*EH1007.2*
April 9, 2025
ENGROSSED
HOUSE BILL No. 1007
_____
DIGEST OF HB 1007 (Updated April 8, 2025 10:27 am - DI 140)
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
(Continued next page)
Effective: Upon passage; January 1, 2025 (retroactive); July 1, 2025.
Soliday, Shonkwiler, Pressel, Bartels, Lauer,
Heaton, May, Lucas, Smith H, DeVon,
Karickhoff, Heine, Smaltz, Teshka, Snow,
Jordan, Thompson, Steuerwald, Olthoff,
Zimmerman, Haggard, Aylesworth, Miller D,
Commons, Judy, Hall, Lehman, Prescott,
Culp, Borders, Baird, Wesco, Lopez,
Carbaugh, McNamara, Jeter, Abbott
(SENATE SPONSORS — KOCH, ROGERS)
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.
February 11, 2025, engrossed.
February 13, 2025, read third time, passed. Yeas 67, nays 25.
SENATE ACTION
February 19, 2025, read first time and referred to Committee on Utilities.
March 27, 2025, amended, reported favorably — Do Pass; reassigned to Committee on Tax
and Fiscal Policy.
April 8, 2025, reported favorably — Do Pass.
EH 1007—LS 7547/DI 101 Digest Continued
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
recovery mechanisms for certain acquisition costs or project costs
incurred by energy utilities. 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
(Continued next page)
EH 1007—LS 7547/DI 101EH 1007—LS 7547/DI 101 Digest Continued
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
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.
EH 1007—LS 7547/DI 101EH 1007—LS 7547/DI 101 April 9, 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.
ENGROSSED
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
EH 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
EH 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 8-1-7.9 IS ADDED TO THE INDIANA CODE AS
22 A NEW CHAPTER TO READ AS FOLLOWS [EFFECTIVE UPON
23 PASSAGE]:
24 Chapter 7.9. Expedited Generation Resource Plans and Large
25 Load Customers
26 Sec. 1. (a) As used in this chapter, "acquisition" means a project
27 or an arrangement that is undertaken:
28 (1) by an energy utility to construct, purchase, lease, or
29 otherwise acquire a generation resource; and
30 (2) in accordance with an approved EGR plan.
31 (b) The term includes the purchase of energy or capacity
32 through a power purchase agreement.
33 Sec. 2. As used in this chapter, "acquisition costs" means the
34 total costs of an acquisition made under an EGR plan, including:
35 (1) planning;
36 (2) construction; and
37 (3) operating;
38 costs related to the acquisition.
39 Sec. 3. As used in this chapter, "appropriate regional
40 transmission organization" has the meaning set forth in
41 IC 8-1-8.5-13(b).
42 Sec. 4. As used in this chapter, "commission" refers to the
EH 1007—LS 7547/DI 101 4
1 Indiana utility regulatory commission created by IC 8-1-1-2.
2 Sec. 5. (a) As used in this chapter, "construction and operating
3 costs" means costs:
4 (1) incurred or to be incurred by an energy utility under this
5 chapter after the issuance of an order by the commission
6 under this chapter; and
7 (2) related to an approved or commission modified acquisition
8 or project.
9 (b) The term includes procurement, contractual, construction,
10 operating, maintenance, financing, legal, regulatory, and project
11 evaluation, analysis, and development costs incurred after the
12 issuance of an order by the commission under this chapter.
13 Sec. 6. As used in this chapter, "corporation" refers to the
14 Indiana economic development corporation established by
15 IC 5-28-3-1 or its successor.
16 Sec. 7. As used in this chapter, "energy utility" means:
17 (1) an electric utility listed in 170 IAC 4-7-2(a) and any
18 successor in interest to that utility; or
19 (2) a corporation organized under IC 8-1-13.
20 Sec. 8. As used in this chapter, "expedited generation resource
21 plan", or "EGR plan", means a plan developed by an energy utility
22 for acquiring generation resources to meet load growth that
23 exceeds the lesser of:
24 (1) five percent (5%) of the energy utility's average peak
25 demand over the most recent three (3) calendar years; or
26 (2) one hundred fifty (150) megawatts.
27 Sec. 9. As used in this chapter, "generation resource submittal"
28 means a compliance filing made to the commission for approval of
29 the acquisition of a specific generation resource in accordance with
30 the criteria set forth in an approved EGR plan.
31 Sec. 10. As used in this chapter, "large load customer" means a
32 new or existing customer of an energy utility, or not more than
33 four (4) multiple new or existing customers of an energy utility,
34 that:
35 (1) requests new or additional electricity demand that in the
36 aggregate exceeds the lesser of:
37 (A) five percent (5%) of the energy utility's average peak
38 demand over the most recent three (3) calendar years; or
39 (B) one hundred fifty (150) megawatts;
40 (2) plans to make a capital investment that exceeds five
41 hundred million dollars ($500,000,000) in a new or expanded
42 facility in Indiana; and
EH 1007—LS 7547/DI 101 5
1 (3) plans to employ at the new or expanded facility in Indiana
2 at least fifty (50) full-time employees with wages that on
3 average meet or exceed the most recently published annual
4 national average according to the Bureau of Labor Statistics
5 of the United States Department of Labor.
6 Sec. 11. As used in this chapter, "office" refers to the Indiana
7 office of energy development established by IC 4-3-23-3.
8 Sec. 12. (a) As used in this chapter, "planning costs" means
9 costs:
10 (1) incurred or to be incurred by an energy utility before the
11 issuance of an order by the commission under this chapter;
12 and
13 (2) related to an acquisition or project.
14 (b) The term includes study, analysis, pre-engineering,
15 engineering, legal, financing, and regulatory costs.
16 Sec. 13. As used in this chapter, "pre-filing meeting" means a
17 meeting to review and discuss a filing or submittal by an energy
18 utility in accordance with:
19 (1) section 18 of this chapter;
20 (2) section 20 of this chapter; or
21 (3) section 22 of this chapter;
22 as applicable.
23 Sec. 14. As used in this chapter, "project" refers to a project
24 relating to energy infrastructure and generation resources that:
25 (1) are required primarily to serve a large load customer of an
26 energy utility; and
27 (2) may be designed to serve more than one (1) large load
28 customer of the energy utility or to meet other customer
29 demand or energy needs.
30 Sec. 15. As used in this chapter, "project costs" means the total
31 costs of a project, including:
32 (1) planning costs; and
33 (2) construction and operating costs;
34 related to the project.
35 Sec. 16. As used in this chapter, "reasonable risk premium"
36 means compensation:
37 (1) negotiated between an energy utility and a large load
38 customer; and
39 (2) paid by the large load customer.
40 Sec. 17. (a) The commission may expedite, in accordance with
41 this chapter, the review of filings and submittals made by an
42 energy utility to meet the energy infrastructure and generation
EH 1007—LS 7547/DI 101 6
1 resource needs of customers. An energy utility may request an
2 expedited review by the commission under either or both of the
3 following:
4 (1) Sections 18 through 21 of this chapter (concerning EGR
5 plans).
6 (2) Sections 22 through 24 of this chapter (concerning large
7 load customer projects).
8 (b) This chapter does not preclude an energy utility from
9 petitioning the commission under other applicable statutes for
10 approval of a generation resource acquisition to meet the needs of
11 its customers.
12 (c) This chapter does not preclude an energy utility from
13 petitioning the commission under, or in conjunction with, other
14 applicable statutes, including:
15 (1) IC 8-1-2-24;
16 (2) IC 8-1-2-42;
17 (3) IC 8-1-2.5;
18 (4) IC 8-1-8.5;
19 (5) IC 8-1-8.8; or
20 (6) IC 8-1-39;
21 for approval of a project to meet the needs of large load customers.
22 Sec. 18. (a) This section applies to an energy utility that petitions
23 the commission for approval of an EGR plan.
24 (b) An energy utility may file a petition with the commission for
25 approval of an EGR plan to acquire generation resources to meet
26 the extraordinary needs for electricity by the energy utility's
27 customers.
28 (c) In a petition under this section, an energy utility must do the
29 following:
30 (1) Describe the energy utility's EGR plan for acquiring
31 generation resources to meet the anticipated extraordinary
32 growth in the load of its customers.
