, and cost-effectively meets the electric energy service to the customer. system demand, taking cost, risk, and uncertainty into consideration.
(dd) "Present value" means the current value of a future sum or stream of money, calculated by discounting the sum or stream of money by an interest rate.
(ee) "Program participant" means a utility customer participating in a DSM program.
(ff) "Public advisory process" refers to the procedures in sections 2.1 and 2.6 of this rule in which customers and interested parties have the opportunity to:
(1) receive information from the utilities;
(2) provide input for the utility to consider in the development of the IRP; and
(3) comment on a utility's IRP.
(gg) "Regional transmission organization" or "RTO" means the regional transmission organization approved by the Federal Energy Regulatory Commission for the control area that includes the utility's assigned service area as defined under IC 8-1-2.3-2.
(hh) "Renewable resource" means a renewable energy resource as defined in IC 8-1-8.8-10.
(ii) "Resource" means a:
(1) facility;
(2) project;
(3) contract; or
(4) mechanism;
used by a utility to assist in providing electric energy service to the customer.
(jj) "Resource action" means a resource change or addition proposed by a utility in a formally docketed commission proceeding.
(kk) "Risk metric" means a measure used to gauge the risk associated with a resource portfolio. As applied to the cost of a resource portfolio, risk metric includes measures of the variability of costs and the magnitude of outcomes.
(hh) As used in this rule, (ll) "Saturation" means the ratio of the number of a specific type of similar appliance appliances or end-use equipment to the total number of customers in that class or the total number of similar appliances or end-use equipment in use.
(ii) As used in this rule, (mm) "Screening" means an evaluation performed by a utility to determine whether a demand-side or supply-side resource option is eligible for potential inclusion in the utility's integrated preferred resource plan. portfolio.
(jj) As used in this rule "self-generation" means an electric generation facility primarily for the customer's own use and not for the primary purpose of producing electricity, heat, or steam for sale to or for the public for compensation.
(kk) As used in this rule, (nn) "Short term action plan" means a schedule of activities and goals developed by a utility to begin efficient implementation of its integrated resource plan. preferred resource portfolio as required by section 4(10) of this rule.
(ll) As used in this rule, "standard industrial classification" or "SIC" means a system developed by the United States Department of Commerce for use in the classification of establishments by type of activity in which engaged, for purposes of facilitating the collection, tabulation, presentation and analysis of data relating to establishments, and for promoting uniformity and comparability in the presentation of statistical data collected by various agencies of the United States Government, state agencies, trade associations, and private research organizations.
(oo) "Smart grid" means use of:
(1) digital electronics;
(2) equipment; or
(3) data;
and the associated communications networks, to monitor and control aspects of the electrical transmission and distribution system from generation to consumption.
(mm) As used in this rule, (pp) "Supply-side resource" means a resource that provides a supply of electrical energy or capacity, or both, to a utility. A supply-side resource includes the following:
(1) A utility-owned generation capacity addition.
(2) A wholesale power purchase. from another utility or non-utility generator.
(3) A refurbishment or upgrading upgrade of an existing utility-owned generating generation facility.
(4) A cogeneration facility.
(5) A renewable resource. technology.
(6) Distributed generation.
(nn) As used in this rule, "targeted demand-side management" or "targeted DSM" means a demand-side program designed to defer or eliminate investment in a transmission or distribution facility.
(oo) As used in this rule, "total resource cost test" means a cost-effectiveness test that eliminates the distinction between a participant and nonparticipant by analyzing whether a resource is cost-effective based on the total cost and benefit of the program, independent of the precise allocation to a shareholder, ratepayer, and participant.
(pp) As used in this rule, (qq) "Utility" means:
(1) a public, municipally owned, or cooperatively owned electric utility; or
(qq) As used in this rule, "utility cost test" or "revenue requirements test" means a cost-effectiveness test designed to minimize the net present value of a utility's revenue requirements.
(Indiana Utility Regulatory Commission; 170 IAC 4-7-1; filed Aug 31, 1995, 9:00 a.m.: 19 IR 16; readopted filed Jul 11, 2001, 4:30 p.m.: 24 IR 4233; readopted filed Apr 24, 2007, 8:21 a.m.: 20070509-IR-170070147RFA; readopted filed Aug 2, 2013, 2:16 p.m.: 20130828-IR-170130227RFA; filed Dec 5, 2018, 11:49 a.m.: 20190102-IR-170180127FRA)
170 IAC 4-7-2 Integrated resource plan submission
Authority:
IC 8-1-1-3;
IC 8-1-8.5-3
Sec. 2.
(a) The commission may use an IRP or written comments, or both, submitted pursuant to this rule, to assist in the preparation of an analysis of the long range needs for expansion of facilities for the generation of electricity and plan for meeting the future requirements of electricity as required by IC 8-1-8.5. The commission may also use the IRP or written comments, or both, submitted pursuant to this rule in the preparation of a staff report in other formally docketed proceedings.
(1) An IRP or written comments submitted to the commission pursuant to this rule may be admitted as evidence in a formally docketed proceeding before the commission under the Indiana Rules of Evidence.
(2) The commission shall give such weight as it determines appropriate to any IRP, or written comments submitted to the commission thereon, admitted as evidence in a formally docketed proceeding as provided in subsection 2(a)(1) above.
(3) An IRP or comments submitted pursuant to this rule may not be admitted as evidence in a formally docketed proceeding before the commission through use of 170 IAC 1-1-18(f).
(b) Notice of the submission of an IRP to the commission shall be provided pursuant to the publication requirements of IC 8-1-1-8.
(a) The following utilities, or their successors in interest, shall submit to the commission an IRP consistent with this rule according to the following schedule:
(1) By November 1, 2017, and every three (3) years thereafter:
(A) Indiana Municipal Power Agency;
(B) Hoosier Energy Rural Electric Cooperative; and
(C) Wabash Valley Power Association.
(2) By November 1, 2018, and every three (3) years thereafter:
(A) Duke Energy Indiana; and
(B) Indiana Michigan Power Company.
(3) By November 1, 2019, and every three (3) years thereafter:
(A) Indianapolis Power & Light Company;
(B) Northern Indiana Public Service Company; and
(C) Southern Indiana Gas and Electric Company.
(b) Upon request of a utility, the director may grant an extension of a submission deadline, for good cause shown.
(c) On or before the applicable date, a utility subject to subsection (a) or (b) must submit electronically to the director or through an electronic filing system if requested by the director, the following documents:
(1) The IRP.
(2) A technical appendix containing supporting documentation sufficient to allow an interested party to evaluate the data and assumptions in the IRP. The technical appendix shall include at least the following:
(A) The utility's energy and demand forecasts and input data used to develop the forecasts.
(B) The characteristics and costs per unit of resources examined in the IRP.
(C) Input and output files from capacity planning models, in electronic format.
(D) For each portfolio, the electronic files for the calculation of the revenue requirement if not provided as an output file.
If a utility does not provide the above information, it shall include a statement in the technical appendix specifying the nature of the information it is omitting and the reason necessitating its omission. The utility may request confidential treatment of the technical appendix under section 2.1 of this rule.
(3) An IRP summary that communicates core IRP concepts and results to nontechnical audiences in a simplified format using visual elements where appropriate. The IRP summary shall include, but is not limited to, the following:
(A) A brief description of the utility's:
(i) existing resources;
(ii) preferred resource portfolio;
(iii) key factors influencing the preferred resource portfolio;
(iv) short term action plan;
(v) public advisory process; and
(vi) additional details requested by the director.
(B) A simplified discussion of the utility's resource types and load characteristics.
The utility shall make the IRP summary readily accessible on its website.
(c) (d) Contemporaneously with the submission of an IRP
to the commission, under this section, a utility
must include shall provide to the director the following information:
(1) The name and address if of known of each individual individuals or entity entities considered by the utility to be an interested party. parties.
(2) A statement that the utility has sent
each known interested
party, parties, electronically or by deposit in the United States mail, first class postage prepaid, a notice of the utility's submission of
an the IRP to the commission. The notice must
contain, at a minimum, include the following information:
(A) A general description of the subject matter of the submitted IRP.
(B) A statement that the commission invites an interested party parties to submit written comment comments on the utility's submitted IRP within ninety (90) days of the IRP submittal.
(C) A statement An interested party includes a business, organization, or particular customer that
participated in the
commission will provide notice of the IRP and the due date for the submission of written utility's previous public advisory process or submitted comments
pursuant to the publication requirements of IC 8-1-1-8. The statement must also include that subsection (e) below provides for a ninety (90) day time period, or longer as determined by the commission, to submit written comments. on the utility's previous IRP.
A utility is not required to separately notice, as provided in this subsection, each of its notify other customers. A utility may, however, individually notify a business, organization, or a particular customer having a substantial interest in the IRP.
(3) A statement that the utility has served a copy of the IRP on the office of the consumer counselor. documents submitted under subsection (c) on the OUCC.
(d) An IRP submitted to the commission may be viewed, inspected, or copied, in accordance with IC 5-14-3, at the office of the commission at 101 West Washington Street, Suite 1500 E, Indianapolis, Indiana 46204.
(e) A customer or interested party may comment on an IRP submitted to the commission. The comments must be in writing and received by the commission within ninety (90) days from the date a utility submits an IRP to the commission. A customer or interested party must:
(1) submit to the commission, at the address provided in subsection (d), an original and eight (8) copies of the written comments;
(2) clearly identify the utility upon which written comments are submitted; and
(3) when submitting written comments on an IRP, serve a copy of the comments upon the utility.
The commission may extend the filing deadline for submitting written comments.
(f) Upon the receipt of written comments of a customer or interested party, a utility may submit to the commission supplemental or response comments. Supplemental or response comments must be in writing and received by the commission within thirty (30) days from the date a customer or interested party submits comments to the commission. A utility must:
(1) submit to the commission, at the address provided in subsection (d), an original and eight (8) copies of the supplemental or response comments; and
(2) serve a copy of the supplemental or response comments upon the customer or interested party who submitted written comments and the office of the consumer counselor.
