Indiana House Bill HB1007 Engrossed / Bill

                    *HB1007.3*
Reprinted
February 11, 2025
HOUSE BILL No. 1007
_____
DIGEST OF HB 1007 (Updated February 10, 2025 3:11 pm - DI 101)
Citations Affected:  IC 6-3.1; IC 8-1.
Synopsis:  Energy generation resources. Provides a credit against state
tax liability for expenses incurred in the manufacture of a small
modular nuclear reactor (SMR) in Indiana. Establishes procedures
under which certain energy utilities may request approval for one or
more of the following from the Indiana utility regulatory commission
(IURC): (1) An expedited generation resource plan (EGR plan) to meet
customer load growth that exceeds a specified threshold. (2) A
generation resource submittal for the acquisition of a specific
generation resource in accordance with an approved EGR plan. (3) A
project to serve one or more large load customers. Sets forth: (1) the
requirements for approval of each of these types of requests; (2)
standards for financial assurances by large load customers; and (3) cost 
(Continued next page)
Effective:  Upon passage; January 1, 2025 (retroactive); July 1, 2025.
Soliday, Shonkwiler, Pressel, Bartels
January 13, 2025, read first time and referred to Committee on Utilities, Energy and
Telecommunications.
January 29, 2025, amended, reported — Do Pass. Referred to Committee on Ways and
Means pursuant to Rule 126.3.
February 6, 2025, reported — Do Pass.
February 10, 2025, read second time, amended, ordered engrossed.
HB 1007—LS 7547/DI 101 Digest Continued
recovery mechanisms for certain acquisition costs or project costs
incurred by energy utilities. Provides that any standard tariff offered by
an energy utility after June 30, 2025, to a large load customer of the
energy utility must include a provision that requires reimbursement by
the large load customer of at least 80% of the project costs reasonably
allocable to the large load customer, regardless of whether the large
load customer ultimately takes service in any anticipated amount and
within any anticipated time frame. Authorizes a public utility to
petition the IURC for approval to incur, before obtaining a certificate
of public convenience and necessity (CPCN) for an SMR, project
development costs for the development of the SMR. Provides that if a
public utility receives approval to incur project development costs for
an SMR, the public utility may petition the IURC 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. Provides that a public utility that is authorized to recover project
development costs shall: (1) recover 80% of the approved project
development costs under the approved rate schedule; and (2) defer the
remaining 20% of approved project development costs for recovery as
part of public utility's next general rate case before the IURC. Provides
that project development costs that: (1) are incurred by a public utility;
and (2) exceed the best estimate of project development costs included
in the IURC's order authorizing the public utility to incur project
development costs; may not be included in the public utility's rates and
charges unless found by the IURC to be reasonable, necessary, and
prudent in supporting the construction, purchase, or lease of the SMR
for which they were incurred. Provides that: (1) project development
costs incurred for a project that is canceled or not completed may be
recovered by the public utility if found by the IURC to be reasonable,
necessary, and prudently incurred; but (2) such costs shall be recovered
without a return unless the IURC makes certain additional findings.
Amends the statute concerning public utilities' annual electric resource
planning reports to the IURC to provide that for an annual report
submitted after December 31, 2025, a public utility must include
information as to the amount of generating resource capacity or energy
that the public utility plans to retire or refuel with respect to any
electric generation resource of at least 125 megawatts. Provides that for
any planned retirement or refueling, the public utility must include,
along with other specified information, information as to the public
utility's plans with respect to the following: (1) For a retirement, the
amount of replacement capacity identified to provide approximately the
same accredited capacity within the appropriate regional transmission
organization (RTO) as the capacity of the facility to be retired. (2) For
a refueling, the extent to which the refueling will maintain or increase
the current generating resource accredited capacity or energy that the
electric generating facility provides, so as to provide approximately the
same accredited capacity within the appropriate RTO. Requires IURC
staff to prepare a staff report for each public utility report that includes
a planned electric generation resource retirement. Provides that if, after
reviewing a public utility's report and any related staff report, the IURC
is not satisfied that the public utility can satisfy both its planning
reserve margin requirement and the statute's prescribed reliability
adequacy metrics, the IURC shall conduct an investigation into the
reasons for the public utility's inability to meet these requirements.
Provides that if the public utility's report indicates that the public utility
plans to retire an electric generating facility within one year of the date
of the report, the IURC must conduct such an investigation. Provides
that: (1) a public utility may request, not earlier than three years before
the planned retirement date of an electric generation facility, that the
IURC conduct an investigation into the planned retirement; and (2) if
the IURC conducts an investigation at the request of the public utility
within that three year period, the IURC may not conduct a subsequent
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HB 1007—LS 7547/DI 101HB 1007—LS 7547/DI 101 Digest Continued
investigation that would otherwise be required under the bill's
provisions unless the IURC is not satisfied that the public utility can
satisfy both its planning reserve margin requirement and the statutory
reliability adequacy metrics as of the time the investigation would
otherwise be required. Provides that if a CPCN is granted by the IURC
for a facility intended to repower or replace a generation unit that is
planned for retirement, and the CPCN 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 CPCN constitutes approval by
the IURC for purposes of an investigation that would otherwise be
required. Provides that if, after an investigation, the IURC determines
that the capacity resources available to the public utility will not be
adequate to allow the public utility to satisfy both its planning reserve
margin requirements and the statute's prescribed reliability adequacy
metrics, the IURC 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 meet these requirements. Provides that if the IURC
does not issue an order in an investigation within 120 days after the
initiation of the investigation, the public utility is considered to be able
to satisfy both its planning reserve margin requirement and the
statutory reliability adequacy metrics with respect to the retirement of
the facility under investigation. Provides that if the IURC issues an
order to prohibit the retirement or refueling of an electric generation
resource, the IURC 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 proposed to be retired or refueled, subject
to a finding by the IURC that the continued costs of operation are just
and reasonable. Makes a technical change to another Indiana Code
section to recognize the redesignation of subsections within the section
containing these provisions.
HB 1007—LS 7547/DI 101HB 1007—LS 7547/DI 101  Reprinted
February 11, 2025
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 BILL No. 1007
A BILL FOR AN ACT to amend the Indiana Code concerning
utilities.
Be it enacted by the General Assembly of the State of Indiana:
1 SECTION 1. IC 6-3.1-45 IS ADDED TO THE INDIANA CODE
2 AS A NEW CHAPTER TO READ AS FOLLOWS [EFFECTIVE
3 JANUARY 1, 2025 (RETROACTIVE)]:
4 Chapter 45. Small Modular Nuclear Reactor Manufacturing
5 Expense Tax Credit
6 Sec. 1. This chapter applies to a taxable year beginning after
7 December 31, 2024.
8 Sec. 2. As used in this chapter, "department" refers to the
9 department of state revenue.
10 Sec. 3. As used in this chapter, "qualified investment" means a
11 taxpayer's expenditures incurred in the manufacture of a small
12 modular nuclear reactor in Indiana.
13 Sec. 4. As used in this chapter, "small modular nuclear reactor"
14 means a nuclear reactor that:
15 (1) has a rated electric generating capacity of not more than
HB 1007—LS 7547/DI 101 2
1 four hundred seventy (470) megawatts;
2 (2) is capable of being constructed and operated, either:
3 (A) alone; or
4 (B) in combination with one (1) or more similar reactors if
5 additional reactors are, or become, necessary;
6 at a single site; and
7 (3) is required to be licensed by the United States Nuclear
8 Regulatory Commission.
9 The term includes a nuclear reactor that is described in this section
10 and that uses a process to produce hydrogen that can be used for
11 energy storage, as a fuel, or for other uses.
12 Sec. 5. As used in this chapter, "state tax liability" means a
13 taxpayer's total tax liability that is incurred under:
14 (1) IC 6-3-1 through IC 6-3-7 (the adjusted gross income tax);
15 (2) IC 6-5.5 (the financial institutions tax); and
16 (3) IC 27-1-18-2 (the insurance premiums tax);
17 as computed after the application of the credits that under
18 IC 6-3.1-1-2 are to be applied before the credit provided by this
19 chapter.
20 Sec. 6. As used in this chapter, "taxpayer" means a person,
21 corporation, partnership, or other entity that makes a qualified
22 investment.
23 Sec. 7. A taxpayer is entitled to a credit against the taxpayer's
24 state tax liability in the taxable year in which the taxpayer makes
25 a qualified investment. The amount of the credit provided by this
26 section is equal to twenty percent (20%) of the amount of the
27 taxpayer's qualified investment.
28 Sec. 8. (a) If the amount determined under section 7 of this
29 chapter for a taxpayer in a taxable year exceeds the taxpayer's
30 state tax liability for that taxable year, the taxpayer may carry the
31 excess over to the following taxable years. The amount of the credit
32 carryover from a taxable year shall be reduced to the extent that
33 the carryover is used by the taxpayer to obtain a credit under this
34 chapter for any subsequent taxable year.
35 (b) A taxpayer is not entitled to a carryback or refund of any
36 unused credit.
37 Sec. 9. (a) If a pass through entity is entitled to a credit under
38 section 7 of this chapter but does not have state tax liability against
39 which the tax credit may be applied, an individual who is a
40 shareholder, partner, or member of the pass through entity is
41 entitled to a tax credit equal to:
42 (1) the tax credit determined for the pass through entity for
HB 1007—LS 7547/DI 101 3
1 the taxable year; multiplied by
2 (2) the percentage of the pass through entity's distributive
3 income to which the shareholder, partner, or member is
4 entitled.
5 (b) The credit provided under subsection (a) is in addition to a
6 tax credit to which a shareholder, partner, or member of a pass
7 through entity is otherwise entitled under this chapter. However,
8 a pass through entity and an individual who is a shareholder,
9 partner, or member of the pass through entity may not claim more
10 than one (1) credit for the same qualified investment.
11 Sec. 10. To receive the credit provided by this chapter, a
12 taxpayer must claim the credit on the taxpayer's annual state tax
13 return or returns in the manner prescribed by the department. The
14 taxpayer shall submit to the department:
15 (1) information verifying that the taxpayer's qualified
16 investment was made with respect to a small modular nuclear
17 reactor that will be manufactured in Indiana; and
18 (2) all information that the department determines is
19 necessary for the calculation of the credit provided by this
20 chapter.