33 (2) Demonstrate a need for generation capacity that exceeds
34 the lesser of:
35 (A) five percent (5%) of the energy utility's average peak
36 demand over the most recent three (3) calendar years; or
37 (B) one hundred fifty (150) megawatts.
38 (3) Provide a load growth forecast for a minimum of five (5)
39 years from the date of the petition.
40 (4) Describe the status of customer contracts and
41 commitments that support the load growth forecast described
42 in subdivision (3).
EH 1007—LS 7547/DI 101 7
1 (5) Explain how the EGR plan is consistent with or differs
2 from the energy utility's most recent integrated resource plan.
3 (6) Propose the accounting authority needed from the
4 commission to support the EGR plan.
5 (7) Propose the manner in which the capital costs and
6 operating and maintenance expenses related to the EGR plan
7 will be included in the energy utility's revenue requirement.
8 (8) Identify the type and amount of capacity and energy:
9 (A) that is included in the EGR plan;
10 (B) that does not exceed seventy-five percent (75%) of the
11 energy utility's peak capacity over the forecast period
12 described in subdivision (3); and
13 (C) with respect to which the energy utility may request
14 expedited approval in a subsequent generation resource
15 submittal.
16 (9) Identify the criteria to be included in a generation
17 resource submittal that must be met for the acquisition to be
18 approved by the commission.
19 (10) Certify that at least thirty (30) days before the filing of
20 the petition the energy utility held a pre-filing meeting with
21 the commission and the office of utility consumer counselor to
22 review the EGR plan.
23 (11) Describe how the energy utility considered implementing
24 grid enhancing technologies to defer or minimize the need for
25 additional investment in generation.
26 (12) Describe how the EGR plan will support the provision of
27 electric utility service with the attributes set forth in
28 IC 8-1-2-0.6, including:
29 (A) reliability;
30 (B) affordability;
31 (C) resiliency;
32 (D) stability; and
33 (E) environmental sustainability.
34 (13) Describe how the EGR plan reasonably protects existing
35 and future customers and is consistent with:
36 (A) the provision of safe, reliable, and affordable electric
37 utility service; and
38 (B) economical rates.
39 (14) Include:
40 (A) verified testimony; and
41 (B) exhibits;
42 supporting the petition and constituting the energy utility's
EH 1007—LS 7547/DI 101 8
1 case in chief.
2 (15) Include a proposed order for the petition.
3 Sec. 19. (a) This section applies to an energy utility that petitions
4 the commission for approval of an EGR plan.
5 (b) Notwithstanding IC 8-1-8.5 or any other statute, the
6 commission may approve an energy utility's EGR plan to
7 construct, purchase, lease, or otherwise acquire generation
8 resources under this chapter for purposes of meeting the needs of
9 the energy utility's customers. The commission shall make its
10 decision based on whether the relief requested is just, reasonable,
11 and in the public interest.
12 (c) The commission may:
13 (1) approve the energy utility's petition in its entirety;
14 (2) deny the energy utility's petition in its entirety; or
15 (3) modify the petition, subject to the energy utility's
16 acceptance of the modification.
17 (d) The commission shall issue a final order on the petition not
18 later than ninety (90) days after receiving the energy utility's
19 complete petition. A petition is considered:
20 (1) complete unless the commission provides a notice of
21 deficiency to the energy utility not later than five (5) business
22 days after the filing of the petition; and
23 (2) approved if the commission does not issue a final order on
24 the petition within the ninety (90) day period set forth in this
25 subsection.
26 Sec. 20. (a) This section applies to an energy utility that submits
27 to the commission for approval a generation resource submittal in
28 accordance with an approved EGR plan.
29 (b) An energy utility may submit a generation resource
30 submittal to the commission for approval of an acquisition that the
31 energy utility intends to make in accordance with an approved
32 EGR plan.
33 (c) In a generation resource submittal under this section, an
34 energy utility must do the following:
35 (1) Describe:
36 (A) the type of technology used in the generation resource
37 to be acquired;
38 (B) the amount of capacity and energy to be acquired;
39 (C) key contractual terms for the acquisition; and
40 (D) the estimated acquisition costs.
41 (2) Demonstrate that the acquisition meets the criteria set
42 forth in the energy utility's approved EGR plan.
EH 1007—LS 7547/DI 101 9
1 (3) Explain how the acquisition is consistent with or differs
2 from the energy utility's most recent integrated resource plan.
3 (4) Detail the status of customer contracts and commitments
4 that support the acquisition.
5 (5) Certify that at least thirty (30) days before the filing of the
6 generation resource submittal the energy utility held a
7 pre-filing meeting with the commission and the office of utility
8 consumer counselor to review the acquisition.
9 (6) Describe how the energy utility considered implementing
10 grid enhancing technologies to defer or minimize the need for
11 additional investment in generation.
12 (7) Describe how the acquisition will support the provision of
13 electric utility service with the attributes set forth in
14 IC 8-1-2-0.6, including:
15 (A) reliability;
16 (B) affordability;
17 (C) resiliency;
18 (D) stability; and
19 (E) environmental sustainability.
20 (8) Describe how the acquisition reasonably protects existing
21 and future customers and is consistent with:
22 (A) the provision of safe, reliable, and affordable electric
23 utility service; and
24 (B) economical rates.
25 (9) Include supporting affidavits and exhibits.
26 (10) Include a proposed order for the submittal.
27 Sec. 21. (a) This section applies to an energy utility that submits
28 to the commission for approval a generation resource submittal in
29 accordance with an approved EGR plan.
30 (b) Notwithstanding IC 8-1-8.5 or any other statute, the
31 commission may approve an energy utility's generation resource
32 submittal to construct, purchase, lease, or otherwise acquire
33 generation resources under this chapter for purposes of meeting
34 the needs of the energy utility's customers. The commission shall
35 make its decision based solely on whether the submittal meets the
36 criteria and requirements set forth in the energy utility's approved
37 EGR plan.
38 (c) The commission may:
39 (1) approve the energy utility's generation resource submittal
40 in its entirety;
41 (2) deny the energy utility's generation resource submittal in
42 its entirety; or
EH 1007—LS 7547/DI 101 10
1 (3) modify the energy utility's generation resource submittal,
2 subject to the energy utility's acceptance of the modification.
3 (d) The commission shall issue a final order on the energy
4 utility's generation resource submittal not later than:
5 (1) sixty (60) days after receiving the energy utility's complete
6 generation resource submittal, if the acquisition is a clean
7 energy project (as defined in IC 8-1-8.8-2); or
8 (2) one hundred twenty (120) days after receiving the energy
9 utility's complete generation resource submittal, if the
10 acquisition would otherwise require a certificate under
11 IC 8-1-8.5-2.
12 A generation resource submittal is considered complete unless the
13 commission provides a notice of deficiency to the energy utility not
14 later than five (5) business days after the filing of the generation
15 resource submittal. A generation resource submittal is considered
16 approved if the commission does not issue a final order on the
17 generation resource submittal within the period set forth in
18 subdivision (1) or (2), as applicable.
19 Sec. 22. (a) This section applies to an energy utility that petitions
20 the commission for approval of a project to serve a large load
21 customer.
22 (b) An energy utility may submit to the commission a petition
23 for approval of a project to serve a large load customer only if the
24 following are satisfied:
25 (1) The petition concerns serving the energy needs of a large
26 load customer.
27 (2) The large load customer commits to significant and
28 meaningful financial assurances that must:
29 (A) include reimbursement by the large load customer of
30 at least eighty percent (80%) of the project costs
31 reasonably allocable to the large load customer; and
32 (B) afford protections for the energy utility's existing and
33 future customers from project costs reasonably allocable
34 to the large load customer regardless of whether the large
35 load customer ultimately takes service in the anticipated
36 amount and within the anticipated time frame.
37 (3) At least thirty (30) days before the energy utility's
38 submission of the petition to the commission, the energy
39 utility held at least one (1) pre-filing meeting with:
40 (A) the corporation;
41 (B) the office;
42 (C) the office of utility consumer counselor;
EH 1007—LS 7547/DI 101 11
1 (D) the appropriate regional transmission organization;
2 and
3 (E) the large load customer;
4 to review the project.