The commission may extend the filing deadline for submitting supplemental or response comments.
(g) The commission may allow additional written comment periods.
(h) The failure of an interested party to file comments pursuant to subsection (e) shall not constitute a waiver of any right to participate as a party or to advance any argument or position in a formally docketed proceeding before the commission. Similarly, the content of comments filed by an interested party under subsection (e) shall not estop or preclude that party from advancing any argument or position in a formally docketed proceeding before the commission, whether or not that argument or position was raised in comments submitted under subsection (e).
(Indiana Utility Regulatory Commission; 170 IAC 4-7-2; filed Aug 31, 1995, 9:00 a.m.: 19 IR 18; readopted filed Jul 11, 2001, 4:30 p.m.: 24 IR 4233; readopted filed Apr 24, 2007, 8:21 a.m.: 20070509-IR-170070147RFA; errata filed Jul 21, 2009, 1:33 p.m.: 20090819-IR-170090571ACA; readopted filed Aug 2, 2013, 2:16 p.m.: 20130828-IR-170130227RFA; filed Dec 5, 2018, 11:49 a.m.: 20190102-IR-170180127FRA)
Authority:
IC 8-1-1-3;
IC 8-1-8.5-3
Sec. 2.1. (a) In an instance where a utility or interested party is required to or wishes to submit to the director information or documents a utility or interested party reasonably believes should be exempt from public access under IC 5-14-3, the utility or interested party may instead, on the applicable date, do the following:
(1) Submit a public version of the IRP, comment, or other submission with information the submitting party believes is exempt from public disclosure under IC 5-14-3 omitted or redacted.
(2) Concurrently with the submission of the public version under subdivision (1), file a petition for confidential treatment with the commission in accordance with the procedural rules in 170 IAC 1-1.1.
(b) Information the commission determines shall be exempt from public disclosure shall be provided to the commission under the commission's procedural rules or based on a commission order.
(c) Nothing in this section prohibits a utility or interested party from sharing information with each other subject to a mutual agreement concerning confidentiality.
(Indiana Utility Regulatory Commission; 170 IAC 4-7-2.1; filed Dec 5, 2018, 11:49 a.m.: 20190102-IR-170180127FRA)
170 IAC 4-7-2.2 Public comments and director's reports
Authority:
IC 8-1-1-3;
IC 8-1-8.5-3
Sec. 2.2. (a) A customer or interested party may comment on an IRP submitted to the commission. A comment must:
(1) be in writing;
(2) be received by the commission within ninety (90) days from the date a utility submits its IRP to the commission;
(3) be electronically submitted to the director unless otherwise agreed by the director;
(4) clearly identify the utility upon which written comments are submitted; and
(5) be provided to the utility using the utility contact information provided in the IRP.
(b) The director shall issue a draft report on the IRP no later than one hundred fifty (150) days from the date a utility submits its IRP to the commission.
(c) Supplemental or response comments may be submitted by:
(1) the utility;
(2) a customer; or
(3) an interested party.
(d) Supplemental or response comments must be:
(1) in writing;
(2) received by the commission within thirty (30) days from the date the director issues the draft report;
(3) electronically submitted to the director or submitted through an electronic filing system if requested by the director; and
(4) provided to:
(A) the utility;
(B) each customer or interested party that submitted written comments; and
(C) the OUCC.
(e) The director may allow additional written comment periods or extend the submission deadline for written comments or supplemental or response comments by notifying the utility and posting notice on the commission's website.
(f) The director shall issue a final report on the IRP within thirty (30) days following the deadline for supplemental or response comments.
(g) The draft report and the final report shall:
(1) be limited to commenting on the IRP's compliance with the requirements of this rule;
(2) list the areas where the director believes the IRP fails to comply with the requirements of this rule; and
(3) not comment on:
(A) the desirability of the utility's preferred resource portfolio; or
(B) a proposed resource action in the IRP.
(h) The director may extend the deadlines for issuance of the draft report and the final report by notifying the utility and posting notice on the commission's website.
(i) Failure by the director to issue a draft or final report by the applicable deadline shall result in a presumption that the IRP complies with this rule.
(j) Subject to a determination by the commission under section 2.1 of this rule, the commission shall make publicly available on the commission's website or other electronic document system the following:
(1) The utilities' IRPs.
(2) Updates to the utilities' IRPs under section 10 of this rule.
(3) Written comments.
(4) Supplementary and responsive comments.
(5) The director's draft report.
(6) The director's final report.
(Indiana Utility Regulatory Commission; 170 IAC 4-7-2.2; filed Dec 5, 2018, 11:49 a.m.: 20190102-IR-170180127FRA)
170 IAC 4-7-2.3 Resource adequacy assessment report
Authority:
IC 8-1-1-3;
IC 8-1-8.5-3
Sec. 2.3. (a) A utility listed in section 2(a) of this rule shall provide to the director and the OUCC the annual resource adequacy assessment reported to an RTO within twenty-five (25) days of the date reported or as otherwise agreed by the director.
(b) A utility providing the information required in subsection (a) shall explain major differences between the information provided under subsection (a) and the utility's most recent IRP, such as significant changes in the timing of capacity additions or retirements.
(Indiana Utility Regulatory Commission; 170 IAC 4-7-2.3; filed Dec 5, 2018, 11:49 a.m.: 20190102-IR-170180127FRA)
170 IAC 4-7-2.5 Effects of integrated resource plans in docketed proceedings
Authority:
IC 8-1-1-3;
IC 8-1-8.5-3
Sec. 2.5. (a) An interested party that does not file comments under this rule may still participate as a party or advance an argument or position in a formally docketed proceeding before the commission. Similarly, the content of comments filed by an interested party under this rule shall not preclude an interested party from advancing an argument or position in a formally docketed proceeding before the commission, whether or not that argument or position was raised in comments submitted under this rule.
(b) When a utility takes a resource action, it shall be consistent with the most recent IRP submitted under this rule, including its:
(1) inputs;
(2) data and assumptions;
(3) methods;
(4) models;
(5) judgment factors; and
(6) rationales used to determine inputs, methods, and risk metrics;
unless differences between the most recent IRP and the resource action are fully explained and justified with supporting evidence, including an updated IRP analysis.
(c) Documents submitted to the commission or created pursuant to this rule may be used as follows:
(1) To assist the commission in the preparation of the commission analysis.
(2) In the preparation of a commission staff report in formally docketed proceedings before the commission.
(3) In a formally docketed proceeding before the commission if admitted into evidence.
(Indiana Utility Regulatory Commission; 170 IAC 4-7-2.5; filed Dec 5, 2018, 11:49 a.m.: 20190102-IR-170180127FRA)
Authority:
IC 8-1-1-3;
IC 8-1-8.5-3
Sec. 2.6. (a) The following utilities are exempt from this section:
(1) Indiana Municipal Power Agency.
(2) Hoosier Energy Rural Electric Cooperative.
(3) Wabash Valley Power Association.
(b) The utility shall provide information requested by an interested party relating to the development of the utility's IRP within fifteen (15) business days of a written request or as otherwise agreed to by the utility and the interested party. If a utility is unable to provide the requested information within fifteen (15) business days or the agreed time frame, it shall provide a statement to the director and the requestor as to the reason it is unable to provide the requested information.
(c) The utility shall solicit, consider, and timely respond to relevant input relating to the development of the utility's IRP provided by:
(1) interested parties;
(2) the OUCC; and
(3) commission staff.
(d) The utility retains full responsibility for the content of its IRP.
(e) The utility shall conduct a public advisory process as follows:
(1) Prior to submitting its IRP to the commission, the utility shall hold at least three (3) meetings, a majority of which shall be held in the utility's service territory. The topics discussed in the meetings shall include, but not be limited to, the following:
(A) An introduction to the IRP and public advisory process.
(B) The utility's load forecast.
(C) Evaluation of existing resources.
(D) Evaluation of supply-side and demand-side resource alternatives, including:
(i) associated costs;
(ii) quantifiable benefits; and
(iii) performance attributes.
(E) Modeling methods.
(F) Modeling inputs.
(G) Treatment of risk and uncertainty.
(H) Discussion seeking input on its candidate resource portfolios.
(I) The utility's scenarios and sensitivities.
(J) Discussion of the utility's preferred resource portfolio and the utility's rationale for its selection.
(2) The utility may hold additional meetings.
(3) The schedule for meetings shall:
(A) be determined by the utility;
(B) be consistent with its internal IRP development schedule; and
(C) provide an opportunity for public participation in a timely manner so that it may affect the outcome of the IRP.
(4) The utility or its designee shall:
(A) chair the participation process;
(B) schedule meetings;
(C) develop and publish to its website agendas and relevant material for those meetings at least seven (7) calendar days prior to the meeting; and
(D) develop and publish to its website meeting minutes within fifteen (15) calendar days following the meeting.
(5) Interested parties may request that relevant items be placed on the agenda of the meetings if they provide adequate notice to the utility.
(6) The utility shall take reasonable steps to notify:
(A) its customers;
(B) the commission;
(C) interested parties; and
(D) the OUCC;
of its public advisory process.
(Indiana Utility Regulatory Commission; 170 IAC 4-7-2.6; filed Dec 5, 2018, 11:49 a.m.: 20190102-IR-170180127FRA)
170 IAC 4-7-2.7 Contemporary issues technical conference
Authority:
IC 8-1-1-3;
IC 8-1-8.5-3
Sec. 2.7. (a) The commission or its staff may host an annual technical conference to facilitate:
(1) identifying contemporary issues;
(2) identifying best practices to manage contemporary issues; and
(3) instituting a standardized IRP format.
(b) The agenda of the technical conference shall be set by the commission staff.
(c) Utilities, the OUCC, and interested parties may request commission staff include specific contemporary issues and presenters.
(d) The director may designate specific contemporary issues for utilities to address in the next IRPs by providing the utilities and interested parties with a list of the contemporary issues to be addressed.
(e) Utilities shall discuss the designated contemporary issues in the next IRP if the contemporary issues were designated by the director at least one (1) year prior to the submittal date of the utility's IRP.
