First Regular Session of the 124th General Assembly (2025)
PRINTING CODE. Amendments: Whenever an existing statute (or a section of the Indiana
Constitution) is being amended, the text of the existing provision will appear in this style type,
additions will appear in this style type, and deletions will appear in this style type.
Additions: Whenever a new statutory provision is being enacted (or a new constitutional
provision adopted), the text of the new provision will appear in this style type. Also, the
word NEW will appear in that style type in the introductory clause of each SECTION that adds
a new provision to the Indiana Code or the Indiana Constitution.
Conflict reconciliation: Text in a statute in this style type or this style type reconciles conflicts
between statutes enacted by the 2024 Regular Session of the General Assembly.
HOUSE ENROLLED ACT No. 1007
AN ACT to amend the Indiana Code concerning utilities.
Be it enacted by the General Assembly of the State of Indiana:
SECTION 1. IC 6-3.1-45 IS ADDED TO THE INDIANA CODE
AS A NEW CHAPTER TO READ AS FOLLOWS [EFFECTIVE
JANUARY 1, 2025 (RETROACTIVE)]:
Chapter 45. Small Modular Nuclear Reactor Manufacturing
Expense Tax Credit
Sec. 1. This chapter applies to a taxable year beginning after
December 31, 2024.
Sec. 2. As used in this chapter, "department" refers to the
department of state revenue.
Sec. 3. As used in this chapter, "qualified investment" means a
taxpayer's expenditures incurred in the manufacture of a small
modular nuclear reactor in Indiana.
Sec. 4. 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
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(3) is required to be licensed by the United States Nuclear
Regulatory Commission.
The term includes a nuclear reactor that is described in this section
and that uses a process to produce hydrogen that can be used for
energy storage, as a fuel, or for other uses.
Sec. 5. As used in this chapter, "state tax liability" means a
taxpayer's total tax liability that is incurred under:
(1) IC 6-3-1 through IC 6-3-7 (the adjusted gross income tax);
(2) IC 6-5.5 (the financial institutions tax); and
(3) IC 27-1-18-2 (the insurance premiums tax);
as computed after the application of the credits that under
IC 6-3.1-1-2 are to be applied before the credit provided by this
chapter.
Sec. 6. As used in this chapter, "taxpayer" means a person,
corporation, partnership, or other entity that makes a qualified
investment.
Sec. 7. A taxpayer is entitled to a credit against the taxpayer's
state tax liability in the taxable year in which the taxpayer makes
a qualified investment. The amount of the credit provided by this
section is equal to twenty percent (20%) of the amount of the
taxpayer's qualified investment.
Sec. 8. (a) If the amount determined under section 7 of this
chapter for a taxpayer in a taxable year exceeds the taxpayer's
state tax liability for that taxable year, the taxpayer may carry the
excess over to the following taxable years. The amount of the credit
carryover from a taxable year shall be reduced to the extent that
the carryover is used by the taxpayer to obtain a credit under this
chapter for any subsequent taxable year.
(b) A taxpayer is not entitled to a carryback or refund of any
unused credit.
Sec. 9. (a) If a pass through entity is entitled to a credit under
section 7 of this chapter but does not have state tax liability against
which the tax credit may be applied, an individual who is a
shareholder, partner, or member of the pass through entity is
entitled to a tax credit equal to:
(1) the tax credit determined for the pass through entity for
the taxable year; multiplied by
(2) the percentage of the pass through entity's distributive
income to which the shareholder, partner, or member is
entitled.
(b) The credit provided under subsection (a) is in addition to a
tax credit to which a shareholder, partner, or member of a pass
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through entity is otherwise entitled under this chapter. However,
a pass through entity and an individual who is a shareholder,
partner, or member of the pass through entity may not claim more
than one (1) credit for the same qualified investment.
Sec. 10. To receive the credit provided by this chapter, a
taxpayer must claim the credit on the taxpayer's annual state tax
return or returns in the manner prescribed by the department. The
taxpayer shall submit to the department:
(1) information verifying that the taxpayer's qualified
investment was made with respect to a small modular nuclear
reactor that will be manufactured in Indiana; and
(2) all information that the department determines is
necessary for the calculation of the credit provided by this
chapter.