5 (c) An energy utility may petition the commission for approval
6 of a project to serve:
7 (1) one (1) or more large load customers at one (1) or more
8 locations; or
9 (2) not more than four (4) customers whose aggregate demand
10 satisfies the amount set forth in section 10(1) of this chapter.
11 In any case in which more than one (1) large load customer is to be
12 served by a project, a reference in this chapter to one (1) large load
13 customer is a reference to all large load customers to be served by
14 the project, in accordance with IC 1-1-4-1(3).
15 (d) In submitting a petition to the commission under this section,
16 an energy utility must demonstrate that the large load customer
17 and the associated projects meet the requirements of this chapter.
18 Sec. 23. (a) This section applies to an energy utility that petitions
19 the commission for approval of a project to serve a large load
20 customer.
21 (b) In a petition under this section, an energy utility must
22 include, at a minimum, the following:
23 (1) The energy utility's complete case in chief, which must
24 include, at a minimum, the following:
25 (A) An agreement from the large load customer that
26 describes the financial assurances:
27 (i) that afford protections for the energy utility's existing
28 and future customers; and
29 (ii) to which the large load customer has committed
30 regardless of whether the large load customer ultimately
31 takes service in the anticipated amount and within the
32 anticipated time frame.
33 (B) A description of:
34 (i) the demand side management and self-generation
35 options reviewed with the large load customer; and
36 (ii) the investments the large load customer will
37 undertake to reasonably minimize the amount of
38 incremental and other costs incurred by the energy
39 utility.
40 (C) A description of how the energy utility considered
41 implementing grid enhancing technologies to defer or
42 minimize the need for additional investment in generation.
EH 1007—LS 7547/DI 101 12
1 (D) A description of how the energy utility may provide for
2 the requisite amount of electricity needed by the large load
3 customer, including the estimated project costs.
4 (E) A description of how the expected project solution will
5 support the provision of electric utility service with the
6 attributes set forth in IC 8-1-2-0.6, including:
7 (i) reliability;
8 (ii) affordability;
9 (iii) resiliency;
10 (iv) stability; and
11 (v) environmental sustainability.
12 (F) A description of how the expected project solution and
13 its implementation, if approved by the commission,
14 reasonably protects existing and future customers and is
15 consistent with:
16 (i) the provision of safe, reliable, and affordable electric
17 utility service; and
18 (ii) economical rates.
19 (G) A description of the changes that the energy utility will
20 make to the energy utility's:
21 (i) submissions under IC 8-1-8.5; or
22 (ii) filings under IC 8-1-39;
23 or both, that are necessary to update the energy utility's
24 plans under those statutes to incorporate the project.
25 (H) Information concerning each:
26 (i) large load customer; and
27 (ii) economic development project;
28 included in the petition.
29 (I) A letter to the energy utility from the corporation
30 supporting the petition's request.
31 (J) A letter to the energy utility from the office certifying
32 that a pre-filing meeting took place and that at the
33 meeting:
34 (i) the large load customer's proposed project; and
35 (ii) the expected project solution proposed by the energy
36 utility;
37 were adequately discussed.
38 (K) A description of the communications and information
39 sharing that:
40 (i) took place with the appropriate regional transmission
41 organization before the pre-filing meeting described in
42 clause (J); and
EH 1007—LS 7547/DI 101 13
1 (ii) concerned the capacity and energy needs of each
2 large load customer included in the petition.
3 (L) A proposed order for the petition.
4 (2) A copy of a notice of filing with:
5 (A) the corporation;
6 (B) the office;
7 (C) the office of utility consumer counselor; and
8 (D) the appropriate regional transmission organization.
9 A notice that is delivered electronically to the parties set forth
10 in this subdivision satisfies the notice requirement under this
11 subdivision.
12 Sec. 24. (a) This section applies to an energy utility that petitions
13 the commission for approval of a project to serve a large load
14 customer.
15 (b) The commission may approve a petition in whole or in part.
16 The commission shall make its decision based on whether the relief
17 requested is just, reasonable, and in the public interest. The
18 commission shall issue its final order on the petition not later than
19 one hundred fifty (150) days after receiving the energy utility's
20 complete petition and case in chief. A petition is considered:
21 (1) complete unless the commission provides a notice of
22 deficiency to the energy utility not later than seven (7)
23 business days after the filing of the petition; and
24 (2) approved if the commission does not issue a final order on
25 the petition within the one hundred fifty (150) day period set
26 forth in this subsection.
27 (c) If an energy utility files a petition that includes one (1) or
28 more large load customers and one (1) or more proposed projects,
29 the commission may:
30 (1) approve the energy utility's petition in its entirety;
31 (2) deny the energy utility's petition in its entirety; or
32 (3) modify the petition, subject to the energy utility's
33 acceptance of the modification.
34 (d) The commission may approve a reasonable risk premium for
35 a project if requested in an energy utility's petition and if the
36 commission finds that the reasonable risk premium is appropriate.
37 If the commission approves a reasonable risk premium:
38 (1) the large load customer is responsible for the amount of
39 the reasonable risk premium; and
40 (2) the reasonable risk premium may not be:
41 (A) included in the energy utility's:
42 (i) revenue requirement;
EH 1007—LS 7547/DI 101 14
1 (ii) authorized net operating income; or
2 (iii) calculations under IC 8-1-2-42(d)(3) or
3 IC 8-1-2-42(g)(3)(C); or
4 (B) otherwise considered for purposes of setting the
5 authorized return in any future general rate case or other
6 regulatory proceeding involving the energy utility.
7 (e) The commission may approve an energy utility's request to
8 construct, purchase, lease, or otherwise acquire an energy
9 generation resource under this chapter (notwithstanding and
10 instead of under IC 8-1-2.5, IC 8-1-8.5, or IC 8-1-8.8) for the
11 purpose of serving one (1) or more large load customers. In
12 approving an energy utility's request under this chapter to acquire
13 an energy generation resource to serve one (1) or more large load
14 customers, the commission must find that:
15 (1) the information provided by the energy utility under
16 section 23 of this chapter is complete;
17 (2) reasonable and demonstrable consideration was given to
18 nongeneration alternatives by the parties involved;
19 (3) existing and future customers of the energy utility will be
20 adequately protected if the request is granted; and
21 (4) the energy utility has considered the impact of the request
22 on the energy utility's preferred resource portfolio in the
23 energy utility's most recent integrated resource plan.
24 (f) An energy utility shall promptly notify the commission if,
25 after the commission has approved a petition under subsection (e),
26 one (1) or more of the large load customers with respect to whom
27 the petition was approved:
28 (1) no longer requires service from the energy utility or
29 materially alters or terminates the large load customer's
30 service requirements; and
31 (2) the project is incomplete.
32 (g) The commission may, not later than sixty (60) days after
33 receiving a notice under subsection (f), conduct an investigation
34 under IC 8-1-2-58 through IC 8-1-2-60 to determine whether the
35 public interest would still be served by completion of the project.
36 An investigation under this subsection does not preclude the energy
37 utility from continuing construction of the project to serve the
38 large load customer or from continuing to serve the large load
39 customer. If the commission finds that completion of the project is
40 no longer in the public interest, the commission may modify or
41 revoke the order approving the petition.
42 Sec. 25. (a) The commission shall review an energy utility's:
EH 1007—LS 7547/DI 101 15
1 (1) estimated acquisition costs submitted under section
2 20(c)(1)(D) of this chapter; or
3 (2) estimated project costs filed under section 23(b)(1)(D) of
4 this chapter;
5 as applicable.
6 (b) If the commission approves, with or without modification, an
7 energy utility's generation resource submittal or petition for
8 approval of a project, the energy utility may recover:
9 (1) acquisition costs; or
10 (2) project costs;
11 as applicable, that have been reviewed and found reasonable by the
12 commission, with a return at the energy utility's weighted average
13 cost of capital.
14 (c) If the commission denies an energy utility's generation
15 resource submittal or petition for approval of a project, the energy
16 utility may recover planning costs that have been reviewed and
17 found reasonable by the commission, without a return.
18 (d) Absent fraud, concealment, or gross mismanagement, an
19 energy utility may recover:
20 (1) acquisition costs; or
21 (2) project costs;
22 as applicable, with a return at the energy utility's weighted average
23 cost of capital, that the energy utility has incurred or contractually
24 will incur in reliance on a commission order issued under this
25 chapter.