(Indiana Utility Regulatory Commission; 170 IAC 4-7-2.7; filed Dec 5, 2018, 11:49 a.m.: 20190102-IR-170180127FRA)
170 IAC 4-7-3 Waiver or variance requests
Authority:
IC 8-1-1-3;
IC 8-1-8.5-3
Sec. 3.
(a) To assist the commission in its administration of the Utility Powerplant Construction Law, IC 8-1-8.5, this rule applies to the following:
(1) A public, municipally owned, or cooperatively owned utility.
(2) A joint agency created under IC 8-1-2.2. An individual member of a joint agency is not required to submit to the commission a separate integrated resource plan.
(b) (a) This
rule section does not apply to a
person who is exempt pursuant to IC 8-1-8.5-7. request for extension of time under sections 2(b), 2.2(e), and 2.2(h) of this rule.
(b) A utility may request a variance from a provision of this rule for good cause.
(c) A utility operating or owning, in part or whole, an electrical generating facility as of January 1, 1995, to provide electric service within the state of Indiana must submit to the commission on a biennial basis, beginning on or before November 1, 1995, an integrated resource plan consistent with this rule. Upon request of a utility, the commission may grant an extension of any such submission dates, for good cause shown.
(d) A utility not subject to subsection (c) prior to constructing, purchasing, or leasing a generating facility to provide electric service within the state of Indiana must submit to the commission an integrated resource plan consistent with this rule. If the generating facility, after appropriate commission review, is constructed, purchased, or leased, the utility shall submit to the commission on a biennial basis, an integrated resource plan consistent with this rule.
(e) A utility subject to subsection (a) must submit to the commission, on or before the applicable date as specified in subsection (c) or (d), the following documents:
(1) The integrated resource plan.
(2) A technical appendix containing supporting documentation.
(f) If a utility considers information in the IRP or technical appendix to be proprietary or otherwise confidential, a utility must file concurrently a redacted version, a nonredacted version under seal which shall be treated as confidential pending completion
(c) As follows, a request under this section shall:
(1) Describe the situation that necessitates the variance.
(2) Identify the provision of the proceeding described below, verified affidavits from appropriate representatives this rule for which the variance is requested.
(3) Explain the difference between a denial and an acceptance of the utility setting forth the reasons why the information is proprietary or otherwise confidential, and a petition requesting requested variance on the utility, its customers, and interested parties in the public advisory.
(4) Explain how the variance is expected to aid the implementation of this rule.
(5) Be submitted in sufficient time so that the
commission find that such information is confidential pursuant to IC 8-1-2-29 and IC 5-14-3. A customer or interested party seeking access to or desiring to contest a commission determination IRP submittal schedule shall not be adversely affected.
(d) The director shall respond in writing regarding
information claimed by a utility to be proprietary acceptance or denial of a request under this section within fifteen (15) calendar days. The request shall not be unreasonably denied, and
confidential may do so only through intervention and participation in the proceeding on the utility petition requesting a finding of confidentiality. If, after review, the commission determines the information is proprietary or confidential, the commission and its staff will treat the information as proprietary or confidential in accordance with IC 8-1-2-29 and IC 5-14-3. denials shall include the reason for the denial. If the director fails to respond within fifteen (15) calendar days, the request shall be deemed accepted.
(e) The request by the utility and the director's acceptance or denial shall be posted on the commission's website or other publicly accessible electronic document system.
(f) An interested party may appeal to the full commission the director's acceptance or denial under this section. An appeal to the full commission must be filed with the commission in a docketed proceeding and provided to:
(1) the utility;
(2) the OUCC; and
(3) other interested parties;
within thirty (30) days of the posting of the director's written acceptance or denial of the request.
(Indiana Utility Regulatory Commission; 170 IAC 4-7-3; filed Aug 31, 1995, 9:00 a.m.: 19 IR 19; readopted filed Jul 11, 2001, 4:30 p.m.: 24 IR 4233; readopted filed Apr 24, 2007, 8:21 a.m.: 20070509-IR-170070147RFA; readopted filed Aug 2, 2013, 2:16 p.m.: 20130828-IR-170130227RFA; filed Dec 5, 2018, 11:49 a.m.: 20190102-IR-170180127FRA)
170 IAC 4-7-4 Integrated resource plan contents
Authority:
IC 8-1-1-3;
IC 8-1-8.5-3
Sec. 4. An IRP
covering at must include the following:
(1) At least a twenty (20) year future period prepared by a utility must include a discussion of the methods, models, data, assumptions, for predicted or forecasted analyses.
(2) An analysis of historical and forecasted levels of peak demand and definitions used energy usage in developing 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. and the goals and objectives of the plan. The following information must be included:
(1) The (12) Appendices of the data sets
including and data sources used to establish
base and alternative forecasts
A in section 5(b) of this rule. If the IRP references a third-party data source,
may be presented in the form of a reference. the
reference IRP must include
for the
relevant data:
(A) source title;
(B) author;
(C) publishing address;
(D) date; and
(E) page number; of relevant data. The data sets must include and
(F) an explanation for of adjustments made to the data.
The data must be provided on electronic media and hard copy, or as specified by the commission. submitted within two (2) weeks of submitting the IRP in an editable format, such as a comma separated value or excel spreadsheet file.
(2) (13) A description of the utility's effort to develop and maintain
by a database of electricity consumption patterns, disaggregated by:
(A) customer class;
(B) rate class; SIC
(C) NAICS code;
(D) DSM program; and
(E) end-use. a data base of electricity consumption patterns. The data base
(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.
(3) (15) A proposed schedule for industrial, commercial, and residential customer surveys to obtain data on:
(A) end-use appliance penetration;
(B) end-use saturation rates; and
(C) end-use electricity consumption patterns.
(4) (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 customer self-generation 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
the its potential effects on:
(A) generation planning;
(B) transmission and planning;
(C) distribution planning; and
(D) load forecasting.
(5) A (19) For models used in the IRP, including optimization and dispatch models, a description of model the model's structure and an evaluation of model performance. applicability.
(6) (20) A complete discussion of the alternative forecast scenarios developed and analyzed, including a justification of how the assumptions and modeling variables used in each scenario.
(7) A description of the utility's fuel inventory and procurement planning practices including the rationale, used in the have been taken into account and influenced the IRP development. of the utility's integrated resource plan.
(8) (21) A description discussion of how the SO2 utility's emission allowance inventory and procurement planning practices including the rationale, used in the for an air emission have been considered and influenced the IRP development. of the utility's integrated resource plan.
(9) (22) A description of the generation expansion planning criteria. used in developing the integrated resource plan. The description must fully explain the basis for the criteria selected. including an analysis and rationale for the level of system wide generation reliability assumed in the IRP.
(10) A regional, or at a minimum, Indiana specific power flow study prepared by a regional or subregional organization. This requirement may be met by submitting Federal Energy Regulatory Commission (FERC) Form 715, as adopted in Docket No. RM93-10-00, in effect October 30, 1993. The power flow study shall include the following:
(A) Solved real flows.
(B) Solved reactive flows.
(C) Voltages.
(D) Detailed assumptions.
(E) Brief description of the model(s).
(F) Glossary of terms with cross references to the names of buses and line terminals.
(G) Sensitivity analysis, including, but not limited to, the forecast of the following:
(i) Summer and winter peak conditions.
(ii) Light load as well as heavy transfer conditions for one (1), two (2), five (5), and ten (10) years out.
(iii) Branch circuit ratings, including, but not limited to, normal, long term, short term, and emergency.
(11) Any recent dynamic stability study prepared for the utility or by the utility. This requirement may be met by submitting FERC Form 715, as adopted in Docket No. RM93-10-00, in effect October 30, 1993.
(12) Applicable transmission maps. This requirement may be met by submitting FERC Form 715, as adopted in Docket No. RM93-10-00, in effect October 30, 1993.
(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:
(13) A description of reliability (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 requirement may be met by submitting FERC Form 715, as adopted in Docket No. RM93-10-00, in effect October 30, 1993. 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.
(14) An evaluation of the reliability criteria in relation to present performance and the expected performance of the utility's transmission system. This requirement may be met by submitting FERC Form 715, as adopted in Docket No. RM93-10-00, in effect October 30, 1993.
(15) (28) A
list and description of the
utility's 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
the data for evaluating a resource (supply-side or inputs, including for its:
(i) load forecast;
(ii) forecasted impact from demand-side option's contribution to system wide reliability. The measure of system wide reliability must cover the reliability of the entire system, including transmission, distribution, and generation. programs;
(iii) cost estimates; and
(iv) analysis of risk and uncertainty.
(16) (29) An explanation, with supporting documentation, of the avoided cost calculation
An avoided cost must be calculated 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
shall calculation must include
but is not limited to, 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:
fuel, plant operation and maintenance, spinning reserve, emission allowances, and transmission and distribution operation and maintenance.
(17) The hourly system lambda (i) fuel cost;
(ii) plant operation and the actual demand for all hours 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
historical year available. For purposes of comparison, a public advisory process, including the following:
(A) Key issues discussed.
(B) How the utility must maintain three (3) years of hourly data and the corresponding dispatch logs. responded to the issues.
(18) (C) A description of how stakeholder input was used in developing the utility's public participation procedure if IRP.
(31) A detailed explanation of the utility conducts a procedure prior to the submission of an IRP assessment of demand-side and supply-side resources considered to the commission. meet future customer electricity service needs.
170 IAC 4-7-5 Energy and demand forecasts
Authority:
IC 8-1-1-3;
IC 8-1-8.5-3
Sec. 5. (a)
An electric utility subject to this rule shall prepare an The analysis of historical and forecasted levels of peak demand and energy usage
which includes must include the following:
(1)
An Historical
and projected analysis of a variety of load shapes, including
but not limited to, the following:
(A) Annual load shapes.
(B) Seasonal load shapes.
(C) Monthly load shapes.
(D) Selected weekly and load shapes.