21 SECTION 2. IC 8-1-2-24.5 IS ADDED TO THE INDIANA CODE
22 AS A NEW SECTION TO READ AS FOLLOWS [EFFECTIVE
23 UPON PASSAGE]: Sec. 24.5. (a) As used in this section, "energy
24 utility" means:
25 (1) an electric utility listed in 170 IAC 4-7-2(a) and any
26 successor in interest to that utility; or
27 (2) a corporation organized under IC 8-1-13.
28 (b) As used in this section, "large load customer" means a new
29 or existing customer of an energy utility, or not more than four (4)
30 multiple new or existing customers of an energy utility, that
31 requests new or additional electricity demand that in the aggregate
32 exceeds the lesser of:
33 (1) five percent (5%) of the energy utility's average peak
34 demand over the most recent three (3) calendar years; or
35 (2) one hundred fifty (150) megawatts.
36 (c) As used in this section, "project" refers to a project relating
37 to energy infrastructure or generation resources that:
38 (1) are required primarily to serve a large load customer of an
39 energy utility; and
40 (2) may be designed to serve more than one (1) large load
41 customer of the energy utility or to meet other customer
42 demand or energy needs.
HB 1007—LS 7547/DI 101 4
1 (d) As used in this section, "project costs" means the total costs
2 of a project, including:
3 (1) planning costs; and
4 (2) construction and operating costs;
5 related to the project.
6 (e) Any standard tariff offered by an energy utility after June
7 30, 2025, to a large load customer of the energy utility must include
8 a provision that requires reimbursement by the large load
9 customer of at least eighty percent (80%) of the project costs
10 reasonably allocable to the large load customer, regardless of
11 whether the large load customer ultimately takes service in any
12 anticipated amount and within any anticipated time frame.
13 SECTION 3. IC 8-1-8.2 IS ADDED TO THE INDIANA CODE AS
14 A NEW CHAPTER TO READ AS FOLLOWS [EFFECTIVE UPON
15 PASSAGE]:
16 Chapter 8.2. Expedited Generation Resource Plans and Large
17 Load Customers
18 Sec. 1. (a) As used in this chapter, "acquisition" means a project
19 or an arrangement that is undertaken:
20 (1) by an energy utility to construct, purchase, lease, or
21 otherwise acquire a generation resource; and
22 (2) in accordance with an approved EGR plan.
23 (b) The term includes the purchase of energy or capacity
24 through a power purchase agreement.
25 Sec. 2. As used in this chapter, "acquisition costs" means the
26 total costs of an acquisition made under an EGR plan, including:
27 (1) planning;
28 (2) construction; and
29 (3) operating;
30 costs related to the acquisition.
31 Sec. 3. As used in this chapter, "appropriate regional
32 transmission organization" has the meaning set forth in
33 IC 8-1-8.5-13(b).
34 Sec. 4. As used in this chapter, "commission" refers to the
35 Indiana utility regulatory commission created by IC 8-1-1-2.
36 Sec. 5. (a) As used in this chapter, "construction and operating
37 costs" means costs:
38 (1) incurred or to be incurred by an energy utility under this
39 chapter after the issuance of an order by the commission
40 under this chapter; and
41 (2) related to an approved or commission modified acquisition
42 or project.
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1 (b) The term includes procurement, contractual, construction,
2 operating, maintenance, financing, legal, regulatory, and project
3 evaluation, analysis, and development costs incurred after the
4 issuance of an order by the commission under this chapter.
5 Sec. 6. As used in this chapter, "corporation" refers to the
6 Indiana economic development corporation established by
7 IC 5-28-3-1 or its successor.
8 Sec. 7. As used in this chapter, "energy utility" means:
9 (1) an electric utility listed in 170 IAC 4-7-2(a) and any
10 successor in interest to that utility; or
11 (2) a corporation organized under IC 8-1-13.
12 Sec. 8. As used in this chapter, "expedited generation resource
13 plan", or "EGR plan", means a plan developed by an energy utility
14 for acquiring generation resources to meet load growth that
15 exceeds the lesser of:
16 (1) five percent (5%) of the energy utility's average peak
17 demand over the most recent three (3) calendar years; or
18 (2) one hundred fifty (150) megawatts.
19 Sec. 9. As used in this chapter, "generation resource submittal"
20 means a compliance filing made to the commission for approval of
21 the acquisition of a specific generation resource in accordance with
22 the criteria set forth in an approved EGR plan.
23 Sec. 10. As used in this chapter, "large load customer" means a
24 new or existing customer of an energy utility, or not more than
25 four (4) multiple new or existing customers of an energy utility,
26 that:
27 (1) requests new or additional electricity demand that in the
28 aggregate exceeds the lesser of:
29 (A) five percent (5%) of the energy utility's average peak
30 demand over the most recent three (3) calendar years; or
31 (B) one hundred fifty (150) megawatts;
32 (2) plans to make a capital investment that exceeds five
33 hundred million dollars ($500,000,000) in a new or expanded
34 facility in Indiana; and
35 (3) plans to employ at the new or expanded facility in Indiana
36 at least fifty (50) full-time employees with wages that on
37 average meet or exceed the most recently published annual
38 national average according to the Bureau of Labor Statistics
39 of the United States Department of Labor.
40 Sec. 11. As used in this chapter, "office" refers to the Indiana
41 office of energy development established by IC 4-3-23-3.
42 Sec. 12. (a) As used in this chapter, "planning costs" mean costs:
HB 1007—LS 7547/DI 101 6
1 (1) incurred or to be incurred by an energy utility before the
2 issuance of an order by the commission under this chapter;
3 and
4 (2) related to an acquisition or project.
5 (b) The term includes study, analysis, pre-engineering,
6 engineering, legal, financing, and regulatory costs.
7 Sec. 13. As used in this chapter, "pre-filing meeting" means a
8 meeting to review and discuss a filing or submittal by an energy
9 utility in accordance with:
10 (1) section 18 of this chapter;
11 (2) section 20 of this chapter; or
12 (3) section 22 of this chapter;
13 as applicable.
14 Sec. 14. As used in this chapter, "project" refers to a project
15 relating to energy infrastructure and generation resources that:
16 (1) are required primarily to serve a large load customer of an
17 energy utility; and
18 (2) may be designed to serve more than one (1) large load
19 customer of the energy utility or to meet other customer
20 demand or energy needs.
21 Sec. 15. As used in this chapter, "project costs" means the total
22 costs of a project, including:
23 (1) planning costs; and
24 (2) construction and operating costs;
25 related to the project.
26 Sec. 16. As used in this chapter, "reasonable risk premium"
27 means compensation:
28 (1) negotiated between an energy utility and a large load
29 customer; and
30 (2) paid by the large load customer.
31 Sec. 17. (a) The commission may expedite, in accordance with
32 this chapter, the review of filings and submittals made by an
33 energy utility to meet the energy infrastructure and generation
34 resource needs of customers. An energy utility may request an
35 expedited review by the commission under either or both of the
36 following:
37 (1) Sections 18 through 21 of this chapter (concerning EGR
38 plans).
39 (2) Sections 22 through 24 of this chapter (concerning large
40 load customer projects).
41 (b) This chapter does not preclude an energy utility from
42 petitioning the commission under other applicable statutes for
HB 1007—LS 7547/DI 101 7
1 approval of a generation resource acquisition to meet the needs of
2 its customers.
3 (c) This chapter does not preclude an energy utility from
4 petitioning the commission under, or in conjunction with, other
5 applicable statutes, including:
6 (1) IC 8-1-2-24;
7 (2) IC 8-1-2-42;
8 (3) IC 8-1-2.5;
9 (4) IC 8-1-8.5;
10 (5) IC 8-1-8.8; or
11 (6) IC 8-1-39;
12 for approval of a project to meet the needs of large load customers.
13 Sec. 18. (a) This section applies to an energy utility that petitions
14 the commission for approval of an EGR plan.
15 (b) An energy utility may file a petition with the commission for
16 approval of an EGR plan to acquire generation resources to meet
17 the extraordinary needs for electricity by the energy utility's
18 customers.
19 (c) In petition under this section, an energy utility must do the
20 following:
21 (1) Describe the energy utility's EGR plan for acquiring
22 generation resources to meet the anticipated extraordinary
23 growth in the load of its customers.
24 (2) Demonstrate a need for generation capacity that exceeds
25 the lesser of:
26 (A) five percent (5%) of the energy utility's average peak
27 demand over the most recent three (3) calendar years; or
28 (B) one hundred fifty (150) megawatts.
29 (3) Provide a load growth forecast for a minimum of five (5)
30 years from the date of the petition.
31 (4) Describe the status of customer contracts and
32 commitments that support the load growth forecast described
33 in subdivision (3).
34 (5) Explain how the EGR plan is consistent with or differs
35 from the energy utility's most recent integrated resource plan.
36 (6) Propose the accounting authority needed from the
37 commission to support the EGR plan.
38 (7) Propose the manner in which the capital costs and
39 operating and maintenance expenses related to the EGR plan
40 will be included in the energy utility's revenue requirement.
41 (8) Identify the type and amount of capacity and energy:
42 (A) that is included in the EGR plan;
HB 1007—LS 7547/DI 101 8
1 (B) that does not exceed seventy-five percent (75%) of the
2 energy utility's peak capacity over the forecast period
3 described in subdivision (3); and
4 (C) with respect to which the energy utility may request
5 expedited approval in a subsequent generation resource
6 submittal.
7 (9) Identify the criteria to be included in a generation
8 resource submittal that must be met for the acquisition to be
9 approved by the commission.
10 (10) Certify that at least thirty (30) days before the filing of
11 the petition the energy utility held a pre-filing meeting with
12 the commission and the office of utility consumer counselor to
13 review the EGR plan.
14 (11) Describe how the energy utility considered implementing
15 grid enhancing technologies to defer or minimize the need for
16 additional investment in generation.
17 (12) Describe how the EGR plan will support the provision of
18 electric utility service with the attributes set forth in
19 IC 8-1-2-0.6, including:
20 (A) reliability;
21 (B) affordability;
22 (C) resiliency;
23 (D) stability; and
24 (E) environmental sustainability.
25 (13) Describe how the EGR plan reasonably protects existing
26 and future customers and is consistent with:
27 (A) the provision of safe, reliable, and affordable electric
28 utility service; and
29 (B) economical rates.