26 Sec. 26. (a) Upon request by an energy utility, the commission
27 shall determine whether the information and related materials
28 filed or submitted, or to be filed or submitted, by an energy utility
29 under this chapter:
30 (1) are confidential under IC 5-14-3-4 or are trade secrets
31 under IC 24-2-3;
32 (2) are exempt from public access and disclosure by Indiana
33 law; and
34 (3) must be treated as confidential and protected from public
35 access and disclosure by the commission.
36 (b) The parties to a pre-filing meeting under this chapter shall
37 execute a nondisclosure agreement to review or discuss
38 information or materials considered confidential under IC 5-14-3-4
39 or to be trade secrets under IC 24-2-3.
40 (c) If the corporation is in negotiations with an industrial,
41 research, or commercial prospect about a potential economic
42 development project and, based on communications related to
EH 1007—LS 7547/DI 101 16
1 those negotiations, determines that the potential economic
2 development project for a new or expanded facility in Indiana may
3 result in the economic development project requiring new or
4 increased energy demand of at least twenty (20) megawatts, the
5 corporation shall notify the affected energy utility not later than
6 fifteen (15) days after making the determination. All
7 communications of the corporation, including notice under this
8 section to an affected energy utility, regarding a potential economic
9 development project are considered confidential and exempt from
10 disclosure under IC 5-14-3-4(b)(5). Upon the corporation's
11 provision of the notice required by this subsection, any subsequent:
12 (1) meeting;
13 (2) pre-filing meeting;
14 (3) communications; or
15 (4) information sharing;
16 involving the corporation, the affected energy utility, or the
17 industrial, research, or commercial prospect about a potential
18 economic development project may be subject to a nondisclosure
19 agreement with respect to information or materials considered
20 confidential under IC 5-14-3-4 or to be trade secrets under
21 IC 24-2-3.
22 (d) An energy utility may request, and the commission may
23 approve, financial incentives under IC 8-1-8.8-11(a) for:
24 (1) an acquisition; or
25 (2) a project;
26 that qualifies as a clean energy project (as defined in IC 8-1-8.8-2).
27 (e) An energy utility may request that review of an arrangement
28 under IC 8-1-2-24 and any related rates and charges under
29 IC 8-1-2-25 that are:
30 (1) submitted with a generation resource submittal; or
31 (2) filed with a petition for a project;
32 under this chapter be reviewed and approved or denied by the
33 commission not later than ninety (90) days after the date of
34 submittal or filing, as applicable.
35 (f) Notwithstanding IC 8-1-8.5 or any other applicable statute,
36 an energy utility may begin construction of an acquisition or a
37 project before filing a petition or submittal under this chapter.
38 (g) The commission may require an energy utility to file with the
39 commission progress reports and updates with respect to an
40 acquisition or project under this chapter. Any required progress
41 reports or updates under this subsection shall be made in a form
42 and at a frequency that the commission determines to be
EH 1007—LS 7547/DI 101 17
1 reasonable.
2 SECTION 3. IC 8-1-8.5-2.1, AS AMENDED BY THE
3 TECHNICAL CORRECTIONS BILL OF THE 2025 GENERAL
4 ASSEMBLY, IS AMENDED TO READ AS FOLLOWS [EFFECTIVE
5 JULY 1, 2025]: Sec. 2.1. (a) This section does not apply to the
6 retirement, sale, or transfer of:
7 (1) a public utility's electric generation facility if the retirement,
8 sale, or transfer is necessary in order for the public utility to
9 comply with a federal consent decree; or
10 (2) an electric generation facility that generates electricity for sale
11 exclusively to the wholesale market.
12 (b) A public utility shall notify the commission if:
13 (1) the public utility intends or decides to retire, sell, or transfer
14 an electric generation facility with a capacity of at least eighty
15 (80) megawatts; and
16 (2) the retirement, sale, or transfer:
17 (A) was not set forth in; or
18 (B) is to take place on a date earlier than the date specified in;
19 the public utility's short term action plan in the public utility's
20 most recently filed integrated resource plan.
21 (c) Upon receiving notice from a public utility under subsection (b),
22 the commission shall consider and may investigate, under IC 8-1-2-58
23 through IC 8-1-2-60, the public utility's intention or decision to retire,
24 sell, or transfer the electric generation facility. In considering the public
25 utility's intention or decision under this subsection, the commission
26 shall examine the impact the retirement, sale, or transfer would have on
27 the public utility's ability to meet:
28 (1) the public utility's planning reserve margin requirements or
29 other federal reliability requirements that the public utility is
30 obligated to meet, as described in section 13(i)(4) 13(n)(6) of this
31 chapter; and
32 (2) the reliability adequacy metrics set forth in section 13(e) 13(h)
33 of this chapter.
34 (d) Before July 1, 2026, if:
35 (1) a public utility intends or decides to retire, sell, or transfer an
36 electric generation facility with a capacity of at least eighty (80)
37 megawatts; and
38 (2) the retirement, sale, or transfer:
39 (A) was not set forth in; or
40 (B) is to take place on a date earlier than the date specified in;
41 the public utility's short term action plan in the public utility's
42 most recently filed integrated resource plan;
EH 1007—LS 7547/DI 101 18
1 the commission shall not permit the public utility's depreciation rates,
2 as established under IC 8-1-2-19, to be amended to reflect the
3 accelerated date for the retirement, sale, or transfer of the electric
4 generation asset unless the commission finds that such an adjustment
5 is necessary to ensure the ability of the public utility to provide reliable
6 service to its customers, and that the unamended depreciation rates
7 would cause an unjust and unreasonable impact on the public utility
8 and its ratepayers.
9 (e) The commission may issue a general administrative order to
10 implement this section.
11 (f) This section expires July 1, 2026.
12 SECTION 4. IC 8-1-8.5-12.1, AS AMENDED BY P.L.93-2024,
13 SECTION 67, IS AMENDED TO READ AS FOLLOWS [EFFECTIVE
14 JULY 1, 2025]: Sec. 12.1. (a) As used in this section, "project
15 development costs" means costs that have been incurred, or are
16 reasonably estimated to be incurred, in the development of one (1)
17 or more small modular nuclear reactors, including:
18 (1) evaluation, design, and engineering costs;
19 (2) costs for federal approvals and licensing;
20 (3) costs for environmental analyses and permitting;
21 (4) early site permit (as defined in 10 CFR 52.1) costs;
22 (5) equipment procurement costs; and
23 (6) authorized carrying costs.
24 (a) (b) As used in this section, "small modular nuclear reactor"
25 means a nuclear reactor that:
26 (1) has a rated electric generating capacity of not more than four
27 hundred seventy (470) megawatts;
28 (2) is capable of being constructed and operated, either:
29 (A) alone; or
30 (B) in combination with one (1) or more similar reactors if
31 additional reactors are, or become, necessary;
32 at a single site; and
33 (3) is required to be licensed by the United States Nuclear
34 Regulatory Commission.
35 The term includes a nuclear reactor that is described in this subsection
36 and that uses a process to produce hydrogen that can be used for energy
37 storage, as a fuel, or for other uses.
38 (b) (c) Not later than July 1, 2023, the commission, in consultation
39 with the department of environmental management, shall adopt rules
40 under IC 4-22-2 concerning the granting of certificates under this
41 chapter for the construction, purchase, or lease of small modular
42 nuclear reactors:
EH 1007—LS 7547/DI 101 19
1 (1) in Indiana for the generation of electricity to be directly or
2 indirectly used to furnish public utility service to Indiana
3 customers; or
4 (2) at the site of a nuclear energy production or generating facility
5 that supplies electricity to Indiana retail customers on July 1,
6 2011.
7 (c) (d) Rules adopted by the commission under this section must
8 provide for the following:
9 (1) That in acting on a public utility's petition for the construction,
10 purchase, or lease of one (1) or more small modular nuclear
11 reactors, as described in subsection (b), (c), the commission shall
12 consider the following:
13 (A) Whether, and to what extent, the one (1) or more small
14 modular nuclear reactors proposed by the public utility will
15 replace a loss of generating capacity in the public utility's
16 portfolio resulting from the retirement or planned retirement
17 of one (1) or more of the public utility's existing electric
18 generating facilities that:
19 (i) are located in Indiana; and
20 (ii) use coal or natural gas as a fuel source.