(E) Selected daily load shapes, Daily load shapes which shall include at a minimum, summer and winter peak days, and a typical weekday and weekend day.
(2) Historical and projected load shapes shall be disaggregated, to the extent possible, by customer class, interruptible load, and end-use and demand-side management program.
(3) (2) Disaggregation of historical data and forecasts by:
(A) customer class;
(B) interruptible load; and
(C) end-use;
where information permits.
(4) The use and reporting of actual (3) Actual and weather normalized energy and demand levels.
(5) (4) A discussion of all methods and processes used to weather normalize. for weather.
(6) (5) A minimum twenty (20) year period for peak demand and energy and demand usage forecasts.
(7) (6) An evaluation of the performance of
peak demand and energy
and demand forecasts usage for the previous ten (10) years, including
but not limited to, the following:
(A) Total system.
(B) Customer classes or rate classes, or both.
(C) Firm wholesale power sales.
(7) A discussion of how the impact of historical DSM programs is reflected in or otherwise treated in the load forecast.
(8) If an end-use Justification for the selected forecasting methodology. has not been used in forecasting, an explanation as to why this methodology has not been used.
(9) A discussion of the potential changes under consideration to improve the credibility of the forecasted demand by improving the data quality, tools, and analysis.
(9) (10) For purposes of section 5(a)(1) and 5(a)(2), subdivisions (1) and (2), a utility may use utility specific data or more generic data such as but not limited to, the types of data described in section 4(2) 4(14) of this rule.
(b)
A To establish plausible risk boundaries, the utility shall provide at least three (3) alternative forecasts of peak demand and energy usage
At a minimum, the utility shall include including:
(1) high;
(2) low; and
(3) most probable; energy and
peak demand and energy use forecasts. based on combinations of
(c) In determining the peak demand and energy usage forecast that is deemed by the utility, with stakeholder input, to be most probable, the utility shall consider alternative assumptions such as:
(1) Rate of change in population.
(2) Economic activity.
(3) Fuel prices.
(4) Changes in technology. Price elasticity.
(5) Penetration of new technology.
(6) Demographic changes in population.
(7) Customer usage.
(8) Changes in technology.
(5) (9) Behavioral factors affecting customer consumption.
(6) (10) State and federal energy policies.
(7) (11) State and federal environmental policies.
(Indiana Utility Regulatory Commission; 170 IAC 4-7-5; filed Aug 31, 1995, 9:00 a.m.: 19 IR 21; readopted filed Jul 11, 2001, 4:30 p.m.: 24 IR 4233; readopted filed Apr 24, 2007, 8:21 a.m.: 20070509-IR-170070147RFA; readopted filed Aug 2, 2013, 2:16 p.m.: 20130828-IR-170130227RFA; filed Dec 5, 2018, 11:49 a.m.: 20190102-IR-170180127FRA)
170 IAC 4-7-6 Description of available resources
Authority:
IC 8-1-1-3;
IC 8-1-8.5-3
Sec. 6. (a)
For each year of the planning period, excluding subsection 6(a)(6), recognizing the potential effects of self-generation, an electric utility shall provide a description of the utility's In describing its existing electric power resources,
that the utility must include
at a minimum, in its IRP the following information
relevant to the twenty (20) year planning period being evaluated:
(1) The net and gross dependable generating capacity of the system and each generating unit.
(2) The expected changes to existing generating capacity, including
but not limited to, the following:
(A) Retirements.
(B) Deratings.
(C) Plant life extensions.
(D) Repowering.
(E) Refurbishment.
(3) A fuel price forecast by generating unit.
(4) The significant environmental effects, including:
(A) air emissions;
(B) solid waste disposal;
(C) hazardous waste; and
(D) subsequent disposal; and
(E) water consumption and discharge;
at each existing fossil fueled generating unit. units.
(5) The scheduled power import and export transactions, both firm and nonfirm, as well as cogeneration and non-utility production expected to be available for purchase by the utility.
(6) (5) An analysis of the existing utility transmission system that includes the following:
(A) An evaluation of the adequacy to support load growth and long term expected power purchases and sales. transfers.
(B) An evaluation of the supply-side resource potential of actions to reduce:
(i) transmission losses;
(ii) congestion; and
(iii) energy costs.
(C) An evaluation of the potential impact of demand-side resources on the transmission network.
(D) An assessment of the transmission component of avoided cost.
(7) (6) A discussion of demand-side programs, including existing company-sponsored resources and government-sponsored or mandated energy conservation or load management programs available in the utility's service area and the their estimated impact of those programs on the utility's historical and forecasted peak demand and energy.
The information listed in subdivisions (1) through (4) and in subdivision (6) shall be provided for each year of the future planning period.
(b)
An electric utility shall consider In describing possible alternative methods of meeting future demand for electric service, a utility must
consider analyze the following resources as alternatives in meeting future electric service requirements:
(1) Rate design as a demand-side resource including innovative rate design, as a source of new supply in meeting future electric service requirements. The
(2) Demand-side resources. For potential demand-side resources, the utility shall
consider a comprehensive array include the following:
(A) A description of demand-side measures that provide the potential demand-side resource, including its costs, characteristics, and parameters.
(B) The method by which the costs, characteristics, and other parameters of the demand-side resource are determined.
(C) The customer class or end-use, or both, affected by the demand-side resource.
(D) Estimated annual and lifetime energy (kWh) and demand (kW) savings.
(E) The estimated impact of a demand-side resource on the utility's load, generating capacity, and transmission and distribution requirements.
(F) Whether the program provides an opportunity for all ratepayers to participate, in DSM, including low-income residential ratepayers. For a utility-sponsored program identified as a potential demand-side resource, the utility's plan shall, at a minimum, include the following:
(1) A description of the demand-side program considered.
(2) A detailed account of utility strategies designed to capture lost opportunities.
(3) The avoided cost projection on an annual basis for the forecast period that accounts for avoided generation, transmission, and distribution system costs. The avoided cost calculation must reflect timing factors specific to resources under consideration such as project life and seasonal operation.
(4) The customer class or end-use, or both, affected by the program.
(5) A participant bill reduction projection and participation incentive to be provided in the program.
(6) A projection of the program cost to be borne by the participant.
(7) Estimated energy (kWh) and demand (kW) savings per participant for each program.
(8) The estimated program penetration rate and the basis of the estimate.
(9) The estimated impact of a program on the utility's load, generating capacity, and transmission and distribution requirements.
(c) A utility shall consider (3) Supply-side resources. For potential supply-side resources,
as an alternative in meeting future electric service requirements. The utility's plan shall the utility shall include
at a minimum, the following:
(1) Identify (A) Identification and
describe description of the
supply-side resource considered, including the following:
(A) (i) Size (MW). in megawatts.
(B) (ii) Utilized technology and fuel type.
(iii) Energy profile of nondispatchable resources.
(C) (iv) Additional transmission facilities necessitated by the resource.
(2) Significant environmental effects, including the following:
(A) Air emissions.
(B) Solid waste disposal.
(C) Hazardous waste and subsequent disposal.
(3) An analysis of how a proposed generation facility conforms with the utility-wide plan to comply with the Clean Air Act Amendments of 1990.
(4) (B) A discussion of the utility's effort to coordinate planning, construction, and operation of the supply-side resource with other utilities to reduce cost.
(d) A utility shall identify transmission (C) A description of significant environmental effects, including the following:
(i) Air emissions.
(ii) Solid waste disposal.
(iii) Hazardous waste and distribution subsequent disposal.
(iv) Water consumption and discharge.
(4) Transmission facilities
required to meet, in an economical and reliable manner, future electric service requirements. The plan shall, at a minimum, as resources. In analyzing transmission resources, the utility shall include the following:
(1) An analysis (A) The type of the transmission network capability to reliably support the loads and resources placed upon the network.
(2) A list of the principal criteria upon which the design resource, including whether the resource consists of
the transmission network is based. Include an explanation one (1) of the
principal criteria and their significance in identifying the need for and selecting transmission facilities. following:
(i) New projects.
(ii) Upgrades to transmission facilities.
(iii) Efficiency improvements.
(iv) Smart grid technology.
(3) (B) A description of the timing, and types of expansion, and alternative options considered.
(4) (C) The approximate cost of expected expansion and alteration of the transmission network.
(D) A description of how the IRP accounts for the value of new or upgraded transmission facilities increasing power transfer capability, thereby increasing the utilization of geographically constrained cost effective resources.
(E) A description of how:
(i) IRP data and information affect the planning and implementation processes of the RTO of which the utility is a member; and
(ii) RTO planning and implementation processes affect the IRP.
Authority:
IC 8-1-1-3
Sec. 7. (a) In order To eliminate nonviable alternatives, a utility shall perform an initial screening of all the future resource alternatives listed in sections section 6(b) through (c) of this rule. The utility's screening process and the decision to reject or accept a resource alternative for further analysis must be fully explained and supported in the IRP. The screening analysis must be additionally summarized in a resource summary table.
(b) Integrated resource planning includes one (1) or more tests used to evaluate the cost-effectiveness of a demand-side resource option. A cost-benefit analysis must be performed using the following tests except as provided under subsection (e):
(1) Participant.
(2) Ratepayer impact measure (RIM).
(3) Utility cost (UC).
(4) Total resource cost (TRC).
(5) Other reasonable tests accepted by the commission.
(c) A utility is not required to express a test result in a specific format. However, a utility must, in all cases, calculate the net present value of the program impact over the life cycle of the impact. A utility shall also explain the rationale for choosing the discount rate used in the test.
(d) A utility is required to:
(1) specify the components of the benefit and the cost for each of the major tests; and
(2) identify the equation used to express the result.
(e) If a reasonable cost-effectiveness analysis for a demand-side management program cannot be performed using the tests in subsection (b), where it is difficult to establish an estimate of load impact, such as a generalized information program, the cost-effectiveness tests are not required.
(f) To determine cost-effectiveness, the RIM test must be applied to a load building program. A load building program shall not be considered as an alternative to other resource options.
