Indiana § 8-1-8-3 - Construction of chapter

Full text of Indiana Indiana Code § 8-1-8-3 — Construction of chapter, with citation guidance and answers to common questions.

§ 8-1-8-3. Construction of chapter

Sec. 3. This chapter shall be construed as supplemental legislation and not as repealing any statutes in force on May 31, 1921.

Formerly: Acts 1921, c.98, s.3. As amended by P.L.59-1984, SEC.61.

IC 8-1-8.1Chapter 8.1. Electric and Magnetic Fields

8-1-8.1-1"Commission" defined 8-1-8.1-2Determination of necessity for rules 8-1-8.1-3Promulgation of protective rules

IC 8-1-8.1-1"Commission" defined Sec. 1. As used in this chapter, "commission" refers to the Indiana utility regulatory commission established by IC 8-1-1-2.

As added by P.L.94-1993, SEC.1.

IC 8-1-8.1-2Determination of necessity for rules Sec. 2. The commission shall determine, based on the preponderance of evidence in the scientific literature, whether rules are necessary to protect the public health from electric and magnetic fields.

As added by P.L.94-1993, SEC.1.

IC 8-1-8.1-3Promulgation of protective rules Sec. 3. If the commission determines under section 2 of this chapter that rules are necessary, the commission shall by rule adopted under IC 4-22-2 establish requirements that reasonably protect the public health from electric and magnetic fields.

As added by P.L.94-1993, SEC.1.

IC 8-1-8.2Chapter 8.2. Energy Production Zones

8-1-8.2-1"Electric generation facility" 8-1-8.2-2"Energy production zone" 8-1-8.2-3"Local authority" 8-1-8.2-4"Permit" 8-1-8.2-5"Premise of land" 8-1-8.2-6"Project owner" 8-1-8.2-7"Retail electric service" 8-1-8.2-8"Unit" 8-1-8.2-9"Wholesale electric service" 8-1-8.2-10Construction of electric generation facility on energy production zone; exemption from permitting requirements or zoning approval; notice to local authority; required information; public hearing; notice of change 8-1-8.2-11Authority of local authority or unit to regulate siting, construction, of deployment of electric generation facility not located in energy production zone

IC 8-1-8.2-1"Electric generation facility" Sec. 1. (a) As used in this chapter, "electric generation facility" means:

(1) a facility; or

(2) infrastructure associated with a facility;

for the generation of electricity.

(b) The term does not include the following:

(1) A wind power device (as defined in IC 8-1-41-7).

(2) A commercial solar energy system (as defined in IC 8-1-42-2).

As added by P.L.202-2025, SEC.1.

IC 8-1-8.2-2"Energy production zone" Sec. 2. (a) As used in this chapter, "energy production zone" means a premise of land on which any of the following was located as of January 1, 2025:

(1) An electric generation facility with a generating capacity of at least eighty (80) megawatts, regardless of whether the electric generation facility is operational.

(2) A surface or underground mine at which mining operations are no longer occurring.

(b) The term does not include a premise of land on which either of the following was located as of January 1, 2025:

(1) One (1) or more wind power devices (as defined in IC 8-1-41-7) that are integrated into an electric generation facility.

(2) One (1) or more commercial solar energy systems (as defined in IC 8-1-42-2).

As added by P.L.202-2025, SEC.1.

IC 8-1-8.2-3"Local authority" Sec. 3. As used in this chapter, "local authority" has the meaning set forth in IC 36-7-4-1109.

As added by P.L.202-2025, SEC.1.

IC 8-1-8.2-4"Permit" Sec. 4. As used in this chapter, "permit" has the meaning set forth in IC 36-7-4-1109.

As added by P.L.202-2025, SEC.1.

IC 8-1-8.2-5"Premise of land" Sec. 5. As used in this chapter, "premise of land" means property comprising a tract of land on which a project owner proposes to construct an electric generation facility, including land within the perimeter of the tract of land that was not owned by the project owner as of January 1, 2025.

As added by P.L.202-2025, SEC.1.

IC 8-1-8.2-6"Project owner" Sec. 6. As used in this chapter, "project owner" means a person that proposes to construct an electric generation facility.

As added by P.L.202-2025, SEC.1.

IC 8-1-8.2-7"Retail electric service" Sec. 7. As used in this chapter, "retail electric service":

(1) means electric service furnished to a customer, including a residential, commercial, or industrial customer, for consumption by the customer; and

(2) does not include wholesale electric service.

As added by P.L.202-2025, SEC.1.

IC 8-1-8.2-8"Unit" Sec. 8. As used in this chapter, "unit" has the meaning set forth in IC 36-1-2-23.

As added by P.L.202-2025, SEC.1.

IC 8-1-8.2-9"Wholesale electric service" Sec. 9. As used in this chapter, "wholesale electric service" means provision of electricity to another person for resale, including in wholesale markets.

As added by P.L.202-2025, SEC.1.

IC 8-1-8.2-10Construction of electric generation facility on energy production zone; exemption from permitting requirements or zoning approval; notice to local authority; required information; public hearing; notice of change Sec. 10. (a) A project owner is not required to obtain a permit, or any other land use or zoning approval, from a local authority for the construction of an electric generation facility if:

(1) the commission:

(A) grants the project owner a certificate under IC 8-1-8.5-2 for the construction; or

(B) declines jurisdiction over the construction under IC 8-1-2.5-5;

(2) the electric generating facility will be located on a premise of land that is an energy production zone; and

(3) the project owner complies with subsections (b) and (c).

(b) Not later than two hundred seventy (270) days before beginning construction to which subsection (a) applies, a project owner shall provide notice of the construction to the local authority with planning authority under IC 36-7 for the premise of land on which the construction will occur. The notice must include the following information with regard to the construction and the electric generation facility to be constructed:

(1) A comprehensive description of the electric generation facility, including the following:

(A) The planned generation capacity of the electric generation facility, expressed in megawatts.

(B) The energy source or technology that will be used by the electric generation facility to generate electricity.

(2) The expected date on which the construction will begin.

(3) The expected date on which the electric generation facility will begin operation.

(4) Whether the electric generation facility will provide retail electric service, wholesale electric service, or both.

(5) The project owner's plan for eventual decommissioning of the electric generation facility.

(6) If construction of the electric generation facility will entail decommissioning an existing electric generation facility that is located on the premise of land on which the electric generation facility will be located, the project owner's plan for decommissioning the existing electric generation facility, including financial assurances for the decommissioning.

(7) A detailed site plan that includes the location of the following within or adjacent to the premise of land on which the electric generation facility will be constructed:

(A) The structures associated with the electric generation facility.

(B) The:

(i) existing electric generation facility, and any structures associated with the existing electric generation facility; or

(ii) surface or underground mine, and any structures associated with the surface or underground mine;

located on the premise of land on which the electric generation facility will be located.

(D) Regulated drains or ditches.

(E) Flood plains.

(F) Wetlands.

(G) Historic sites or other areas of cultural or environmental significance.

(8) An economic development plan detailing the expected economic effect of the electric generation facility on the unit within which the electric generation facility will be located, including the following:

(A) The anticipated number and types of jobs to be created:

(i) during the construction of the electric generation facility; and

(ii) in the operation of the electric generation facility.

(B) The estimated property tax revenue the electric generation facility will produce for the unit.

(i) cost to the unit; and

(ii) effect on the unit's revenue;

associated with the electric generation facility.

(9) A safety, security, and emergency response plan describing measures to ensure:

(A) site security and safety;

(B) coordination with the unit's services; and

with regard to the construction and operation of the electric generation facility.

(c) Not later than sixty (60) days after a project owner's provision of the notice under subsection (b), the project owner shall hold a public hearing in the unit in which the electric generation facility will be located, during which the project owner shall:

(1) provide information to the public; and

(2) receive public comment;

regarding the electric generation facility and the construction of the electric generation facility. The project owner shall publish notice of the date, time, location, and subject of the public hearing in accordance with IC 5-3-1-2(b).

(d) After providing notice to a local authority under subsection (b), a project owner shall notify the local authority regarding any substantive changes in the information provided by the project owner under subsection (b) that occur before construction begins on the electric generation facility to which the notice pertains.

As added by P.L.202-2025, SEC.1.

IC 8-1-8.2-11Authority of local authority or unit to regulate siting, construction, of deployment of electric generation facility not located in energy production zone Sec. 11. This chapter may not be construed to increase or modify the authority of a local authority or a unit to regulate the siting, construction, or deployment of an electric generation facility that is not located in an energy production zone.

As added by P.L.202-2025, SEC.1.

IC 8-1-8.3Chapter 8.3. Public Utility Employees; Utility Service Interruption Emergencies

8-1-8.3-1"Commercial driver's license" 8-1-8.3-2"Commercial motor vehicle" 8-1-8.3-3"Public utility" 8-1-8.3-4"Utility service interruption emergency" 8-1-8.3-5"Utility service vehicle" 8-1-8.3-6Utility service interruption emergency worker; maximum hours of service

IC 8-1-8.3-1"Commercial driver's license" Sec. 1. As used in this chapter, "commercial driver's license" has the meaning set forth in 49 CFR 383.5 as in effect July 1, 2010.

As added by P.L.42-2004, SEC.1. Amended by P.L.198-2016, SEC.59.

IC 8-1-8.3-2"Commercial motor vehicle" Sec. 2. As used in this chapter, "commercial motor vehicle" has the meaning set forth in IC 9-13-2-31.

As added by P.L.42-2004, SEC.1.

IC 8-1-8.3-3"Public utility" Sec. 3. As used in this chapter, "public utility" has the meaning set forth in IC 8-1-2-1(a).

As added by P.L.42-2004, SEC.1.

IC 8-1-8.3-4"Utility service interruption emergency" Sec. 4. As used in this chapter, "utility service interruption emergency" means an outage or interruption of utility service in Indiana, including a near term threat or occurrence of a meteorological or other condition reasonably likely to result in outages or service interruption. A utility service interruption emergency:

(1) is declared to exist within the meaning of 49 CFR 390.23 when a public utility receives:

(A) notice of or a request to respond to an outage or a service interruption; or

(B) notice of the existence of conditions reasonably likely to result in an outage or a service interruption; and

(2) continues until:

(A) the necessary maintenance or repair work is completed; and

(B) personnel used to perform necessary maintenance or repair work have returned to their respective normal work routines.

As added by P.L.42-2004, SEC.1.

IC 8-1-8.3-5"Utility service vehicle" Sec. 5. As used in this chapter, "utility service vehicle" has the meaning set forth in 49 CFR 395.2.

As added by P.L.42-2004, SEC.1.

IC 8-1-8.3-6Utility service interruption emergency worker; maximum hours of service Sec. 6. An individual who:

(1) is the holder of a commercial driver's license;

(2) is:

(A) an employee;

(B) an employee of a contractor; or

of a public utility in an employment capacity in which the commercial driver's license is used; and

(3) operates a commercial motor vehicle as a utility service vehicle and engages in intrastate maintenance or repair work in response to a utility service interruption emergency;

is exempt from any regulation of the maximum hours of service that the employee may work under 49 CFR 395.

As added by P.L.42-2004, SEC.1.

IC 8-1-8.4Chapter 8.4. Federally Mandated Requirements for Energy Utilities

8-1-8.4-1"Certificate" 8-1-8.4-2"Compliance project" 8-1-8.4-3"Energy utility" 8-1-8.4-4"Federally mandated costs" 8-1-8.4-5"Federally mandated requirements" 8-1-8.4-6Necessity for public convenience and necessity certification; considerations for issuing a certificate 8-1-8.4-7Application for certificate of public convenience and necessity; public hearing; conditions for approval; recovery of costs

IC 8-1-8.4-1"Certificate" Sec. 1. As used in this chapter, "certificate" refers to a certificate of public convenience and necessity issued by the commission under section 7(b) of this chapter.

As added by P.L.150-2011, SEC.1.

IC 8-1-8.4-2"Compliance project" Sec. 2. (a) As used in this chapter, "compliance project" means a project:

(1) undertaken by an energy utility; and

(2) related to the direct or indirect compliance by the energy utility with one (1) or more federally mandated requirements.

(b) The term includes:

(1) an addition; or

(2) an integrity, enhancement, or a replacement project;

undertaken by an energy utility to comply with a federally mandated requirement described in section 5(5) of this chapter.

As added by P.L.150-2011, SEC.1. Amended by P.L.2-2023, SEC.2.

IC 8-1-8.4-3"Energy utility" Sec. 3. As used in this chapter, "energy utility" has the meaning set forth in IC 8-1-2.5-2.

As added by P.L.150-2011, SEC.1.

IC 8-1-8.4-4"Federally mandated costs" Sec. 4. (a) As used in this chapter, "federally mandated costs" means costs that an energy utility has incurred, or estimates that it will incur, in connection with a compliance project, including capital, operating, maintenance, depreciation, tax, or financing costs, or costs that are directly related to the preparation and conduct of a regulatory proceeding.

(b) The term includes costs related to a compliance project and incurred by an energy utility before the date of:

(1) the energy utility's application to the commission under section 7 of this chapter; or

(2) an order of the commission under section 7 of this chapter with respect to the application;

if the commission finds the costs are just and reasonable.

(c) The term does not include fines or penalties assessed against or imposed on an energy utility for violating laws, regulations, or consent decrees related to a federally mandated requirement.

As added by P.L.150-2011, SEC.1. Amended by P.L.2-2023, SEC.3.

IC 8-1-8.4-5"Federally mandated requirements" Sec. 5. As used in this chapter, "federally mandated requirement" means a requirement that the commission determines is imposed on an energy utility by the federal government in connection with any of the following:

(1) The federal Clean Air Act (42 U.S.C. 7401 et seq.).

(2) The federal Water Pollution Control Act (33 U.S.C. 1251 et seq.).

(3) The federal Resource Conservation and Recovery Act (42 U.S.C. 6901 et seq.).

(4) The federal Toxic Substances Control Act (15 U.S.C. 2601 et seq.).

(5) Standards or regulations concerning the integrity, safety, or reliable operation of:

(A) transmission; or

(B) distribution;

pipeline facilities.

(6) Requirements relating to a license issued by the United States Nuclear Regulatory Commission to operate a nuclear energy production or generating facility (as defined in IC 8-1-8.8-8.5).

(7) Any other law, order, or regulation administered or issued by the United States Environmental Protection Agency, the United States Department of Transportation, the Federal Energy Regulatory Commission, or the United States Department of Energy.

As added by P.L.150-2011, SEC.1.

IC 8-1-8.4-6Necessity for public convenience and necessity certification; considerations for issuing a certificate Sec. 6. (a) Except as provided in subsection (c), or unless an energy utility has elected to file for:

(1) a certificate of public convenience and necessity; or

(2) the recovery of costs;

under another statute, an energy utility that seeks to recover federally mandated costs under section 7(c) of this chapter must obtain from the commission a certificate that states that public convenience and necessity is served by the energy utility's compliance project.

(b) The commission shall issue a certificate of public convenience and necessity under section 7(b) of this chapter if the commission finds that the compliance project allows the energy utility to comply directly or indirectly with one (1) or more federally mandated requirements. In determining whether to grant a certificate under this section, the commission shall examine the following factors:

(1) The following, which must be set forth in the energy utility's application for the certificate sought, in accordance with section 7(a) of this chapter:

(A) A description of the federally mandated requirements, including any consent decrees related to the federally mandated requirements, that the energy utility will comply with through the compliance project.

(B) A description of the federally mandated costs associated with the compliance project, including costs that are allocated to the energy utility:

(i) in connection with regional transmission expansion planning and construction; or

(ii) under a Federal Energy Regulatory Commission approved tariff, rate schedule, or agreement.

(C) A description of how the compliance project allows the energy utility to comply with the federally mandated requirements described by the energy utility under clause (A).

(D) Alternative plans that demonstrate that the compliance project is reasonable and necessary.

(E) Information as to whether the compliance project will extend the useful life of an existing energy utility facility and, if so, the value of that extension.

(2) Any other factors the commission considers relevant.

(c) An energy utility is not required to obtain a certificate under this section for a project that constitutes a research and development project.

As added by P.L.150-2011, SEC.1. Amended by P.L.2-2023, SEC.4.

IC 8-1-8.4-7Application for certificate of public convenience and necessity; public hearing; conditions for approval; recovery of costs Sec. 7. (a) As a condition for receiving the certificate required under section 6 of this chapter, an energy utility must file with the commission an application that sets forth the information described in section 6(b) of this chapter, supported with technical information in as much detail as the commission requires. An application under this section must be filed either:

(1) before; or

(2) within a reasonable time with respect to;

any federally mandated compliance date.