30 (14) Include:
31 (A) verified testimony; and
32 (B) exhibits;
33 supporting the petition and constituting the energy utility's
34 case in chief.
35 (15) Include a proposed order for the petition.
36 Sec. 19. (a) This section applies to an energy utility that petitions
37 the commission for approval of an EGR plan.
38 (b) Notwithstanding IC 8-1-8.5 or any other statute, the
39 commission may approve an energy utility's EGR plan to
40 construct, purchase, lease, or otherwise acquire generation
41 resources under this chapter for purposes of meeting the needs of
42 the energy utility's customers. The commission shall make its
HB 1007—LS 7547/DI 101 9
1 decision based on whether the relief requested is just, reasonable,
2 and in the public interest.
3 (c) The commission may:
4 (1) approve the energy utility's petition in its entirety;
5 (2) deny the energy utility's petition in its entirety; or
6 (3) modify the petition, subject to the energy utility's
7 acceptance of the modification.
8 (d) The commission shall issue a final order on the petition not
9 later than ninety (90) days after receiving the energy utility's
10 complete petition. A petition is considered:
11 (1) complete unless the commission provides a notice of
12 deficiency to the energy utility not later than five (5) business
13 days after the filing of the petition; and
14 (2) approved if the commission does not issue a final order on
15 the petition within the ninety (90) day period set forth in this
16 subsection.
17 Sec. 20. (a) This section applies to an energy utility that submits
18 to the commission for approval a generation resource submittal in
19 accordance with an approved EGR plan.
20 (b) An energy utility may submit a generation resource
21 submittal to the commission for approval of an acquisition that the
22 energy utility intends to make in accordance with an approved
23 EGR plan.
24 (c) In a generation resource submittal under this section, an
25 energy utility must do the following:
26 (1) Describe:
27 (A) the type of technology used in the generation resource
28 to be acquired;
29 (B) the amount of capacity and energy to be acquired;
30 (C) key contractual terms for the acquisition; and
31 (D) the estimated acquisition costs.
32 (2) Demonstrate that the acquisition meets the criteria set
33 forth in the energy utility's approved EGR plan.
34 (3) Explain how the acquisition is consistent with or differs
35 from the energy utility's most recent integrated resource plan.
36 (4) Detail the status of customer contracts and commitments
37 that support the acquisition.
38 (5) Certify that at least thirty (30) days before the filing of the
39 generation resource submittal the energy utility held a
40 pre-filing meeting with the commission and the office of utility
41 consumer counselor to review the acquisition.
42 (6) Describe how the energy utility considered implementing
HB 1007—LS 7547/DI 101 10
1 grid enhancing technologies to defer or minimize the need for
2 additional investment in generation.
3 (7) Describe how the acquisition will support the provision of
4 electric utility service with the attributes set forth in
5 IC 8-1-2-0.6, including:
6 (A) reliability;
7 (B) affordability;
8 (C) resiliency;
9 (D) stability; and
10 (E) environmental sustainability.
11 (8) Describe how the acquisition reasonably protects existing
12 and future customers and is consistent with:
13 (A) the provision of safe, reliable, and affordable electric
14 utility service; and
15 (B) economical rates.
16 (9) Include supporting affidavits and exhibits.
17 (10) Include a proposed order for the submittal.
18 Sec. 21. (a) This section applies to an energy utility that submits
19 to the commission for approval a generation resource submittal in
20 accordance with an approved EGR plan.
21 (b) Notwithstanding IC 8-1-8.5 or any other statute, the
22 commission may approve an energy utility's generation resource
23 submittal to construct, purchase, lease, or otherwise acquire
24 generation resources under this chapter for purposes of meeting
25 the needs of the energy utility's customers. The commission shall
26 make its decision based solely on whether the submittal meets the
27 criteria and requirements set forth in the energy utility's approved
28 EGR plan.
29 (c) The commission may:
30 (1) approve the energy utility's generation resource submittal
31 in its entirety;
32 (2) deny the energy utility's generation resource submittal in
33 its entirety; or
34 (3) modify the energy utility's generation resource submittal,
35 subject to the energy utility's acceptance of the modification.
36 (d) The commission shall issue a final order on the energy
37 utility's generation resource submittal not later than:
38 (1) sixty (60) days after receiving the energy utility's complete
39 generation resource submittal, if the acquisition is a clean
40 energy project (as defined in IC 8-1-8.8-2); or
41 (2) one hundred twenty (120) days after receiving the energy
42 utility's complete generation resource submittal, if the
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1 acquisition would otherwise require a certificate under
2 IC 8-1-8.5-2.
3 A generation resource submittal is considered complete unless the
4 commission provides a notice of deficiency to the energy utility not
5 later than five (5) business days after the filing of the generation
6 resource submittal. A generation resource submittal is considered
7 approved if the commission does not issue a final order on the
8 generation resource submittal within the period set forth in
9 subdivision (1) or (2), as applicable.
10 Sec. 22. (a) This section applies to an energy utility that petitions
11 the commission for approval of a project to serve a large load
12 customer.
13 (b) An energy utility may submit to the commission a petition
14 for approval of a project to serve a large load customer only if the
15 following are satisfied:
16 (1) The petition concerns serving the energy needs of a large
17 load customer.
18 (2) The large load customer commits to significant and
19 meaningful financial assurances that must:
20 (A) include reimbursement by the large load customer of
21 at least eighty percent (80%) of the project costs
22 reasonably allocable to the large load customer; and
23 (B) afford protections for the energy utility's existing and
24 future customers from project costs reasonably allocable
25 to the large load customer regardless of whether the large
26 load customer ultimately takes service in the anticipated
27 amount and within the anticipated time frame.
28 (3) At least thirty (30) days before the energy utility's
29 submission of the petition to the commission, the energy
30 utility held at least one (1) pre-filing meeting with:
31 (A) the corporation;
32 (B) the office;
33 (C) the office of utility consumer counselor;
34 (D) the appropriate regional transmission organization;
35 and
36 (E) the large load customer;
37 to review the project.
38 (c) An energy utility may petition the commission for approval
39 of a project to serve:
40 (1) one (1) or more large load customers at one (1) or more
41 locations; or
42 (2) not more than four (4) customers whose aggregate demand
HB 1007—LS 7547/DI 101 12
1 satisfies the amount set forth in section 10(1) of this chapter.
2 In any case in which more than one (1) large load customer is to be
3 served by a project, a reference in this chapter to one (1) large load
4 customer is a reference to all large load customers to be served by
5 the project, in accordance with IC 1-1-4-1(3).
6 (d) In submitting a petition to the commission under this section,
7 an energy utility must demonstrate that the large load customer
8 and the associated projects meet the requirements of this chapter.
9 Sec. 23. (a) This section applies to an energy utility that petitions
10 the commission for approval of a project to serve a large load
11 customer.
12 (b) In a petition under this section, an energy utility must
13 include, at a minimum, the following:
14 (1) The energy utility's complete case in chief, which must
15 include, at a minimum, the following:
16 (A) An agreement from the large load customer that
17 describes the financial assurances:
18 (i) that afford protections for the energy utility's existing
19 and future customers; and
20 (ii) to which the large load customer has committed
21 regardless of whether the large load customer ultimately
22 takes service in the anticipated amount and within the
23 anticipated time frame.
24 (B) A description of:
25 (i) the demand side management and self-generation
26 options reviewed with the large load customer; and
27 (ii) the investments the large load customer will
28 undertake to reasonably minimize the amount of
29 incremental and other costs incurred by the energy
30 utility.
31 (C) A description of how the energy utility considered
32 implementing grid enhancing technologies to defer or
33 minimize the need for additional investment in generation.
34 (D) A description of how the energy utility may provide for
35 the requisite amount of electricity needed by the large load
36 customer, including the estimated project costs.
37 (E) A description of how the expected project solution will
38 support the provision of electric utility service with the
39 attributes set forth in IC 8-1-2-0.6, including:
40 (i) reliability;
41 (ii) affordability;
42 (iii) resiliency;
HB 1007—LS 7547/DI 101 13
1 (iv) stability; and
2 (v) environmental sustainability.
3 (F) A description of how the expected project solution and
4 its implementation, if approved by the commission,
5 reasonably protects existing and future customers and is
6 consistent with:
7 (i) the provision of safe, reliable, and affordable electric
8 utility service; and
9 (ii) economical rates.
10 (G) A description of the changes that the energy utility will
11 make to the energy utility's:
12 (i) submissions under IC 8-1-8.5; or
13 (ii) filings under IC 8-1-39;
14 or both, that are necessary to update the energy utility's
15 plans under those statutes to incorporate the project.
16 (H) Information concerning each:
17 (i) large load customer; and
18 (ii) economic development project;
19 included in the petition.
20 (I) A letter to the energy utility from the corporation
21 supporting the petition's request.
22 (J) A letter to the energy utility from the office certifying
23 that a pre-filing meeting took place and that at the
24 meeting:
25 (i) the large load customer's proposed project; and
26 (ii) the expected project solution proposed by the energy
27 utility;
28 were adequately discussed.
29 (K) A description of the communications and information
30 sharing that:
31 (i) took place with the appropriate regional transmission
32 organization before the pre-filing meeting described in
33 clause (J); and
34 (ii) concerned the capacity and energy needs of each
35 large load customer included in the petition.
36 (L) A proposed order for the petition.
37 (2) A copy of a notice of filing with:
38 (A) the corporation;
39 (B) the office;
40 (C) the office of utility consumer counselor; and
41 (D) the appropriate regional transmission organization.
42 A notice that is delivered electronically to the parties set forth
HB 1007—LS 7547/DI 101 14
1 in this subdivision satisfies the notice requirement under this
2 subdivision.
3 Sec. 24. (a) This section applies to an energy utility that petitions
4 the commission for approval of a project to serve a large load
5 customer.
6 (b) The commission may approve a petition in whole or in part.
7 The commission shall make its decision based on whether the relief
8 requested is just, reasonable, and in the public interest. The
9 commission shall issue its final order on the petition not later than
10 one hundred fifty (150) days after receiving the energy utility's
11 complete petition and case in chief. A petition is considered:
12 (1) complete unless the commission provides a notice of
13 deficiency to the energy utility not later than seven (7)
14 business days after the filing of the petition; and
15 (2) approved if the commission does not issue a final order on
16 the petition within the one hundred fifty (150) day period set
17 forth in this subsection.