(Indiana Utility Regulatory Commission; 170 IAC 4-7-7; filed Aug 31, 1995, 9:00 a.m.: 19 IR 23; readopted filed Jul 11, 2001, 4:30 p.m.: 24 IR 4233; readopted filed Apr 24, 2007, 8:21 a.m.: 20070509-IR-170070147RFA; readopted filed Aug 2, 2013, 2:16 p.m.: 20130828-IR-170130227RFA; filed Dec 5, 2018, 11:49 a.m.: 20190102-IR-170180127FRA)
Authority:
IC 8-1-1-3;
IC 8-1-8.5-3
Sec. 8.
A utility shall select a mix of resources consistent with the objectives of the integrated resource plan. The utility must provide the commission, at a minimum, the following information:
(1) Describe the utility's resource plan.
(2) Identify the variables,
(1) risk;
(2) uncertainty;
(3) regional resources;
(4) environmental regulations;
(5) projections for fuel costs;
(6) load growth uncertainty;
(7) economic factors; and
(8) technological change.
(b) With regard to candidate resource portfolios, the IRP must include the following:
(1) An analysis of how candidate resource portfolios performed across a wide range of potential future scenarios, including the alternative scenarios required under section 4(25) of this rule.
(2) The results of testing and rank ordering of the candidate resource portfolios by key resource planning objectives, including cost effectiveness and risk metrics.
(3) The present value of revenue requirement for each candidate resource portfolio in dollars per kilowatt-hour delivered, with the interest rate specified.
(c) Considering the analyses of the candidate resource portfolios, a utility shall select a preferred resource portfolio and include in the IRP the following:
(1) A description of the utility's preferred resource portfolio.
(2) Identification of the standards of reliability. and other
(3) A description of the assumptions expected to have the greatest effect on the least-cost mix of resources. preferred resource portfolio.
(4) An analysis showing that supply-side resources and demand-side resources have been evaluated on a consistent and comparable basis, including consideration of:
(A) safety;
(B) reliability;
(C) risk and uncertainty;
(D) cost effectiveness; and
(E) customer rate impacts.
(3) Determine (5) An analysis showing the present value revenue requirement of the utility's preferred resource plan, stated in total dollars and in dollars per kilowatt-hour delivered, with the discount rate specified.
(4) Demonstrate that the utility's resource plan portfolio utilizes to the extent practical, all economical load management, conservation, nonconventional technology relying on renewable resources, cogeneration, and energy efficiency improvements as sources of new supply.
(5) Discuss how the utility's resource plan takes into account the utility's judgment of risks and uncertainties associated with potential environmental and other regulations.
(6) Demonstrate that the most economical source of supply-side resources has been included in the integrated resource plan. and demand-side resources that safely, reliably, efficiently, and cost-effectively meets the electric system demand taking cost, risk, and uncertainty into consideration.
(7) Discuss the utility's (6) An evaluation of dispersed generation and targeted the utility's DSM programs designed to defer or eliminate investment in a transmission or distribution facility, including their impacts if any, on the utility's transmission and distribution system. for the first ten (10) years of the planning period.
(8) Discuss (7) A discussion of the financial impact on the utility of acquiring future resources identified in the utility's
preferred resource
plan. The discussion shall include, portfolio including, where appropriate, the following:
(A) The Operating and capital costs of the integrated preferred resource plan. portfolio.
(B) The average price cost per kilowatt-hour as calculated in the resource plan. The price of the future resources, which must be consistent with the electricity price assumption used to forecast the utility's expected load by customer class in section 5 of this rule.
(C) An estimate of the utility's avoided cost for each year of the plan. preferred resource portfolio.
(D) The impact of a planned addition to supply-side or demand-side resources on the utility's rate.
(E) (D) The utility's ability to finance the acquisition of a required new preferred resource portfolio.
(9) Identify and explain assumptions concerning existing and proposed regulations, laws, practices, and policies made concerning decisions used in formulating the IRP.
(8) A description of how the preferred resource portfolio balances cost effectiveness, reliability, and portfolio risk and uncertainty, including the following:
(A) Quantification, where possible, of assumed risks and uncertainties, including, but not limited to:
(i) environmental and other regulatory compliance;
(ii) reasonably anticipated future regulations;
(iii) public policy;
(iv) fuel prices;
(v) operating costs;
(vi) construction costs;
(vii) resource performance;
(viii) load requirements;
(ix) wholesale electricity and transmission prices;
(x) RTO requirements; and
(xi) technological progress.
(B) An assessment of how robustness of risk considerations factored into the selection of the preferred resource portfolio.
(9) Utilities shall include a discussion of potential methods under consideration to improve the data quality, tools, and analysis as part of the ongoing efforts to improve the credibility and efficiencies of their resource planning process.
(10)
Demonstrate, to the extent practicable and reasonable, that the utility's resource plan incorporates A workable strategy
for reacting to unexpected changes. A workable strategy is one that allows the utility to
quickly and appropriately adapt
its preferred resource portfolio to unexpected circumstances,
and preserves the plan's ability to achieve its intended purpose. Unexpected changes include, but are not limited to, including changes in the following:
(A) The Demand for electric service.
(B) The Cost of a new supply-side resources or demand-side technology. resources.
(C) Regulatory compliance requirements and costs.
(D) Wholesale market conditions.
(E) Fuel costs.
(F) Environmental compliance costs.
(G) Technology and associated costs and penetration.
(C) (H) Other factors which that would cause the forecasted relationship between supply and demand for electric service to be in error.
(Indiana Utility Regulatory Commission; 170 IAC 4-7-8; filed Aug 31, 1995, 9:00 a.m.: 19 IR 23; readopted filed Jul 11, 2001, 4:30 p.m.: 24 IR 4233; readopted filed Apr 24, 2007, 8:21 a.m.: 20070509-IR-170070147RFA; readopted filed Aug 2, 2013, 2:16 p.m.: 20130828-IR-170130227RFA; filed Dec 5, 2018, 11:49 a.m.: 20190102-IR-170180127FRA)
Authority:
IC 8-1-1-3;
IC 8-1-8.5-3
Sec. 9. (a) A utility shall prepare a short term action plan shall be prepared as part of the utility's its IRP filing or separately, and shall cover each of the two (2) years a three (3) year period beginning with the first year of the IRP submitted pursuant to this rule.
(b) The short term action plan is a summary of the shall summarize the utility's preferred resource options or programs contained portfolio and its workable strategy, as described in the utility's current integrated resource plan section 8(c)(9) of this rule, where the utility must take action or incur expenses during the two (2) three (3) year period.
(c) The short term action plan must include, but is not limited to, the following:
(1) A description of
each resources in the preferred resource
option or program portfolio included in the short term action plan.
The description may include references to other sections of the IRP to avoid duplicate descriptions. The description must include, but is not limited to, the following:
(A) The objective of the preferred resource option or program. portfolio.
(B) The criteria for measuring progress toward the objective.
(C) The actual progress toward the objective to date.
(2)
The participation Identification of
small business in the goals for implementation of
a DSM
programs that can be developed in accordance with IC 8-1-8.5-10 and 170 IAC 4-8-1 et seq. and consistent with the utility's longer resource
option or program. planning objectives.
(3) The implementation schedule for the preferred resource option or program. portfolio.
(4) The timetable for implementation and resource acquisition.
(5) (4) A detailed budget with an estimated range for the cost to be incurred for each resource or program and expected system impacts.
(5) A description and explanation of differences between what was stated in the utility's last filed short term action plan and what actually occurred.
(Indiana Utility Regulatory Commission; 170 IAC 4-7-9; filed Aug 31, 1995, 9:00 a.m.: 19 IR 24; readopted filed Jul 11, 2001, 4:30 p.m.: 24 IR 4233; readopted filed Apr 24, 2007, 8:21 a.m.: 20070509-IR-170070147RFA; readopted filed Aug 2, 2013, 2:16 p.m.: 20130828-IR-170130227RFA; filed Dec 5, 2018, 11:49 a.m.: 20190102-IR-170180127FRA)
Authority:
IC 8-1-1-3;
IC 8-1-8.5-3
Sec. 10. (a) The utility may provide the director an update regarding substantial, unexpected changes that occur between IRP submissions. Copies of an update shall be provided to the OUCC and other interested parties.
(b) Upon the request of the commission or its staff, the utility shall provide updated IRP information to the director, the OUCC, and interested parties.
(c) When submitting an update under this section, the utility shall provide the relevant IRP sections with the updated information. The utility shall also provide a separate document clearly itemizing the parts of the IRP that were updated.
(Indiana Utility Regulatory Commission; 170 IAC 4-7-10; filed Dec 5, 2018, 11:49 a.m.: 20190102-IR-170180127FRA)
Authority:
IC 8-1-1-3;
IC 8-1-8.5-10
Sec. 0.5. (a) The purpose of this rule is to:
(1) provide the requirements for a utility's energy efficiency plan and requests for cost recovery as set forth in IC 8-1-8.5-10; and
(2) provide the rules and procedures applicable to the implementation of a utility's:
(A) demand response programs;
(B) energy efficiency programs; and
(C) accompanying cost recovery.
(b) This rule applies to utilities as defined in this rule, unless otherwise noted.
(Indiana Utility Regulatory Commission; 170 IAC 4-8-0.5; filed Dec 5, 2018, 11:49 a.m.: 20190102-IR-170180127FRA)
Authority:
IC 8-1-1-3;
IC 8-1-8.5-10
Sec. 1. (a) As used The definitions in this section apply throughout this rule.
(b) "Allowance for funds used during construction" or "AFUDC" means the cost of borrowed funds used for capital expenditures associated with a utility-sponsored DSM demand response or energy efficiency program, and a reasonable rate on other funds when so used. AFUDC for capital expenditures shall be recorded in separate subaccounts or their subdivisions in accordance with the FERC or NARUC uniform system of accounts.
(b) As used in this rule, "avoided cost" means the amount of fuel, operation, maintenance, purchased power, labor, capital, taxes, and other cost not incurred by a utility if an alternative supply or demand-side resource is included in the utility's integrated resource plan.