SECTION 2. IC 8-1-7.9 IS ADDED TO THE INDIANA CODE AS
A NEW CHAPTER TO READ AS FOLLOWS [EFFECTIVE UPON
PASSAGE]:
Chapter 7.9. Expedited Generation Resource Plans and Large
Load Customers
Sec. 1. (a) As used in this chapter, "acquisition" means a project
or an arrangement that is undertaken:
(1) by an energy utility to construct, purchase, lease, or
otherwise acquire a generation resource; and
(2) in accordance with an approved EGR plan.
(b) The term includes the purchase of energy or capacity
through a power purchase agreement.
Sec. 2. As used in this chapter, "acquisition costs" means the
total costs of an acquisition made under an EGR plan, including:
(1) planning;
(2) construction; and
(3) operating;
costs related to the acquisition.
Sec. 3. As used in this chapter, "appropriate regional
transmission organization" has the meaning set forth in
IC 8-1-8.5-13(b).
Sec. 4. As used in this chapter, "commission" refers to the
Indiana utility regulatory commission created by IC 8-1-1-2.
Sec. 5. (a) As used in this chapter, "construction and operating
costs" means costs:
(1) incurred or to be incurred by an energy utility under this
chapter after the issuance of an order by the commission
under this chapter; and
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(2) related to an approved or commission modified acquisition
or project.
(b) The term includes procurement, contractual, construction,
operating, maintenance, financing, legal, regulatory, and project
evaluation, analysis, and development costs incurred after the
issuance of an order by the commission under this chapter.
Sec. 6. As used in this chapter, "corporation" refers to the
Indiana economic development corporation established by
IC 5-28-3-1 or its successor.
Sec. 7. As used in this chapter, "energy utility" means:
(1) an electric utility listed in 170 IAC 4-7-2(a) and any
successor in interest to that utility; or
(2) a corporation organized under IC 8-1-13.
Sec. 8. As used in this chapter, "expedited generation resource
plan", or "EGR plan", means a plan developed by an energy utility
for acquiring generation resources to meet load growth that
exceeds the lesser of:
(1) five percent (5%) of the energy utility's average peak
demand over the most recent three (3) calendar years; or
(2) one hundred fifty (150) megawatts.
Sec. 9. As used in this chapter, "generation resource submittal"
means a compliance filing made to the commission for approval of
the acquisition of a specific generation resource in accordance with
the criteria set forth in an approved EGR plan.
Sec. 10. As used in this chapter, "large load customer" means a
new or existing customer of an energy utility, or not more than
four (4) multiple new or existing customers of an energy utility,
that:
(1) requests new or additional electricity demand that in the
aggregate exceeds the lesser of:
(A) five percent (5%) of the energy utility's average peak
demand over the most recent three (3) calendar years; or
(B) one hundred fifty (150) megawatts;
(2) plans to make a capital investment that exceeds five
hundred million dollars ($500,000,000) in a new or expanded
facility in Indiana; and
(3) plans to employ at the new or expanded facility in Indiana
at least fifty (50) full-time employees with wages that on
average meet or exceed the most recently published annual
national average according to the Bureau of Labor Statistics
of the United States Department of Labor.
Sec. 11. As used in this chapter, "office" refers to the Indiana
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office of energy development established by IC 4-3-23-3.
Sec. 12. (a) As used in this chapter, "planning costs" means
costs:
(1) incurred or to be incurred by an energy utility before the
issuance of an order by the commission under this chapter;
and
(2) related to an acquisition or project.
(b) The term includes study, analysis, pre-engineering,
engineering, legal, financing, and regulatory costs.
Sec. 13. As used in this chapter, "pre-filing meeting" means a
meeting to review and discuss a filing or submittal by an energy
utility in accordance with:
(1) section 18 of this chapter;
(2) section 20 of this chapter; or
(3) section 22 of this chapter;
as applicable.
Sec. 14. As used in this chapter, "project" refers to a project
relating to energy infrastructure and generation resources that:
(1) are required primarily to serve a large load customer of an
energy utility; and
(2) may be designed to serve more than one (1) large load
customer of the energy utility or to meet other customer
demand or energy needs.