18 (c) If an energy utility files a petition that includes one (1) or
19 more large load customers and one (1) or more proposed projects,
20 the commission may:
21 (1) approve the energy utility's petition in its entirety;
22 (2) deny the energy utility's petition in its entirety; or
23 (3) modify the petition, subject to the energy utility's
24 acceptance of the modification.
25 (d) The commission may approve a reasonable risk premium for
26 a project if requested in an energy utility's petition and if the
27 commission finds that the reasonable risk premium is appropriate.
28 If the commission approves a reasonable risk premium:
29 (1) the large load customer is responsible for the amount of
30 the reasonable risk premium; and
31 (2) the reasonable risk premium may not be:
32 (A) included in the energy utility's:
33 (i) revenue requirement;
34 (ii) authorized net operating income; or
35 (iii) calculations under IC 8-1-2-42(d)(3) or
36 IC 8-1-2-42(g)(3)(C); or
37 (B) otherwise considered for purposes of setting the
38 authorized return in any future general rate case or other
39 regulatory proceeding involving the energy utility.
40 (e) The commission may approve an energy utility's request to
41 construct, purchase, lease, or otherwise acquire an energy
42 generation resource under this chapter (notwithstanding and
HB 1007—LS 7547/DI 101 15
1 instead of under IC 8-1-2.5, IC 8-1-8.5, or IC 8-1-8.8) for the
2 purpose of serving one (1) or more large load customers. In
3 approving an energy utility's request under this chapter to acquire
4 an energy generation resource to serve one (1) or more large load
5 customers, the commission must find that:
6 (1) the information provided by the energy utility under
7 section 23 of this chapter is complete;
8 (2) reasonable and demonstrable consideration was given to
9 non-generation alternatives by the parties involved;
10 (3) existing and future customers of the energy utility will be
11 adequately protected if the request is granted; and
12 (4) the energy utility has considered the impact of the request
13 on the energy utility's preferred resource portfolio in the
14 energy utility's most recent integrated resource plan.
15 (f) An energy utility shall promptly notify the commission if,
16 after the commission has approved a petition under subsection (e),
17 one (1) or more of the large load customers with respect to whom
18 the petition was approved:
19 (1) no longer requires service from the energy utility or
20 materially alters or terminates the large load customer's
21 service requirements; and
22 (2) the project is incomplete.
23 (g) The commission may, not later than sixty (60) days after
24 receiving a notice under subsection (f), conduct an investigation
25 under IC 8-1-2-58 through IC 8-1-2-60 to determine whether the
26 public interest would still be served by completion of the project.
27 An investigation under this subsection does not preclude the energy
28 utility from continuing construction of the project to serve the
29 large load customer or from continuing to serve the large load
30 customer. If the commission finds that completion of the project is
31 no longer in the public interest, the commission may modify or
32 revoke the order approving the petition.
33 Sec. 25. (a) The commission shall review an energy utility's:
34 (1) estimated acquisition costs submitted under section
35 20(c)(1)(D) of this chapter; or
36 (2) estimated project costs filed under section 23(b)(1)(D) of
37 this chapter;
38 as applicable.
39 (b) If the commission approves, with or without modification, an
40 energy utility's generation resource submittal or petition for
41 approval of a project, the energy utility may recover:
42 (1) acquisition costs; or
HB 1007—LS 7547/DI 101 16
1 (2) project costs;
2 as applicable, that have been reviewed and found reasonable by the
3 commission, with a return at the energy utility's weighted average
4 cost of capital.
5 (c) If the commission denies an energy utility's generation
6 resource submittal or petition for approval of a project, the energy
7 utility may recover planning costs that have been reviewed and
8 found reasonable by the commission, without a return.
9 (d) Absent fraud, concealment, or gross mismanagement, an
10 energy utility may recover:
11 (1) acquisition costs; or
12 (2) project costs;
13 as applicable, with a return at the energy utility's weighted average
14 cost of capital, that the energy utility has incurred or contractually
15 will incur in reliance on a commission order issued under this
16 chapter.
17 Sec. 26. (a) Upon request by an energy utility, the commission
18 shall determine whether the information and related materials
19 filed or submitted, or to be filed or submitted, by an energy utility
20 under this chapter:
21 (1) are confidential under IC 5-14-3-4 or are trade secrets
22 under IC 24-2-3;
23 (2) are exempt from public access and disclosure by Indiana
24 law; and
25 (3) must be treated as confidential and protected from public
26 access and disclosure by the commission.
27 (b) The parties to a pre-filing meeting under this chapter shall
28 execute a nondisclosure agreement to review or discuss
29 information or materials considered confidential under IC 5-14-3-4
30 or to be trade secrets under IC 24-2-3.
31 (c) If the corporation is in negotiations with an industrial,
32 research, or commercial prospect about a potential economic
33 development project and, based on communications related to
34 those negotiations, determines that the potential economic
35 development project for a new or expanded facility in Indiana may
36 result in the economic development project requiring new or
37 increased energy demand of at least twenty (20) megawatts, the
38 corporation shall notify the affected energy utility not later than
39 fifteen (15) days after making the determination. All
40 communications of the corporation, including notice under this
41 section to an affected energy utility, regarding a potential economic
42 development project are considered confidential and exempt from
HB 1007—LS 7547/DI 101 17
1 disclosure under IC 5-14-3-4(b)(5). Upon the corporation's
2 provision of the notice required by this subsection, any subsequent:
3 (1) meeting;
4 (2) pre-filing meeting;
5 (3) communications; or
6 (4) information sharing;
7 involving the corporation, the affected energy utility, or the
8 industrial, research, or commercial prospect about a potential
9 economic development project may be subject to a nondisclosure
10 agreement with respect to information or materials considered
11 confidential under IC 5-14-3-4 or to be trade secrets under
12 IC 24-2-3.
13 (d) An energy utility may request, and the commission may
14 approve, financial incentives under IC 8-1-8.8-11(a) for:
15 (1) an acquisition; or
16 (2) a project;
17 that qualifies as a clean energy project (as defined in IC 8-1-8.8-2).
18 (e) An energy utility may request that review of an arrangement
19 under IC 8-1-2-42 and any related rates and charges under
20 IC 8-1-2-43 that are:
21 (1) submitted with a generation resource submittal; or
22 (2) filed with a petition for a project;
23 under this chapter be reviewed and approved or denied by the
24 commission not later than ninety (90) dates after the date of
25 submittal or filing, as applicable.
26 (f) Notwithstanding IC 8-1-8.5 or any other applicable statute,
27 an energy utility may begin construction of an acquisition or a
28 project before filing a petition or submittal under this chapter.
29 (g) The commission may require an energy utility to file with the
30 commission progress reports and updates with respect to an
31 acquisition or project under this chapter. Any required progress
32 reports or updates under this subsection shall be made in a form
33 and at a frequency that the commission determines to be
34 reasonable.
35 SECTION 4. IC 8-1-8.5-2.1, AS AMENDED BY THE
36 TECHNICAL CORRECTIONS BILL OF THE 2025 GENERAL
37 ASSEMBLY, IS AMENDED TO READ AS FOLLOWS [EFFECTIVE
38 JULY 1, 2025]: Sec. 2.1. (a) This section does not apply to the
39 retirement, sale, or transfer of:
40 (1) a public utility's electric generation facility if the retirement,
41 sale, or transfer is necessary in order for the public utility to
42 comply with a federal consent decree; or
HB 1007—LS 7547/DI 101 18
1 (2) an electric generation facility that generates electricity for sale
2 exclusively to the wholesale market.
3 (b) A public utility shall notify the commission if:
4 (1) the public utility intends or decides to retire, sell, or transfer
5 an electric generation facility with a capacity of at least eighty
6 (80) megawatts; and
7 (2) the retirement, sale, or transfer:
8 (A) was not set forth in; or
9 (B) is to take place on a date earlier than the date specified in;
10 the public utility's short term action plan in the public utility's
11 most recently filed integrated resource plan.
12 (c) Upon receiving notice from a public utility under subsection (b),
13 the commission shall consider and may investigate, under IC 8-1-2-58
14 through IC 8-1-2-60, the public utility's intention or decision to retire,
15 sell, or transfer the electric generation facility. In considering the public
16 utility's intention or decision under this subsection, the commission
17 shall examine the impact the retirement, sale, or transfer would have on
18 the public utility's ability to meet:
19 (1) the public utility's planning reserve margin requirements or
20 other federal reliability requirements that the public utility is
21 obligated to meet, as described in section 13(i)(4) 13(n)(6) of this
22 chapter; and
23 (2) the reliability adequacy metrics set forth in section 13(e) 13(h)
24 of this chapter.
25 (d) Before July 1, 2026, if:
26 (1) a public utility intends or decides to retire, sell, or transfer an
27 electric generation facility with a capacity of at least eighty (80)
28 megawatts; and
29 (2) the retirement, sale, or transfer:
30 (A) was not set forth in; or
31 (B) is to take place on a date earlier than the date specified in;
32 the public utility's short term action plan in the public utility's
33 most recently filed integrated resource plan;
34 the commission shall not permit the public utility's depreciation rates,
35 as established under IC 8-1-2-19, to be amended to reflect the
36 accelerated date for the retirement, sale, or transfer of the electric
37 generation asset unless the commission finds that such an adjustment
38 is necessary to ensure the ability of the public utility to provide reliable
39 service to its customers, and that the unamended depreciation rates
40 would cause an unjust and unreasonable impact on the public utility
41 and its ratepayers.
42 (e) The commission may issue a general administrative order to
HB 1007—LS 7547/DI 101 19
1 implement this section.
2 (f) This section expires July 1, 2026.
3 SECTION 5. IC 8-1-8.5-12.1, AS AMENDED BY P.L.93-2024,
4 SECTION 67, IS AMENDED TO READ AS FOLLOWS [EFFECTIVE
5 JULY 1, 2025]: Sec. 12.1. (a) As used in this section, "project
6 development costs" means costs that have been incurred, or are
7 reasonably estimated to be incurred, in the development of one (1)
8 or more small modular nuclear reactors, including:
9 (1) evaluation, design, and engineering costs;
10 (2) costs for federal approvals and licensing;
11 (3) costs for environmental analyses and permitting;
12 (4) early site permit (as defined in 10 CFR 52.1) costs;
13 (5) equipment procurement costs; and
14 (6) authorized carrying costs.