(b) The commission shall hold a properly noticed public hearing on each application and grant a certificate only if the commission has:

(1) made a finding that the public convenience and necessity will be served by the compliance project;

(2) approved the incurred and projected federally mandated costs associated with the compliance project; and

(3) made a finding on each of the factors set forth in section 6(b) of this chapter.

(c) If the commission approves under subsection (b) a compliance project and the federally mandated costs associated with the compliance project, the following apply:

(1) Eighty percent (80%) of the approved federally mandated costs shall be recovered by the energy utility through a periodic retail rate adjustment mechanism that allows the timely recovery of the approved federally mandated costs. The commission shall adjust the energy utility's authorized net operating income to reflect any approved earnings for purposes of IC 8-1-2-42(d)(3) and IC 8-1-2-42(g)(3), with recovery commencing no earlier than:

(A) the date of a final agency action regarding the federally mandated requirement; or

(B) in the absence of a final agency action, the date on which the federally mandated requirement becomes effective.

(2) Twenty percent (20%) of the approved federally mandated costs, including depreciation, allowance for funds used during construction, and post in service carrying costs, based on the overall cost of capital most recently approved by the commission, shall be deferred and recovered by the energy utility as part of the next general rate case filed by the energy utility with the commission.

(3) Actual costs that exceed the projected federally mandated costs of the approved compliance project by more than twenty-five percent (25%) shall require specific justification by the energy utility and specific approval by the commission before being authorized in the next general rate case filed by the energy utility with the commission.

As added by P.L.150-2011, SEC.1. Amended by P.L.2-2023, SEC.5; P.L.81-2023, SEC.3; P.L.170-2023, SEC.5.

IC 8-1-8.5Chapter 8.5. Electric Utility Resource Planning and Certification

8-1-8.5-1Definitions 8-1-8.5-2Necessity for certification 8-1-8.5-2.1Retirement, sale, or transfer of electric generation facility; notice; commission consideration and investigation; recovery of accelerated depreciation 8-1-8.5-3Analysis of needs; integrated resource plans; hearings; report 8-1-8.5-3.1Expired 8-1-8.5-3.2Integrated resources plans submitted after June 30, 2021, and before January 1, 2025; commission to evaluate impact of federal phaseout mandates on estimated useful life of existing and proposed generating facilities 8-1-8.5-3.3Integrated resource plans submitted after June 30, 2023; director's evaluation of preferred resource portfolio for attributes of electric utility service specified in state policy 8-1-8.5-3.4Inclusion in integrated resource plan of information regarding advanced transmission technologies and utility's transmission and distribution systems 8-1-8.5-3.5Forecasting group 8-1-8.5-3.6"Electric utility"; "interconnection service"; "surplus interconnection service"; "third party facility"; integrated resource plans filed after December 31, 2029; analysis of potential use of surplus interconnection service at utility owned facilities; solicitations regarding potential use at third party facilities; proposed use exceeding amount available 8-1-8.5-4Commission's review of petition; considerations; impact of federal phaseout mandates; provision of service with attributes specified in state policy; use of surplus interconnection service 8-1-8.5-5Estimate of costs; hearing on application; granting of certificate; findings; utility specific proposals; construction of large generating facilities; competitive bidding 8-1-8.5-5.5Review of continuing need for facility under construction; modification or revocation of certificate; consideration of state policy 8-1-8.5-6Review of construction; force and effect of certificate approved under review; election to defer review 8-1-8.5-6.5Rates; recovery of costs 8-1-8.5-7Exemptions from certification requirements; report to commission of proposed construction required 8-1-8.5-8Construction of chapter; valuation of property 8-1-8.5-9Energy efficiency programs; opt out by industrial customers; prohibition against extending or renewing energy efficiency programs established under DSM order 8-1-8.5-10Energy efficiency goals and programs; evaluation, measurement, and verification; recovery of program costs; opt out by industrial customers 8-1-8.5-11Expired 8-1-8.5-12Coal transition workers; priority for awarding high value workforce ready credit-bearing grants 8-1-8.5-12.1Commission rules concerning granting of certificates for small modular reactors; public utility recovery of small modular reactor project costs 8-1-8.5-13Public utilities' annual resource planning reports; three-year forecast; contents; plans to retire or refuel generation resource; replacement capacity; commission staff reports on planned retirements; commission's review of reports; required investigations; public utility's request for investigation; approval of certificate constitutes approval for required investigation; order to acquire or construct resources or prohibiting retirement or refueling; time frame for order; appeal of order; cost recovery for continued operation; information in commission's annual report 8-1-8.5-14Commission study of advanced transmission technologies 8-1-8.5-15Commission study of use of surplus interconnection service by electric utilities; topics for study; provision of information to commission; protection of confidential information; consultation with stakeholders; inclusion of findings in commission's annual report

IC 8-1-8.5-1Definitions Sec. 1. (a) Except as provided in subsection (c), as used in this chapter, "public utility" means a:

(1) public, municipally owned, or cooperatively owned utility; or

(2) joint agency created under IC 8-1-2.2.

(b) As used in this chapter, "public utility service" means the service rendered by a public utility.

(c) As used in section 13 of this chapter, "public utility" means only those utilities listed in 170 IAC 4-7-2(a) and their successors in interest.

As added by P.L.43-1983, SEC.12. Amended by P.L.23-1988, SEC.40; P.L.54-1992, SEC.4; P.L.60-2021, SEC.1.

IC 8-1-8.5-2Necessity for certification Sec. 2. Except as provided in section 7 of this chapter, a public utility may not begin the construction, purchase, or lease of any steam, water, or other facility for the generation of electricity to be directly or indirectly used for the furnishing of public utility service, even though the facility is for furnishing the service already being rendered, without first obtaining from the commission a certificate that public convenience and necessity requires, or will require, such construction, purchase, or lease.

As added by P.L.43-1983, SEC.12. Amended by P.L.88-1985, SEC.6; P.L.11-1987, SEC.14.

IC 8-1-8.5-2.1Retirement, sale, or transfer of electric generation facility; notice; commission consideration and investigation; recovery of accelerated depreciation Sec. 2.1. (a) This section does not apply to the retirement, sale, or transfer of:

(1) a public utility's electric generation facility if the retirement, sale, or transfer is necessary in order for the public utility to comply with a federal consent decree; or

(2) an electric generation facility that generates electricity for sale exclusively to the wholesale market.

(b) A public utility shall notify the commission if:

(1) the public utility intends or decides to retire, sell, or transfer an electric generation facility with a capacity of at least eighty (80) megawatts; and

(2) the retirement, sale, or transfer:

(A) was not set forth in; or

(B) is to take place on a date earlier than the date specified in;

the public utility's short term action plan in the public utility's most recently filed integrated resource plan.

(c) Upon receiving notice from a public utility under subsection (b), the commission shall consider and may investigate, under IC 8-1-2-58 through IC 8-1-2-60, the public utility's intention or decision to retire, sell, or transfer the electric generation facility. In considering the public utility's intention or decision under this subsection, the commission shall examine the impact the retirement, sale, or transfer would have on the public utility's ability to meet:

(1) the public utility's planning reserve margin requirements or other federal reliability requirements that the public utility is obligated to meet, as described in section 13(n)(6) of this chapter; and

(2) the reliability adequacy metrics set forth in section 13(h) of this chapter.

(d) Before July 1, 2026, if:

(1) a public utility intends or decides to retire, sell, or transfer an electric generation facility with a capacity of at least eighty (80) megawatts; and

(2) the retirement, sale, or transfer:

(A) was not set forth in; or

(B) is to take place on a date earlier than the date specified in;

the public utility's short term action plan in the public utility's most recently filed integrated resource plan;

the commission shall not permit the public utility's depreciation rates, as established under IC 8-1-2-19, to be amended to reflect the accelerated date for the retirement, sale, or transfer of the electric generation asset unless the commission finds that such an adjustment is necessary to ensure the ability of the public utility to provide reliable service to its customers, and that the unamended depreciation rates would cause an unjust and unreasonable impact on the public utility and its ratepayers.

(e) The commission may issue a general administrative order to implement this section.

(f) This section expires July 1, 2026.

As added by P.L.2-2023, SEC.6. Amended by P.L.1-2025, SEC.116; P.L.217-2025, SEC.3.

IC 8-1-8.5-3Analysis of needs; integrated resource plans; hearings; report Sec. 3. (a) The commission shall develop, publicize, and keep current an analysis of the long-range needs for expansion of facilities for the generation of electricity.

(b) This analysis must include an estimate of:

(1) the probable future growth of the use of electricity;

(2) the probable needed generating reserves;

(3) in the judgment of the commission, the optimal extent, size, mix, and general location of generating plants;

(4) in the judgment of the commission, the optimal arrangements for statewide or regional pooling of power and arrangements with other utilities and energy suppliers to achieve maximum efficiencies for the benefit of the people of Indiana; and

(5) the comparative costs of meeting future growth by other means of providing reliable, efficient, and economic electric service, including purchase of power, joint ownership of facilities, refurbishment of existing facilities, conservation (including energy efficiency), load management, distributed generation, and cogeneration.

(d) In developing the analysis, the commission:

(1) shall confer and consult with:

(A) the public utilities in Indiana;

(B) the utility commissions or comparable agencies of neighboring states;

(D) other agencies having relevant information; and

(2) may participate as it considers useful in any joint boards investigating generating plant sites or the probable needs for future generating facilities.

(e) In addition to such reports as public utilities may be required by statute or rule of the commission to file with the commission, a utility:

(1) may submit to the commission a current or updated integrated resource plan as part of a utility specific proposal as to the future needs for electricity to serve the people of the state or the area served by the utility; and

(2) shall submit to the commission an integrated resource plan that assesses a variety of demand side management and supply side resources to meet future customer electricity service needs in a cost effective and reliable manner.

The commission shall adopt rules under IC 4-22-2 concerning the submission of an integrated resource plan under subdivision (2).

(f) Insofar as practicable, each utility, the utility consumer counselor, and any intervenor may attend or be represented at any formal conference conducted by the commission in developing an analysis for the future requirements of electricity for Indiana or this region.

(g) In the course of making the analysis required by subsection (a) and, if applicable, developing an analysis described in subsection (f), the commission shall conduct one (1) or more public hearings.

(h) Each year, the commission shall submit to the governor and to the appropriate committees of the general assembly a report of its analysis regarding the future requirements of electricity for Indiana or this region.

As added by P.L.43-1983, SEC.12. Amended by P.L.88-1985, SEC.7; P.L.53-1992, SEC.2; P.L.246-2015, SEC.1.

IC 8-1-8.5-3.1ExpiredAs added by P.L.250-2019, SEC.2. Expired 1-2-2021 by P.L.250-2019, SEC.2.

IC 8-1-8.5-3.2Integrated resources plans submitted after June 30, 2021, and before January 1, 2025; commission to evaluate impact of federal phaseout mandates on estimated useful life of existing and proposed generating facilities Sec. 3.2. (a) This section applies to an electric utility that submits an integrated resource plan described in section 3(e) of this chapter after June 30, 2021, and before January 1, 2025.

(b) Except as otherwise provided in this section, the definitions in 170 IAC 4-7 apply throughout this section.

(d) As used in this section, "federal phaseout mandate" means any federal statutory or regulatory requirement that:

(1) is established after April 20, 2021, by the Congress of the United States, a federal regulatory agency, or a federal executive order; and

(2) requires the phaseout or discontinuance of a particular type of electric generating facility, technology, or fuel source.

(e) In reviewing an integrated resource plan submitted by an electric utility after June 30, 2021, the commission shall evaluate the impact of federal phaseout mandates on the estimated useful lives of both:

(1) the existing electric generating facilities of the electric utility; and

(2) any proposed electric generating facilities of the electric utility;

including depreciation expense associated with such facilities, as set forth in the integrated resource plan.

As added by P.L.180-2021, SEC.2.

IC 8-1-8.5-3.3Integrated resource plans submitted after June 30, 2023; director's evaluation of preferred resource portfolio for attributes of electric utility service specified in state policy Sec. 3.3. (a) Except as otherwise provided in this section, the definitions in 170 IAC 4-7 apply throughout this section.

(b) As used in this section, "electric utility" refers to an electric utility listed in 170 IAC 4-7-2(a).

(c) In reviewing an integrated resource plan that is submitted to the commission by an electric utility under section 3(e)(2) of this chapter after June 30, 2023, the director of the commission's research, policy, and planning division shall evaluate and comment in the commission's final director's report for the plan as to whether the electric utility's preferred resource portfolio takes into account the attributes of electric utility service set forth in IC 8-1-2-0.6, including:

(1) reliability;

(2) affordability;

(3) resiliency;

(4) stability; and

(5) environmental sustainability;

as described in IC 8-1-2-0.6.

As added by P.L.55-2023, SEC.3.

IC 8-1-8.5-3.4Inclusion in integrated resource plan of information regarding advanced transmission technologies and utility's transmission and distribution systems Sec. 3.4. (a) As used in this section, "advanced transmission technologies" means software or hardware technologies that increase the capacity, efficiency, reliability, or safety of an existing or new electric transmission facility, including:

(1) grid enhancing technologies, such as dynamic line rating, advanced power flow controllers, and topology optimization;

(2) advanced conductors; and

(3) other technologies designed to:

(A) reduce transmission congestion; or

(B) increase the capacity, efficiency, reliability, or safety of an existing or new electric transmission facility.

(b) As used in this section, "electric utility" refers to an electric utility that:

(1) is listed in 170 IAC 4-7-2(a); and

(2) owns and operates a transmission or distribution system.

(c) In any integrated resource plan filed with the commission under 170 IAC 4-7 after December 31, 2025, an electric utility must include a description of the potential use of, or investment in, one (1) or more advanced transmission technologies to enable the electric utility to safely, reliably, efficiently, and cost effectively meet electric system demand, taking into consideration cost, risk, uncertainty, and the alternative investments needed to build new transmission infrastructure if advanced transmission technologies are not deployed.

(d) In any integrated resource plan filed with the commission under 170 IAC 4-7 after December 31, 2029, an electric utility must include a description of the electric utility's transmission and distribution systems, as applicable, as specified by the commission under 170 IAC 4-7.

As added by P.L.10-2025, SEC.1.

IC 8-1-8.5-3.5Forecasting group Sec. 3.5. (a) To arrive at estimates of the probable future growth of the use of electricity required by section 3(b)(1) of this chapter, the commission shall establish a permanent forecasting group to be located at a state supported college or university within Indiana. The commission shall financially support the group, which shall consist of a director and such staff as mutually agreed upon by the commission and college or university, from funds appropriated to the commission.

(b) The forecasting group shall develop and keep current a methodology for forecasting the probable future growth of the use of electricity within Indiana and within this region of the nation. To do this, the group shall solicit the input of residential, commercial, and industrial consumers and the electric industry.

(c) The commission shall use the methodology that the forecasting group devises as the commission's primary methodology in developing and keeping current the commission's:

(1) analysis of the long range needs for expansion of facilities for the generation of electricity required by section 3(a) of this chapter; and

(2) plan for meeting the future requirements of electricity required by sections 3(e), 3(f), and 3(g) of this chapter.

As added by P.L.88-1985, SEC.8. Amended by P.L.53-1992, SEC.3.

IC 8-1-8.5-3.6"Electric utility"; "interconnection service"; "surplus interconnection service"; "third party facility"; integrated resource plans filed after December 31, 2029; analysis of potential use of surplus interconnection service at utility owned facilities; solicitations regarding potential use at third party facilities; proposed use exceeding amount available Sec. 3.6. (a) As used in this section, "electric utility" refers to an electric utility listed in 170 IAC 4-7-2(a).

(b) As used in this section, "interconnection service" refers to a service that is:

(1) established in a standard large generator interconnection agreement, as defined in the Federal Energy Regulatory Commission's pro forma Large Generator Interconnection Procedures for electric generating facilities having a generating facility capacity of more than twenty (20) megawatts;

(2) provided by an electric transmission provider; and

(3) associated with interconnecting a generating facility with the transmission provider's transmission system and enabling the transmission system to receive electric energy and capacity from the generating facility at the point of interconnection.

(1) has not been used; and

(2) is not reasonably expected to be needed;

the use of which would result in the total amount of interconnection service at the point of interconnection remaining the same.

(d) As used in this section, "third party facility", with respect to an electric utility, means a generating facility that is not owned or operated by the electric utility or an affiliate of the electric utility.