Sec. 15. As used in this chapter, "project costs" means the total
costs of a project, including:
(1) planning costs; and
(2) construction and operating costs;
related to the project.
Sec. 16. As used in this chapter, "reasonable risk premium"
means compensation:
(1) negotiated between an energy utility and a large load
customer; and
(2) paid by the large load customer.
Sec. 17. (a) The commission may expedite, in accordance with
this chapter, the review of filings and submittals made by an
energy utility to meet the energy infrastructure and generation
resource needs of customers. An energy utility may request an
expedited review by the commission under either or both of the
following:
(1) Sections 18 through 21 of this chapter (concerning EGR
plans).
(2) Sections 22 through 24 of this chapter (concerning large
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load customer projects).
(b) This chapter does not preclude an energy utility from
petitioning the commission under other applicable statutes for
approval of a generation resource acquisition to meet the needs of
its customers.
(c) This chapter does not preclude an energy utility from
petitioning the commission under, or in conjunction with, other
applicable statutes, including:
(1) IC 8-1-2-24;
(2) IC 8-1-2-42;
(3) IC 8-1-2.5;
(4) IC 8-1-8.5;
(5) IC 8-1-8.8; or
(6) IC 8-1-39;
for approval of a project to meet the needs of large load customers.
Sec. 18. (a) This section applies to an energy utility that petitions
the commission for approval of an EGR plan.
(b) An energy utility may file a petition with the commission for
approval of an EGR plan to acquire generation resources to meet
the extraordinary needs for electricity by the energy utility's
customers.
(c) In a petition under this section, an energy utility must do the
following:
(1) Describe the energy utility's EGR plan for acquiring
generation resources to meet the anticipated extraordinary
growth in the load of its customers.
(2) Demonstrate a need for generation capacity that exceeds
the lesser of:
(A) five percent (5%) of the energy utility's average peak
demand over the most recent three (3) calendar years; or
(B) one hundred fifty (150) megawatts.
(3) Provide a load growth forecast for a minimum of five (5)
years from the date of the petition.
(4) Describe the status of customer contracts and
commitments that support the load growth forecast described
in subdivision (3).
(5) Explain how the EGR plan is consistent with or differs
from the energy utility's most recent integrated resource plan.
(6) Propose the accounting authority needed from the
commission to support the EGR plan.
(7) Propose the manner in which the capital costs and
operating and maintenance expenses related to the EGR plan
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will be included in the energy utility's revenue requirement.
(8) Identify the type and amount of capacity and energy:
(A) that is included in the EGR plan;
(B) that does not exceed seventy-five percent (75%) of the
energy utility's peak capacity over the forecast period
described in subdivision (3); and
(C) with respect to which the energy utility may request
expedited approval in a subsequent generation resource
submittal.
(9) Identify the criteria to be included in a generation
resource submittal that must be met for the acquisition to be
approved by the commission.
(10) Certify that at least thirty (30) days before the filing of
the petition the energy utility held a pre-filing meeting with
the commission and the office of utility consumer counselor to
review the EGR plan.
(11) Describe how the energy utility considered implementing
grid enhancing technologies to defer or minimize the need for
additional investment in generation.
(12) Describe how the EGR plan will support the provision of
electric utility service with the attributes set forth in
IC 8-1-2-0.6, including:
(A) reliability;
(B) affordability;
(C) resiliency;
(D) stability; and
(E) environmental sustainability.
(13) Describe how the EGR plan reasonably protects existing
and future customers and is consistent with:
(A) the provision of safe, reliable, and affordable electric
utility service; and
(B) economical rates.
(14) Include:
(A) verified testimony; and
(B) exhibits;
supporting the petition and constituting the energy utility's
case in chief.
(15) Include a proposed order for the petition.
Sec. 19. (a) This section applies to an energy utility that petitions
the commission for approval of an EGR plan.
(b) Notwithstanding IC 8-1-8.5 or any other statute, the
commission may approve an energy utility's EGR plan to
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construct, purchase, lease, or otherwise acquire generation
resources under this chapter for purposes of meeting the needs of
the energy utility's customers. The commission shall make its
decision based on whether the relief requested is just, reasonable,
and in the public interest.