21 (B) Whether one (1) or more of the small modular nuclear
22 reactors that will replace an existing facility will be located on
23 the same site as or near the existing facility and, if so, potential
24 opportunities for the public utility to:
25 (i) make use of any land and existing infrastructure or
26 facilities already owned or under the control of the public
27 utility; or
28 (ii) create new employment opportunities for workers who
29 have been, or would be, displaced as a result of the
30 retirement of the existing facility.
31 (2) That the commission may grant a certificate under this chapter
32 under circumstances and for locations other than those described
33 in subdivision (1).
34 (3) That the commission may not grant a certificate under this
35 chapter unless the owner or operator of a proposed small modular
36 nuclear reactor provides evidence of a plan to apply for all
37 licenses or permits to construct or operate the proposed small
38 modular nuclear reactor as may be required by:
39 (A) the United States Nuclear Regulatory Commission;
40 (B) the department of environmental management; or
41 (C) any other relevant state or federal regulatory agency with
42 jurisdiction over the construction or operation of nuclear
EH 1007—LS 7547/DI 101 20
1 generating facilities.
2 (4) That any:
3 (A) reports;
4 (B) notices of violations; or
5 (C) other notifications;
6 sent to or from the United States Nuclear Regulatory Commission
7 by or to the owner or operator of a proposed small nuclear reactor
8 must be submitted by the owner or operator to the commission
9 within such times as prescribed by the commission, subject to the
10 commission's duty to treat as confidential and protect from public
11 access and disclosure any information that is contained in a report
12 or notice and that is considered confidential or exempt from
13 public access and disclosure under state or federal law.
14 (5) That any person that owns or operates a small modular nuclear
15 reactor in Indiana may not store:
16 (A) spent nuclear fuel (as defined in IC 13-11-2-216); or
17 (B) high level radioactive waste (as defined in
18 IC 13-11-2-102);
19 from the small modular nuclear reactor on the site of the small
20 modular nuclear reactor without first meeting all applicable
21 requirements of the United States Nuclear Regulatory
22 Commission.
23 (d) In adopting the rules required by this section, the commission
24 may adopt rules under IC 4-22-2.
25 (e) A public utility may petition the commission for approval to
26 incur, before obtaining a certificate under this chapter, project
27 development costs for the development of one (1) or more small
28 modular nuclear reactors. The public utility must file with the
29 petition the public utility's case in chief, which must contain the
30 information and supporting documentation regarding the factors
31 the commission must consider under this subsection. In reviewing
32 a petition and the supporting case in chief under this subsection,
33 the commission shall consider the following:
34 (1) Whether a project by the utility to construct, purchase, or
35 lease a small modular nuclear reactor is reasonably consistent
36 with:
37 (A) this section and rules adopted by the commission under
38 this section; and
39 (B) the purposes set forth in IC 8-1-8.8-1(b), as applicable.
40 (2) The following factors with respect to the project
41 development costs and the project for which they are to be
42 incurred:
EH 1007—LS 7547/DI 101 21
1 (A) The amount of project development costs the public
2 utility anticipates incurring.
3 (B) The anticipated timeline for incurring the project
4 development costs.
5 (C) The anticipated date by which the public utility will
6 make a decision as to whether to seek a certificate under
7 this chapter.
8 The commission shall review a petition submitted under this
9 subsection and issue a final order approving or denying the petition
10 not later than one hundred eighty (180) days after receiving the
11 petition and complete case in chief. However, if the commission
12 makes a docket entry extending the procedural schedule and the
13 public utility does not object to the entered extension, the
14 commission may extend the one hundred eighty (180) day time
15 frame for issuing a final order under this subsection for the
16 amount of time set forth in the docket entry. In an order approving
17 a petition, the commission must make a finding as to the best
18 estimate and reasonableness of project development costs based on
19 the evidence of record.
20 (f) If a public utility has received approval from the commission
21 under subsection (e) to incur project development costs, the public
22 utility may petition the commission at any time before or during
23 the development and execution of a small modular nuclear reactor
24 project for the approval of a rate schedule that periodically adjusts
25 the public utility's rates and charges to provide for the timely
26 recovery of project development costs. A petition under this
27 subsection must describe any efforts by the public utility to pursue
28 funding opportunities from the United States Department of
29 Energy to offset the project development costs that the public
30 utility seeks to recover under the proposed rate schedule.
31 (g) If, after reviewing a public utility's proposed rate schedule
32 in a petition submitted under subsection (f), the commission
33 determines that the public utility has incurred or will incur project
34 development costs that are:
35 (1) reasonable in amount;
36 (2) necessary to support the construction, purchase, or lease
37 of a small modular nuclear reactor; and
38 (3) consistent with the commission's finding as to the best
39 estimate of project development costs in the commission's
40 order of approval under subsection (e);
41 the commission shall approve the recovery of the project
42 development costs, subject to subsections (h) and (i). However, a
EH 1007—LS 7547/DI 101 22
1 public utility may not file adjustments to a rate schedule to adjust
2 for cost recovery approved under this subsection more than one (1)
3 time every twelve (12) months.
4 (h) A public utility that recovers project development costs
5 under subsection (g) shall recover eighty percent (80%) of the
6 approved project development costs under the rate schedule
7 approved under subsection (g) and shall defer the remaining
8 twenty percent (20%) of approved project development costs,
9 including, to the extent applicable, depreciation, allowance for
10 funds used during construction, and post in service carrying costs,
11 based on the overall cost of capital most recently approved by the
12 commission, and shall recover those project development costs as
13 part of the next general rate case that the public utility files with
14 the commission.
15 (i) The recovery of a public utility's project development costs
16 through a periodic rate adjustment mechanism approved by the
17 commission under subsection (g) must occur over a period that is
18 equal to:
19 (1) the period over which the approved project development
20 costs are incurred; or
21 (2) three (3) years;
22 whichever is less.
23 (j) Project development costs that are found by the commission
24 to be reasonable, necessary, and consistent with the best estimate
25 of project development costs in the commission's order of approval
26 under subsection (e) shall be recovered by a public utility by
27 inclusion in the public utility's rates and charges. Project
28 development costs that are incurred by a public utility and that
29 exceed the best estimate of project development costs under
30 subsection (e) may not be included in the public utility's rates and
31 charges unless found by the commission to be reasonable,
32 necessary, and prudent in supporting the construction, purchase,
33 or lease of the small modular nuclear reactor for which they were
34 incurred. Project development costs that are incurred by a public
35 utility for a project that is canceled or not completed may be
36 recovered by the public utility if found by the commission to be
37 reasonable, necessary, and prudently incurred, but such costs shall
38 be recovered without a return unless the commission also finds
39 that:
40 (1) the decision to cancel or not complete the project was
41 prudently made for good cause;
42 (2) the project development costs incurred will be offset, as
EH 1007—LS 7547/DI 101 23
1 applicable, by:
2 (A) funding opportunities from the United States
3 Department of Energy that are pursued in good faith by
4 the public utility;
5 (B) a recoupment of revenues received by the public utility
6 from one (1) or more third parties for the transfer of assets
7 created through the costs incurred; or
8 (C) a reimbursement of costs by a single customer or
9 prospective customer at whose request the project was
10 pursued; and
11 (3) a return on the project development costs incurred is
12 appropriate under the circumstances to avoid harm to the
13 public utility and its customers.
14 (k) A public utility may elect not to seek approval of, or cost
15 recovery for, project development costs under subsections (e)
16 through (i) and instead seek approval from the commission to defer
17 and amortize project development costs in accordance with the
18 procedures set forth in section 6.5 of this chapter with respect to
19 construction costs.
20 (l) The commission may adopt rules under IC 4-22-2 to
21 implement subsections (e) through (k).
22 (e) (m) This section shall not be construed to affect the authority of
23 the United States Nuclear Regulatory Commission.
24 SECTION 5. IC 8-1-8.5-13, AS AMENDED BY P.L.93-2024,
25 SECTION 68, IS AMENDED TO READ AS FOLLOWS [EFFECTIVE
26 JULY 1, 2025]: Sec. 13. (a) The general assembly finds that it is in the
27 public interest to support the reliability, availability, and diversity of
28 electric generating capacity in Indiana for the purpose of providing
29 reliable and stable electric service to customers of public utilities.