(e) In any integrated resource plan filed with the commission under 170 IAC 4-7 after December 31, 2029, an electric utility must include an analysis of the potential for surplus interconnection service to meet immediate needs for capacity and energy at facilities owned by the electric utility. In performing the analysis required under this subsection, an electric utility shall assess the potential use of surplus interconnection service at utility owned facilities with surplus interconnection service greater than twenty (20) megawatts. In addition, the electric utility may solicit information concerning the potential use of surplus interconnection service at third party facilities, including the willingness of the owners or operators of third party facilities to accommodate surplus interconnection service. The electric utility may include in its integrated resource plan the results of a solicitation made under this subsection to the extent that the electric utility receives information concerning viable opportunities for the use of surplus interconnection service at the third party facilities considered in the solicitation.

(f) In an integrated resource plan filed with the commission after December 31, 2029, an electric utility may include, in addition to the information set forth in subsection (e), the proposed use of more than one hundred percent (100%) of the surplus interconnection service at a utility owned facility or a third party facility so as to facilitate the use of the entire interconnection service established for the facility in a standard large generator interconnection agreement, so long as the use of the proposed surplus interconnection service when combined with the existing used capacity does not exceed the total interconnection service established for the facility in the standard large generator interconnection agreement.

As added by P.L.126-2026, SEC.1.

IC 8-1-8.5-4Commission's review of petition; considerations; impact of federal phaseout mandates; provision of service with attributes specified in state policy; use of surplus interconnection service Sec. 4. (a) As used in this section, "federal phaseout mandate" means any federal statutory or regulatory requirement that:

(1) is established after April 20, 2021, by the Congress of the United States, a federal regulatory agency, or a federal executive order; and

(2) requires the phaseout or discontinuance of a particular type of electric generating facility, technology, or fuel source.

(b) As used in this section, "surplus interconnection service" has the meaning set forth in section 3.6 of this chapter.

(c) In acting upon any petition for the construction, purchase, or lease of any facility for the generation of electricity, the commission shall take into account the following:

(1) The applicant's current and potential arrangement with other electric utilities for:

(A) the interchange of power;

(B) the pooling of facilities;

(D) joint ownership of facilities.

(2) Other methods for providing reliable, efficient, and economical electric service, including the refurbishment of existing facilities, conservation, load management, cogeneration, and renewable energy sources.

(3) With respect to a petition that:

(A) is for the construction of a new generating facility; and

(B) is submitted to the commission after June 30, 2021, and before January 1, 2025;

the impact of federal phaseout mandates on the estimated useful life of each proposed generating facility included in the petition, including depreciation expense associated with each facility.

(4) With respect to a petition that is submitted to the commission after June 30, 2023, whether the proposed construction, purchase, or lease of the facility will result in the provision of electric utility service with the attributes set forth in IC 8-1-2-0.6, including:

(A) reliability;

(B) affordability;

(D) stability; and

(E) environmental sustainability;

as described in IC 8-1-2-0.6.

(5) With respect to a petition that is submitted to the commission after December 31, 2029, whether:

(A) the petitioner has conducted an analysis, as part of an integrated resource plan in accordance with section 3.6 of this chapter or otherwise, of the use of surplus interconnection service as an alternative to, or in conjunction with, the proposed construction, purchase, or lease of the facility; and

(B) the proposed construction, use, or lease of the facility will make use of, or allow for the use of, surplus interconnection service.

As added by P.L.43-1983, SEC.12. Amended by P.L.88-1985, SEC.9; P.L.180-2021, SEC.3; P.L.55-2023, SEC.4; P.L.126-2026, SEC.2.

IC 8-1-8.5-5Estimate of costs; hearing on application; granting of certificate; findings; utility specific proposals; construction of large generating facilities; competitive bidding Sec. 5. (a) As a condition for receiving the certificate required under section 2 of this chapter, the applicant shall file an estimate of construction, purchase, or lease costs in such detail as the commission may require.

(b) The commission shall hold a public hearing on each such application. The commission may consider all relevant information related to construction, purchase, or lease costs. The commission shall issue an order granting or denying a certificate not later than two hundred forty (240) days after the date the application for the certificate and the applicant's case in chief are filed with the commission. The commission may issue a general administrative order establishing guidelines regarding the information to be included in the applicant's case in chief. A certificate shall be granted only if the commission has:

(1) made a finding as to the best estimate of construction, purchase, or lease costs based on the evidence of record;

(2) made a finding that either:

(A) the construction, purchase, or lease will be consistent with the commission's analysis (or such part of the analysis as may then be developed, if any) for expansion of electric generating capacity; or

(B) the construction, purchase, or lease is consistent with a utility specific proposal submitted under section 3(e)(1) of this chapter and approved under subsection (d). However, if the commission has developed, in whole or in part, an analysis for the expansion of electric generating capacity and the applicant has filed and the commission has approved under subsection (d) a utility specific proposal submitted under section 3(e)(1) of this chapter, the commission shall make a finding under this clause that the construction, purchase, or lease is consistent with the commission's analysis, to the extent developed, and that the construction, purchase, or lease is consistent with the applicant's plan under section 3(e)(1) of this chapter, to the extent the plan was approved by the commission;

(3) made a finding that the public convenience and necessity require or will require the construction, purchase, or lease of the facility;

(4) made a finding that the facility, if it is a coal-consuming facility, utilizes Indiana coal or is justified, because of economic considerations or governmental requirements, in using non-Indiana coal; and

(5) made the findings under subsection (e), if applicable.

(1) the commission grants a certificate under this chapter based upon a finding under subsection (b)(2) that the construction, purchase, or lease of a generating facility is consistent with the commission's analysis for the expansion of electric generating capacity; and

(2) a court finally determines that the commission analysis is invalid;

the certificate shall remain in full force and effect if the certificate was also based upon a finding under subsection (b)(2) that the construction, purchase, or lease of the facility was consistent with a utility specific plan submitted under section 3(e)(1) of this chapter and approved under subsection (d).

(d) The commission shall consider and approve, in whole or in part, or disapprove a utility specific proposal or an amendment thereto jointly with an application for a certificate under this chapter. However, such an approval or disapproval shall be solely for the purpose of acting upon the pending certificate for the construction, purchase, or lease of a facility for the generation of electricity.

(e) This subsection applies if an applicant proposes to construct a facility with a generating capacity of more than eighty (80) megawatts. Before granting a certificate to the applicant, the commission:

(1) must, in addition to the findings required under subsection (b), find that:

(A) the estimated costs of the proposed facility are, to the extent commercially practicable, the result of competitively bid engineering, procurement, or construction contracts, as applicable; and

(B) if the applicant is an electricity supplier (as defined in IC 8-1-37-6), the applicant allowed or will allow third parties to submit firm and binding bids for the construction of the proposed facility on behalf of the applicant that met or meet all of the technical, commercial, and other specifications required by the applicant for the proposed facility so as to enable ownership of the proposed facility to vest with the applicant not later than the date on which the proposed facility becomes commercially available; and

(2) shall also consider the following factors:

(A) Reliability.

(B) Solicitation by the applicant of competitive bids to obtain purchased power capacity and energy from alternative suppliers.

The applicant, including an affiliate of the applicant, may participate in competitive bidding described in this subsection.

As added by P.L.43-1983, SEC.12. Amended by P.L.88-1985, SEC.10; P.L.53-1992, SEC.4; P.L.210-2014, SEC.1; P.L.246-2015, SEC.2; P.L.264-2017, SEC.4; P.L.83-2023, SEC.1.

IC 8-1-8.5-5.5Review of continuing need for facility under construction; modification or revocation of certificate; consideration of state policy Sec. 5.5. When, in the opinion of the commission, changes in the estimate of the probable future growth of the use of electricity so indicate, the commission shall commence a review of any certificate granted under this chapter to determine whether the public convenience and necessity continues to require the facility under construction. If the commission finds that completion of the facility under construction is no longer in the public interest, the commission may modify or revoke the certificate. In conducting a review under this section, the commission shall consider whether the completion of the facility under construction will result in the provision of electric utility service with the attributes set forth in IC 8-1-2-0.6, including:

(1) reliability;

(2) affordability;

(3) resiliency;

(4) stability; and

(5) environmental sustainability;

as described in IC 8-1-2-0.6, in making a determination as to whether the public convenience and necessity continues to require the facility under construction.

As added by P.L.88-1985, SEC.11. Amended by P.L.53-1992, SEC.5; P.L.55-2023, SEC.5.

IC 8-1-8.5-6Review of construction; force and effect of certificate approved under review; election to defer review Sec. 6. (a) In addition to the review of the continuing need for the facility under construction prescribed in section 5.5 of this chapter, the commission shall, at the request of the public utility, maintain an ongoing review of such construction as it proceeds. The applicant shall submit each year during construction, or at such other periods as the commission and the public utility mutually agree, a progress report and any revisions in the cost estimates for the construction.

(b) If the commission approves the construction and the cost of the portion of the facility under review, the certificate shall remain in full force and effect.

(c) If the commission disapproves of all or part of the construction or cost of the portion of the facility under review, the commission may modify or revoke the certificate.

(d) Alternatively, the public utility may elect to forego commission review under subsection (a) and defer the review of the construction and cost until completion or cancellation of the facility.

As added by P.L.43-1983, SEC.12. Amended by P.L.88-1985, SEC.12; P.L.53-1992, SEC.6.

IC 8-1-8.5-6.5Rates; recovery of costs Sec. 6.5. Absent fraud, concealment, or gross mismanagement, a utility shall recover through rates the actual costs the utility has incurred in reliance on a certificate issued under this chapter, and as modified under sections 5.5 and 6 of this chapter as follows:

(1) If a facility has been found to be completed and the facility's construction has been subject to ongoing review under section 6(a) of this chapter, the costs of construction approved by the commission during the ongoing review shall be included in the utility's rate base without further commission review.

(2) If a facility has been found to be completed and the facility's construction is subject to subsequent review under section 6(d) of this chapter, the costs of construction that do not exceed the estimate found under section 5(b)(1) of this chapter shall be included in the utility's rate base, except for costs that are shown to result from inadequate quality controls. However, inclusion of costs in excess of the estimate found by the commission under section 5(b)(1) of this chapter in the utility's rate base is not permitted unless shown by the utility in construction of that facility to be necessary and prudent.

(3) If a facility has been canceled as a result of the modification or revocation of the certificate under section 5.5 or 6 of this chapter and the facility's construction has been subject to ongoing review under section 6(a) of this chapter (including reviews after cancellation), the costs of construction approved by the commission during the review shall be recovered by the utility by inclusion in rates and amortization over a reasonable time to be determined by the commission. The utility shall be permitted to earn a return, computed using the utility's authorized rate of return, on the unamortized balance.

(4) If a facility has been canceled as a result of the modification or revocation of the certificate under section 5.5 or 6 of this chapter and the facility's construction is subject to subsequent review under section 6(d) of this chapter, the costs of construction incurred before cancellation that were included in the estimate found under section 5(b)(1) of this chapter and that have not been shown to result from inadequate quality controls shall be recovered by the utility by inclusion in rates and amortization over a reasonable time to be determined by the commission. The utility shall be permitted to earn a return, computed using the utility's authorized rate of return, on the unamortized balance. However, costs that were not included in the estimate found by the commission under section 5(b)(1) of this chapter may not be included in rates unless shown by the utility in construction of that facility to be necessary and prudent.

As added by P.L.53-1992, SEC.7.

IC 8-1-8.5-7Exemptions from certification requirements; report to commission of proposed construction required Sec. 7. The certification requirements of this chapter do not apply to a person that:

(1) constructs an electric generating facility primarily for that person's own use and not for the primary purpose of producing electricity, heat, or steam for sale to or for the public for compensation;

(2) constructs an alternate energy production facility, cogeneration facility, or a small hydro facility that complies with the limitations set forth in IC 8-1-2.4-5;

(3) is a municipal utility, including a joint agency created under IC 8-1-2.2-8, and installs an electric generating facility that has a capacity of ten thousand (10,000) kilowatts or less;

(4) is a public utility and:

(A) installs a clean energy project described in IC 8-1-8.8-2(2) that is approved by the commission and that:

(i) uses a clean energy resource described in IC 8-1-37-4(a)(1), IC 8-1-37-4(a)(2), or IC 8-1-37-4(a)(5); and

(ii) has a nameplate capacity of not more than fifty thousand (50,000) kilowatts; and

(B) uses a contractor that:

(i) is subject to Indiana unemployment taxes; and

(ii) is selected by the public utility through bids solicited in a competitive procurement process;

in the engineering, procurement, or construction of the project; or

(5) is:

(A) a corporation organized under IC 8-1-13;

(B) a corporation organized under IC 23-17 that is an electric cooperative and that has at least one (1) member that is a corporation organized under IC 8-1-13; or

(i) surviving corporation that remains after a merger of two (2) or more corporations under IC 8-1-17.5; or

(ii) successor corporation that is formed from a consolidation of two (2) or more corporations under IC 8-1-17.5;

that installs an electric generating facility that has a capacity of ten thousand (10,000) kilowatts or less.

However, a person described in this section shall, nevertheless, be required to report to the commission the proposed construction of such a facility before beginning construction of the facility.

As added by P.L.43-1983, SEC.12. Amended by P.L.168-2013, SEC.2; P.L.264-2017, SEC.5; P.L.57-2024, SEC.1.

IC 8-1-8.5-8Construction of chapter; valuation of property Sec. 8. Except as otherwise provided in this chapter, nothing in this chapter limits the commission's responsibility regarding valuation of utility property under IC 8-1-2-6.

As added by P.L.5-1988, SEC.47. Amended by P.L.53-1992, SEC.8.

IC 8-1-8.5-9Energy efficiency programs; opt out by industrial customers; prohibition against extending or renewing energy efficiency programs established under DSM order Sec. 9. (a) For purposes of this section, "DSM order" refers to an order of the commission that establishes or approves:

(1) energy efficiency targets or goals for electricity suppliers; or

(2) an energy efficiency program sponsored by an electricity supplier.

The term includes the December 9, 2009, order of the commission concerning demand side management programs.

(b) For purposes of this section, "electricity supplier" has the meaning set forth in IC 8-1-2.3-2(b).

(1) sponsored by an electricity supplier or a third party administrator; and

(2) designed to implement energy efficiency improvements (as defined in 170 IAC 4-8-1(j)) for customers.

The term does not include a program designed primarily to reduce demand.

(d) For purposes of this section, "energy efficiency program costs" include:

(1) program costs;

(2) lost revenues; and

(3) incentives approved by the commission.

(e) For purposes of this section, "industrial customer" means a person that receives services at a single site constituting more than one (1) megawatt of electric capacity from an electricity supplier.

(f) An industrial customer may opt out of participating in an energy efficiency program that is established by an electricity supplier by providing notice to the electricity supplier. Except as provided in subsection (g), an electricity supplier may not charge an industrial customer that opts out rates that include energy efficiency program costs that accrue or are incurred after the date on which the industrial customer opts out. However, an industrial customer remains liable for rates that include energy efficiency program costs that accrued or were incurred, or related to investments made, before the date on which the industrial customer opts out, regardless of the date on which the rates are actually assessed against the industrial customer.

(g) An industrial customer that opts out of participating in an energy efficiency program may subsequently opt to participate in the same or a different energy efficiency program. The industrial customer must participate in the subsequent energy efficiency program for at least three (3) years after the date on which the industrial customer opts in. If the industrial customer terminates participation in the subsequent energy efficiency program during the three (3) year period described in this subsection, the industrial customer shall continue paying energy efficiency program rates, including costs described in subsection (f), for the remainder of the three (3) year period.

(h) Energy efficiency targets or goals that are approved or mandated by the commission in a DSM order must be calculated to exclude all load from an industrial customer that opts out under subsection (f).

(i) The commission may adopt:

(1) rules under IC 4-22-2; or

(2) guidelines;

to assist electricity suppliers and industrial customers in complying with this section.

(j) The commission may not:

(1) extend, renew, or require the establishment of an energy efficiency program under; or

(2) after December 31, 2014, require an electricity supplier to meet a goal or target established in;

the DSM order issued by the commission on December 9, 2009. An electricity supplier may not renew or extend an existing contract or enter into a new contract with a statewide third party administrator for an energy efficiency program established or approved by the DSM order issued by the commission on December 9, 2009.