15 (a) (b) As used in this section, "small modular nuclear reactor"
16 means a nuclear reactor that:
17 (1) has a rated electric generating capacity of not more than four
18 hundred seventy (470) megawatts;
19 (2) is capable of being constructed and operated, either:
20 (A) alone; or
21 (B) in combination with one (1) or more similar reactors if
22 additional reactors are, or become, necessary;
23 at a single site; and
24 (3) is required to be licensed by the United States Nuclear
25 Regulatory Commission.
26 The term includes a nuclear reactor that is described in this subsection
27 and that uses a process to produce hydrogen that can be used for energy
28 storage, as a fuel, or for other uses.
29 (b) (c) Not later than July 1, 2023, the commission, in consultation
30 with the department of environmental management, shall adopt rules
31 under IC 4-22-2 concerning the granting of certificates under this
32 chapter for the construction, purchase, or lease of small modular
33 nuclear reactors:
34 (1) in Indiana for the generation of electricity to be directly or
35 indirectly used to furnish public utility service to Indiana
36 customers; or
37 (2) at the site of a nuclear energy production or generating facility
38 that supplies electricity to Indiana retail customers on July 1,
39 2011.
40 (c) (d) Rules adopted by the commission under this section must
41 provide for the following:
42 (1) That in acting on a public utility's petition for the construction,
HB 1007—LS 7547/DI 101 20
1 purchase, or lease of one (1) or more small modular nuclear
2 reactors, as described in subsection (b), (c), the commission shall
3 consider the following:
4 (A) Whether, and to what extent, the one (1) or more small
5 modular nuclear reactors proposed by the public utility will
6 replace a loss of generating capacity in the public utility's
7 portfolio resulting from the retirement or planned retirement
8 of one (1) or more of the public utility's existing electric
9 generating facilities that:
10 (i) are located in Indiana; and
11 (ii) use coal or natural gas as a fuel source.
12 (B) Whether one (1) or more of the small modular nuclear
13 reactors that will replace an existing facility will be located on
14 the same site as or near the existing facility and, if so, potential
15 opportunities for the public utility to:
16 (i) make use of any land and existing infrastructure or
17 facilities already owned or under the control of the public
18 utility; or
19 (ii) create new employment opportunities for workers who
20 have been, or would be, displaced as a result of the
21 retirement of the existing facility.
22 (2) That the commission may grant a certificate under this chapter
23 under circumstances and for locations other than those described
24 in subdivision (1).
25 (3) That the commission may not grant a certificate under this
26 chapter unless the owner or operator of a proposed small modular
27 nuclear reactor provides evidence of a plan to apply for all
28 licenses or permits to construct or operate the proposed small
29 modular nuclear reactor as may be required by:
30 (A) the United States Nuclear Regulatory Commission;
31 (B) the department of environmental management; or
32 (C) any other relevant state or federal regulatory agency with
33 jurisdiction over the construction or operation of nuclear
34 generating facilities.
35 (4) That any:
36 (A) reports;
37 (B) notices of violations; or
38 (C) other notifications;
39 sent to or from the United States Nuclear Regulatory Commission
40 by or to the owner or operator of a proposed small nuclear reactor
41 must be submitted by the owner or operator to the commission
42 within such times as prescribed by the commission, subject to the
HB 1007—LS 7547/DI 101 21
1 commission's duty to treat as confidential and protect from public
2 access and disclosure any information that is contained in a report
3 or notice and that is considered confidential or exempt from
4 public access and disclosure under state or federal law.
5 (5) That any person that owns or operates a small modular nuclear
6 reactor in Indiana may not store:
7 (A) spent nuclear fuel (as defined in IC 13-11-2-216); or
8 (B) high level radioactive waste (as defined in
9 IC 13-11-2-102);
10 from the small modular nuclear reactor on the site of the small
11 modular nuclear reactor without first meeting all applicable
12 requirements of the United States Nuclear Regulatory
13 Commission.
14 (d) In adopting the rules required by this section, the commission
15 may adopt rules under IC 4-22-2.
16 (e) A public utility may petition the commission for approval to
17 incur, before obtaining a certificate under this chapter, project
18 development costs for the development of one (1) or more small
19 modular nuclear reactors. The public utility must file with the
20 petition the public utility's case in chief, which must contain the
21 information and supporting documentation regarding the factors
22 the commission must consider under this subsection. In reviewing
23 a petition and the supporting case in chief under this subsection,
24 the commission shall consider the following:
25 (1) Whether a project by the utility to construct, purchase, or
26 lease a small modular nuclear reactor is reasonably consistent
27 with:
28 (A) this section and rules adopted by the commission under
29 this section; and
30 (B) the purposes set forth in IC 8-1-8.8-1(b), as applicable.
31 (2) The following factors with respect to the project
32 development costs and the project for which they are to be
33 incurred:
34 (A) The amount of project development costs the public
35 utility anticipates incurring.
36 (B) The anticipated timeline for incurring the project
37 development costs.
38 (C) The anticipated date by which the public utility will
39 make a decision as to whether to seek a certificate under
40 this chapter.
41 The commission shall review a petition submitted under this
42 subsection and issue a final order approving or denying the petition
HB 1007—LS 7547/DI 101 22
1 not later than one hundred eighty (180) days after receiving the
2 petition and complete case in chief. However, if the commission
3 makes a docket entry extending the procedural schedule and the
4 public utility does not object to the entered extension, the
5 commission may extend the one hundred eighty (180) day time
6 frame for issuing a final order under this subsection for the
7 amount of time set forth in the docket entry. In an order approving
8 a petition, the commission must make a finding as to the best
9 estimate and reasonableness of project development costs based on
10 the evidence of record.
11 (f) If a public utility has received approval from the commission
12 under subsection (e) to incur project development costs, the public
13 utility may petition the commission at any time before or during
14 the development and execution of a small modular nuclear reactor
15 project for the approval of a rate schedule that periodically adjusts
16 the public utility's rates and charges to provide for the timely
17 recovery of project development costs. A petition under this
18 subsection must describe any efforts by the public utility to pursue
19 funding opportunities from the United States Department of
20 Energy to offset the project development costs that the public
21 utility seeks to recover under the proposed rate schedule.
22 (g) If, after reviewing a public utility's proposed rate schedule
23 in a petition submitted under subsection (f), the commission
24 determines that the public utility has incurred or will incur project
25 development costs that are:
26 (1) reasonable in amount;
27 (2) necessary to support the construction, purchase, or lease
28 of a small modular nuclear reactor; and
29 (3) consistent with the commission's finding as to the best
30 estimate of project development costs in the commission's
31 order of approval under subsection (e);
32 the commission shall approve the recovery of the project
33 development costs, subject to subsections (h) and (i). However, a
34 public utility may not file adjustments to a rate schedule to adjust
35 for cost recovery approved under this subsection more than one (1)
36 time every twelve (12) months.
37 (h) A public utility that recovers project development costs
38 under subsection (g) shall recover eighty percent (80%) of the
39 approved project development costs under the rate schedule
40 approved under subsection (g) and shall defer the remaining
41 twenty percent (20%) of approved project development costs,
42 including, to the extent applicable, depreciation, allowance for
HB 1007—LS 7547/DI 101 23
1 funds used during construction, and post in service carrying costs,
2 based on the overall cost of capital most recently approved by the
3 commission, and shall recover those project development costs as
4 part of the next general rate case that the public utility files with
5 the commission.
6 (i) The recovery of a public utility's project development costs
7 through a periodic rate adjustment mechanism approved by the
8 commission under subsection (g) must occur over a period that is
9 equal to:
10 (1) the period over which the approved project development
11 costs are incurred; or
12 (2) three (3) years;
13 whichever is less.
14 (j) Project development costs that are found by the commission
15 to be reasonable, necessary, and consistent with the best estimate
16 of project development costs in the commission's order of approval
17 under subsection (e) shall be recovered by a public utility by
18 inclusion in the public utility's rates and charges. Project
19 development costs that are incurred by a public utility and that
20 exceed the best estimate of project development costs under
21 subsection (e) may not be included in the public utility's rates and
22 charges unless found by the commission to be reasonable,
23 necessary, and prudent in supporting the construction, purchase,
24 or lease of the small modular nuclear reactor for which they were
25 incurred. Project development costs that are incurred by a public
26 utility for a project that is canceled or not completed may be
27 recovered by the public utility if found by the commission to be
28 reasonable, necessary, and prudently incurred, but such costs shall
29 be recovered without a return unless the commission also finds
30 that:
31 (1) the decision to cancel or not complete the project was
32 prudently made for good cause;
33 (2) the project development costs incurred will be offset, as
34 applicable, by:
35 (A) funding opportunities from the United States
36 Department of Energy that are pursued in good faith by
37 the public utility;
38 (B) a recoupment of revenues received by the public utility
39 from one (1) or more third parties for the transfer of assets
40 created through the costs incurred; or
41 (C) a reimbursement of costs by a single customer or
42 prospective customer at whose request the project was
HB 1007—LS 7547/DI 101 24
1 pursued; and
2 (3) a return on the project development costs incurred is
3 appropriate under the circumstances to avoid harm to the
4 public utility and its customers.
5 (k) A public utility may elect not to seek approval of, or cost
6 recovery for, project development costs under subsections (e)
7 through (i) and instead seek approval from the commission to defer
8 and amortize project development costs in accordance with the
9 procedures set forth in section 6.5 of this chapter with respect to
10 construction costs.
11 (l) The commission may adopt rules under IC 4-22-2 to
12 implement subsections (e) through (k).
13 (e) (m) This section shall not be construed to affect the authority of
14 the United States Nuclear Regulatory Commission.
15 SECTION 6. IC 8-1-8.5-13, AS AMENDED BY P.L.93-2024,
16 SECTION 68, IS AMENDED TO READ AS FOLLOWS [EFFECTIVE
17 JULY 1, 2025]: Sec. 13. (a) The general assembly finds that it is in the
18 public interest to support the reliability, availability, and diversity of
19 electric generating capacity in Indiana for the purpose of providing
20 reliable and stable electric service to customers of public utilities.