(c) As used in this rule, "Commission" means the Indiana utility regulatory commission.
(d) As used in this rule, "conservation" means reducing the amount of energy consumed by a customer for a specific end-use. Conservation includes behavior changes such as thermostat setback. Conservation does not include changing the timing of energy use, switching to another fossil fuel source, or increasing off-peak usage.
(e) As used in this rule, "demand-side management" or "DSM" means the planning, implementation, and monitoring of a utility activity designed to influence customer use of electricity that produces a desired change in a utility's load shape, for example, a change in the time pattern and magnitude of a utility's load. DSM includes only an activity that involves deliberate intervention by a utility to alter load shape.
(f) As used in this rule, "demand-side measure" means a particular end-use device, technology, service, or rate design at a targeted customer's premises or a utility's energy delivery system for a specific DSM program.
(d) "Commission analysis" means the required state energy analysis developed by the commission under IC 8-1-8.5-3.
(e) "Demand-side resource" means one (1) or more demand response programs or energy efficiency programs, or both.
(f) "Demand response" means a reduction in electrical usage for limited intervals of time, such as during peak electricity usage or emergency conditions.
(g) As used in this rule, "demand-side program" "Demand response program" means a utility program designed to implement a demand-side measure. demand response.
(h) As used in this rule, "demand-side resource" means a resource that reduces the demand for electrical power or energy by applying a demand-side program to implement one (1) or more demand-side measures.
(h) "Demand response program costs" means the direct and indirect costs of a demand response program.
(i) "Electricity supplier" has the same meaning as set forth in IC 8-1-8.5-10(a).
(i) As used in this rule, (j) "End-use" means the:
(1) light;
(2) heat;
(3) cooling;
(4) refrigeration;
(5) motor drive;
(6) microwave energy;
(7) video or signal;
(8) audio signal;
(9) computer processing;
(10) electrolytic process; or
(11) other useful work;
produced by equipment using electricity.
(j) As used in this rule, (k) "Energy efficiency" improvement" means reduced energy use for a comparable or improved level of energy service.
(k) As used in (l) "Energy efficiency plan" means a utility's filing with the commission under this rule
as required by IC 8-1-8.5-10(h).
(m) "Energy efficiency program" has the meaning set forth in IC 8-1-8.5-10(d).
(n) "Energy efficiency program costs" means:
(1) direct and indirect costs of energy efficiency programs;
(2) costs associated with the EM&V of energy efficiency program results;
(3) reasonable lost revenues; and
(4) reasonable financial incentives.
(o) "Energy service" means the:
(1) light;
(2) heat;
(3) motor drive; and or
(4) other service;
for which a customer purchases electricity from the utility.
(l) As used in this rule, (p) "Engineering estimate" means an a calculated estimate of the change in energy (kWh) and demand (kW) impact resulting from a demand-side measure based on an engineering calculation procedure. An engineering estimate addresses change in energy use of a building or system resulting from installation of a DSM measure. If multiple DSM measures are installed, an engineering estimate accounts for the interactive effect between the DSM measures. demand response program or an energy efficiency program, accounting for dynamic interactions between or among the programs.
(m) As used in this rule, the "FERC Uniform System of Accounts" means the rules and regulations governing the classification of accounts for Class A-B private electric utilities, as approved, prescribed, and promulgated by the Federal Energy Regulatory Commission in 18 CFR 41 and 18 CFR 101 and adopted by the commission for Indiana electric utilities at 170 IAC 4-2-1.1.
(q) "Evaluation, measurement, and verification" or "EM&V" means the independent application of methods and processes used to assess the performance of one (1) or more energy efficiency programs or demand response programs, or both.
(n) As used in this rule, (r) "Free-rider" means a customer who would have installed a demand-side measure implemented demand response or energy efficiency without participating in a utility-sponsored DSM an energy efficiency program or demand response program, yet participates in the DSM a demand response program or energy efficiency program and receives an incentive or bonus for participation.
(s) "Gross demand reduction" means the change in kilowatts over a limited period of time that results directly from the implementation of an energy efficiency program or demand response program.
(o) As used in this rule, "income effect" (t) "Gross energy savings" means the change in a customer's energy use kilowatt-hours consumed that is induced by a change in results directly from the amount implementation of disposable income available to the customer. an energy efficiency program or demand response program.
(p) As used in this rule, (u) "Integrated resource
planning", or plan" or "IRP" means a
utility's assessment of a variety of demand-side and supply-side resources utility's document submitted to
cost-effectively the commission to meet
customer electricity service needs. The IRP may also include, but is not limited to, the following: the requirements of 170 IAC 4-7.
(1) A public participation procedure.
(2) An analysis of the uncertainty and risk posed by different resources and external factors.
(q) As used in this rule, (v) "Load building" means a program intended to increase electricity consumption without regard to the timing of the increased usage.
(r) As used in this rule, "load research" means the collection of electricity usage data through a metering device associated with an end-use, a circuit, or a building. The metered data is used to better understand the characteristics of electric loads, the timing of their use, and the amount of electricity consumed by users. The data may be collected over a variety of time intervals, usually sixty (60) minutes or less.
(s) As used in this rule, (w) "Load retention" means a program intended to induce customers that have a bona fide option of switching to alternative sources of energy services or self-generation, customer owned generation to remain as utility customers.
(t) As used in this rule, "load shape" means the time pattern of customer electricity use and the relationship of the level of energy use to a specific time during the day, month, and year.
(u) As used in this rule, (x) "Lost revenue" means
the revenue lost less the
difference, if any, between:
(1) revenues lost; and
(2) the variable operating and maintenance costs saved;
as a result of not generating electricity because of a utility-sponsored DSM by an electricity supplier as a result of implementing an energy efficiency program or demand response program.
(v) As used in this rule, "NARUC Uniform System of Accounts" means the rules and regulations governing the classification of accounts for Class C-D private electric utilities and Class A-B-C-D municipal electric utilities, as developed by the National Association of Regulatory Utility Commissioners and adopted by the commission for Indiana electric utilities under 170 IAC 4-2-2.
(w) As used in this rule, "participant" means a utility customer participating in a utility-sponsored DSM program.
(y) "Market effects" means the indirect influence of an energy efficiency program or demand response program that results in energy savings or demand reductions, or both, that have not been captured in EM&V activities.
(z) "Net demand reduction" means the portion of gross demand reduction that is attributable to a demand response program or energy efficiency program, adjusted for free-ridership and spillover.
(aa) "Net energy savings" means the portion of gross energy savings that is attributable to an energy efficiency program or demand response program, adjusted for free-ridership and spillover.
(bb) "Participant cost test" means a cost effectiveness test that measures the quantifiable benefits and costs to the customer due to participation in an energy efficiency program or demand response program.
(x) As used in this rule, (cc) "Participation level" means the actual number of customers participating in a specific demand-side program relative to the eligible number of customers available to participate in the demand-side program expressed as a percentage or a fraction.
(y) As used in this rule, (dd) "Penetration" means the ratio of the number of a specific type of new units appliances or end-use equipment installed to the total number of new units installed during a given time.
(z) As used in this rule, (ee) "Persistence" means
the DSM measure's effectiveness over time. The effectiveness of a DSM measure is represented as the percentage of energy-saving effectiveness remaining in a particular year compared to the initial year of the measure's installation or implementation.
The measure of effectiveness Persistence is a function of the following two (2) factors:
(1) Equipment degradation.
(2) Consumer behavior.
(aa) As used in this rule, "program cost" means all expenses incurred by a utility in a given year for operation of a DSM program whether the cost is capitalized or expensed. An expense includes, but is not limited to, the following:
(1) Administration.
(2) Equipment.
(3) Incentives paid to program participants.
(4) Marketing and advertising.
(5) Monitoring and evaluation.
(bb) As used in this rule, "public participation" means a procedure where a customer or interested party is provided the opportunity to comment on a utility's integrated resource plan prior to the submission of the IRP to the commission.
(ff) "Program administrator cost test" or "utility cost test" means a cost effectiveness test that measures the costs incurred by the program administrator, including incentive costs, and excluding net costs incurred by the participant, compared to the benefits incurred by the program administrator.
(gg) "Program participant" means a utility customer participating in a utility-sponsored energy efficiency or demand response program.
(hh) "Ratepayer impact measure test" means a cost effectiveness test that measures the change in customer bills or rates due to changes in utility revenues and operating costs caused by an energy efficiency program or demand response program.
(cc) As used in this rule, (ii) "Rebound effect" means a specific effect where a customer responds to a lower relative cost of electric service by purchasing more electricity in the same end-use where the demand-side an energy efficiency program is concentrated.
(dd) As used in this rule, (jj) "Resource" means a:
(1) facility;
(2) project;
(3) contract; or other
(4) mechanism;
used by a utility to provide assist in providing electric energy service to the customer.
(ee) As used in this rule, "self-generation" means an electric generation facility primarily for the customer's own use and not for the primary purpose of producing electricity, heat, or steam for sale to or for the public for compensation.
(kk) "Spillover" means additional reductions in energy consumption or demand by program participants beyond those directly associated with program participation.
(ff) As used in this rule, (ll) "Supply-side resource" means a resource that provides a supply of electrical energy or capacity, or both, to a utility. A supply-side resource includes the following:
(1) A utility-owned generation capacity addition.
(2) A wholesale power purchase. from another utility or non-utility generator.
(3) A refurbishment or upgrading upgrade of an existing utility-owned generating generation facility.
(4) A cogeneration facility.
(5) A renewable resource. technology.
(6) Distributed generation.
(mm) "Total resource cost test" means a cost effectiveness test that measures whether an energy efficiency program or demand response program is cost effective based on the total cost and benefit of the program, including both the participants' and the utility's costs.
(gg) As used in this rule, (nn) "Useful life" means the period of time the investment in a measure remains cost-effectively serviceable.
(hh) As used in this rule, (oo) "Utility" means
(1) a public, municipally owned, or cooperatively owned utility; or
an electricity supplier.