(k) After December 31, 2014, an electricity supplier may continue to timely recover energy efficiency program costs that:

(1) accrued or were incurred under or relate to an energy efficiency program implemented under the DSM order issued by the commission on December 9, 2009; and

(2) are approved by the commission for recovery.

(l) After December 31, 2014, an electricity supplier may offer a cost effective portfolio of energy efficiency programs to customers. An electricity supplier may submit a proposed energy efficiency program to the commission for review. If an electricity supplier submits a proposed energy efficiency program for review and the commission determines that the portfolio included in the proposed energy efficiency program is reasonable and cost effective, the electricity supplier may recover energy efficiency program costs in the same manner as energy efficiency program costs were recoverable under the DSM order issued by the commission on December 9, 2009. The commission may not:

(1) require an energy efficiency program to be implemented by a third party administrator; or

(2) in making its determination, consider whether a third party administrator implements the energy efficiency program.

(m) This section does not affect:

(1) an energy efficiency program offered by an energy utility (as defined in IC 8-1-2.5-2) that is not an electricity supplier; or

(2) the manner in or means by which an energy utility described in subdivision (1) may recover costs associated with an energy efficiency program described in subdivision (1).

As added by P.L.223-2014, SEC.1. Amended by P.L.246-2015, SEC.3; P.L.149-2016, SEC.35.

IC 8-1-8.5-10Energy efficiency goals and programs; evaluation, measurement, and verification; recovery of program costs; opt out by industrial customers Sec. 10. (a) For purposes of this section, "electricity supplier" means a public utility (as defined in IC 8-1-2-1) that furnishes retail electric service to customers in Indiana. The term does not include a utility that is:

(1) a municipally owned utility (as defined in IC 8-1-2-1(h));

(2) a corporation organized under IC 8-1-13;

(3) a corporation organized under IC 23-17 that is an electric cooperative and that has at least one (1) member that is a corporation organized under IC 8-1-13; or

(4) a joint agency created under IC 8-1-2.2-8.

(b) For purposes of this section, "energy efficiency" means a reduction in electricity use for a comparable level of electricity service.

(c) For purposes of this section, "energy efficiency goals" means all energy efficiency produced by cost effective plans that are:

(1) reasonably achievable;

(2) consistent with an electricity supplier's integrated resource plan; and

(3) designed to achieve an optimal balance of energy resources in an electricity supplier's service territory.

(d) For purposes of this section, "energy efficiency program" or "program" means a program that is:

(1) sponsored by an electricity supplier; and

(2) designed to implement energy efficiency improvements.

The term does not include a program designed primarily to reduce demand for limited intervals of time, such as during peak electricity usage or emergency conditions.

(e) For purposes of this section, "lost revenues" means the difference, if any, between:

(1) revenues lost; and

(2) the variable operating and maintenance costs saved;

by an electricity supplier as a result of implementing energy efficiency programs.

(f) For purposes of this section, "plan" refers to the goals, programs, program budgets, program costs, and procedures submitted by an electricity supplier to the commission under subsection (h).

(g) For purposes of this section, "program costs" include the following:

(1) Direct and indirect costs of energy efficiency programs.

(2) Costs associated with the evaluation, measurement, and verification of program results.

(3) Other recoveries or incentives approved by the commission, including lost revenues and financial incentives approved by the commission under subsection (o).

(h) Beginning not later than calendar year 2017, and not less than one (1) time every three (3) years, an electricity supplier shall petition the commission for approval of a plan that includes:

(1) energy efficiency goals;

(2) energy efficiency programs to achieve the energy efficiency goals;

(3) program budgets and program costs; and

(4) evaluation, measurement, and verification procedures that must include independent evaluation, measurement, and verification.

An electricity supplier may submit a plan required under this subsection to the commission for a determination of the overall reasonableness of the plan either as part of a general basic rate proceeding or as an independent proceeding. A petition submitted under this subsection may include a home energy efficiency assistance program for qualified customers of the electricity supplier whether or not the program is cost effective. The commission shall make the petition and its disclosable contents available through the commission's website.

(i) At the same time an electricity supplier petitions the commission under subsection (h), the electricity supplier shall:

(1) provide a copy of the petition and plan to the office of utility consumer counselor; and

(2) post an electronic copy of the petition and plan on the electricity supplier's website. The electricity supplier may redact confidential or proprietary information.

(j) In making a determination of the overall reasonableness of a plan submitted under subsection (h), the commission shall consider the following:

(1) Projected changes in customer consumption of electricity resulting from the implementation of the plan.

(2) A cost and benefit analysis of the plan, including the likelihood of achieving the goals of the energy efficiency programs included in the plan.

(3) Whether the plan is consistent with the following:

(A) The state energy analysis developed by the commission under section 3 of this chapter.

(B) The electricity supplier's most recent long range integrated resource plan submitted to the commission.

(4) The inclusion and reasonableness of procedures to evaluate, measure, and verify the results of the energy efficiency programs included in the plan, including the alignment of the procedures with applicable environmental regulations, including federal regulations concerning credits for emission reductions.

(5) Any undue or unreasonable preference to any customer class resulting, or potentially resulting, from the implementation of an energy efficiency program or from the overall design of a plan.

(6) Comments provided by customers, customer representatives, the office of utility consumer counselor, and other stakeholders concerning the adequacy and reasonableness of the plan, including alternative or additional means to achieve energy efficiency in the electricity supplier's service territory.

(7) The effect, or potential effect, in both the long term and the short term, of the plan on the electric rates and bills of customers that participate in energy efficiency programs compared to the electric rates and bills of customers that do not participate in energy efficiency programs.

(8) The lost revenues and financial incentives associated with the plan and sought to be recovered or received by the electricity supplier.

(9) The electricity supplier's current integrated resource plan and the underlying resource assessment.

(10) Any other information the commission considers necessary.

(k) If, after notice and hearing, the commission determines that an electricity supplier's plan is reasonable in its entirety, the commission shall:

(1) approve the plan in its entirety;

(2) allow the electricity supplier to recover all associated program costs on a timely basis through a periodic rate adjustment mechanism; and

(3) allocate and assign costs associated with a program to the class or classes of customers that are eligible to participate in the program.

(l) If, after notice and hearing, the commission determines that an electricity supplier's plan is not reasonable because the costs associated with one (1) or more programs included in the plan exceed the projected benefits of the program or programs, the commission:

(1) may exclude the program or programs and approve the remainder of the plan; and

(2) shall allow the electricity supplier to recover only those program costs associated with the portion of the plan approved under subdivision (1) on a timely basis through a periodic rate adjustment mechanism.

(m) If, after notice and hearing, the commission determines that an electricity supplier's plan is not reasonable in its entirety, the commission shall issue an order setting forth the reasons supporting its determination. The electricity supplier shall submit a modified plan within a reasonable time. After notice and hearing, the commission shall issue an order approving or denying the modified plan. If the commission approves the modified plan, the commission shall allow the electricity supplier to recover program costs associated with the modified plan on a timely basis through a periodic rate adjustment mechanism.

(n) The commission may not:

(1) require an energy efficiency program to be implemented by a third party administrator; or

(2) in making a determination of reasonableness under subsection (j), consider whether a third party administrator implements an energy efficiency program.

(o) If the commission finds a plan submitted by an electricity supplier under subsection (h) to be reasonable, the commission shall allow the electricity supplier to recover or receive the following:

(1) Reasonable financial incentives that:

(A) encourage implementation of cost effective energy efficiency programs; or

(B) eliminate or offset regulatory or financial bias:

(i) against energy efficiency programs; or

(ii) in favor of supply side resources.

(2) Reasonable lost revenues.

A retail rate adjustment mechanism proposed by an electricity supplier under this section to implement the timely recovery of program costs (including reasonable lost revenues) may be based on a reasonable forecast, with consideration given to the electricity supplier's historical lost revenue forecasting accuracy. If forecasted data is used, the retail rate adjustment mechanism must include a reconciliation mechanism to correct for any variance between the forecasted program costs (including reasonable lost revenues and financial incentives) and the actual program costs (including reasonable lost revenues and financial incentives based on the evaluation, measurement, and verification of the energy efficiency programs under the plan).

(p) An industrial customer (as defined in section 9(e) of this chapter) may opt out of an electricity supplier's plan under this section by following the procedure set forth in section 9(f) and 9(g) of this chapter. The opt out of an industrial customer who has previously complied with the procedure set forth in section 9(f) of this chapter constitutes an opt out of an electricity supplier's plan under this section. An industrial customer may follow the procedure set forth in section 9(g) of this chapter to opt back in.

(q) The commission shall adopt:

(1) rules under IC 4-22-2; or

(2) guidelines;

to assist electricity suppliers and industrial customers in complying with this section.

As added by P.L.246-2015, SEC.4. Amended by P.L.1-2025, SEC.117.

IC 8-1-8.5-11ExpiredAs added by P.L.165-2020, SEC.1. Expired 5-1-2021 by P.L.165-2020, SEC.1.

IC 8-1-8.5-12Coal transition workers; priority for awarding high value workforce ready credit-bearing grants Sec. 12. (a) As used in this section, "coal industry employment" means employment:

(1) at a commercial coal mine in Indiana;

(2) at a coal fired electric generating unit in Indiana; or

(3) in an Indiana based manufacturing or transportation supply chain serving:

(A) a commercial coal mine in Indiana; or

(B) a coal fired electric generating unit in Indiana.

(b) As used in this section, "coal transition worker" means:

(1) an individual who:

(A) has been laid off or terminated from the individual's coal industry employment; or

(B) has received a notice of termination or layoff from the individual's coal industry employment;

as a result of the permanent closure of, or a substantial layoff at, a commercial coal mine in Indiana or a coal fired electric generating unit in Indiana; or

(2) an individual who:

(A) has:

(i) been laid off or terminated, for a reason other than cause; or

(ii) received a notice of termination or layoff, for a reason other than cause;

from the individual's coal industry employment; and

(B) is unlikely to obtain employment in an industry described in subsection (a)(1) through (a)(3) because of market forces or other factors affecting the industry.

(c) In awarding high value workforce ready credit-bearing grants under IC 21-12-8, the commission for higher education, in conjunction with the department of workforce development, shall give priority to an applicant who is a coal transition worker if the applicant is otherwise eligible for a grant under IC 21-12-8-9.

As added by P.L.165-2020, SEC.2.

IC 8-1-8.5-12.1Commission rules concerning granting of certificates for small modular reactors; public utility recovery of small modular reactor project costs Sec. 12.1. (a) As used in this section, "project development costs" means costs that have been incurred, or are reasonably estimated to be incurred, in the development of one (1) or more small modular nuclear reactors, including:

(1) evaluation, design, and engineering costs;

(2) costs for federal approvals and licensing;

(3) costs for environmental analyses and permitting;

(4) early site permit (as defined in 10 CFR 52.1) costs;

(5) equipment procurement costs; and

(6) authorized carrying costs.

(b) As used in this section, "small modular nuclear reactor" means a nuclear reactor that:

(1) has a rated electric generating capacity of not more than four hundred seventy (470) megawatts;

(2) is capable of being constructed and operated, either:

(A) alone; or

(B) in combination with one (1) or more similar reactors if additional reactors are, or become, necessary;

at a single site; and

(3) is required to be licensed by the United States Nuclear Regulatory Commission.

The term includes a nuclear reactor that is described in this subsection and that uses a process to produce hydrogen that can be used for energy storage, as a fuel, or for other uses.

(c) Not later than July 1, 2023, the commission, in consultation with the department of environmental management, shall adopt rules under IC 4-22-2 concerning the granting of certificates under this chapter for the construction, purchase, or lease of small modular nuclear reactors:

(1) in Indiana for the generation of electricity to be directly or indirectly used to furnish public utility service to Indiana customers; or

(2) at the site of a nuclear energy production or generating facility that supplies electricity to Indiana retail customers on July 1, 2011.

(d) Rules adopted by the commission under this section must provide for the following:

(1) That in acting on a public utility's petition for the construction, purchase, or lease of one (1) or more small modular nuclear reactors, as described in subsection (c), the commission shall consider the following:

(A) Whether, and to what extent, the one (1) or more small modular nuclear reactors proposed by the public utility will replace a loss of generating capacity in the public utility's portfolio resulting from the retirement or planned retirement of one (1) or more of the public utility's existing electric generating facilities that:

(i) are located in Indiana; and

(ii) use coal or natural gas as a fuel source.

(B) Whether one (1) or more of the small modular nuclear reactors that will replace an existing facility will be located on the same site as or near the existing facility and, if so, potential opportunities for the public utility to:

(i) make use of any land and existing infrastructure or facilities already owned or under the control of the public utility; or

(ii) create new employment opportunities for workers who have been, or would be, displaced as a result of the retirement of the existing facility.

(2) That the commission may grant a certificate under this chapter under circumstances and for locations other than those described in subdivision (1).

(3) That the commission may not grant a certificate under this chapter unless the owner or operator of a proposed small modular nuclear reactor provides evidence of a plan to apply for all licenses or permits to construct or operate the proposed small modular nuclear reactor as may be required by:

(A) the United States Nuclear Regulatory Commission;

(B) the department of environmental management; or

(C) any other relevant state or federal regulatory agency with jurisdiction over the construction or operation of nuclear generating facilities.

(4) That any:

(A) reports;

(B) notices of violations; or

sent to or from the United States Nuclear Regulatory Commission by or to the owner or operator of a proposed small nuclear reactor must be submitted by the owner or operator to the commission within such times as prescribed by the commission, subject to the commission's duty to treat as confidential and protect from public access and disclosure any information that is contained in a report or notice and that is considered confidential or exempt from public access and disclosure under state or federal law.

(5) That any person that owns or operates a small modular nuclear reactor in Indiana may not store:

(A) spent nuclear fuel (as defined in IC 13-11-2-216); or

(B) high level radioactive waste (as defined in IC 13-11-2-102);

from the small modular nuclear reactor on the site of the small modular nuclear reactor without first meeting all applicable requirements of the United States Nuclear Regulatory Commission.

(e) A public utility may petition the commission for approval to incur, before obtaining a certificate under this chapter, project development costs for the development of one (1) or more small modular nuclear reactors. The public utility must file with the petition the public utility's case in chief, which must contain the information and supporting documentation regarding the factors the commission must consider under this subsection. In reviewing a petition and the supporting case in chief under this subsection, the commission shall consider the following:

(1) Whether a project by the utility to construct, purchase, or lease a small modular nuclear reactor is reasonably consistent with:

(A) this section and rules adopted by the commission under this section; and

(B) the purposes set forth in IC 8-1-8.8-1(b), as applicable.

(2) The following factors with respect to the project development costs and the project for which they are to be incurred:

(A) The amount of project development costs the public utility anticipates incurring.

(B) The anticipated timeline for incurring the project development costs.

(C) The anticipated date by which the public utility will make a decision as to whether to seek a certificate under this chapter.

The commission shall review a petition submitted under this subsection and issue a final order approving or denying the petition not later than one hundred eighty (180) days after receiving the petition and complete case in chief. However, if the commission makes a docket entry extending the procedural schedule and the public utility does not object to the entered extension, the commission may extend the one hundred eighty (180) day time frame for issuing a final order under this subsection for the amount of time set forth in the docket entry. In an order approving a petition, the commission must make a finding as to the best estimate and reasonableness of project development costs based on the evidence of record.

(f) If a public utility has received approval from the commission under subsection (e) to incur project development costs, the public utility may petition the commission at any time before or during the development and execution of a small modular nuclear reactor project for the approval of a rate schedule that periodically adjusts the public utility's rates and charges to provide for the timely recovery of project development costs. A petition under this subsection must describe any efforts by the public utility to pursue funding opportunities from the United States Department of Energy to offset the project development costs that the public utility seeks to recover under the proposed rate schedule.

(g) If, after reviewing a public utility's proposed rate schedule in a petition submitted under subsection (f), the commission determines that the public utility has incurred or will incur project development costs that are:

(1) reasonable in amount;

(2) necessary to support the construction, purchase, or lease of a small modular nuclear reactor; and

(3) consistent with the commission's finding as to the best estimate of project development costs in the commission's order of approval under subsection (e);

the commission shall approve the recovery of the project development costs, subject to subsections (h) and (i). However, a public utility may not file adjustments to a rate schedule to adjust for cost recovery approved under this subsection more than one (1) time every twelve (12) months.

(h) A public utility that recovers project development costs under subsection (g) shall recover eighty percent (80%) of the approved project development costs under the rate schedule approved under subsection (g) and shall defer the remaining twenty percent (20%) of approved project development costs, including, to the extent applicable, depreciation, allowance for funds used during construction, and post in service carrying costs, based on the overall cost of capital most recently approved by the commission, and shall recover those project development costs as part of the next general rate case that the public utility files with the commission.