30 (b) As used in this section, "appropriate regional transmission
31 organization", with respect to a public utility, refers to the regional
32 transmission organization approved by the Federal Energy Regulatory
33 Commission for the control area that includes the public utility's
34 assigned service area (as defined in IC 8-1-2.3-2).
35 (c) As used in this section, "capacity market" means an auction
36 conducted by an appropriate regional transmission organization to
37 determine a market clearing price for capacity based on the planning
38 reserve margin requirements established by the appropriate regional
39 transmission organization for a planning year with respect to which an
40 auction has not yet been conducted.
41 (d) As used in this section, "fall unforced capacity", or "fall UCAP",
42 with respect to an electric generating facility, means:
EH 1007—LS 7547/DI 101 24
1 (1) the capacity value of the electric generating facility's installed
2 capacity rate adjusted for the electric generating facility's average
3 forced outage rate for the fall period, calculated as required by the
4 appropriate regional transmission organization or by the Federal
5 Energy Regulatory Commission;
6 (2) a metric that is similar to the metric described in subdivision
7 (1) and that is required by the appropriate regional transmission
8 organization; or
9 (3) if the appropriate regional transmission organization does not
10 require a metric described in subdivision (1) or (2), a metric that:
11 (A) can be used to demonstrate that a public utility has
12 sufficient capacity to:
13 (i) provide reliable electric service to Indiana customers for
14 the fall period; and
15 (ii) meet its planning reserve margin requirement and other
16 federal reliability requirements described in subsection
17 (l)(4); (n)(6); and
18 (B) is acceptable to the commission.
19 (e) As used in this section, "MISO" refers to the regional
20 transmission organization known as the Midcontinent Independent
21 System Operator that operates the bulk power transmission system
22 serving most of the geographic territory in Indiana.
23 (f) As used in this section, "planning reserve margin requirement",
24 with respect to a public utility for a particular resource planning year,
25 means the planning reserve margin requirement for that planning year
26 that the public utility is obligated to meet in accordance with the public
27 utility's membership in the appropriate regional transmission
28 organization.
29 (g) As used in this section, "refuel" or "refueling" means a
30 planned fuel conversion from one fuel source to another fuel source
31 with respect to an electric generation resource with a nameplate
32 capacity of at least one hundred twenty-five (125) megawatts by a
33 public utility.
34 (g) (h) As used in this section, "reliability adequacy metrics", with
35 respect to a public utility, means calculations used to demonstrate all
36 of the following:
37 (1) Subject to subsection (q)(2)(B), (u)(2), that the public utility:
38 (A) has in place sufficient summer UCAP; or
39 (B) can reasonably acquire not more than:
40 (i) thirty percent (30%) of its total summer UCAP from
41 capacity markets, with respect to a report filed with the
42 commission under subsection (l) (n) before July 1, 2023; or
EH 1007—LS 7547/DI 101 25
1 (ii) fifteen percent (15%) of its total summer UCAP from
2 capacity markets, with respect to a report filed with the
3 commission under subsection (l) (n) after June 30, 2023;
4 such that it will have sufficient summer UCAP;
5 to provide reliable electric service to Indiana customers, and to
6 meet its planning reserve margin requirement and other federal
7 reliability requirements described in subsection (l)(4). (n)(6).
8 (2) Subject to subsection (q)(2)(B), (u)(2), that the public utility:
9 (A) has in place sufficient winter UCAP; or
10 (B) can reasonably acquire not more than:
11 (i) thirty percent (30%) of its total winter UCAP from
12 capacity markets, with respect to a report filed with the
13 commission under subsection (l) (n) before July 1, 2023; or
14 (ii) fifteen percent (15%) of its total winter UCAP from
15 capacity markets, with respect to a report filed with the
16 commission under subsection (l) (n) after June 30, 2023;
17 such that it will have sufficient winter UCAP;
18 to provide reliable electric service to Indiana customers, and to
19 meet its planning reserve margin requirement and other federal
20 reliability requirements described in subsection (l)(4). (n)(6).
21 (3) Subject to subsection (q)(2)(B), (u)(2), with respect to a report
22 filed with the commission under subsection (l) (n) after June 30,
23 2026, that the public utility:
24 (A) has in place sufficient spring UCAP; or
25 (B) can reasonably acquire not more than fifteen percent
26 (15%) of its total spring UCAP from capacity markets, such
27 that it will have sufficient spring UCAP;
28 to provide reliable electric service to Indiana customers, and to
29 meet its planning reserve margin requirement and other federal
30 reliability requirements described in subsection (l)(4). (n)(6).
31 (4) Subject to subsection (q)(2)(B), (u)(2), with respect to a report
32 filed with the commission under subsection (l) (n) after June 30,
33 2026, that the public utility:
34 (A) has in place sufficient fall UCAP; or
35 (B) can reasonably acquire not more than fifteen percent
36 (15%) of its total fall UCAP from capacity markets, such that
37 it will have sufficient fall 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 (i) As used in this section, "retire" or retirement" means a
42 planned permanent ceasing of electric generation operations with
EH 1007—LS 7547/DI 101 26
1 respect to an electric generation resource with a nameplate
2 capacity of at least one hundred twenty-five (125) megawatts by a
3 public utility.
4 (h) (j) As used in this section, "spring unforced capacity", or "spring
5 UCAP", with respect to an electric generating facility, means:
6 (1) the capacity value of the electric generating facility's installed
7 capacity rate adjusted for the electric generating facility's average
8 forced outage rate for the spring period, calculated as required by
9 the appropriate regional transmission organization or by the
10 Federal Energy Regulatory Commission;
11 (2) a metric that is similar to the metric described in subdivision
12 (1) and that is required by the appropriate regional transmission
13 organization; or
14 (3) if the appropriate regional transmission organization does not
15 require a metric described in subdivision (1) or (2), a metric that:
16 (A) can be used to demonstrate that a public utility has
17 sufficient capacity to:
18 (i) provide reliable electric service to Indiana customers for
19 the spring period; and
20 (ii) meet its planning reserve margin requirement and other
21 federal reliability requirements described in subsection
22 (l)(4); (n)(6); and
23 (B) is acceptable to the commission.
24 (i) (k) As used in this section, "summer unforced capacity", or
25 "summer UCAP", with respect to an electric generating facility, means:
26 (1) the capacity value of the electric generating facility's installed
27 capacity rate adjusted for the electric generating facility's average
28 forced outage rate for the summer period, calculated as required
29 by the appropriate regional transmission organization or by the
30 Federal Energy Regulatory Commission; or
31 (2) a metric that is similar to the metric described in subdivision
32 (1) and that is required by the appropriate regional transmission
33 organization.
34 (j) (l) As used in this section, "winter unforced capacity", or "winter
35 UCAP", with respect to an electric generating facility, means:
36 (1) the capacity value of the electric generating facility's installed
37 capacity rate adjusted for the electric generating facility's average
38 forced outage rate for the winter period, calculated as required by
39 the appropriate regional transmission organization or by the
40 Federal Energy Regulatory Commission;
41 (2) a metric that is similar to the metric described in subdivision
42 (1) and that is required by the appropriate regional transmission
EH 1007—LS 7547/DI 101 27
1 organization; or
2 (3) if the appropriate regional transmission organization does not
3 require a metric described in subdivision (1) or (2), a metric that:
4 (A) can be used to demonstrate that a public utility has
5 sufficient capacity to:
6 (i) provide reliable electric service to Indiana customers for
7 the winter period; and
8 (ii) meet its planning reserve margin requirement and other
9 federal reliability requirements described in subsection
10 (l)(4); (n)(6); and
11 (B) is acceptable to the commission.
12 (k) (m) A public utility that owns and operates an electric
13 generating facility serving customers in Indiana shall operate and
14 maintain the facility using good utility practices and in a manner:
15 (1) reasonably intended to support the provision of reliable and
16 economic electric service to customers of the public utility; and
17 (2) reasonably consistent with the resource reliability
18 requirements of MISO or any other appropriate regional
19 transmission organization; and
20 (3) reasonably maximizes the economic value of the electric
21 generating facility.