(c) The commission may:
(1) approve the energy utility's petition in its entirety;
(2) deny the energy utility's petition in its entirety; or
(3) modify the petition, subject to the energy utility's
acceptance of the modification.
(d) The commission shall issue a final order on the petition not
later than ninety (90) days after receiving the energy utility's
complete petition. A petition is considered:
(1) complete unless the commission provides a notice of
deficiency to the energy utility not later than five (5) business
days after the filing of the petition; and
(2) approved if the commission does not issue a final order on
the petition within the ninety (90) day period set forth in this
subsection.
Sec. 20. (a) This section applies to an energy utility that submits
to the commission for approval a generation resource submittal in
accordance with an approved EGR plan.
(b) An energy utility may submit a generation resource
submittal to the commission for approval of an acquisition that the
energy utility intends to make in accordance with an approved
EGR plan.
(c) In a generation resource submittal under this section, an
energy utility must do the following:
(1) Describe:
(A) the type of technology used in the generation resource
to be acquired;
(B) the amount of capacity and energy to be acquired;
(C) key contractual terms for the acquisition; and
(D) the estimated acquisition costs.
(2) Demonstrate that the acquisition meets the criteria set
forth in the energy utility's approved EGR plan.
(3) Explain how the acquisition is consistent with or differs
from the energy utility's most recent integrated resource plan.
(4) Detail the status of customer contracts and commitments
that support the acquisition.
(5) Certify that at least thirty (30) days before the filing of the
generation resource submittal the energy utility held a
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pre-filing meeting with the commission and the office of utility
consumer counselor to review the acquisition.
(6) Describe how the energy utility considered implementing
grid enhancing technologies to defer or minimize the need for
additional investment in generation.
(7) Describe how the acquisition will support the provision of
electric utility service with the attributes set forth in
IC 8-1-2-0.6, including:
(A) reliability;
(B) affordability;
(C) resiliency;
(D) stability; and
(E) environmental sustainability.
(8) Describe how the acquisition reasonably protects existing
and future customers and is consistent with:
(A) the provision of safe, reliable, and affordable electric
utility service; and
(B) economical rates.
(9) Include supporting affidavits and exhibits.
(10) Include a proposed order for the submittal.
Sec. 21. (a) This section applies to an energy utility that submits
to the commission for approval a generation resource submittal in
accordance with an approved EGR plan.
(b) Notwithstanding IC 8-1-8.5 or any other statute, the
commission may approve an energy utility's generation resource
submittal to construct, purchase, lease, or otherwise acquire
generation resources under this chapter for purposes of meeting
the needs of the energy utility's customers. The commission shall
make its decision based solely on whether the submittal meets the
criteria and requirements set forth in the energy utility's approved
EGR plan.
(c) The commission may:
(1) approve the energy utility's generation resource submittal
in its entirety;
(2) deny the energy utility's generation resource submittal in
its entirety; or
(3) modify the energy utility's generation resource submittal,
subject to the energy utility's acceptance of the modification.
(d) The commission shall issue a final order on the energy
utility's generation resource submittal not later than:
(1) sixty (60) days after receiving the energy utility's complete
generation resource submittal, if the acquisition is a clean
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energy project (as defined in IC 8-1-8.8-2); or
(2) one hundred twenty (120) days after receiving the energy
utility's complete generation resource submittal, if the
acquisition would otherwise require a certificate under
IC 8-1-8.5-2.
A generation resource submittal is considered complete unless the
commission provides a notice of deficiency to the energy utility not
later than five (5) business days after the filing of the generation
resource submittal. A generation resource submittal is considered
approved if the commission does not issue a final order on the
generation resource submittal within the period set forth in
subdivision (1) or (2), as applicable.
Sec. 22. (a) This section applies to an energy utility that petitions
the commission for approval of a project to serve a large load
customer.
(b) An energy utility may submit to the commission a petition
for approval of a project to serve a large load customer only if the
following are satisfied:
(1) The petition concerns serving the energy needs of a large
load customer.