(i) The recovery of a public utility's project development costs through a periodic rate adjustment mechanism approved by the commission under subsection (g) must occur over a period that is equal to:

(1) the period over which the approved project development costs are incurred; or

(2) three (3) years;

whichever is less.

(j) Project development costs that are found by the commission to be reasonable, necessary, and consistent with the best estimate of project development costs in the commission's order of approval under subsection (e) shall be recovered by a public utility by inclusion in the public utility's rates and charges. Project development costs that are incurred by a public utility and that exceed the best estimate of project development costs under subsection (e) may not be included in the public utility's rates and charges unless found by the commission to be reasonable, necessary, and prudent in supporting the construction, purchase, or lease of the small modular nuclear reactor for which they were incurred. Project development costs that are incurred by a public utility for a project that is canceled or not completed may be recovered by the public utility if found by the commission to be reasonable, necessary, and prudently incurred, but such costs shall be recovered without a return unless the commission also finds that:

(1) the decision to cancel or not complete the project was prudently made for good cause;

(2) the project development costs incurred will be offset, as applicable, by:

(A) funding opportunities from the United States Department of Energy that are pursued in good faith by the public utility;

(B) a recoupment of revenues received by the public utility from one (1) or more third parties for the transfer of assets created through the costs incurred; or

(3) a return on the project development costs incurred is appropriate under the circumstances to avoid harm to the public utility and its customers.

(k) A public utility may elect not to seek approval of, or cost recovery for, project development costs under subsections (e) through (i) and instead seek approval from the commission to defer and amortize project development costs in accordance with the procedures set forth in section 6.5 of this chapter with respect to construction costs.

(l) The commission may adopt rules under IC 4-22-2 to implement subsections (e) through (k).

(m) This section shall not be construed to affect the authority of the United States Nuclear Regulatory Commission.

As added by P.L.155-2022, SEC.1. Amended by P.L.11-2023, SEC.35; P.L.33-2023, SEC.1; P.L.93-2024, SEC.67; P.L.48-2025, SEC.1.

IC 8-1-8.5-13Public utilities' annual resource planning reports; three-year forecast; contents; plans to retire or refuel generation resource; replacement capacity; commission staff reports on planned retirements; commission's review of reports; required investigations; public utility's request for investigation; approval of certificate constitutes approval for required investigation; order to acquire or construct resources or prohibiting retirement or refueling; time frame for order; appeal of order; cost recovery for continued operation; information in commission's annual report Sec. 13. (a) The general assembly finds that it is in the public interest to support the reliability, availability, and diversity of electric generating capacity in Indiana for the purpose of providing reliable and stable electric service to customers of public utilities.

(b) As used in this section, "appropriate regional transmission organization", with respect to a public utility, refers to the regional transmission organization approved by the Federal Energy Regulatory Commission for the control area that includes the public utility's assigned service area (as defined in IC 8-1-2.3-2).

(c) As used in this section, "capacity market" means an auction conducted by an appropriate regional transmission organization to determine a market clearing price for capacity based on the planning reserve margin requirements established by the appropriate regional transmission organization for a planning year with respect to which an auction has not yet been conducted.

(d) As used in this section, "fall unforced capacity", or "fall UCAP", with respect to an electric generating facility, means:

(1) the capacity value of the electric generating facility's installed capacity rate adjusted for the electric generating facility's average forced outage rate for the fall period, calculated as required by the appropriate regional transmission organization or by the Federal Energy Regulatory Commission;

(2) a metric that is similar to the metric described in subdivision (1) and that is required by the appropriate regional transmission organization; or

(3) if the appropriate regional transmission organization does not require a metric described in subdivision (1) or (2), a metric that:

(A) can be used to demonstrate that a public utility has sufficient capacity to:

(i) provide reliable electric service to Indiana customers for the fall period; and

(ii) meet its planning reserve margin requirement and other federal reliability requirements described in subsection (n)(6); and

(B) is acceptable to the commission.

(e) As used in this section, "MISO" refers to the regional transmission organization known as the Midcontinent Independent System Operator that operates the bulk power transmission system serving most of the geographic territory in Indiana.

(f) As used in this section, "planning reserve margin requirement", with respect to a public utility for a particular resource planning year, means the planning reserve margin requirement for that planning year that the public utility is obligated to meet in accordance with the public utility's membership in the appropriate regional transmission organization.

(g) As used in this section, "refuel" or "refueling" means a planned fuel conversion from one fuel source to another fuel source with respect to an electric generation resource with a nameplate capacity of at least one hundred twenty-five (125) megawatts by a public utility.

(h) As used in this section, "reliability adequacy metrics", with respect to a public utility, means calculations used to demonstrate all of the following:

(1) Subject to subsection (u)(2), that the public utility:

(A) has in place sufficient summer UCAP; or

(B) can reasonably acquire not more than:

(i) thirty percent (30%) of its total summer UCAP from capacity markets, with respect to a report filed with the commission under subsection (n) before July 1, 2023; or

(ii) fifteen percent (15%) of its total summer UCAP from capacity markets, with respect to a report filed with the commission under subsection (n) after June 30, 2023;

such that it will have sufficient summer UCAP;

to provide reliable electric service to Indiana customers, and to meet its planning reserve margin requirement and other federal reliability requirements described in subsection (n)(6).

(2) Subject to subsection (u)(2), that the public utility:

(A) has in place sufficient winter UCAP; or

(B) can reasonably acquire not more than:

(i) thirty percent (30%) of its total winter UCAP from capacity markets, with respect to a report filed with the commission under subsection (n) before July 1, 2023; or

(ii) fifteen percent (15%) of its total winter UCAP from capacity markets, with respect to a report filed with the commission under subsection (n) after June 30, 2023;

such that it will have sufficient winter UCAP;

to provide reliable electric service to Indiana customers, and to meet its planning reserve margin requirement and other federal reliability requirements described in subsection (n)(6).

(3) Subject to subsection (u)(2), with respect to a report filed with the commission under subsection (n) after June 30, 2026, that the public utility:

(A) has in place sufficient spring UCAP; or

(B) can reasonably acquire not more than fifteen percent (15%) of its total spring UCAP from capacity markets, such that it will have sufficient spring UCAP;

to provide reliable electric service to Indiana customers, and to meet its planning reserve margin requirement and other federal reliability requirements described in subsection (n)(6).

(4) Subject to subsection (u)(2), with respect to a report filed with the commission under subsection (n) after June 30, 2026, that the public utility:

(A) has in place sufficient fall UCAP; or

(B) can reasonably acquire not more than fifteen percent (15%) of its total fall UCAP from capacity markets, such that it will have sufficient fall UCAP;

to provide reliable electric service to Indiana customers, and to meet its planning reserve margin requirement and other federal reliability requirements described in subsection (n)(6).

(i) As used in this section, "retire" or retirement" means a planned permanent ceasing of electric generation operations with respect to an electric generation resource with a nameplate capacity of at least one hundred twenty-five (125) megawatts by a public utility.

(j) As used in this section, "spring unforced capacity", or "spring UCAP", with respect to an electric generating facility, means:

(1) the capacity value of the electric generating facility's installed capacity rate adjusted for the electric generating facility's average forced outage rate for the spring period, calculated as required by the appropriate regional transmission organization or by the Federal Energy Regulatory Commission;

(2) a metric that is similar to the metric described in subdivision (1) and that is required by the appropriate regional transmission organization; or

(3) if the appropriate regional transmission organization does not require a metric described in subdivision (1) or (2), a metric that:

(A) can be used to demonstrate that a public utility has sufficient capacity to:

(i) provide reliable electric service to Indiana customers for the spring period; and

(ii) meet its planning reserve margin requirement and other federal reliability requirements described in subsection (n)(6); and

(B) is acceptable to the commission.

(k) As used in this section, "summer unforced capacity", or "summer UCAP", with respect to an electric generating facility, means:

(1) the capacity value of the electric generating facility's installed capacity rate adjusted for the electric generating facility's average forced outage rate for the summer period, calculated as required by the appropriate regional transmission organization or by the Federal Energy Regulatory Commission; or

(2) a metric that is similar to the metric described in subdivision (1) and that is required by the appropriate regional transmission organization.

(l) As used in this section, "winter unforced capacity", or "winter UCAP", with respect to an electric generating facility, means:

(1) the capacity value of the electric generating facility's installed capacity rate adjusted for the electric generating facility's average forced outage rate for the winter period, calculated as required by the appropriate regional transmission organization or by the Federal Energy Regulatory Commission;

(2) a metric that is similar to the metric described in subdivision (1) and that is required by the appropriate regional transmission organization; or

(3) if the appropriate regional transmission organization does not require a metric described in subdivision (1) or (2), a metric that:

(A) can be used to demonstrate that a public utility has sufficient capacity to:

(i) provide reliable electric service to Indiana customers for the winter period; and

(ii) meet its planning reserve margin requirement and other federal reliability requirements described in subsection (n)(6); and

(B) is acceptable to the commission.

(m) A public utility that owns and operates an electric generating facility serving customers in Indiana shall operate and maintain the facility using good utility practices and in a manner:

(1) reasonably intended to support the provision of reliable and economic electric service to customers of the public utility;

(2) reasonably consistent with the resource reliability requirements of MISO or any other appropriate regional transmission organization; and

(3) reasonably maximizes the economic value of the electric generating facility.

(n) Not later than thirty (30) days after the deadline for submitting an annual planning reserve margin report to MISO, each public utility providing electric service to Indiana customers shall, regardless of whether the public utility is required to submit an annual planning reserve margin report to MISO, file with the commission a report, in a form specified by the commission, that provides the following information for each of the next three (3) resource planning years, beginning with the planning year covered by the planning reserve margin report to MISO described in this subsection:

(1) The:

(A) capacity;

(B) location; and

for each electric generating facility that is owned and operated by the electric utility and that will be used to provide electric service to Indiana customers.

(2) With respect to a report submitted to the commission after December 31, 2025, the amount of generating resource capacity or energy, or both, that the public utility plans to retire and that is owned and operated by the public utility and used to provide retail electric service in Indiana, including the:

(A) capacity;

(B) location;

(D) planned retirement date;

for each electric generating facility. The public utility must include information as to whether the planned retirement is required in order to comply with environmental laws, regulations, or court orders, including consent decrees, that are or will be in effect at the time of the planned retirement. In addition, the public utility must provide its economic rationale for the planned retirement, including anticipated ratepayer impacts, and information concerning the public utility's plan or plans with respect to the amount of replacement capacity identified to provide approximately the same accredited capacity within the appropriate regional transmission organization as the amount of capacity of the facility to be retired.

(3) With respect to a report submitted to the commission after December 31, 2025, the amount of generating resource capacity or energy, or both, that the public utility plans to refuel, including the:

(A) capacity;

(B) location;

(D) proposed fuel source; and

(E) planned completion date of the refueling;

with respect to each electric generating facility that the public utility plans to refuel. The public utility must provide its economic rationale for the planned refueling, including anticipated ratepayer impacts, and information concerning the public utility's plan or plans with respect to the extent to which the refueling will maintain or increase the current generating resource accredited capacity or energy, or both, that the electric generating facility provides, so as to provide approximately the same accredited capacity within the appropriate regional transmission organization.

(4) The amount of generating resource capacity or energy, or both, that the public utility has procured under contract and that will be used to provide electric service to Indiana customers, including the:

(A) capacity;

(B) location; and

for each electric generating facility that will supply capacity or energy under the contract, to the extent known by the public utility.

(5) The amount of demand response resources available to the public utility under contracts and tariffs.

(6) The following:

(A) The planning reserve margin requirements established by MISO for the planning years covered by the report, to the extent known by the public utility with respect to any particular planning year covered by the report.

(B) If applicable, any other planning reserve margin requirement that:

(i) applies to the planning years covered by the report; and

(ii) the public utility is obligated to meet in accordance with the public utility's membership in an appropriate regional transmission organization;

to the extent known by the public utility with respect to any particular planning year covered by the report.

(C) Other federal reliability requirements that the public utility is obligated to meet in accordance with its membership in an appropriate regional transmission organization with respect to the planning years covered by the report, to the extent known by the public utility with respect to any particular planning year covered by the report.

For each planning reserve margin requirement reported under clause (A) or (B), the public utility shall include a comparison of that planning reserve margin requirement to the planning reserve margin requirement established by the same regional transmission organization for the 2021-2022 planning year.

(7) The reliability adequacy metrics of the public utility, as forecasted for the three (3) planning years covered by the report.

(o) Upon request by a public utility, the commission shall determine whether information provided in a report filed by the public utility under subsection (n):

(1) is confidential under IC 5-14-3-4 or is a trade secret under IC 24-2-3;

(2) is exempt from public access and disclosure by Indiana law; and

(3) shall be treated as confidential and protected from public access and disclosure by the commission.

(p) A joint agency created under IC 8-1-2.2 may file the report required under subsection (n) as a consolidated report on behalf of any or all of the municipally owned utilities that make up its membership.

(q) A:

(1) corporation organized under IC 23-17 that is an electric cooperative and that has at least one (1) member that is a corporation organized under IC 8-1-13; or

(2) general district corporation within the meaning of IC 8-1-13-23;

may file the report required under subsection (n) as a consolidated report on behalf of any or all of the cooperatively owned electric utilities that it serves.

(r) In reviewing a report filed by a public utility under subsection (n), the commission may request technical assistance from MISO or any other appropriate regional transmission organization in determining:

(1) the planning reserve margin requirements or other federal reliability requirements that the public utility is obligated to meet, as described in subsection (n)(6); and

(2) whether the resources available to the public utility under subsections (n)(1) through (n)(5) will be adequate to support the provision of reliable electric service to the public utility's Indiana customers.

(s) With respect to a report submitted under subsection (n) after December 31, 2025, commission staff shall review the reports submitted by public utilities and shall, not later than ninety (90) days after the date of submission of the reports, submit to the commission a staff report concerning any planned retirements included in the reports under subsection (n)(2). The report must make recommendations to the commission based on whether each planned retirement:

(1) is consistent with the standards set forth in subsection (m);

(2) will be replaced with an amount of replacement capacity that will provide approximately the same accredited capacity within the appropriate regional transmission organization as the amount of capacity of the facility to be retired;

(3) will not adversely and unreasonably impact a public utility's ability to provide safe, reliable, and economical electric utility service to the public utility's customers;

(4) will result in the provision to Indiana customers of electric utility service with the attributes of:

(A) reliability;

(B) affordability;

(D) stability; and

(E) environmental sustainability;

as set forth in IC 8-1-2-0.6; and

(5) is required in order to comply with environmental laws, regulations, or court orders, including consent decrees, that are or will be in effect at the time of the planned retirement.

(t) The commission shall make the staff reports prepared under subsection (s) publicly available by posting the staff reports on the commission's website. Upon the posting of a staff report on the commission's website, the commission shall accept public comments on the report for a period not to exceed thirty (30) days after the date of posting.

(u) If, after reviewing a report filed by a public utility under subsection (n) and any staff report prepared with respect to the public utility under subsection (s), the commission is not satisfied that the public utility can either:

(1) satisfy both:

(A) its planning reserve margin requirement or other federal reliability requirements that the public utility is obligated to meet, as described in subsection (n)(6); and

(B) the reliability adequacy metrics set forth in subsection (h); or

(2) provide sufficient reason as to why the public utility is unable to satisfy both:

(A) its planning reserve margin requirement or other federal reliability requirements that the public utility is obligated to meet, as described in subsection (n)(6); and

(B) the reliability adequacy metrics set forth in subsection (h);

during one (1) more of the planning years covered by the report, the commission shall conduct an investigation under IC 8-1-2-58 through IC 8-1-2-60 as to the reasons for the public utility's potential inability to meet the requirements described in subdivision (1) or provide sufficient reason as to that inability, as described in subdivision (2). In addition, if the public utility has indicated in its report under subsection (n)(2) that it plans to retire an electric generating facility within one (1) year of the date of the report, the commission must conduct an investigation under IC 8-1-2-58 through IC 8-1-2-60 as to the reasons for the public utility's potential inability to meet the requirements described in subdivision (1) or provide sufficient reason as to that inability, as described in subdivision (2). However, a public utility may request, not earlier than three (3) years before the planned retirement date of an electric generation facility, that the commission conduct an investigation under IC 8-1-2-58 through IC 8-1-2-60, for the purposes described in this subsection, with respect to the planned retirement. If the commission conducts an investigation at the request of a public utility within the three (3) year period before the planned retirement date of an electric generation facility, the commission may not conduct a subsequent investigation that would otherwise be required under this subsection with respect to the retirement of that same electric generation facility unless the commission is not satisfied, as of the time that an investigation would otherwise be required under this subsection, that the public utility can meet the requirements described in subdivision (1) or provide sufficient reason as to that inability, as described in subdivision (2). If a certificate is granted by the commission under this chapter for a facility intended to repower or replace a generation unit that is planned for retirement, and the certificate includes findings that the project will result in at least equivalent accredited capacity and will provide economic benefit to ratepayers as compared to the continued operation of the generating unit to be retired, the certificate under this chapter constitutes approval by the commission for purposes of an investigation required by this subsection. However, if the commission finds that facts and circumstances regarding the planned retirement have changed significantly since the certificate was granted and that those changes concern the public utility's ability to meet the requirements described in subdivision (1), the commission may conduct an investigation into the planned retirement of the unit.