22 (l) (n) Not later than thirty (30) days after the deadline for
23 submitting an annual planning reserve margin report to MISO, each
24 public utility providing electric service to Indiana customers shall,
25 regardless of whether the public utility is required to submit an annual
26 planning reserve margin report to MISO, file with the commission a
27 report, in a form specified by the commission, that provides the
28 following information for each of the next three (3) resource planning
29 years, beginning with the planning year covered by the planning
30 reserve margin report to MISO described in this subsection:
31 (1) The:
32 (A) capacity;
33 (B) location; and
34 (C) fuel source;
35 for each electric generating facility that is owned and operated by
36 the electric utility and that will be used to provide electric service
37 to Indiana customers.
38 (2) With respect to a report submitted to the commission after
39 December 31, 2025, the amount of generating resource
40 capacity or energy, or both, that the public utility plans to
41 retire and that is owned and operated by the public utility and
42 used to provide retail electric service in Indiana, including
EH 1007—LS 7547/DI 101 28
1 the:
2 (A) capacity;
3 (B) location;
4 (C) fuel source; and
5 (D) planned retirement date;
6 for each electric generating facility. The public utility must
7 include information as to whether the planned retirement is
8 required in order to comply with environmental laws,
9 regulations, or court orders, including consent decrees, that
10 are or will be in effect at the time of the planned retirement.
11 In addition, the public utility must provide its economic
12 rationale for the planned retirement, including anticipated
13 ratepayer impacts, and information concerning the public
14 utility's plan or plans with respect to the amount of
15 replacement capacity identified to provide approximately the
16 same accredited capacity within the appropriate regional
17 transmission organization as the amount of capacity of the
18 facility to be retired.
19 (3) With respect to a report submitted to the commission after
20 December 31, 2025, the amount of generating resource
21 capacity or energy, or both, that the public utility plans to
22 refuel, including the:
23 (A) capacity;
24 (B) location;
25 (C) existing fuel source;
26 (D) proposed fuel source; and
27 (E) planned completion date of the refueling;
28 with respect to each electric generating facility that the public
29 utility plans to refuel. The public utility must provide its
30 economic rationale for the planned refueling, including
31 anticipated ratepayer impacts, and information concerning
32 the public utility's plan or plans with respect to the extent to
33 which the refueling will maintain or increase the current
34 generating resource accredited capacity or energy, or both,
35 that the electric generating facility provides, so as to provide
36 approximately the same accredited capacity within the
37 appropriate regional transmission organization.
38 (2) (4) The amount of generating resource capacity or energy, or
39 both, that the public utility has procured under contract and that
40 will be used to provide electric service to Indiana customers,
41 including the:
42 (A) capacity;
EH 1007—LS 7547/DI 101 29
1 (B) location; and
2 (C) fuel source;
3 for each electric generating facility that will supply capacity or
4 energy under the contract, to the extent known by the public
5 utility.
6 (3) (5) The amount of demand response resources available to the
7 public utility under contracts and tariffs.
8 (4) (6) The following:
9 (A) The planning reserve margin requirements established by
10 MISO for the planning years covered by the report, to the
11 extent known by the public utility with respect to any
12 particular planning year covered by the report.
13 (B) If applicable, any other planning reserve margin
14 requirement that:
15 (i) applies to the planning years covered by the report; and
16 (ii) the public utility is obligated to meet in accordance with
17 the public utility's membership in an appropriate regional
18 transmission organization;
19 to the extent known by the public utility with respect to any
20 particular planning year covered by the report.
21 (C) Other federal reliability requirements that the public utility
22 is obligated to meet in accordance with its membership in an
23 appropriate regional transmission organization with respect to
24 the planning years covered by the report, to the extent known
25 by the public utility with respect to any particular planning
26 year covered by the report.
27 For each planning reserve margin requirement reported under
28 clause (A) or (B), the public utility shall include a comparison of
29 that planning reserve margin requirement to the planning reserve
30 margin requirement established by the same regional transmission
31 organization for the 2021-2022 planning year.
32 (5) (7) The reliability adequacy metrics of the public utility, as
33 forecasted for the three (3) planning years covered by the report.
34 (m) (o) Upon request by a public utility, the commission shall
35 determine whether information provided in a report filed by the public
36 utility under subsection (l): (n):
37 (1) is confidential under IC 5-14-3-4 or is a trade secret under
38 IC 24-2-3;
39 (2) is exempt from public access and disclosure by Indiana law;
40 and
41 (3) shall be treated as confidential and protected from public
42 access and disclosure by the commission.
EH 1007—LS 7547/DI 101 30
1 (n) (p) A joint agency created under IC 8-1-2.2 may file the report
2 required under subsection (l) (n) as a consolidated report on behalf of
3 any or all of the municipally owned utilities that make up its
4 membership.
5 (o) (q) A:
6 (1) corporation organized under IC 23-17 that is an electric
7 cooperative and that has at least one (1) member that is a
8 corporation organized under IC 8-1-13; or
9 (2) general district corporation within the meaning of
10 IC 8-1-13-23;
11 may file the report required under subsection (l) (n) as a consolidated
12 report on behalf of any or all of the cooperatively owned electric
13 utilities that it serves.
14 (p) (r) In reviewing a report filed by a public utility under
15 subsection (l), (n), the commission may request technical assistance
16 from MISO or any other appropriate regional transmission organization
17 in determining:
18 (1) the planning reserve margin requirements or other federal
19 reliability requirements that the public utility is obligated to meet,
20 as described in subsection (l)(4); (n)(6); and
21 (2) whether the resources available to the public utility under
22 subsections (l)(1) (n)(1) through (l)(3) (n)(5) will be adequate to
23 support the provision of reliable electric service to the public
24 utility's Indiana customers.
25 (s) With respect to a report submitted under subsection (n) after
26 December 31, 2025, commission staff shall review the reports
27 submitted by public utilities and shall, not later than ninety (90)
28 days after the date of submission of the reports, submit to the
29 commission a staff report concerning any planned retirements
30 included in the reports under subsection (n)(2). The report must
31 make recommendations to the commission based on whether each
32 planned retirement:
33 (1) is consistent with the standards set forth in subsection (m);
34 (2) will be replaced with an amount of replacement capacity
35 that will provide approximately the same accredited capacity
36 within the appropriate regional transmission organization as
37 the amount of capacity of the facility to be retired;
38 (3) will not adversely and unreasonably impact a public
39 utility's ability to provide safe, reliable, and economical
40 electric utility service to the public utility's customers;
41 (4) will result in the provision to Indiana customers of electric
42 utility service with the attributes of:
EH 1007—LS 7547/DI 101 31
1 (A) reliability;
2 (B) affordability;
3 (C) resiliency;
4 (D) stability; and
5 (E) environmental sustainability;
6 as set forth in IC 8-1-2-0.6; and
7 (5) is required in order to comply with environmental laws,
8 regulations, or court orders, including consent decrees, that
9 are or will be in effect at the time of the planned retirement.
10 (t) The commission shall make the staff reports prepared under
11 subsection (s) publicly available by posting the staff reports on the
12 commission's website. Upon the posting of a staff report on the
13 commission's website, the commission shall accept public
14 comments on the report for a period not to exceed thirty (30) days
15 after the date of posting.