(2) The large load customer commits to significant and
meaningful financial assurances that must:
(A) include reimbursement by the large load customer of
at least eighty percent (80%) of the project costs
reasonably allocable to the large load customer; and
(B) afford protections for the energy utility's existing and
future customers from project costs reasonably allocable
to the large load customer regardless of whether the large
load customer ultimately takes service in the anticipated
amount and within the anticipated time frame.
(3) At least thirty (30) days before the energy utility's
submission of the petition to the commission, the energy
utility held at least one (1) pre-filing meeting with:
(A) the corporation;
(B) the office;
(C) the office of utility consumer counselor;
(D) the appropriate regional transmission organization;
and
(E) the large load customer;
to review the project.
(c) An energy utility may petition the commission for approval
of a project to serve:
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(1) one (1) or more large load customers at one (1) or more
locations; or
(2) not more than four (4) customers whose aggregate demand
satisfies the amount set forth in section 10(1) of this chapter.
In any case in which more than one (1) large load customer is to be
served by a project, a reference in this chapter to one (1) large load
customer is a reference to all large load customers to be served by
the project, in accordance with IC 1-1-4-1(3).
(d) In submitting a petition to the commission under this section,
an energy utility must demonstrate that the large load customer
and the associated projects meet the requirements of this chapter.
Sec. 23. (a) This section applies to an energy utility that petitions
the commission for approval of a project to serve a large load
customer.
(b) In a petition under this section, an energy utility must
include, at a minimum, the following:
(1) The energy utility's complete case in chief, which must
include, at a minimum, the following:
(A) An agreement from the large load customer that
describes the financial assurances:
(i) that afford protections for the energy utility's existing
and future customers; and
(ii) to which the large load customer has committed
regardless of whether the large load customer ultimately
takes service in the anticipated amount and within the
anticipated time frame.
(B) A description of:
(i) the demand side management and self-generation
options reviewed with the large load customer; and
(ii) the investments the large load customer will
undertake to reasonably minimize the amount of
incremental and other costs incurred by the energy
utility.
(C) A description of how the energy utility considered
implementing grid enhancing technologies to defer or
minimize the need for additional investment in generation.
(D) A description of how the energy utility may provide for
the requisite amount of electricity needed by the large load
customer, including the estimated project costs.
(E) A description of how the expected project solution will
support the provision of electric utility service with the
attributes set forth in IC 8-1-2-0.6, including:
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(i) reliability;
(ii) affordability;
(iii) resiliency;
(iv) stability; and
(v) environmental sustainability.
(F) A description of how the expected project solution and
its implementation, if approved by the commission,
reasonably protects existing and future customers and is
consistent with:
(i) the provision of safe, reliable, and affordable electric
utility service; and
(ii) economical rates.
(G) A description of the changes that the energy utility will
make to the energy utility's:
(i) submissions under IC 8-1-8.5; or
(ii) filings under IC 8-1-39;
or both, that are necessary to update the energy utility's
plans under those statutes to incorporate the project.
(H) Information concerning each:
(i) large load customer; and
(ii) economic development project;
included in the petition.
(I) A letter to the energy utility from the corporation
supporting the petition's request.
(J) A letter to the energy utility from the office certifying
that a pre-filing meeting took place and that at the
meeting:
(i) the large load customer's proposed project; and
(ii) the expected project solution proposed by the energy
utility;
were adequately discussed.
(K) A description of the communications and information
sharing that:
(i) took place with the appropriate regional transmission
organization before the pre-filing meeting described in
clause (J); and
(ii) concerned the capacity and energy needs of each
large load customer included in the petition.
(L) A proposed order for the petition.
(2) A copy of a notice of filing with:
(A) the corporation;
(B) the office;
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(C) the office of utility consumer counselor; and
(D) the appropriate regional transmission organization.
A notice that is delivered electronically to the parties set forth
in this subdivision satisfies the notice requirement under this
subdivision.
Sec. 24. (a) This section applies to an energy utility that petitions
the commission for approval of a project to serve a large load
customer.
(b) The commission may approve a petition in whole or in part.