21 (b) As used in this section, "appropriate regional transmission
22 organization", with respect to a public utility, refers to the regional
23 transmission organization approved by the Federal Energy Regulatory
24 Commission for the control area that includes the public utility's
25 assigned service area (as defined in IC 8-1-2.3-2).
26 (c) As used in this section, "capacity market" means an auction
27 conducted by an appropriate regional transmission organization to
28 determine a market clearing price for capacity based on the planning
29 reserve margin requirements established by the appropriate regional
30 transmission organization for a planning year with respect to which an
31 auction has not yet been conducted.
32 (d) As used in this section, "fall unforced capacity", or "fall UCAP",
33 with respect to an electric generating facility, means:
34 (1) the capacity value of the electric generating facility's installed
35 capacity rate adjusted for the electric generating facility's average
36 forced outage rate for the fall period, calculated as required by the
37 appropriate regional transmission organization or by the Federal
38 Energy Regulatory Commission;
39 (2) a metric that is similar to the metric described in subdivision
40 (1) and that is required by the appropriate regional transmission
41 organization; or
42 (3) if the appropriate regional transmission organization does not
HB 1007—LS 7547/DI 101 25
1 require a metric described in subdivision (1) or (2), a metric that:
2 (A) can be used to demonstrate that a public utility has
3 sufficient capacity to:
4 (i) provide reliable electric service to Indiana customers for
5 the fall period; and
6 (ii) meet its planning reserve margin requirement and other
7 federal reliability requirements described in subsection
8 (l)(4); (n)(6); and
9 (B) is acceptable to the commission.
10 (e) As used in this section, "MISO" refers to the regional
11 transmission organization known as the Midcontinent Independent
12 System Operator that operates the bulk power transmission system
13 serving most of the geographic territory in Indiana.
14 (f) As used in this section, "planning reserve margin requirement",
15 with respect to a public utility for a particular resource planning year,
16 means the planning reserve margin requirement for that planning year
17 that the public utility is obligated to meet in accordance with the public
18 utility's membership in the appropriate regional transmission
19 organization.
20 (g) As used in this section, "refuel" or "refueling" means a
21 planned fuel conversion from one fuel source to another fuel source
22 with respect to an electric generation resource with a nameplate
23 capacity of at least one hundred twenty-five (125) megawatts by a
24 public utility.
25 (g) (h) As used in this section, "reliability adequacy metrics", with
26 respect to a public utility, means calculations used to demonstrate all
27 of the following:
28 (1) Subject to subsection (q)(2)(B), (u)(2), that the public utility:
29 (A) has in place sufficient summer UCAP; or
30 (B) can reasonably acquire not more than:
31 (i) thirty percent (30%) of its total summer UCAP from
32 capacity markets, with respect to a report filed with the
33 commission under subsection (l) (n) before July 1, 2023; or
34 (ii) fifteen percent (15%) of its total summer UCAP from
35 capacity markets, with respect to a report filed with the
36 commission under subsection (l) (n) after June 30, 2023;
37 such that it will have sufficient summer UCAP;
38 to provide reliable electric service to Indiana customers, and to
39 meet its planning reserve margin requirement and other federal
40 reliability requirements described in subsection (l)(4). (n)(6).
41 (2) Subject to subsection (q)(2)(B), (u)(2), that the public utility:
42 (A) has in place sufficient winter UCAP; or
HB 1007—LS 7547/DI 101 26
1 (B) can reasonably acquire not more than:
2 (i) thirty percent (30%) of its total winter UCAP from
3 capacity markets, with respect to a report filed with the
4 commission under subsection (l) (n) before July 1, 2023; or
5 (ii) fifteen percent (15%) of its total winter UCAP from
6 capacity markets, with respect to a report filed with the
7 commission under subsection (l) (n) after June 30, 2023;
8 such that it will have sufficient winter UCAP;
9 to provide reliable electric service to Indiana customers, and to
10 meet its planning reserve margin requirement and other federal
11 reliability requirements described in subsection (l)(4). (n)(6).
12 (3) Subject to subsection (q)(2)(B), (u)(2), with respect to a report
13 filed with the commission under subsection (l) (n) after June 30,
14 2026, that the public utility:
15 (A) has in place sufficient spring UCAP; or
16 (B) can reasonably acquire not more than fifteen percent
17 (15%) of its total spring UCAP from capacity markets, such
18 that it will have sufficient spring UCAP;
19 to provide reliable electric service to Indiana customers, and to
20 meet its planning reserve margin requirement and other federal
21 reliability requirements described in subsection (l)(4). (n)(6).
22 (4) Subject to subsection (q)(2)(B), (u)(2), with respect to a report
23 filed with the commission under subsection (l) (n) after June 30,
24 2026, that the public utility:
25 (A) has in place sufficient fall UCAP; or
26 (B) can reasonably acquire not more than fifteen percent
27 (15%) of its total fall UCAP from capacity markets, such that
28 it will have sufficient fall UCAP;
29 to provide reliable electric service to Indiana customers, and to
30 meet its planning reserve margin requirement and other federal
31 reliability requirements described in subsection (l)(4). (n)(6).
32 (i) As used in this section, "retire" or retirement" means a
33 planned permanent ceasing of electric generation operations with
34 respect to an electric generation resource with a nameplate
35 capacity of at least one hundred twenty-five (125) megawatts by a
36 public utility.
37 (h) (j) As used in this section, "spring unforced capacity", or "spring
38 UCAP", with respect to an electric generating facility, means:
39 (1) the capacity value of the electric generating facility's installed
40 capacity rate adjusted for the electric generating facility's average
41 forced outage rate for the spring period, calculated as required by
42 the appropriate regional transmission organization or by the
HB 1007—LS 7547/DI 101 27
1 Federal Energy Regulatory Commission;
2 (2) a metric that is similar to the metric described in subdivision
3 (1) and that is required by the appropriate regional transmission
4 organization; or
5 (3) if the appropriate regional transmission organization does not
6 require a metric described in subdivision (1) or (2), a metric that:
7 (A) can be used to demonstrate that a public utility has
8 sufficient capacity to:
9 (i) provide reliable electric service to Indiana customers for
10 the spring period; and
11 (ii) meet its planning reserve margin requirement and other
12 federal reliability requirements described in subsection
13 (l)(4); (n)(6); and
14 (B) is acceptable to the commission.
15 (i) (k) As used in this section, "summer unforced capacity", or
16 "summer UCAP", with respect to an electric generating facility, means:
17 (1) the capacity value of the electric generating facility's installed
18 capacity rate adjusted for the electric generating facility's average
19 forced outage rate for the summer period, calculated as required
20 by the appropriate regional transmission organization or by the
21 Federal Energy Regulatory Commission; or
22 (2) a metric that is similar to the metric described in subdivision
23 (1) and that is required by the appropriate regional transmission
24 organization.
25 (j) (l) As used in this section, "winter unforced capacity", or "winter
26 UCAP", with respect to an electric generating facility, means:
27 (1) the capacity value of the electric generating facility's installed
28 capacity rate adjusted for the electric generating facility's average
29 forced outage rate for the winter period, calculated as required by
30 the appropriate regional transmission organization or by the
31 Federal Energy Regulatory Commission;
32 (2) a metric that is similar to the metric described in subdivision
33 (1) and that is required by the appropriate regional transmission
34 organization; or
35 (3) if the appropriate regional transmission organization does not
36 require a metric described in subdivision (1) or (2), a metric that:
37 (A) can be used to demonstrate that a public utility has
38 sufficient capacity to:
39 (i) provide reliable electric service to Indiana customers for
40 the winter period; and
41 (ii) meet its planning reserve margin requirement and other
42 federal reliability requirements described in subsection
HB 1007—LS 7547/DI 101 28
1 (l)(4); (n)(6); and
2 (B) is acceptable to the commission.
3 (k) (m) A public utility that owns and operates an electric
4 generating facility serving customers in Indiana shall operate and
5 maintain the facility using good utility practices and in a manner:
6 (1) reasonably intended to support the provision of reliable and
7 economic electric service to customers of the public utility; and
8 (2) reasonably consistent with the resource reliability
9 requirements of MISO or any other appropriate regional
10 transmission organization; and
11 (3) reasonably maximizes the economic value of the electric
12 generating facility.
13 (l) (n) Not later than thirty (30) days after the deadline for
14 submitting an annual planning reserve margin report to MISO, each
15 public utility providing electric service to Indiana customers shall,
16 regardless of whether the public utility is required to submit an annual
17 planning reserve margin report to MISO, file with the commission a
18 report, in a form specified by the commission, that provides the
19 following information for each of the next three (3) resource planning
20 years, beginning with the planning year covered by the planning
21 reserve margin report to MISO described in this subsection:
22 (1) The:
23 (A) capacity;
24 (B) location; and
25 (C) fuel source;
26 for each electric generating facility that is owned and operated by
27 the electric utility and that will be used to provide electric service
28 to Indiana customers.
29 (2) With respect to a report submitted to the commission after
30 December 31, 2025, the amount of generating resource
31 capacity or energy, or both, that the public utility plans to
32 retire and that is owned and operated by the public utility and
33 used to provide retail electric service in Indiana, including
34 the:
35 (A) capacity;
36 (B) location;
37 (C) fuel source; and
38 (D) planned retirement date;
39 for each electric generating facility. The public utility must
40 include information as to whether the planned retirement is
41 required in order to comply with environmental laws,
42 regulations, or court orders, including consent decrees, that
HB 1007—LS 7547/DI 101 29
1 are or will be in effect at the time of the planned retirement.
2 In addition, the public utility must provide its economic
3 rationale for the planned retirement, including anticipated
4 ratepayer impacts, and information concerning the public
5 utility's plan or plans with respect to the amount of
6 replacement capacity identified to provide approximately the
7 same accredited capacity within the appropriate regional
8 transmission organization as the amount of capacity of the
9 facility to be retired.
10 (3) With respect to a report submitted to the commission after
11 December 31, 2025, the amount of generating resource
12 capacity or energy, or both, that the public utility plans to
13 refuel, including the:
14 (A) capacity;
15 (B) location;
16 (C) existing fuel source;
17 (D) proposed fuel source; and
18 (E) planned completion date of the refueling;
19 with respect to each electric generating facility that the public
20 utility plans to refuel. The public utility must provide its
21 economic rationale for the planned refueling, including
22 anticipated ratepayer impacts, and information concerning
23 the public utility's plan or plans with respect to the extent to
24 which the refueling will maintain or increase the current
25 generating resource accredited capacity or energy, or both,
26 that the electric generating facility provides, so as to provide
27 approximately the same accredited capacity within the
28 appropriate regional transmission organization.