(Indiana Utility Regulatory Commission; 170 IAC 4-8-1; filed Aug 31, 1995, 10:00 a.m.: 19 IR 24; readopted filed Jul 11, 2001, 4:30 p.m.: 24 IR 4233; readopted filed Apr 24, 2007, 8:21 a.m.: 20070509-IR-170070147RFA; readopted filed Aug 2, 2013, 2:16 p.m.: 20130828-IR-170130227RFA; filed Dec 5, 2018, 11:49 a.m.: 20190102-IR-170180127FRA)
170 IAC 4-8-2 Energy efficiency plan filing
Authority:
IC 8-1-1-3;
IC 8-1-8.5-10
Sec. 2. (a) To assist An electricity supplier shall file a request for approval of an energy efficiency plan not less than one (1) time every three (3) years beginning no later than December 31, 2017.
(b) A utility applying to the commission
in its administration of the Utility Powerplant Construction Law (IC 8-1-8.5), this rule applies to the following:
(1) A public, municipally owned, or cooperatively owned utility.
(b) Section 7 of this rule does not apply to a municipally owned or cooperatively owned utility or a joint agency created under IC 8-1-2.2. for approval of its energy efficiency plan shall include the following information with its petition:
(1) A description of each energy efficiency program and demand response program proposed by the utility.
(2) A budget for the energy efficiency plan, including budgets for each energy efficiency program and demand response program.
(3) A cost-benefit analysis as required by IC 8-1-8.5-10(j)(2), using at a minimum all the following:
(A) Participant cost test.
(B) Ratepayer impact measure test.
(C) Program administrator cost test.
(D) Total resource cost test.
Additional reasonable cost-benefit tests may be proposed. A utility is not required to express a test result in a specific format, however, results must include the total costs and total benefits used in calculations and the benefit-cost ratio for the specific test.
(4) Projected changes in customer consumption of electricity resulting from the implementation of the energy efficiency plan.
(5) A statement of whether the energy efficiency plan is consistent with the commission analysis.
(6) A description of how the energy efficiency plan is consistent with the utility's most recent IRP, including copies of relevant portions of the utility's most recent IRP.
(7) Identification of a preference to a customer class potentially resulting from implementation of an energy efficiency program or demand response program.
(8) A description of the lost revenues and financial incentives the utility seeks to recover.
(9) The effect, or potential effect, in both the long term and the short term, of the energy efficiency plan on the electric rates and bills of program participants compared to the electric rates and bills of customers that do not participate in the program.
(10) An EM&V procedure, complying with section 4 of this rule, to assess implementation and quantify the impact on energy and demand of each energy efficiency program and demand response program included in the energy efficiency plan.
(11) A statement of the utility's energy efficiency goals for producing reasonably achievable energy efficiency through implementation of cost effective energy efficiency programs. The energy efficiency goals shall be designed to achieve an optimal balance of energy resources in an electricity supplier's service territory. The energy efficiency goals shall exclude industrial customers that have opted out of the utility's energy efficiency plan.
(12) If an electricity supplier is using forecasted costs and energy savings for cost recovery purposes, it shall propose a mechanism to reconcile forecasted costs and energy savings with actual costs and energy savings.
(13) The work papers and data used for calculations performed under subdivisions (3), (8), and (9).
(c) An electricity supplier may submit a plan required under this section either as an independent proceeding or as part of a general base rate proceeding.
(d) At the same time an electricity supplier petitions the commission under IC 8-1-8.5-10(h), the electricity supplier shall:
(1) provide a copy of the petition and plan to the Indiana office of utility consumer counselor; and
(2) post a copy of the petition and plan on the electricity supplier's website.
The electricity supplier may redact confidential or proprietary information.
(Indiana Utility Regulatory Commission; 170 IAC 4-8-2; filed Aug 31, 1995, 10:00 a.m.: 19 IR 26; readopted filed Jul 11, 2001, 4:30 p.m.: 24 IR 4233; readopted filed Apr 24, 2007, 8:21 a.m.: 20070509-IR-170070147RFA; readopted filed Aug 2, 2013, 2:16 p.m.: 20130828-IR-170130227RFA; filed Dec 5, 2018, 11:49 a.m.: 20190102-IR-170180127FRA)
170 IAC 4-8-3 Home energy efficiency assistance programs
Authority:
IC 8-1-1-3;
IC 8-1-8.5-10
Sec. 3.
(a) In order to facilitate compliance with the Utility Powerplant Construction Act (IC 8-1-8.5) and to comply with the National Energy Policy Act of 1992 (16 U.S.C. 2621 and 16 U.S.C. 2622 effective October 24, 1992, P.L.102-486 Stat. 2795), the commission has developed a regulatory framework that allows a utility an incentive to meet long term resource needs with both supply-side and demand-side resource options in a least-cost manner and ensures that the financial incentive offered to a DSM program participant is fair and economically justified. The regulatory framework attempts to eliminate or offset regulatory or financial bias against DSM, or in favor of a supply-side resource, a utility might encounter in procuring least-cost resources. The commission, where appropriate, will review and evaluate the existence and extent of regulatory or financial bias.
(b) In order to comply with the National Energy Policy Act of 1992 (16 U.S.C. 2621 and 16 U.S.C. 2622 effective October 24, 1992, P.L.102-486 Stat. 2795), the commission will review and evaluate the impact the utility's proposed demand-side management program may have on small privately owned business, as specified in section 8 of this rule.
(c) To ensure a utility's proposal is consistent with acquiring the least-cost mix of demand-side and supply-side resources to reliably meet the long term electric service requirements of the utility's customers, the commission, where appropriate, will review and evaluate, as a package, the proposed DSM programs, DSM cost recovery, lost revenue, and shareholder DSM incentive mechanisms.
(a) For purposes of this section, a home energy efficiency assistance program means an energy efficiency program that:
(1) includes an assessment of the customer's home; and
(2) allows participation by customers who qualify based on financial need.
(b) The commission may approve a home energy efficiency assistance program as part of an energy efficiency plan, approved in its entirety or in part, whether or not the home energy efficiency assistance program is cost effective as analyzed in accordance with section 2(b)(3) of this rule or as determined by the commission.
(c) The commission shall not approve financial incentives for a home energy efficiency assistance program that is not cost effective.
(Indiana Utility Regulatory Commission; 170 IAC 4-8-3; filed Aug 31, 1995, 10:00 a.m.: 19 IR 27; readopted filed Jul 11, 2001, 4:30 p.m.: 24 IR 4233; readopted filed Apr 24, 2007, 8:21 a.m.: 20070509-IR-170070147RFA; readopted filed Aug 2, 2013, 2:16 p.m.: 20130828-IR-170130227RFA; filed Dec 5, 2018, 11:49 a.m.: 20190102-IR-170180127FRA)
170 IAC 4-8-4 Evaluation, measurement, and verification plan
Authority:
IC 8-1-1-3;
IC 8-1-8.5-10
Sec. 4. (a)
When seeking commission approval for cost recovery, DSM incentives, or lost revenue, a utility shall develop a process and load impact evaluation plan to assess implementation and quantify the impact on energy and demand of the demand-side resource. The
evaluation EM&V plan must include the following
for energy efficiency programs and demand response programs in the utility's energy efficiency plan:
(1) The type and timing of the measurement activity. used to evaluate a demand-side resource.
(2) The process where the result is used to modify the impact estimate for future planning and design of the demand-side program.
(3) The
utility's evaluation procedure.
employed regarding the following aspects of the evaluation of each program: (A) Establish a protocol to The utility must include information on how it shall collect
basic data
on to determine:
(A) load impact;
(B) participation level;
(C) utility cost and benefits;
(D) participant cost and total cost. Data must be gathered to determine the load shape impact, benefits;
(E) net program energy savings;
(F) net demand reductions;
(G) useful life; of the measure, and
(H) persistence. of savings, including
(4) How the utility
actions to optimize will measure the utility's effectiveness in:
(A) optimizing market penetration of the program; and minimize
(B) minimizing free-riders; and
(B) Compare (C) measuring spillover.
(5) A comparison of usage and demand patterns of similar participant and nonparticipant groups, through the use of:
(A) customer bill analysis;
(B) engineering estimates;
(C) end-use meter data; or
(D) other methods. to
(6) The comparison must identify the:
gross and net impacts of program participation on customers' usage and demand patterns.
(A) gross energy saving;
(B) gross demand reductions;
(C) net energy savings; and
(D) net demand reductions;
attributable to the participation in the energy efficiency program or demand response program.
(4) (7) A method to measure rebound or the income effect for a an energy efficiency program and demand response program. or a sector where the effect may be significant.
(b) A In addition to the EM&V plan submitted to the commission under this section, a utility shall submit to the commission and post to the utility's website, annually, a document containing information, data, and results from the utility's process and EM&V activities, including its load impact evaluation studies.
(Indiana Utility Regulatory Commission; 170 IAC 4-8-4; filed Aug 31, 1995, 10:00 a.m.: 19 IR 27; readopted filed Jul 11, 2001, 4:30 p.m.: 24 IR 4233; readopted filed Apr 24, 2007, 8:21 a.m.: 20070509-IR-170070147RFA; readopted filed Aug 2, 2013, 2:16 p.m.: 20130828-IR-170130227RFA; filed Dec 5, 2018, 11:49 a.m.: 20190102-IR-170180127FRA)
Authority:
IC 8-1-1-3;
IC 8-1-8.5-10
Sec. 5. (a) A utility is entitled to recover The commission shall approve the recovery of reasonable cost of planning and implementing a demand-side management energy efficiency program in one (1) or more of the costs and may approve the recovery of reasonable demand response program costs on a timely basis through a periodic rate adjustment mechanism.
(b) The commission shall limit the periodic rate adjustment mechanism to the incremental energy efficiency program costs or demand response program costs, or both, not already included in the utility's base rates, if applicable.