The commission shall make its decision based on whether the relief
requested is just, reasonable, and in the public interest. The
commission shall issue its final order on the petition not later than
one hundred fifty (150) days after receiving the energy utility's
complete petition and case in chief. A petition is considered:
(1) complete unless the commission provides a notice of
deficiency to the energy utility not later than seven (7)
business days after the filing of the petition; and
(2) approved if the commission does not issue a final order on
the petition within the one hundred fifty (150) day period set
forth in this subsection.
(c) If an energy utility files a petition that includes one (1) or
more large load customers and one (1) or more proposed projects,
the commission may:
(1) approve the energy utility's petition in its entirety;
(2) deny the energy utility's petition in its entirety; or
(3) modify the petition, subject to the energy utility's
acceptance of the modification.
(d) The commission may approve a reasonable risk premium for
a project if requested in an energy utility's petition and if the
commission finds that the reasonable risk premium is appropriate.
If the commission approves a reasonable risk premium:
(1) the large load customer is responsible for the amount of
the reasonable risk premium; and
(2) the reasonable risk premium may not be:
(A) included in the energy utility's:
(i) revenue requirement;
(ii) authorized net operating income; or
(iii) calculations under IC 8-1-2-42(d)(3) or
IC 8-1-2-42(g)(3)(C); or
(B) otherwise considered for purposes of setting the
authorized return in any future general rate case or other
regulatory proceeding involving the energy utility.
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(e) The commission may approve an energy utility's request to
construct, purchase, lease, or otherwise acquire an energy
generation resource under this chapter (notwithstanding and
instead of under IC 8-1-2.5, IC 8-1-8.5, or IC 8-1-8.8) for the
purpose of serving one (1) or more large load customers. In
approving an energy utility's request under this chapter to acquire
an energy generation resource to serve one (1) or more large load
customers, the commission must find that:
(1) the information provided by the energy utility under
section 23 of this chapter is complete;
(2) reasonable and demonstrable consideration was given to
nongeneration alternatives by the parties involved;
(3) existing and future customers of the energy utility will be
adequately protected if the request is granted; and
(4) the energy utility has considered the impact of the request
on the energy utility's preferred resource portfolio in the
energy utility's most recent integrated resource plan.
(f) An energy utility shall promptly notify the commission if,
after the commission has approved a petition under subsection (e),
one (1) or more of the large load customers with respect to whom
the petition was approved:
(1) no longer requires service from the energy utility or
materially alters or terminates the large load customer's
service requirements; and
(2) the project is incomplete.
(g) The commission may, not later than sixty (60) days after
receiving a notice under subsection (f), conduct an investigation
under IC 8-1-2-58 through IC 8-1-2-60 to determine whether the
public interest would still be served by completion of the project.
An investigation under this subsection does not preclude the energy
utility from continuing construction of the project to serve the
large load customer or from continuing to serve the large load
customer. If the commission finds that completion of the project is
no longer in the public interest, the commission may modify or
revoke the order approving the petition.
Sec. 25. (a) The commission shall review an energy utility's:
(1) estimated acquisition costs submitted under section
20(c)(1)(D) of this chapter; or
(2) estimated project costs filed under section 23(b)(1)(D) of
this chapter;
as applicable.
(b) If the commission approves, with or without modification, an
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energy utility's generation resource submittal or petition for
approval of a project, the energy utility may recover:
(1) acquisition costs; or
(2) project costs;
as applicable, that have been reviewed and found reasonable by the
commission, with a return at the energy utility's weighted average
cost of capital.
(c) If the commission denies an energy utility's generation
resource submittal or petition for approval of a project, the energy
utility may recover planning costs that have been reviewed and
found reasonable by the commission, without a return.
(d) Absent fraud, concealment, or gross mismanagement, an
energy utility may recover:
(1) acquisition costs; or
(2) project costs;
as applicable, with a return at the energy utility's weighted average
cost of capital, that the energy utility has incurred or contractually
will incur in reliance on a commission order issued under this
chapter.