29 (2) (4) The amount of generating resource capacity or energy, or
30 both, that the public utility has procured under contract and that
31 will be used to provide electric service to Indiana customers,
32 including the:
33 (A) capacity;
34 (B) location; and
35 (C) fuel source;
36 for each electric generating facility that will supply capacity or
37 energy under the contract, to the extent known by the public
38 utility.
39 (3) (5) The amount of demand response resources available to the
40 public utility under contracts and tariffs.
41 (4) (6) The following:
42 (A) The planning reserve margin requirements established by
HB 1007—LS 7547/DI 101 30
1 MISO for the planning years covered by the report, to the
2 extent known by the public utility with respect to any
3 particular planning year covered by the report.
4 (B) If applicable, any other planning reserve margin
5 requirement that:
6 (i) applies to the planning years covered by the report; and
7 (ii) the public utility is obligated to meet in accordance with
8 the public utility's membership in an appropriate regional
9 transmission organization;
10 to the extent known by the public utility with respect to any
11 particular planning year covered by the report.
12 (C) Other federal reliability requirements that the public utility
13 is obligated to meet in accordance with its membership in an
14 appropriate regional transmission organization with respect to
15 the planning years covered by the report, to the extent known
16 by the public utility with respect to any particular planning
17 year covered by the report.
18 For each planning reserve margin requirement reported under
19 clause (A) or (B), the public utility shall include a comparison of
20 that planning reserve margin requirement to the planning reserve
21 margin requirement established by the same regional transmission
22 organization for the 2021-2022 planning year.
23 (5) (7) The reliability adequacy metrics of the public utility, as
24 forecasted for the three (3) planning years covered by the report.
25 (m) (o) Upon request by a public utility, the commission shall
26 determine whether information provided in a report filed by the public
27 utility under subsection (l): (n):
28 (1) is confidential under IC 5-14-3-4 or is a trade secret under
29 IC 24-2-3;
30 (2) is exempt from public access and disclosure by Indiana law;
31 and
32 (3) shall be treated as confidential and protected from public
33 access and disclosure by the commission.
34 (n) (p) A joint agency created under IC 8-1-2.2 may file the report
35 required under subsection (l) (n) as a consolidated report on behalf of
36 any or all of the municipally owned utilities that make up its
37 membership.
38 (o) (q) A:
39 (1) corporation organized under IC 23-17 that is an electric
40 cooperative and that has at least one (1) member that is a
41 corporation organized under IC 8-1-13; or
42 (2) general district corporation within the meaning of
HB 1007—LS 7547/DI 101 31
1 IC 8-1-13-23;
2 may file the report required under subsection (l) (n) as a consolidated
3 report on behalf of any or all of the cooperatively owned electric
4 utilities that it serves.
5 (p) (r) In reviewing a report filed by a public utility under
6 subsection (l), (n), the commission may request technical assistance
7 from MISO or any other appropriate regional transmission organization
8 in determining:
9 (1) the planning reserve margin requirements or other federal
10 reliability requirements that the public utility is obligated to meet,
11 as described in subsection (l)(4); (n)(6); and
12 (2) whether the resources available to the public utility under
13 subsections (l)(1) (n)(1) through (l)(3) (n)(5) will be adequate to
14 support the provision of reliable electric service to the public
15 utility's Indiana customers.
16 (s) With respect to a report submitted under subsection (n) after
17 December 31, 2025, commission staff shall review the reports
18 submitted by public utilities and shall, not later than ninety (90)
19 days after the date of submission of the reports, submit to the
20 commission a staff report concerning any planned retirements
21 included in the reports under subsection (n)(2). The report must
22 make recommendations to the commission based on whether each
23 planned retirement:
24 (1) is consistent with the standards set forth in subsection (m);
25 (2) will be replaced with an amount of replacement capacity
26 that will provide approximately the same accredited capacity
27 within the appropriate regional transmission organization as
28 the amount of capacity of the facility to be retired;
29 (3) will not adversely and unreasonably impact a public
30 utility's ability to provide safe, reliable, and economical
31 electric utility service to the public utility's customers;
32 (4) will result in the provision to Indiana customers of electric
33 utility service with the attributes of:
34 (A) reliability;
35 (B) affordability;
36 (C) resiliency;
37 (D) stability; and
38 (E) environmental sustainability;
39 as set forth in IC 8-1-2-0.6; and
40 (5) is required in order to comply with environmental laws,
41 regulations, or court orders, including consent decrees, that
42 are or will be in effect at the time of the planned retirement.
HB 1007—LS 7547/DI 101 32
1 (t) The commission shall make the staff reports prepared under
2 subsection (s) publicly available by posting the staff reports on the
3 commission's website. Upon the posting of a staff report on the
4 commission's website, the commission shall accept public
5 comments on the report for a period not to exceed thirty (30) days
6 after the date of posting.
7 (q) (u) If, after reviewing a report filed by a public utility under
8 subsection (l), (n) and any staff report prepared with respect to the
9 public utility under subsection (s), the commission is not satisfied
10 that the public utility can either:
11 (1) provide reliable electric service to the public utility's Indiana
12 customers; or
13 (2) either:
14 (A) (1) satisfy both:
15 (i) (A) its planning reserve margin requirement or other
16 federal reliability requirements that the public utility is
17 obligated to meet, as described in subsection (l)(4); (n)(6); and
18 (ii) (B) the reliability adequacy metrics set forth in subsection
19 (g); (h); or
20 (B) (2) provide sufficient reason as to why the public utility is
21 unable to satisfy both:
22 (i) (A) its planning reserve margin requirement or other
23 federal reliability requirements that the public utility is
24 obligated to meet, as described in subsection (l)(4); (n)(6); and
25 (ii) (B) the reliability adequacy metrics set forth in subsection
26 (g); (h);
27 during one (1) more of the planning years covered by the report, the
28 commission may shall conduct an investigation under IC 8-1-2-58
29 through IC 8-1-2-60 as to the reasons for the public utility's potential
30 inability to meet the requirements described in subdivision (1) or (2),
31 or both. provide sufficient reason as to that inability, as described
32 in subdivision (2). In addition, if the public utility has indicated in
33 its report under subsection (n)(2) that it plans to retire an electric
34 generating facility within one (1) year of the date of the report, the
35 commission must conduct an investigation under IC 8-1-2-58
36 through IC 8-1-2-60 as to the reasons for the public utility's
37 potential inability to meet the requirements described in
38 subdivision (1) or provide sufficient reason as to that inability, as
39 described in subdivision (2). However, a public utility may request,
40 not earlier than three (3) years before the planned retirement date
41 of an electric generation facility, that the commission conduct an
42 investigation under IC 8-1-2-58 through IC 8-1-2-60, for the
HB 1007—LS 7547/DI 101 33
1 purposes described in this subsection, with respect to the planned
2 retirement. If the commission conducts an investigation at the
3 request of a public utility within the three (3) year period before
4 the planned retirement date of an electric generation facility, the
5 commission may not conduct a subsequent investigation that would
6 otherwise be required under this subsection with respect to the
7 retirement of that same electric generation facility unless the
8 commission is not satisfied, as of the time that an investigation
9 would otherwise be required under this subsection, that the public
10 utility can meet the requirements described in subdivision (1) or
11 provide sufficient reason as to that inability, as described in
12 subdivision (2). If a certificate is granted by the commission under
13 this chapter for a facility intended to repower or replace a
14 generation unit that is planned for retirement, and the certificate
15 includes findings that the project will result in at least equivalent
16 accredited capacity and will provide economic benefit to
17 ratepayers as compared to the continued operation of the
18 generating unit to be retired, the certificate under this chapter
19 constitutes approval by the commission for purposes of an
20 investigation required by this subsection. However, if the
21 commission finds that facts and circumstances regarding the
22 planned retirement have changed significantly since the certificate
23 was granted and that those changes concern the public utility's
24 ability to meet the requirements described in subdivision (1), the
25 commission may conduct an investigation into the planned
26 retirement of the unit.
27 (r) (v) If, upon investigation under IC 8-1-2-58 through IC 8-1-2-60,
28 and after notice and hearing, as required by IC 8-1-2-59, the
29 commission determines that the capacity resources available to the
30 public utility under subsections (l)(1) (n)(1) through (l)(3) (n)(5) will
31 not be adequate to support the provision of reliable electric service to
32 the public utility's Indiana customers, or to allow the public utility to
33 satisfy both its planning reserve margin requirements or other federal
34 reliability requirements that the public utility is obligated to meet (as
35 described in subsection (l)(4)) (n)(6)) and the reliability adequacy
36 metrics set forth in subsection (g), (h), the commission shall issue an
37 order:
38 (1) directing the public utility to acquire or construct; or
39 (2) prohibiting the retirement or refueling of;
40 such capacity resources that are reasonable and necessary to enable the
41 public utility to provide reliable electric service to its Indiana
42 customers, and to satisfy both its planning reserve margin requirements
HB 1007—LS 7547/DI 101 34
1 or other federal reliability requirements described in subsection (l)(4)
2 (n)(6) and the reliability adequacy metrics set forth in subsection (g).
3 (h). The commission shall issue an order under this subsection not
4 later than one hundred twenty (120) days after the initiation of the
5 investigation under subsection (u). If the commission does not issue
6 an order within the one hundred twenty (120) day period
7 prescribed by this subsection, the public utility is considered to be
8 able to meet the requirements described in subsection (u)(1) with
9 respect to the retirement of the electric generation facility under
10 investigation. Not later than ninety (90) days after the date of the
11 commission's an order by the commission under this subsection, the
12 public utility shall file for approval with the commission a plan to
13 comply with the commission's order. Notwithstanding IC 8-1-3 or
14 any other law, any appeal of an order by the commission under this
15 subsection is entitled to priority review and shall be given
16 expedited consideration in accordance with Rule 21 of the Indiana
17 Rules of Appellate Procedure.
18 (w) With respect to a report submitted under subsection (n)
19 after December 31, 2025, if the commission issues an order under
20 subsection (v) to prohibit the retirement or refueling of an electric
21 generation resource, the commission shall create a sub-docket to
22 authorize the public utility to recover in rates the costs of the
23 continued operation of the electric generation resource that was
24 proposed to be retired or refueled. The commission must find that
25 the continued costs of operation are just and reasonable before
26 authorizing their recovery in the public utility's rates. The creation
27 of a sub-docket under this subsection is not subject to the one
28 hundred twenty (120) day time frame for the commission to issue
29 an order under subsection (v).