(c) Nothing in this rule precludes a utility from requesting or the commission from approving in a rate case the following:
ways, or any combination of them, as determined by the commission:
(1) The inclusion of the cost energy efficiency program costs or demand response program costs, or both, in the utility's base rates during a rate case using a balancing account, where appropriate, to reconcile the utility's recovered expenditures. The commission may, where appropriate, limit cost recovery to the utility's actual incurred expenses, if the utility is spending less than the costs authorized by the commission for inclusion in the utility's base rates.
(2) The periodic recovery of the cost incurred in excess of the cost that is included in the utility's base rates.
(3) (2) The inclusion of the capital cost, with accumulated AFUDC, in the utility's rate base during its rate case, amortized over a period set by the commission.
(4) (3) The accumulation, with a carrying charge, of the non-capital cost incurred and not otherwise recovered through the utility's base rates or through periodic adjustments in a deferred account to be amortized over a period set by the commission.
(5) A cost recovery mechanism proposed by the utility, other parties, or the commission.
(b) The commission shall determine the cost recovery mechanism for a demand-side management program when the demand-side management program is submitted for commission approval.
(c) The determination of a cost recovery mechanism for a demand-side management program under this section shall not constitute approval of a specific dollar amount, and the reasonableness or prudence of a revenue requirement for cost recovery may be debated in a future proceeding before the commission.
(d) A utility proposing a load building or load retention program must quantify and document by program specific analysis, the net benefit to the utility's customers, and justify nonparticipant ratepayer funding for the program.
(e) Cost recovery of a demand-side management program (d) Recovery of energy efficiency program costs or demand response program costs, or both, under this section shall continue as determined by the commission provided that the utility maintains satisfactory implementation and completion of DSM program measurement and evaluation EM&V activities as specified in section 4 of this rule.
(f) In order (e) To ensure that
DSM energy efficiency program and demand response program benefits and costs are allocated between utility shareholders, participants, and nonparticipants in a fair and economical way, the utility must
show demonstrate to the commission
when a DSM program is reviewed that
an a customer incentive paid by the utility
to the customer for
participating in a DSM program participation, when combined with the reduction in the participant's utility bills:
(1) reflects the net benefit of the DSM energy efficiency or demand response program to the utility and all customers; and
(2) minimize minimizes cross-subsidies between customer groups and between program participants and nonparticipants within a customer group.
(Indiana Utility Regulatory Commission; 170 IAC 4-8-5; filed Aug 31, 1995, 10:00 a.m.: 19 IR 27; readopted filed Jul 11, 2001, 4:30 p.m.: 24 IR 4233; readopted filed Apr 24, 2007, 8:21 a.m.: 20070509-IR-170070147RFA; readopted filed Aug 2, 2013, 2:16 p.m.: 20130828-IR-170130227RFA; filed Dec 5, 2018, 11:49 a.m.: 20190102-IR-170180127FRA)
Authority:
IC 8-1-1-3;
IC 8-1-8.5-10
Sec. 6. (a) The commission may allow shall approve the utility to recover the utility's recovery of reasonable lost revenue from the implementation of a demand-side management program sponsored or instituted by the utility. The calculation revenues for energy efficiency programs and may approve the recovery of reasonable lost revenue must account revenues for demand response programs.
(b) A utility seeking recovery of lost revenues shall propose for commission review a methodology or process for calculating lost revenues that accounts for the following:
(1) The impact of free-riders.
(2) Spillover.
(2) (3) The change in the number of DSM program participants between base rate changes cases. and on the
(4) A revised estimate of a program the energy efficiency program's and demand response program's specific load impact that result resulting from the utility's measurement and evaluation EM&V activities. under sections 4 and 5(e) of this rule.
(b) A utility seeking (c) Nothing in this rule precludes a utility from proposing an alternative regulatory plan that eliminates the disincentive to pursue an energy efficiency program or demand response program in lieu of recovery of
the utility's reasonable lost
revenue shall propose for revenues. If the commission
review approves a
methodology utility's proposed alternative regulatory plan in a manner that eliminates the utility's disincentive to implement an energy efficiency or
process for incorporating a demand response program, lost revenue recovery
mechanism which includes the following: shall not be approved.
(1) The level of free-riders in a DSM program.
(2) A revised estimate of a DSM program specific load impact resulting from regular utility measurement and evaluation activities.
(c) The commission may periodically review the need for continued recovery of the lost revenue as a result of a utility's DSM program, and the approval of a lost revenue recovery mechanism shall not constitute approval of specific dollar amount, the prudence or reasonableness of which may be debated in a future proceeding before the commission.
(Indiana Utility Regulatory Commission; 170 IAC 4-8-6; filed Aug 31, 1995, 10:00 a.m.: 19 IR 28; readopted filed Jul 11, 2001, 4:30 p.m.: 24 IR 4233; readopted filed Apr 24, 2007, 8:21 a.m.: 20070509-IR-170070147RFA; readopted filed Aug 2, 2013, 2:16 p.m.: 20130828-IR-170130227RFA; filed Dec 5, 2018, 11:49 a.m.: 20190102-IR-170180127FRA)
Authority:
IC 8-1-1-3;
IC 8-1-8.5-10
Sec. 7. (a) A utility
is allowed an opportunity for earnings from prudent investments in both supply-side and demand-side resources. When appropriate, the commission may provide the utility with a shareholder incentive to encourage participation in and promotion of a demand-side management program. A utility may propose a
shareholder financial incentive based on particular attributes of
a DSM an energy efficiency program or demand response program and the program's desired results. A
shareholder financial incentive may include, but is not limited to, the following:
(1) Grant Granting a utility a percentage share of the net benefit attributable to a demand-side management an energy efficiency program or demand response program.
(2) Allow Allowing a utility to earn a greater than normal return on equity for a rate-based demand-side management expenditure. energy efficiency program or demand response program costs.
(3) Adjust Adjusting a utility's overall return on equity in response to quantitative or qualitative evaluation of demand-side management program an energy efficiency program's or demand response program's performance.
(b) The commission may terminate when appropriate, a shareholder a financial incentive.
(c) A shareholder financial incentive shall not provide an incentive payment for a an energy efficiency program or demand response program unless the net kilowatt or kilowatt-hour impact, or both, can be reasonably determined.
(d) Load building and load retention programs are not eligible for shareholder financial incentives.
(e) A utility must include a comprehensive measurement and evaluation plan with a shareholder incentive request as described in section 4 of this rule.
(f) (e) A shareholder incentive mechanism financial incentive must reflect the value to the utility's customers of the supply-side resource cost avoided or deferred by the utility's DSM energy efficiency program or demand response program minus the incurred utility DSM program cost. costs.
(g) In order (f) To reflect only the conservation energy efficiency and load management demand impact of a utility-sponsored DSM an energy efficiency program or demand response program, the shareholder financial incentive mechanism must exclude the effect of free-riders from the incentive calculation.
(h) (g) A shareholder financial incentive applicable to a DSM program may be based on prespecified forecasted demand and reductions or energy savings until the information on demand reductions and energy savings from utility measurement and evaluation the utility's EM&V activities becomes available.
(i) Commission approval of a mechanism for the recovery of a shareholder incentive based on a utility-sponsored DSM program is not approval for a specific dollar amount. The reasonableness or prudence of a revenue requirement for recovery of a shareholder incentive may be debated in a future proceeding before the commission.
(Indiana Utility Regulatory Commission; 170 IAC 4-8-7; filed Aug 31, 1995, 10:00 a.m.: 19 IR 28; readopted filed Jul 11, 2001, 4:30 p.m.: 24 IR 4233; readopted filed Apr 24, 2007, 8:21 a.m.: 20070509-IR-170070147RFA; readopted filed Aug 2, 2013, 2:16 p.m.: 20130828-IR-170130227RFA; filed Dec 5, 2018, 11:49 a.m.: 20190102-IR-170180127FRA)
170 IAC 4-8-7.5 Industrial customer opt out of participation in energy efficiency plan
Authority:
IC 8-1-1-3;
IC 8-1-8.5-10
Sec. 7.5. (a) An industrial customer (as defined in IC 8-1-8.5-9(e)) may opt out of an electricity supplier's energy efficiency plan under this section by following the procedure set forth in IC 8-1-8.5-9(f) and IC 8-1-8.5-9(g).
(b) The opt out of an industrial customer who has previously complied with the procedure set forth in IC 8-1-8.5-9(f) constitutes an opt out of an electricity supplier's energy efficiency plan under this section.
(c) An industrial customer may follow the procedure set forth in IC 8-1-8.5-9(g) to opt back in to an electricity supplier's energy efficiency plan.
(Indiana Utility Regulatory Commission; 170 IAC 4-8-7.5; filed Dec 5, 2018, 11:49 a.m.: 20190102-IR-170180127FRA)
170 IAC 4-8-8 Impact of demand-side management on small business
Authority:
IC 8-1-1-3;
IC 8-1-8.5-10
Sec. 8. Contemporaneously with the commission's approval of a utility's
DSM program, petition under this rule, the commission shall, under 16 U.S.C. 2621(c)(3)(A) and 16 U.S.C. 2621(c)(3)(B) effective October 23, 1992, do the following:
(1) Consider the impact that implementation of the proposed DSM energy efficiency or demand response program would have on small business. engaged in design, sale, supply, installation, or servicing of energy conservation, energy efficiency improvements, or other demand-side management measures.
(2) If necessary, implement a revision to the proposed DSM energy efficiency program or demand response program to assure ensure that utility actions would not provide the utility with an unfair competitive advantage over small business.
Hearing Held: August 20, 2018
Approved by Attorney General: November 30, 2018
Approved by Governor: December 5, 2018
Filed with Publisher: December 5, 2018, 11:49 a.m.
Documents Incorporated by Reference: 16 U.S.C. 824a-3
Small Business Regulatory Coordinator: Jeremy Comeau, Assistant General Counsel, Indiana Utility Regulatory Commission, 101 West Washington Street, Suite 1500 East, Indianapolis, IN 46204, (317) 232-2102, jcomeau@urc.in.gov
Posted: 01/02/2019 by Legislative Services Agency
DIN: 20190102-IR-170180127FRA
Composed: Apr 29,2024 9:46:12PM EDT
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