Sec. 26. (a) Upon request by an energy utility, the commission
shall determine whether the information and related materials
filed or submitted, or to be filed or submitted, by an energy utility
under this chapter:
(1) are confidential under IC 5-14-3-4 or are trade secrets
under IC 24-2-3;
(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.
(b) The parties to a pre-filing meeting under this chapter shall
execute a nondisclosure agreement to review or discuss
information or materials considered confidential under IC 5-14-3-4
or to be trade secrets under IC 24-2-3.
(c) If the corporation is in negotiations with an industrial,
research, or commercial prospect about a potential economic
development project and, based on communications related to
those negotiations, determines that the potential economic
development project for a new or expanded facility in Indiana may
result in the economic development project requiring new or
increased energy demand of at least twenty (20) megawatts, the
corporation shall notify the affected energy utility not later than
fifteen (15) days after making the determination. All
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communications of the corporation, including notice under this
section to an affected energy utility, regarding a potential economic
development project are considered confidential and exempt from
disclosure under IC 5-14-3-4(b)(5). Upon the corporation's
provision of the notice required by this subsection, any subsequent:
(1) meeting;
(2) pre-filing meeting;
(3) communications; or
(4) information sharing;
involving the corporation, the affected energy utility, or the
industrial, research, or commercial prospect about a potential
economic development project may be subject to a nondisclosure
agreement with respect to information or materials considered
confidential under IC 5-14-3-4 or to be trade secrets under
IC 24-2-3.
(d) An energy utility may request, and the commission may
approve, financial incentives under IC 8-1-8.8-11(a) for:
(1) an acquisition; or
(2) a project;
that qualifies as a clean energy project (as defined in IC 8-1-8.8-2).
(e) An energy utility may request that review of an arrangement
under IC 8-1-2-24 and any related rates and charges under
IC 8-1-2-25 that are:
(1) submitted with a generation resource submittal; or
(2) filed with a petition for a project;
under this chapter be reviewed and approved or denied by the
commission not later than ninety (90) days after the date of
submittal or filing, as applicable.
(f) Notwithstanding IC 8-1-8.5 or any other applicable statute,
an energy utility may begin construction of an acquisition or a
project before filing a petition or submittal under this chapter.
(g) The commission may require an energy utility to file with the
commission progress reports and updates with respect to an
acquisition or project under this chapter. Any required progress
reports or updates under this subsection shall be made in a form
and at a frequency that the commission determines to be
reasonable.
SECTION 3. IC 8-1-8.5-2.1, AS AMENDED BY THE
TECHNICAL CORRECTIONS BILL OF THE 2025 GENERAL
ASSEMBLY, IS AMENDED TO READ AS FOLLOWS [EFFECTIVE
JULY 1, 2025]: Sec. 2.1. (a) This section does not apply to the
retirement, sale, or transfer of:
HEA 1007 — Concur 17
(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(i)(4) 13(n)(6) of this
chapter; and
(2) the reliability adequacy metrics set forth in section 13(e) 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
HEA 1007 — Concur 18
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.
SECTION 4. IC 8-1-8.5-13, AS AMENDED BY P.L.93-2024,
SECTION 68, IS AMENDED TO READ AS FOLLOWS [EFFECTIVE
JULY 1, 2025]: 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
(l)(4); (n)(6); and
(B) is acceptable to the commission.
HEA 1007 — Concur 19
(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.
(g) (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 (q)(2)(B), (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 (l) (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 (l) (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 (l)(4). (n)(6).
(2) Subject to subsection (q)(2)(B), (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 (l) (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 (l) (n) after June 30, 2023;
such that it will have sufficient winter UCAP;
to provide reliable electric service to Indiana customers, and to
HEA 1007 — Concur 20
meet its planning reserve margin requirement and other federal
reliability requirements described in subsection (l)(4). (n)(6).
(3) Subject to subsection (q)(2)(B), (u)(2), with respect to a report
filed with the commission under subsection (l) (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 (l)(4). (n)(6).
(4) Subject to subsection (q)(2)(B), (u)(2), with respect to a report
filed with the commission under subsection (l) (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 (l)(4). (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.
(h) (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
HEA 1007 — Concur 21
the spring period; and
(ii) meet its planning reserve margin requirement and other
federal reliability requirements described in subsection
(l)(4); (n)(6); and
(B) is acceptable to the commission.