30 The (x) A public utility's plan under subsection (v) may include:
31 (1) a request for a certificate of public convenience and necessity
32 under this chapter; or
33 (2) an application under IC 8-1-8.8;
34 or both.
35 (s) (y) Beginning in 2022, the commission shall include in its annual
36 report under IC 8-1-1-14 the following information:
37 (1) The commission's analysis regarding the ability of public
38 utilities to:
39 (A) provide reliable electric service to Indiana customers; and
40 (B) satisfy both:
41 (i) their planning reserve margin requirements or other
42 federal reliability requirements; and
HB 1007—LS 7547/DI 101 35
1 (ii) the reliability adequacy metrics set forth in subsection
2 (g); (h);
3 for the next three (3) utility resource planning years, based on the
4 most recent reports filed by public utilities under subsection (l).
5 (n).
6 (2) A summary of:
7 (A) the projected demand for retail electricity in Indiana over
8 the next calendar year; and
9 (B) the amount and type of capacity resources committed to
10 meeting the projected demand;
11 (C) beginning with the commission's annual report due
12 before October 1, 2026, and in each subsequent annual
13 report, the planned retirements or refuelings of electric
14 generation resources and the plans to replace or retain the
15 capacity or energy, or both, of the electric generation
16 resources planned to be retired or refueled; and
17 (D) beginning with the commission's annual report due
18 before October 1, 2026, and in each subsequent annual
19 report, the reports of commission staff under subsection
20 (s).
21 In preparing the summary required under this subdivision, the
22 commission may consult with the forecasting group established
23 under section 3.5 of this chapter.
24 (3) Beginning with the commission's annual report filed under
25 IC 8-1-1-14 in 2025, the commission's analysis regarding the
26 appropriate percentage or portion of:
27 (A) total spring UCAP that public utilities should be
28 authorized to acquire from capacity markets under subsection
29 (g)(3)(B); (h)(3)(B); and
30 (B) total fall UCAP that public utilities should be authorized
31 to acquire from capacity markets under subsection (g)(4)(B).
32 (h)(4)(B).
33 (t) (z) The commission may adopt rules under IC 4-22-2 to
34 implement this section.
35 SECTION 7. An emergency is declared for this act.
HB 1007—LS 7547/DI 101 36
COMMITTEE REPORT
Mr. Speaker: Your Committee on Utilities, Energy and
Telecommunications, to which was referred House Bill 1007, has had
the same under consideration and begs leave to report the same back
to the House with the recommendation that said bill be amended as
follows:
Page 2, line 26, delete "ten percent (10%)" and insert "twenty
percent (20%)".
Page 3, line 17, delete "installed" and insert "manufactured".
Page 3, line 26, after "1." insert "(a)".
Page 3, line 26, after "project" insert "or an arrangement".
Page 3, between lines 30 and 31, begin a new paragraph and insert:
"(b) The term includes the purchase of energy or capacity
through a power purchase agreement.".
Page 4, line 8, delete "planning" and insert "project evaluation,
analysis, and development".
Page 4, line 14, delete "means an" and insert "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.".
Page 4, delete lines 15 through 16.
Page 9, between lines 21 and 22, begin a new line block indented
and insert:
"(10) Include a proposed order for the submittal.".
Page 15, line 35, delete "determines that any potential economic"
and insert "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 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).".
Page 15, delete lines 36 through 39.
Page 15, line 40, delete "later than fifteen (15) days after making the
determination.".
HB 1007—LS 7547/DI 101 37
Page 16, line 5, delete "one (1) or" and insert "the industrial,
research, or commercial prospect about a potential economic
development project".
Page 16, line 6, delete "more potential new large load customers".
Page 22, line 2, delete "Actual project development costs that are".
Page 22, delete lines 3 through 8.
Page 22, line 17, delete "Reasonable and necessary project
development costs that are" and insert "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
(C) a reimbursement of costs by a single customer or
prospective customer at whose request the project was
pursued; and
(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)
HB 1007—LS 7547/DI 101 38
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.".
Page 22, delete lines 18 through 31.
Page 22, line 32, delete "(k)" and insert "(l)".
Page 22, line 33, delete "(j)." and insert "(k).".
Page 22, line 34, delete "(l)" and insert "(m)".
Page 24, line 1, delete "of at least one" and insert "with a
nameplate capacity of at least one hundred twenty-five (125)
megawatts by a public utility.".
Page 24, delete line 2.
Page 24, line 6, delete "(u)(2)(B)," and insert "(u)(2),".
Page 24, line 20, delete "(u)(2)(B)," and insert "(u)(2),".
Page 24, line 34, delete "(u)(2)(B)," and insert "(u)(2),".
Page 25, line 2, delete "(u)(2)(B)," and insert "(u)(2),".
Page 25, line 14, delete "of at least one hundred" and insert "with
a nameplate capacity of at least one hundred twenty-five (125)
megawatts by a public utility.".
Page 25, delete line 15.
Page 27, line 11, delete "retire," and insert "retire and that is
owned and operated by the public utility and used to provide retail
electric service in Indiana,".
Page 27, line 16, delete "facility that the public utility" and insert
"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.".
Page 27, line 17, delete "plans to retire. The" and insert "In
addition, the".
Page 27, line 22, delete "credit" and insert "accredited".
Page 27, line 40, after "resource" insert "accredited".
Page 27, line 41, delete "provides." and insert "provides, so as to
provide approximately the same accredited capacity within the
appropriate regional transmission organization.".
Page 29, line 29, delete "Commission" and insert "With respect to
a report submitted under subsection (n) after December 31, 2025,
commission".
Page 29, line 30, delete "under subsection (n)".
Page 29, line 38, delete "capacity credit" and insert "accredited
capacity".
HB 1007—LS 7547/DI 101 39
Page 30, line 1, delete "and".
Page 30, line 9, delete "IC 8-1-2-0.6." and insert "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.".
Page 30, line 19, after "can" delete ":" and insert "either:".
Page 30, strike lines 20 through 22.
Page 30, line 23, beginning with "(A)" begin a new line block
indented.
Page 30, line 23, strike "(A)" and insert "(1)".
Page 30, line 24, beginning with "(i)" begin a new line double block
indented.
Page 30, line 24, strike "(i)" and insert "(A)".
Page 30, line 27, beginning with "(ii)" begin a new line double block
indented.
Page 30, line 27, strike "(ii)" and insert "(B)".
Page 30, line 29, beginning with "(B)" begin a new line block
indented.
Page 30, line 29, strike "(B)" and insert "(2)".
Page 30, line 31, beginning with "(i)" begin a new line double block
indented.
Page 30, line 31, strike "(i)" and insert "(A)".
Page 30, line 34, beginning with "(ii)" begin a new line double block
indented.
Page 30, line 34, strike "(ii)" and insert "(B)".
Page 30, line 37, strike "may" and insert "shall".
Page 30, line 39, strike "(2), or both." and insert "provide sufficient
reason as to that inability, as described in subdivision (2).".
Page 30, line 40, delete "However," and insert "In addition,".
Page 30, line 41, delete "(n)" and insert "(n)(2)".
Page 31, line 3, delete "(2), or both." and insert "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
HB 1007—LS 7547/DI 101 40
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.".
Page 31, line 8, strike "to support the provision of reliable electric
service to".
Page 31, line 9, strike "the public utility's Indiana customers, or".
Page 31, line 22, after "(h)." insert "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.".
Page 31, line 22, strike "the commission's" and insert "an".
Page 31, line 23, after "order" insert "by the commission".
Page 31, between lines 28 and 29, begin a new paragraph and insert:
"(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
HB 1007—LS 7547/DI 101 41
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).".
Page 31, line 29, delete "(w)" and insert "(x)".
Page 31, line 34, delete "(x)" and insert "(y)".
Page 32, line 32, delete "(y)" and insert "(z)".
and when so amended that said bill do pass.
(Reference is to HB 1007 as introduced.)
SOLIDAY
Committee Vote: yeas 9, nays 4.
_____
COMMITTEE REPORT
Mr. Speaker: Your Committee on Ways and Means, to which was
referred House Bill 1007, has had the same under consideration and
begs leave to report the same back to the House with the
recommendation that said bill do pass. 
(Reference is to HB 1007 as printed January 29, 2025.) 
THOMPSON
Committee Vote: Yeas 16, Nays 7
_____
HOUSE MOTION
Mr. Speaker: I move that House Bill 1007 be amended to read as
follows:
Page 3, between lines 20 and 21, begin a new paragraph and insert:
"SECTION 2. IC 8-1-2-24.5 IS ADDED TO THE INDIANA CODE
AS A NEW SECTION TO READ AS FOLLOWS [EFFECTIVE
UPON PASSAGE]: Sec. 24.5. (a) As used in this section, "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.
(b) As used in this section, "large load customer" means a new
or existing customer of an energy utility, or not more than four (4)
HB 1007—LS 7547/DI 101 42
multiple new or existing customers of an energy utility, that
requests new or additional electricity demand that in the aggregate
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.
(c) As used in this section, "project" refers to a project relating
to energy infrastructure or 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.
(d) As used in this section, "project costs" means the total costs
of a project, including:
(1) planning costs; and
(2) construction and operating costs;
related to the project.
(e) Any standard tariff offered by an energy utility after June
30, 2025, to a large load customer of the energy utility must include
a provision that requires reimbursement by the large load
customer of at least eighty percent (80%) of the project costs
reasonably allocable to the large load customer, regardless of
whether the large load customer ultimately takes service in any
anticipated amount and within any anticipated time frame.".
Page 10, line 29, delete "seventy-five percent (75%)" and insert
"eighty percent (80%)".
Page 11, line 6, after "large" insert "load".
Page 13, line 24, after "hundred" insert "fifty".
Renumber all SECTIONS consecutively.
(Reference is to HB 1007 as printed February 6, 2025.)
PIERCE M
HB 1007—LS 7547/DI 101