(v) If, upon investigation under IC 8-1-2-58 through IC 8-1-2-60, and after notice and hearing, as required by IC 8-1-2-59, the commission determines that the capacity resources available to the public utility under subsections (n)(1) through (n)(5) will not be adequate to allow the public utility to satisfy both its planning reserve margin requirements or other federal reliability requirements that the public utility is obligated to meet (as described in subsection (n)(6)) and the reliability adequacy metrics set forth in subsection (h), the commission shall issue an order:

(1) directing the public utility to acquire or construct; or

(2) prohibiting the retirement or refueling of;

such capacity resources that are reasonable and necessary to enable the public utility to provide reliable electric service to its Indiana customers, and to satisfy both its planning reserve margin requirements or other federal reliability requirements described in subsection (n)(6) and the reliability adequacy metrics set forth in subsection (h). The commission shall issue an order under this subsection not later than one hundred twenty (120) days after the initiation of the investigation under subsection (u). If the commission does not issue an order within the one hundred twenty (120) day period prescribed by this subsection, the public utility is considered to be able to meet the requirements described in subsection (u)(1) with respect to the retirement of the electric generation facility under investigation. Not later than ninety (90) days after the date of an order by the commission under this subsection, the public utility shall file for approval with the commission a plan to comply with the commission's order. Notwithstanding IC 8-1-3 or any other law, any appeal of an order by the commission under this subsection is entitled to priority review and shall be given expedited consideration in accordance with Rule 21 of the Indiana Rules of Appellate Procedure.

(w) With respect to a report submitted under subsection (n) after December 31, 2025, if the commission issues an order under subsection (v) to prohibit the retirement or refueling of an electric generation resource, the commission shall create a sub-docket to authorize the public utility to recover in rates the costs of the continued operation of the electric generation resource that was proposed to be retired or refueled. The commission must find that the continued costs of operation are just and reasonable before authorizing their recovery in the public utility's rates. The creation of a sub-docket under this subsection is not subject to the one hundred twenty (120) day time frame for the commission to issue an order under subsection (v).

(x) A public utility's plan under subsection (v) may include:

(1) a request for a certificate of public convenience and necessity under this chapter; or

(2) an application under IC 8-1-8.8;

or both.

(y) Beginning in 2022, the commission shall include in its annual report under IC 8-1-1-14 the following information:

(1) The commission's analysis regarding the ability of public utilities to:

(A) provide reliable electric service to Indiana customers; and

(B) satisfy both:

(i) their planning reserve margin requirements or other federal reliability requirements; and

(ii) the reliability adequacy metrics set forth in subsection (h);

for the next three (3) utility resource planning years, based on the most recent reports filed by public utilities under subsection (n).

(2) A summary of:

(A) the projected demand for retail electricity in Indiana over the next calendar year;

(B) the amount and type of capacity resources committed to meeting the projected demand;

(C) beginning with the commission's annual report due before October 1, 2026, and in each subsequent annual report, the planned retirements or refuelings of electric generation resources and the plans to replace or retain the capacity or energy, or both, of the electric generation resources planned to be retired or refueled; and

(D) beginning with the commission's annual report due before October 1, 2026, and in each subsequent annual report, the reports of commission staff under subsection (s).

In preparing the summary required under this subdivision, the commission may consult with the forecasting group established under section 3.5 of this chapter.

(3) Beginning with the commission's annual report filed under IC 8-1-1-14 in 2025, the commission's analysis regarding the appropriate percentage or portion of:

(A) total spring UCAP that public utilities should be authorized to acquire from capacity markets under subsection (h)(3)(B); and

(B) total fall UCAP that public utilities should be authorized to acquire from capacity markets under subsection (h)(4)(B).

(z) The commission may adopt rules under IC 4-22-2 to implement this section.

As added by P.L.60-2021, SEC.2. Amended by P.L.55-2023, SEC.6; P.L.93-2024, SEC.68; P.L.217-2025, SEC.4.

IC 8-1-8.5-14Commission study of advanced transmission technologies Sec. 14. (a) As used in this section, "advanced transmission technologies" means software or hardware technologies that increase the capacity, efficiency, reliability, or safety of an existing or new electric transmission facility, including:

(1) grid enhancing technologies, such as dynamic line rating, advanced power flow controllers, and topology optimization;

(2) advanced conductors; and

(3) other technologies designed to:

(A) reduce transmission congestion; or

(B) increase the capacity, efficiency, reliability, or safety of an existing or new electric transmission facility.

(b) As used in this section, "public utility" has the meaning set forth in section 1 of this chapter.

(c) The commission shall conduct a study to evaluate the potential use or deployment of advanced transmission technologies by public utilities to enable public utilities to:

(1) safely, reliably, efficiently, and cost effectively meet electric system demand; and

(2) provide safe, reliable, and affordable electric utility service to customers.

(d) In conducting the study, the commission shall evaluate the following:

(1) The attributes, functions, costs, and benefits of various advanced transmission technologies, including grid enhancing technologies and advanced conductors. In evaluating the attributes of various advanced transmission technologies under this subdivision, the commission shall consider whether a particular technology does the following:

(A) Increases transmission capacity.

(B) Increases transmission efficiency.

(D) Reduces the curtailment of generation resources.

(E) Increases system reliability.

(F) Increases system resiliency.

(G) Increases the capacity to connect new energy generation resources.

(2) The potential of each of the advanced transmission technologies studied to be used or deployed by public utilities to provide safe, reliable, and affordable electric utility service to customers in Indiana, considering existing and planned transmission infrastructure and projected demand growth.

(3) Potential reductions in project costs and project completion timelines by deploying advanced transmission technologies, as compared to traditional transmission infrastructure.

(4) Potential ways to streamline the deployment of advanced transmission technologies, including streamlined processes for permitting, maintenance, and upgrades.

(5) Any other aspect of advanced transmission technologies that the commission determines will assist policymakers, public utilities, ratepayers, and other stakeholders in understanding the potential role of advanced transmission technologies in the transmission system serving Indiana and the region.

(e) In conducting the study required by this section, the commission may consult with or invite comments from:

(1) regional transmission organizations;

(2) the Federal Energy Regulatory Commission or other federal regulators;

(3) public utilities;

(4) the office of the utility consumer counselor;

(5) associations or organizations representing utility ratepayers;

(6) regulatory commissions in other states;

(7) engineers or other experts; or

(8) other stakeholders.

The commission may incorporate any information or comments received under this subsection in its report under subsection (f).

(f) The commission shall include in the annual report that the commission is required to submit under IC 8-1-1-14 before October 1, 2026, a report that includes the commission's findings with respect to the topics outlined in subsection (d).

As added by P.L.10-2025, SEC.2.

IC 8-1-8.5-15Commission study of use of surplus interconnection service by electric utilities; topics for study; provision of information to commission; protection of confidential information; consultation with stakeholders; inclusion of findings in commission's annual report Sec. 15. (a) The definitions in section 3.6 of this chapter apply throughout this section.

(b) The commission shall conduct a study to evaluate the potential use of surplus interconnection service by electric utilities to enable electric utilities to:

(1) safely, reliably, efficiently, and cost effectively meet electric system demand; and

(2) provide safe, reliable, and affordable electric utility service to customers.

(1) The potential use of surplus interconnection service to enable electric utilities to provide safe, reliable, and affordable electric utility service to customers in Indiana, considering existing and planned transmission infrastructure and projected demand growth.

(2) Any other aspect of surplus interconnection service that the commission determines will assist policymakers, electric utilities, ratepayers, and other stakeholders in understanding the potential role of surplus interconnection service in the transmission system serving Indiana and the region.

(d) An electric utility shall provide the commission, at the time and in the manner prescribed by the commission, any information or related materials required by the commission to perform the evaluation described in subsection (c). If the electric utility has solicited information concerning the potential use of surplus interconnection service at third party facilities under section 3.6(e) of this chapter, and the commission requires further information or related materials regarding the potential use of surplus interconnection service at those third party facilities, the commission may request the information or materials directly from the owners or operators of those third party facilities. Upon request by an electric utility or an owner or operator of a third party facility, the commission shall determine whether any information or related materials requested by the commission:

(1) are confidential under IC 5-14-3-4;

(2) are exempt from public access and disclosure by Indiana law; and

(3) must be treated as confidential and protected from public access and disclosure by the commission.

(e) In conducting the study required by this section, the commission may consult with or invite comments from:

(1) regional transmission organizations;

(2) the Federal Energy Regulatory Commission or other federal regulators;

(3) electric utilities;

(4) the office of utility consumer counselor;

(5) associations or organizations representing utility ratepayers;

(6) regulatory commissions in other states;

(7) engineers or other experts; and

(8) other stakeholders.

The commission may incorporate any information or comments received under this subsection in its report under subsection (f).

(f) The commission shall include in the annual report that the commission is required to submit under IC 8-1-1-14 before October 1, 2027, a report that includes the commission's findings with respect to the topics set forth in subsection (c).

As added by P.L.126-2026, SEC.3.

IC 8-1-8.6Chapter 8.6. RepealedRepealed by P.L.2-2005, SEC.131.

IC 8-1-8.7Chapter 8.7. Clean Coal Technology

8-1-8.7-1"Clean coal technology" 8-1-8.7-2"Public utility" 8-1-8.7-3Certificate of public convenience and necessity; use of clean coal technology 8-1-8.7-4Hearings and requisite findings; estimated costs; use of Indiana coal 8-1-8.7-5Modification or revocation of certificate 8-1-8.7-6Cancellation of clean coal technology implementation; recovery of expenditures 8-1-8.7-7Ongoing review of construction and costs 8-1-8.7-8Review of completed construction; costs exceeding estimated and approved costs 8-1-8.7-9Dispatching priority 8-1-8.7-10Construction of electric generating facilities; additional certification; joint applications

IC 8-1-8.7-1"Clean coal technology" Sec. 1. As used in this chapter, "clean coal technology" means a technology (including precombustion treatment of coal):

(1) that is used in a new or existing electric generating facility and directly or indirectly reduces airborne emissions of sulfur or nitrogen based pollutants associated with the combustion or use of coal; and

(2) that either:

(A) is not in general commercial use at the same or greater scale in new or existing facilities in the United States as of January 1, 1989; or

(B) has been selected by the United States Department of Energy for funding under its Innovative Clean Coal Technology program and is finally approved for such funding on or after January 1, 1989.

As added by P.L.105-1989, SEC.4.

IC 8-1-8.7-2"Public utility" Sec. 2. As used in this chapter, "public utility" means a public or municipally owned utility.

As added by P.L.105-1989, SEC.4.

IC 8-1-8.7-3Certificate of public convenience and necessity; use of clean coal technology Sec. 3. (a) Except as provided in subsection (c), a public utility may not use clean coal technology at a new or existing electric generating facility without first applying for and obtaining from the commission a certificate that states that public convenience and necessity will be served by the use of clean coal technology.

(b) The commission shall issue a certificate of public convenience and necessity under subsection (a) if the commission finds that a clean coal technology project offers substantial potential of reducing sulfur or nitrogen based pollutants in a more efficient manner than conventional technologies in general use as of January 1, 1989. For purposes of this chapter, a project that the United States Department of Energy has selected for funding under its Innovative Clean Coal Technology program and is finally approved for funding after December 31, 1988, is not considered a conventional technology in general use as of January 1, 1989. When determining whether to grant a certificate under this section, the commission shall examine the following factors:

(1) The costs for constructing, implementing, and using clean coal technology compared to the costs for conventional emission reduction facilities.

(2) Whether a clean coal technology project will also extend the useful life of an existing electric generating facility and the value of that extension.

(3) The potential reduction of sulfur and nitrogen based pollutants achieved by the proposed clean coal technology system.

(4) The reduction of sulfur nitrogen based pollutants that can be achieved by conventional pollution control equipment.

(5) Federal sulfur and nitrogen based pollutant emission standards.

(6) The likelihood of success of the proposed project.

(7) The cost and feasibility of the retirement of an existing electric generating facility.

(8) The dispatching priority for the facility utilizing clean coal technology, considering direct fuel costs, revenues and expenses of the utility, and environmental factors associated with byproducts resulting from the utilization of the clean coal technology.

(9) Any other factors the commission considers relevant, including whether the construction, implementation, and use of clean coal technology is in the public's interest.

(c) A public utility is not required to obtain a certificate under this chapter for a clean coal technology project that constitutes a research and development project that may be expensed under IC 8-1-2-6.1.

As added by P.L.105-1989, SEC.4.

IC 8-1-8.7-4Hearings and requisite findings; estimated costs; use of Indiana coal Sec. 4. (a) As a condition for receiving the certificate required under section 3 of this chapter, an applicant must file an estimate of the cost of constructing, implementing, and using clean coal technology and supportive technical information in as much detail as the commission requires.

(b) The commission shall hold a public hearing on each application. A certificate shall be granted only if the commission has:

(1) made a finding that the public convenience and necessity will be served by the construction, implementation, and use of clean coal technology;

(2) approved the estimated costs;

(3) made a finding that the facility where the clean coal technology is employed:

(A) utilizes and will continue to utilize Indiana coal as its primary fuel source; or

(B) is justified, because of economic considerations or governmental requirements, in utilizing non-Indiana coal;

after the technology is in place; and

(4) made a finding on each of the factors described in section 3(b) of this chapter, including the dispatching priority of the facility to the utility.

As added by P.L.105-1989, SEC.4.

IC 8-1-8.7-5Modification or revocation of certificate Sec. 5. When, in the opinion of the commission, changes in the estimate of the cost or the need for clean coal technology occur, the commission shall immediately commence a review of the certificate granted under this chapter to determine if public convenience and necessity will be served by the implementation of the technology. If the commission finds that implementation of the technology will not serve the public convenience and necessity, the commission may modify or revoke the certificate.

As added by P.L.105-1989, SEC.4.

IC 8-1-8.7-6Cancellation of clean coal technology implementation; recovery of expenditures Sec. 6. If a public utility cancels the implementation of the technology as a result of the modification or revocation of a certificate by the commission under section 5 of this chapter, the public utility may recover the amount of its investment in the technology, along with a reasonable return on the unamortized balance. The utility may not recover on amounts expended in excess of the cost estimates approved by the commission under section 4 of this chapter unless the utility can prove to the commission that those expenditures were necessary and prudent. The recovery must be made over a reasonable period of time through rates charged by the public utility. A recovery may not be made if there was fraud, concealment, or gross mismanagement on the part of the public utility.

As added by P.L.105-1989, SEC.4.

IC 8-1-8.7-7Ongoing review of construction and costs Sec. 7. (a) This section does not apply if the utility elects the review described in section 8 of this chapter.

(b) In addition to the review of the continuing need for the clean coal technology system under construction prescribed in section 5 of this chapter, the commission shall at the request of the public utility maintain an ongoing review of that construction as the construction proceeds. The applicant shall submit each year during construction, or at other times as the commission and the public utility mutually agree, a progress report and any revisions in the cost estimates for the construction. The commission must hold a public hearing before it may approve or deny a proposed increase in the cost estimates for the implementation, construction, or use of clean coal technology.

(c) If the commission approves the construction and the cost of the part of the clean coal technology system under review, the approval forecloses subsequent challenges to the inclusion of that part of the clean coal technology system in the public utility's rate base on the basis of excessive cost, inadequate quality control, or inability to employ the technology.