(i) (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.
(j) (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
(l)(4); (n)(6); and
(B) is acceptable to the commission.
(k) (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; and
(2) reasonably consistent with the resource reliability
requirements of MISO or any other appropriate regional
HEA 1007 — Concur 22
transmission organization; and
(3) reasonably maximizes the economic value of the electric
generating facility.
(l) (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
(C) fuel source;
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;
(C) fuel source; and
(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.
HEA 1007 — Concur 23
(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;
(C) existing fuel source;
(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.
(2) (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
(C) fuel source;
for each electric generating facility that will supply capacity or
energy under the contract, to the extent known by the public
utility.
(3) (5) The amount of demand response resources available to the
public utility under contracts and tariffs.
(4) (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;
HEA 1007 — Concur 24
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.
(5) (7) The reliability adequacy metrics of the public utility, as
forecasted for the three (3) planning years covered by the report.
(m) (o) Upon request by a public utility, the commission shall
determine whether information provided in a report filed by the public
utility under subsection (l): (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.
(n) (p) A joint agency created under IC 8-1-2.2 may file the report
required under subsection (l) (n) as a consolidated report on behalf of
any or all of the municipally owned utilities that make up its
membership.
(o) (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 (l) (n) as a consolidated
report on behalf of any or all of the cooperatively owned electric
utilities that it serves.
(p) (r) In reviewing a report filed by a public utility under
subsection (l), (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
HEA 1007 — Concur 25
reliability requirements that the public utility is obligated to meet,
as described in subsection (l)(4); (n)(6); and
(2) whether the resources available to the public utility under
subsections (l)(1) (n)(1) through (l)(3) (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;
(C) resiliency;
(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.
(q) (u) If, after reviewing a report filed by a public utility under
subsection (l), (n) and any staff report prepared with respect to the
public utility under subsection (s), the commission is not satisfied
HEA 1007 — Concur 26
that the public utility can either:
(1) provide reliable electric service to the public utility's Indiana
customers; or
(2) either:
(A) (1) satisfy both:
(i) (A) its planning reserve margin requirement or other
federal reliability requirements that the public utility is
obligated to meet, as described in subsection (l)(4); (n)(6); and
(ii) (B) the reliability adequacy metrics set forth in subsection
(g); (h); or
(B) (2) provide sufficient reason as to why the public utility is
unable to satisfy both:
(i) (A) its planning reserve margin requirement or other
federal reliability requirements that the public utility is
obligated to meet, as described in subsection (l)(4); (n)(6); and
(ii) (B) the reliability adequacy metrics set forth in subsection
(g); (h);
during one (1) more of the planning years covered by the report, the
commission may 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 (2),
or both. 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
HEA 1007 — Concur 27
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.
(r) (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 (l)(1) (n)(1) through (l)(3) (n)(5) will
not be adequate to support the provision of reliable electric service to
the public utility's Indiana customers, or 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 (l)(4)) (n)(6)) and the reliability adequacy
metrics set forth in subsection (g), (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 (l)(4)
(n)(6) and the reliability adequacy metrics set forth in subsection (g).
(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
HEA 1007 — Concur 28
investigation. Not later than ninety (90) days after the date of the
commission's 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).
The (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.
(s) (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
(g); (h);
for the next three (3) utility resource planning years, based on the
most recent reports filed by public utilities under subsection (l).
(n).
(2) A summary of:
(A) the projected demand for retail electricity in Indiana over
the next calendar year; and
(B) the amount and type of capacity resources committed to
HEA 1007 — Concur 29
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
(g)(3)(B); (h)(3)(B); and
(B) total fall UCAP that public utilities should be authorized
to acquire from capacity markets under subsection (g)(4)(B).
(h)(4)(B).
(t) (z) The commission may adopt rules under IC 4-22-2 to
implement this section.
SECTION 5. An emergency is declared for this act.
HEA 1007 — Concur Speaker of the House of Representatives
President of the Senate
President Pro Tempore
Governor of the State of Indiana
Date: Time:
HEA 1007 — Concur