(d) If the commission disapproves of all or part of the construction or cost of the part of the clean coal technology system under review, the commission may modify or revoke the certificate. If the public utility cancels construction of the clean coal technology system as a result of the modification or revocation of the certificate, the utility may recover over a reasonable period of time through rates, absent fraud, concealment, or gross mismanagement, the amount of its investment in the clean coal technology system along with a reasonable return on the unamortized balance to the extent the construction and the cost were approved previously by the commission.

As added by P.L.105-1989, SEC.4.

IC 8-1-8.7-8Review of completed construction; costs exceeding estimated and approved costs Sec. 8. A public utility may elect to forgo any commission review of the construction and cost until completion of the clean coal technology system. If the commission has annually approved the continuing need for the project under section 5 of this chapter, and to the extent the public utility seeks to add to the rate base an amount that does not exceed that filed under section 4(a) of this chapter, the inclusion of that amount may be challenged only on the basis of inadequate quality controls. However, inclusion of costs in excess of those approved by the commission under section 4(b)(2) of this chapter is not permitted unless the public utility shows those costs to be necessary and prudent.

As added by P.L.105-1989, SEC.4.

IC 8-1-8.7-9Dispatching priority Sec. 9. After the commission has made a finding under section 4(b)(4) of this chapter as to the dispatching priority of a facility utilizing clean coal technology, the utility receiving the certificate under this chapter may dispatch the facility for which the certificate is issued in accordance with such finding, and such dispatch shall not be considered to be in conflict with the provisions of IC 8-1-2-42.

As added by P.L.105-1989, SEC.4.

IC 8-1-8.7-10Construction of electric generating facilities; additional certification; joint applications Sec. 10. (a) This chapter does not relieve a public utility of the duty to obtain a certificate under IC 8-1-8.5 if the utility is proposing the use of clean coal technology as a part of the construction of an electric generating facility.

(b) A public utility seeking a certificate under IC 8-1-8.5 and this chapter for one (1) project may file a joint application for both certificates. If a joint application is filed, the commission shall jointly consider both certificates.

As added by P.L.105-1989, SEC.4.

IC 8-1-8.8Chapter 8.8. Utility Generation and Clean Coal Technology

8-1-8.8-1Legislative findings and declaration of purpose 8-1-8.8-2"Clean energy projects" 8-1-8.8-3"Clean coal technology" 8-1-8.8-4"Coal gasification facility" 8-1-8.8-5"Costs associated with qualified utility system property" 8-1-8.8-6"Eligible business" 8-1-8.8-7"Group" 8-1-8.8-8"New energy production or generating facility" 8-1-8.8-8.5"Nuclear energy production or generating facility" 8-1-8.8-8.7"Qualified utility system expenses" 8-1-8.8-9"Qualified utility system property" 8-1-8.8-10"Renewable energy resources" 8-1-8.8-10.2"Small modular nuclear reactor" 8-1-8.8-11Incentives for clean energy projects; application to commission; commission's time for determining eligibility 8-1-8.8-12Recovery of costs; rate adjustment mechanisms 8-1-8.8-13Repealed 8-1-8.8-14Annual study of renewable energy resources 8-1-8.8-15Commission's power to review approved projects

IC 8-1-8.8-1Legislative findings and declaration of purpose Sec. 1. (a) The general assembly makes the following findings:

(1) Growth of Indiana's population and economic base has created a need for new energy production or generating facilities in Indiana.

(2) The development of a robust and diverse portfolio of energy production or generating capacity, including coal gasification and the use of renewable energy resources, is needed if Indiana is to continue to be successful in attracting new businesses and jobs.

(3) Indiana has considerable natural resources that are currently underutilized and could support development of new energy production or generating facilities, including coal gasification facilities, at an affordable price.

(4) Certain regions of the state, such as southern Indiana, could benefit greatly from new employment opportunities created by development of new energy production or generating facilities utilizing the plentiful supply of coal from the geological formation known as the Illinois Basin.

(5) Technology can be deployed that allows high sulfur coal from the geological formation known as the Illinois Basin to be burned or gasified efficiently while meeting strict state and federal air quality limitations. Specifically, the state should encourage the use of advanced clean coal technology, such as coal gasification.

(6) It is in the public interest for the state to encourage the construction of new energy production or generating facilities that increase the in-state capacity to provide for current and anticipated energy demand at a competitive price.

(7) It is in the public interest for the state to encourage the study, analysis, development, and life cycle management of nuclear energy production or generating facilities, as well as carbon dioxide capture, transportation, and storage facilities.

(b) The purpose of this chapter is to enhance Indiana's energy security and reliability by ensuring all of the following:

(1) Indiana's and the region's energy production or generating capacity continues to be adequate to provide for Indiana's current and future energy needs, including the support of the state's economic development efforts.

(2) The vast and underutilized coal resources of the Illinois Basin are used as a fuel source for new energy production or generating facilities.

(3) The electric transmission and gas transportation systems within Indiana are upgraded to distribute additional amounts of electricity and gas more efficiently.

(4) Jobs are created as new energy production or generating facilities are built in regions throughout Indiana.

(5) The study, analysis, development, and life cycle management of nuclear energy production or generating facilities are encouraged at the same time as are new coal fired and other fossil fuel based energy production or generating facilities.

As added by P.L.159-2002, SEC.6. Amended by P.L.175-2007, SEC.11; P.L.150-2011, SEC.2.

IC 8-1-8.8-2"Clean energy projects" Sec. 2. As used in this chapter, "clean energy projects" means any of the following:

(1) Any of the following projects:

(A) Projects at new energy production or generating facilities that employ the use of clean coal technology and that produce energy, including substitute natural gas, primarily from coal, or gases derived from coal, from the geological formation known as the Illinois Basin.

(B) Projects to provide advanced technologies that reduce regulated air emissions from or increase the efficiency of existing energy production or generating plants that are fueled primarily by coal or gases from coal from the geological formation known as the Illinois Basin, such as flue gas desulfurization and selective catalytic reduction equipment.

(C) Projects to provide electric transmission facilities to serve a new energy production or generating facility or a nuclear energy production or generating facility.

(D) Projects that produce substitute natural gas from Indiana coal by construction and operation of a coal gasification facility.

(E) Projects or potential projects:

(i) to construct, after June 30, 2023, one (1) or more small modular nuclear reactors in Indiana for the generation of electricity to be directly or indirectly used to furnish public utility service to Indiana customers, or at the site of a nuclear energy production or generating facility that supplies electricity to Indiana retail customers on July 1, 2011, under rules adopted by the commission under IC 8-1-8.5-12.1; or

(ii) that enhance the safe and reliable use of nuclear energy production or generating technologies to produce electricity.

(2) Projects to develop alternative energy sources, including renewable energy resource projects or coal gasification facilities.

(3) The purchase of fuels or energy produced by a coal gasification facility or by a nuclear energy production or generating facility.

(4) Projects described in subdivisions (1) through (2) that use coal bed methane.

(5) Projects to construct or repower a facility described in IC 8-1-37-4(a)(21).

As added by P.L.159-2002, SEC.6. Amended by P.L.174-2005, SEC.2; P.L.175-2007, SEC.12; P.L.150-2011, SEC.3; P.L.155-2022, SEC.2; P.L.83-2023, SEC.2.

IC 8-1-8.8-3"Clean coal technology" Sec. 3. As used in this chapter, "clean coal technology" means a technology (including precombustion treatment of coal):

(1) that is used in a new or existing energy production or generating facility and directly or indirectly reduces or avoids airborne emissions of sulfur, mercury, or nitrogen oxides or other regulated air emissions associated with the combustion or use of coal; and

(2) that either:

(A) was not in general commercial use at the same or greater scale in new or existing facilities in the United States at the time of enactment of the federal Clean Air Act Amendments of 1990 (P.L.101-549); or

(B) has been selected by the United States Department of Energy for funding or loan guaranty under an Innovative Clean Coal Technology or loan guaranty program under the Energy Policy Act of 2005, or any successor program, and is finally approved for such funding or loan guaranty on or after the date of enactment of the federal Clean Air Act Amendments of 1990 (P.L.101-549).

As added by P.L.159-2002, SEC.6. Amended by P.L.175-2007, SEC.13.

IC 8-1-8.8-4"Coal gasification facility" Sec. 4. As used in this chapter, "coal gasification facility" means a facility in Indiana that uses a manufacturing process that converts coal into a clean gas that can be used:

(1) as a fuel to generate energy; or

(2) as substitute natural gas.

As added by P.L.159-2002, SEC.6. Amended by P.L.175-2007, SEC.14; P.L.150-2011, SEC.4.

IC 8-1-8.8-5"Costs associated with qualified utility system property" Sec. 5. As used in this chapter, "costs associated with qualified utility system property" means capital, operation, maintenance, depreciation, tax costs, and financing costs of or for qualified utility system property.

As added by P.L.159-2002, SEC.6.

IC 8-1-8.8-6"Eligible business" Sec. 6. As used in this chapter, "eligible business" means a business that is an energy utility (as defined in IC 8-1-2.5-2), a joint agency (as defined in IC 8-1-2.2-2), or an owner of a coal gasification facility and that:

(1) proposes to construct or repower a new energy production or generating facility;

(2) proposes to construct or repower a project described in section 2(1) or 2(2) of this chapter;

(3) undertakes a project to develop alternative energy sources, including renewable energy resource projects or coal gasification facilities;

(4) purchases fuels or energy produced by a coal gasification facility or by a nuclear energy production or generating facility; or

(5) proposes to construct or repower a facility described in IC 8-1-37-4(a)(21).

As added by P.L.159-2002, SEC.6. Amended by P.L.175-2007, SEC.15; P.L.150-2011, SEC.5; P.L.83-2023, SEC.3.

IC 8-1-8.8-7"Group" Sec. 7. As used in this chapter, "group" refers to the forecasting group established by IC 8-1-8.5-3.5.

As added by P.L.159-2002, SEC.6.

IC 8-1-8.8-8"New energy production or generating facility" Sec. 8. (a) As used in this chapter, "new energy production or generating facility" refers to a generation or coal gasification facility that satisfies all of the following:

(1) The facility produces energy primarily from coal or gases from coal from the geological formation known as the Illinois Basin.

(2) The facility is a:

(A) newly constructed or newly repowered energy plant; or

(B) newly constructed capacity expansion at an existing plant;

dedicated primarily to serving Indiana retail customers.

(3) The repowering, construction, or expansion of the facility was begun by an Indiana utility after July 1, 2002.

(4) Except for a facility that is a clean energy project under section 2(2) of this chapter, the facility has an aggregate rated electric generating capacity of at least one hundred (100) megawatts for all units at one (1) site or a generating capacity of at least four hundred thousand (400,000) pounds per hour of steam.

(b) The term includes the transmission lines, gas transportation facilities, and associated equipment employed specifically to serve a new energy production or generating facility.

As added by P.L.159-2002, SEC.6. Amended by P.L.175-2007, SEC.16; P.L.150-2011, SEC.6.

IC 8-1-8.8-8.5"Nuclear energy production or generating facility" Sec. 8.5. (a) As used in this chapter, "nuclear energy production or generating facility" means:

(1) an energy production or generation facility that:

(A) uses a nuclear reactor as its heat source to provide steam to a turbine generator to produce or generate electricity;

(B) supplies electricity to Indiana retail customers on July 1, 2011;

(D) is undergoing a comprehensive life cycle management project to enhance the safe and reliable operation of the facility during the period the facility is licensed to operate by the United States Nuclear Regulatory Commission; or

(2) a small modular nuclear reactor that is constructed after June 30, 2023:

(A) in Indiana for the generation of electricity to be directly or indirectly used to furnish public utility service to Indiana customers; or

(B) at the site of a nuclear energy production or generating facility that supplies electricity to Indiana retail customers on July 1, 2011;

under rules adopted by the commission under IC 8-1-8.5-12.1.

(b) The term includes the transmission lines and other associated equipment employed specifically to serve a nuclear energy production or generating facility.

As added by P.L.150-2011, SEC.7. Amended by P.L.155-2022, SEC.3; P.L.11-2023, SEC.36.

IC 8-1-8.8-8.7"Qualified utility system expenses" Sec. 8.7. As used in this chapter, "qualified utility system expenses" means the costs associated with the study, analysis, or development of a life cycle management project for a nuclear energy production or generating facility.

As added by P.L.150-2011, SEC.8.

IC 8-1-8.8-9"Qualified utility system property" Sec. 9. As used in this chapter, "qualified utility system property" means any:

(1) new energy production or generating facility; or

(2) nuclear energy production or generating facility;

used, or to be used, in whole or in part, by an energy utility to provide retail energy service (as defined in IC 8-1-2.5-3) regardless of whether that service is provided under IC 8-1-2.5 or another provision of this article.

As added by P.L.159-2002, SEC.6. Amended by P.L.175-2007, SEC.17; P.L.150-2011, SEC.9.

IC 8-1-8.8-10"Renewable energy resources" Sec. 10. (a) As used in this chapter "renewable energy resource" means the following:

(1) A clean energy resource listed in:

(A) IC 8-1-37-4(a)(1) through IC 8-1-37-4(a)(16);

(B) IC 8-1-37-4(a)(22); or

(2) Low temperature, oxygen starved gasification of municipal solid waste.

(3) Methane recovered from landfills for the production of electricity.

(b) Except for energy described in subsection (a)(2) and IC 8-1-37-4(a)(9), the term does not include energy from the incinerations, burning, or heating of any of the following:

(1) Tires.

(2) General household, institutional, commercial, industrial lunchroom, office, or landscape waste.

As added by P.L.159-2002, SEC.6. Amended by P.L.175-2007, SEC.18; P.L.151-2009, SEC.4; P.L.95-2010, SEC.1; P.L.96-2011, SEC.1; P.L.150-2011, SEC.10; P.L.224-2011, SEC.1; P.L.13-2013, SEC.29; P.L.152-2022, SEC.1; P.L.83-2023, SEC.4.

IC 8-1-8.8-10.2"Small modular nuclear reactor" Sec. 10.2. (a) As used in this chapter, "small modular nuclear reactor" means a nuclear reactor that:

(1) has a rated electric generating capacity of not more than four hundred seventy (470) megawatts;

(2) is capable of being constructed and operated, either:

(A) alone; or

(B) in combination with one (1) or more similar reactors if additional reactors are, or become, necessary;

at a single site; and

(3) is required to be licensed by the United States Nuclear Regulatory Commission.

(b) The term includes a nuclear reactor that:

(1) is described in subsection (a); and

(2) uses a process to produce hydrogen that can be used:

(A) for energy storage;

(B) as a fuel; or

As added by P.L.155-2022, SEC.4. Amended by P.L.33-2023, SEC.2.

IC 8-1-8.8-11Incentives for clean energy projects; application to commission; commission's time for determining eligibility Sec. 11. (a) The commission shall encourage clean energy projects by creating the following financial incentives for clean energy projects, if the projects are found to be just and reasonable:

(1) The timely recovery of costs and expenses incurred during construction and operation of projects described in section 2(1), 2(2), or 2(5) of this chapter. The commission may not approve a financial incentive under this subdivision unless the commission finds that the eligible business has demonstrated that the timely recovery of costs and expenses incurred during the construction and operation of the project:

(A) is just and reasonable; and

(B) in the case of construction financing costs, will result in a gross financing costs savings over the life of the project.

(2) Financial incentives for the purchase of fuels or energy produced by a coal gasification facility or by a nuclear energy production or generating facility, including cost recovery.

(3) Financial incentives for projects to develop alternative energy sources, including renewable energy resource projects or coal gasification facilities.

(4) Other financial incentives the commission considers appropriate.

(b) An eligible business must file an application to the commission for approval of a clean energy project under this section. This chapter does not relieve an eligible business of the duty to obtain any certificate required under IC 8-1-8.5 or IC 8-1-8.7. An eligible business seeking a certificate under IC 8-1-8.5 or IC 8-1-8.7 and this chapter for one (1) project may file a single application for all necessary certificates. If a single application is filed, the commission shall consider all necessary certificates at the same time.

(c) The commission shall promptly review an application filed under this section for completeness. The commission may request additional information the commission considers necessary to aid in its review.

(d) The commission shall, after notice and hearing, issue a determination of a project's eligibility for the financial incentives described in subsection (a) not later than:

(1) one hundred twenty (120) days after the date of the application; or

(2) the time frame set forth in IC 8-1-8.5-5(b) if a certificate under IC 8-1-8.5 is required for the project;

unless the commission finds that the applicant has not cooperated fully in the proceeding.

As added by P.L.159-2002, SEC.6. Amended by P.L.150-2011, SEC.11; P.L.83-2023, SEC.5.

IC 8-1-8.8-12Recovery of costs; rate adjustment mechanisms Sec. 12. (a) The commission shall provide financial incentives to eligible businesses for:

(1) new energy production or generating facilities; and

(2) nuclear energy production or generating facilities;

in the form of timely recovery of the costs incurred in connection with the study, analysis, development, siting, design, licensing, permitting, construction, repowering, expansion, life cycle management, operation, or maintenance of the facilities.

(b) An eligible business seeking authority to timely recover the costs described in subsection (a) must apply to the commission for approval of a rate adjustment mechanism in the manner determined by the commission.

(1) A schedule for the completion of construction, repowering, life cycle management, or expansion of the facility for which rate relief is sought.

(2) Copies of the most recent integrated resource plan filed with the commission, if applicable.

(3) The amount of capital investment by the eligible business in the facility.

(4) Other information the commission considers necessary.

(d) The commission shall allow an eligible business to recover:

(1) the costs associated with qualified utility system property; and

(2) qualified utility system expenses;

if the eligible business provides substantial documentation that the expected costs and expenses and the schedule for incurring those costs and expenses are reasonable and necessary.

(e) The commission shall allow an eligible business to recover the costs associated with the purchase of fuels or energy produced by a coal gasification facility or by a nuclear energy production or generating facility if the eligible business provides substantial documentation that the costs associated with the purchase are reasonable and necessary.

(f) A retail rate adjustment mechanism proposed by an eligible business under this section may be based on actual or forecasted data. If forecast data is used, the retail rate adjustment mechanism must contain a reconciliation mechanism to correct for any variance between the forecasted costs and the actual costs.

As added by P.L.159-2002, SEC.6. Amended by P.L.175-2007, SEC.19; P.L.150-2011, SEC.12.

IC 8-1-8.8-13RepealedAs added by P.L.159-2002, SEC.6. Amended by P.L.1-2006, SEC.151; P.L.175-2007, SEC.20; P.L.150-2011, SEC.13. Repealed by P.L.87-2024, SEC.16.

IC 8-1-8.8-14Annual study of renewable energy resources Sec. 14. The group shall conduct an annual study on the:

(1) use of;

(2) availability of; and

(3) economics of using;

in Indiana the clean energy resources listed in IC 8-1-37-4(a)(1) through IC 8-1-37-4(a)(6) and in IC 8-1-37-4(a)(22). The commission may direct the group to study additional clean energy resources as the commission considers appropriate. Each year, the group shall submit a report on the study to the commission for inclusion in the commission's annual report to the interim study committee on energy, utilities, and telecommunications established by IC 2-5-1.3-4 in an electronic format under IC 5-14-6. The commission shall direct the group concerning the appropriate level of detail for the report. The report must include suggestions from the group to encourage the development and use of clean energy resources and technologies appropriate for use in Indiana.

As added by P.L.159-2002, SEC.6. Amended by P.L.71-2009, SEC.2; P.L.150-2011, SEC.14; P.L.53-2014, SEC.78; P.L.152-2022, SEC.2.

IC 8-1-8.8-15Commission's power to review approved projects Sec. 15. The commission may review any project approved under this chapter to determine that the project continues to comply with the commission's order initially approving incentives under this chapter. The commission may revoke any incentive approved in the order if the commission finds that the project no longer complies with the provisions of the order concerning the incentive.

As added by P.L.159-2002, SEC.6.

IC 8-1-8.9Chapter 8.9. Financing of Substitute Natural Gas Costs

8-1-8.9-0.3General assembly findings of fact 8-1-8.9-1"Assignee" defined 8-1-8.9-2"Commission" defined 8-1-8.9-3"Energy utility" defined 8-1-8.9-4"Financing entity" defined 8-1-8.9-5"Qualified contract" defined 8-1-8.9-6"Qualified cost" defined 8-1-8.9-7"Qualified order" defined 8-1-8.9-8"Substitute natural gas" defined 8-1-8.9-9"SNG property interest" defined 8-1-8.9-10"SNG seller" defined 8-1-8.9-11Qualified order for cost recovery 8-1-8.9-12SNG property interest; property rights 8-1-8.9-13SNG property interest; assignability 8-1-8.9-14SNG property interest; bankruptcy setoff 8-1-8.9-15SNG property interest; true sale 8-1-8.9-16SNG property interest; security interests 8-1-8.9-17SNG property interest; status of parties to transaction 8-1-8.9-18SNG property interest; successor obligations 8-1-8.9-19SNG property interest; SNG seller contract with energy utility 8-1-8.9-20SNG property interest; SNG seller rights

IC 8-1-8.9-0.3General assembly findings of fact Sec. 0.3. The general assembly finds the following:

(1) The development of coal gasification facilities in Indiana that would use local coal resources for the production of substitute natural gas is in the public interest for purposes of:

(A) reducing the reliance of Indiana energy utilities on gas imports;

(B) mitigating price and supply risk;

(D) promoting economic development and job creation.

(2) Coal gasification is encouraged by federal policies intended to increase the energy independence of the United States, including through the availability of tax incentives and loan guarantees.

(3) Indiana has the necessary resources and infrastructure suitable for development of coal gasification facilities.

(4) The receipt of federal incentives for the development, construction, and financing of new coal gasification facilities in Indiana will be enhanced by Indiana energy utilities entering into long term contracts for the purchase of substitute natural gas produced by such facilities.

(5) It is necessary to allow Indiana energy utilities to recover, through rate adjustments for the utility's customers, costs incurred from entering into supply contracts for substitute natural gas in order to promote the creation of such contracts without causing Indiana energy utilities to incur undue risk.

As added by P.L.220-2011, SEC.186.

IC 8-1-8.9-1"Assignee" defined Sec. 1. (a) As used in this chapter, "assignee" means any individual, corporation, or other legal entity to which an SNG property interest is transferred.

(b) The term includes an assignee of a person described in subsection (a).

As added by P.L.175-2007, SEC.21.

IC 8-1-8.9-2"Commission" defined Sec. 2. As used in this chapter, "commission" refers to the Indiana utility regulatory commission created by IC 8-1-1-2.

As added by P.L.175-2007, SEC.21.

IC 8-1-8.9-3"Energy utility" defined Sec. 3. As used in this chapter, "energy utility" has the meaning set forth in IC 8-1-2.5-2.

As added by P.L.175-2007, SEC.21.

IC 8-1-8.9-4"Financing entity" defined Sec. 4. As used in this chapter, "financing entity" means a person that provides:

(1) equity financing; or

(2) debt financing;

that is secured by an SNG property interest.

As added by P.L.175-2007, SEC.21.

IC 8-1-8.9-5"Qualified contract" defined Sec. 5. As used in this chapter, "qualified contract" means a contract with a term of at least thirty (30) years for the sale of substitute natural gas to an energy utility.

As added by P.L.175-2007, SEC.21.

IC 8-1-8.9-6"Qualified cost" defined Sec. 6. As used in this chapter, "qualified cost" means any cost incurred by an energy utility in purchasing substitute natural gas under a qualified contract.

As added by P.L.175-2007, SEC.21.

IC 8-1-8.9-7"Qualified order" defined Sec. 7. As used in this chapter, "qualified order" means a final and irrevocable order that:

(1) is issued by the commission; and

(2) approves a qualified contract adopted in accordance with this chapter and IC 8-1-2-42.1.

As added by P.L.175-2007, SEC.21.

IC 8-1-8.9-8"Substitute natural gas" defined Sec. 8. As used in this chapter, "substitute natural gas" or "SNG" has the meaning set forth in IC 8-1-2-42.1(a).

As added by P.L.175-2007, SEC.21.

IC 8-1-8.9-9"SNG property interest" defined Sec. 9. As used in this chapter, "SNG property interest" means the right, title, and interest that:

(1) are held by an energy utility or its assignee;

(2) are created by a qualified order; and

(3) entitle the energy utility or its assignee to recover qualified costs under IC 8-1-2-42.1.

As added by P.L.175-2007, SEC.21.

IC 8-1-8.9-10"SNG seller" defined Sec. 10. As used in this chapter, "SNG seller" means any individual, corporation, or other legal entity that engages in the production and sale of substitute natural gas.

As added by P.L.175-2007, SEC.21.

IC 8-1-8.9-11Qualified order for cost recovery Sec. 11. (a) Notwithstanding any other law, the commission may, in accordance with this chapter and IC 8-1-2-42.1, issue a qualified order that:

(1) approves the terms of a qualified contract; and

(2) authorizes the recovery of qualified costs by an energy utility from its customers.

(b) A qualified order issued under this section may not be:

(1) rescinded;

(2) nullified; or

(3) modified;

in such a manner that reduces or otherwise impairs the value of an SNG property interest.

As added by P.L.175-2007, SEC.21.

IC 8-1-8.9-12SNG property interest; property rights Sec. 12. (a) An SNG property interest, including any right to future purchases of substitute natural gas during the term of a qualified contract, constitutes a present property right.

(b) Qualified costs recovered by an energy utility under a qualified order constitute proceeds of only the SNG property interest that is created by the qualified order.

(c) If the commission issues a qualified order under section 11 of this chapter, the state covenants and agrees, for the benefit of the energy utility and any assignee or financing entity involved, that the state will not take or permit any action that would:

(1) reduce or otherwise impair the value of the SNG property interest created by the qualified order; or

(2) limit, alter, or impair:

(A) the qualified order;

(B) the SNG property interest created by the qualified order; or

(i) imposed on and collected by the energy utility; and

(ii) remitted to the SNG seller;

under the terms of the qualified contract;

until the qualified contract has been performed in full.

As added by P.L.175-2007, SEC.21.

IC 8-1-8.9-13SNG property interest; assignability Sec. 13. (a) An energy utility may assign an SNG property interest to an assignee, including:

(1) another party to the qualified contract; or

(2) a financing entity.

An assignee may in turn assign an SNG property interest to a financing entity that provides financing to the assignee.

(b) An assignment to a financing entity under this section may be:

(1) an absolute assignment of the SNG property interest; or

(2) an assignment of the SNG property interest as collateral for an obligation owed to the financing entity.

(d) Any amounts collected by an energy utility in connection with the sale, transfer, or disposition of substitute natural gas under a qualified contract that forms the basis of an SNG property interest assigned under this section constitute the property of the assignee. Pending the transfer of the SNG property interest to the assignee, the amounts described in this subsection shall be:

(1) segregated by the energy utility; and

(2) held in trust for the benefit of the assignee;

subject to the terms of the qualified contract that forms the basis of the SNG property interest that is being assigned.

As added by P.L.175-2007, SEC.21.

IC 8-1-8.9-14SNG property interest; bankruptcy setoff Sec. 14. The interests of an assignee in:

(1) an SNG property interest transferred to the assignee under section 13 of this chapter; and

(2) any revenues or collections arising from the SNG property interest transferred;

are not subject to setoff by the energy utility that transferred the SNG property interest, or by any other person, in connection with any bankruptcy proceeding involving the energy utility.

As added by P.L.175-2007, SEC.21.

IC 8-1-8.9-15SNG property interest; true sale Sec. 15. (a) If an agreement by an energy utility or an assignee to assign an SNG property interest expressly states that the assignment is a sale or is otherwise an absolute transfer:

(1) the resulting transaction:

(A) is a true sale; and

(B) is not a secured transaction; and

(2) title, both legal and equitable, passes to the person to which the SNG property interest is assigned.

(b) A transaction resulting from an agreement described in subsection (a) is a true sale regardless of whether:

(1) the assignee has recourse against the assignor; or

(2) the agreement provides for any of the following:

(A) The assignor's retention of an equity interest in the SNG property interest transferred.

(B) Continuing obligations of the energy utility under the qualified contract, including the obligation of the energy utility to serve as the collector of qualified costs.

As added by P.L.175-2007, SEC.21.

IC 8-1-8.9-16SNG property interest; security interests Sec. 16. (a) An SNG property interest does not constitute an account or a general intangible under IC 26-1-9.1-102. The creation, granting, perfection, and enforcement of liens and security interests in SNG property interests are governed by this chapter and not by IC 26-1-9.1.

(b) A valid and enforceable lien and security interest in an SNG property interest may be created only by the execution and delivery of a security agreement with a financing entity in connection with the issuance of indebtedness. The security interest attaches automatically from the time that value is received for the indebtedness secured by the SNG property interest and, upon perfection through the filing of notice with the secretary of state:

(1) constitutes a continuously perfected lien and security interest in the SNG property interest and all proceeds of the SNG property interest, whether or not accrued;

(2) has priority in the order of its filing; and

(3) takes precedence over any subsequent judicial lien or other creditor's lien.

If notice is filed with the secretary of state not later than ten (10) days after value is received for the indebtedness, the security interest is perfected retroactive to the date the value was received. If notice is not filed with the secretary of state within ten (10) days after value is received for the indebtedness, the security interest is perfected as of the date of filing.

(c) Transfer of an SNG property interest to an assignee is perfected against all third parties, including subsequent judicial or other lien creditors, upon:

(1) the delivery of transfer documents to the assignee; and

(2) the filing of notice with the secretary of state in accordance with subsection (b).

However, if notice of the transfer is not filed with the secretary of state within ten (10) days after the delivery of the transfer documentation, the transfer of the SNG property interest is not perfected against third parties until the notice is filed.

(d) The priority of a lien and security interest under this section is not impaired by either of the following:

(1) A later modification of the qualified order creating the SNG property interest being transferred.

(2) The commingling of other funds with funds collected in connection with a qualified contract. Any other security interest that may apply to funds collected in connection with a qualified contract terminates when the funds are transferred to a segregated account for the benefit of the assignee or a financing entity. If an SNG property interest has been transferred to an assignee, any proceeds from the SNG property interest shall be held in trust for the assignee.

(e) If a default or termination occurs in connection with a financing secured by an SNG property interest, the financing entity or its representative may foreclose on or otherwise enforce its lien and security interest in the SNG property interest as if the financing entity were a secured party under IC 26-1-9.1. Amounts arising from the qualified contract that is the basis of the SNG property interest shall be transferred to a separate account for the financing entity's benefit and are subject to the financing entity's security interest and lien.

As added by P.L.175-2007, SEC.21.

IC 8-1-8.9-17SNG property interest; status of parties to transaction Sec. 17. An assignee or a financing party is not considered an energy utility solely by virtue of its participation in any transaction described in this chapter.

As added by P.L.175-2007, SEC.21.

IC 8-1-8.9-18SNG property interest; successor obligations Sec. 18. Any entity that becomes a successor to an energy utility as the result of:

(1) any bankruptcy, reorganization, or other insolvency proceeding;

(2) any merger, sale, or transfer involving the energy utility; or

(3) the operation of law;

or for any other reason, shall perform and satisfy any obligations of the energy utility incurred under this chapter in the same manner and to the same extent as the energy utility would have been obligated to perform, including the obligation to pay to an assignee any funds collected by the energy utility in connection with the SNG property interest assigned to the assignee.

As added by P.L.175-2007, SEC.21.

IC 8-1-8.9-19SNG property interest; SNG seller contract with energy utility Sec. 19. An SNG seller that is an assignee may contract with the energy utility, in the qualified contract or in another contract, for the performance of services related to the sale of substitute natural gas under the qualified contract, including:

(1) the transportation and distribution of substitute natural gas; and

(2) billing, collection, and other related services;

according to terms and conditions that reasonably compensate the energy utility for its services and adequately secure payment to the SNG seller.

As added by P.L.175-2007, SEC.21.

IC 8-1-8.9-20SNG property interest; SNG seller rights Sec. 20. If an energy utility makes a true sale of an SNG property interest to an SNG seller under section 15 of this chapter, the SNG seller:

(1) retains title to all substitute natural gas distributed by the energy utility to the energy utility's retail end use customers;

(2) is entitled to all amounts collected by the energy utility from its retail end use customers for the distribution of the substitute natural gas, subject to the terms of the qualified contract; and

(3) has the same rights to payments made by the energy utility's retail end use customers as does the energy utility that provides the substitute natural gas to those customers.

As added by P.L.175-2007, SEC.21.

IC 8-1-9Chapter 9. Relocation of Utilities in Highway Rights-of-Way

8-1-9-1Public policy 8-1-9-2Definitions 8-1-9-3Audits 8-1-9-4New location; right to operate 8-1-9-5Certain projects; payment of initial cost

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Indiana § 8-1-8-3 - Construction of chapter

§ 8-1-8-3. Construction of chapter

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