16 (q) (u) If, after reviewing a report filed by a public utility under
17 subsection (l), (n) and any staff report prepared with respect to the
18 public utility under subsection (s), the commission is not satisfied
19 that the public utility can either:
20 (1) provide reliable electric service to the public utility's Indiana
21 customers; or
22 (2) either:
23 (A) (1) satisfy both:
24 (i) (A) its planning reserve margin requirement or other
25 federal reliability requirements that the public utility is
26 obligated to meet, as described in subsection (l)(4); (n)(6); and
27 (ii) (B) the reliability adequacy metrics set forth in subsection
28 (g); (h); or
29 (B) (2) provide sufficient reason as to why the public utility is
30 unable to satisfy both:
31 (i) (A) its planning reserve margin requirement or other
32 federal reliability requirements that the public utility is
33 obligated to meet, as described in subsection (l)(4); (n)(6); and
34 (ii) (B) the reliability adequacy metrics set forth in subsection
35 (g); (h);
36 during one (1) more of the planning years covered by the report, the
37 commission may shall conduct an investigation under IC 8-1-2-58
38 through IC 8-1-2-60 as to the reasons for the public utility's potential
39 inability to meet the requirements described in subdivision (1) or (2),
40 or both. provide sufficient reason as to that inability, as described
41 in subdivision (2). In addition, if the public utility has indicated in
42 its report under subsection (n)(2) that it plans to retire an electric
EH 1007—LS 7547/DI 101 32
1 generating facility within one (1) year of the date of the report, the
2 commission must conduct an investigation under IC 8-1-2-58
3 through IC 8-1-2-60 as to the reasons for the public utility's
4 potential inability to meet the requirements described in
5 subdivision (1) or provide sufficient reason as to that inability, as
6 described in subdivision (2). However, a public utility may request,
7 not earlier than three (3) years before the planned retirement date
8 of an electric generation facility, that the commission conduct an
9 investigation under IC 8-1-2-58 through IC 8-1-2-60, for the
10 purposes described in this subsection, with respect to the planned
11 retirement. If the commission conducts an investigation at the
12 request of a public utility within the three (3) year period before
13 the planned retirement date of an electric generation facility, the
14 commission may not conduct a subsequent investigation that would
15 otherwise be required under this subsection with respect to the
16 retirement of that same electric generation facility unless the
17 commission is not satisfied, as of the time that an investigation
18 would otherwise be required under this subsection, that the public
19 utility can meet the requirements described in subdivision (1) or
20 provide sufficient reason as to that inability, as described in
21 subdivision (2). If a certificate is granted by the commission under
22 this chapter for a facility intended to repower or replace a
23 generation unit that is planned for retirement, and the certificate
24 includes findings that the project will result in at least equivalent
25 accredited capacity and will provide economic benefit to
26 ratepayers as compared to the continued operation of the
27 generating unit to be retired, the certificate under this chapter
28 constitutes approval by the commission for purposes of an
29 investigation required by this subsection. However, if the
30 commission finds that facts and circumstances regarding the
31 planned retirement have changed significantly since the certificate
32 was granted and that those changes concern the public utility's
33 ability to meet the requirements described in subdivision (1), the
34 commission may conduct an investigation into the planned
35 retirement of the unit.
36 (r) (v) If, upon investigation under IC 8-1-2-58 through IC 8-1-2-60,
37 and after notice and hearing, as required by IC 8-1-2-59, the
38 commission determines that the capacity resources available to the
39 public utility under subsections (l)(1) (n)(1) through (l)(3) (n)(5) will
40 not be adequate to support the provision of reliable electric service to
41 the public utility's Indiana customers, or to allow the public utility to
42 satisfy both its planning reserve margin requirements or other federal
EH 1007—LS 7547/DI 101 33
1 reliability requirements that the public utility is obligated to meet (as
2 described in subsection (l)(4)) (n)(6)) and the reliability adequacy
3 metrics set forth in subsection (g), (h), the commission shall issue an
4 order:
5 (1) directing the public utility to acquire or construct; or
6 (2) prohibiting the retirement or refueling of;
7 such capacity resources that are reasonable and necessary to enable the
8 public utility to provide reliable electric service to its Indiana
9 customers, and to satisfy both its planning reserve margin requirements
10 or other federal reliability requirements described in subsection (l)(4)
11 (n)(6) and the reliability adequacy metrics set forth in subsection (g).
12 (h). The commission shall issue an order under this subsection not
13 later than one hundred twenty (120) days after the initiation of the
14 investigation under subsection (u). If the commission does not issue
15 an order within the one hundred twenty (120) day period
16 prescribed by this subsection, the public utility is considered to be
17 able to meet the requirements described in subsection (u)(1) with
18 respect to the retirement of the electric generation facility under
19 investigation. Not later than ninety (90) days after the date of the
20 commission's an order by the commission under this subsection, the
21 public utility shall file for approval with the commission a plan to
22 comply with the commission's order. Notwithstanding IC 8-1-3 or
23 any other law, any appeal of an order by the commission under this
24 subsection is entitled to priority review and shall be given
25 expedited consideration in accordance with Rule 21 of the Indiana
26 Rules of Appellate Procedure.
27 (w) With respect to a report submitted under subsection (n)
28 after December 31, 2025, if the commission issues an order under
29 subsection (v) to prohibit the retirement or refueling of an electric
30 generation resource, the commission shall create a sub-docket to
31 authorize the public utility to recover in rates the costs of the
32 continued operation of the electric generation resource that was
33 proposed to be retired or refueled. The commission must find that
34 the continued costs of operation are just and reasonable before
35 authorizing their recovery in the public utility's rates. The creation
36 of a sub-docket under this subsection is not subject to the one
37 hundred twenty (120) day time frame for the commission to issue
38 an order under subsection (v).
39 The (x) A public utility's plan under subsection (v) may include:
40 (1) a request for a certificate of public convenience and necessity
41 under this chapter; or
42 (2) an application under IC 8-1-8.8;
EH 1007—LS 7547/DI 101 34
1 or both.
2 (s) (y) Beginning in 2022, the commission shall include in its annual
3 report under IC 8-1-1-14 the following information:
4 (1) The commission's analysis regarding the ability of public
5 utilities to:
6 (A) provide reliable electric service to Indiana customers; and
7 (B) satisfy both:
8 (i) their planning reserve margin requirements or other
9 federal reliability requirements; and
10 (ii) the reliability adequacy metrics set forth in subsection
11 (g); (h);
12 for the next three (3) utility resource planning years, based on the
13 most recent reports filed by public utilities under subsection (l).
14 (n).
15 (2) A summary of:
16 (A) the projected demand for retail electricity in Indiana over
17 the next calendar year; and
18 (B) the amount and type of capacity resources committed to
19 meeting the projected demand;
20 (C) beginning with the commission's annual report due
21 before October 1, 2026, and in each subsequent annual
22 report, the planned retirements or refuelings of electric
23 generation resources and the plans to replace or retain the
24 capacity or energy, or both, of the electric generation
25 resources planned to be retired or refueled; and
26 (D) beginning with the commission's annual report due
27 before October 1, 2026, and in each subsequent annual
28 report, the reports of commission staff under subsection
29 (s).
30 In preparing the summary required under this subdivision, the
31 commission may consult with the forecasting group established
32 under section 3.5 of this chapter.
33 (3) Beginning with the commission's annual report filed under
34 IC 8-1-1-14 in 2025, the commission's analysis regarding the
35 appropriate percentage or portion of:
36 (A) total spring UCAP that public utilities should be
37 authorized to acquire from capacity markets under subsection
38 (g)(3)(B); (h)(3)(B); and
39 (B) total fall UCAP that public utilities should be authorized
40 to acquire from capacity markets under subsection (g)(4)(B).
41 (h)(4)(B).
42 (t) (z) The commission may adopt rules under IC 4-22-2 to
EH 1007—LS 7547/DI 101 35
1 implement this section.
2 SECTION 6. An emergency is declared for this act.
EH 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.".
EH 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)
EH 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".
EH 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
EH 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
EH 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)
EH 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
_____
COMMITTEE REPORT
Mr. President: The Senate Committee on Utilities, to which was
referred House Bill No. 1007, has had the same under consideration
and begs leave to report the same back to the Senate with the
recommendation that said bill be AMENDED as follows:
EH 1007—LS 7547/DI 101 43
Page 3, delete lines 21 through 42.
Page 4, delete lines 1 through 12.
Page 4, line 13, delete "IC 8-1-8.2" and insert "IC 8-1-7.9".
Page 4, line 16, delete "8.2." and insert "7.9.".
Page 5, line 42, delete "mean" and insert "means".
Page 7, line 19, after "In" insert "a".
Page 15, line 9, delete "non-generation" and insert
"nongeneration".
Page 17, line 19, delete "IC 8-1-2-42" and insert "IC 8-1-2-24".
Page 17, line 20, delete "IC 8-1-2-43" and insert "IC 8-1-2-25".
Page 17, line 24, delete "dates" and insert "days".
Renumber all SECTIONS consecutively.
and when so amended that said bill do pass and be reassigned to the
Senate Committee on Tax and Fiscal Policy.
(Reference is to HB 1007 as reprinted February 11, 2025.)
KOCH, Chairperson
Committee Vote: Yeas 8, Nays 3.
_____
COMMITTEE REPORT
Mr. President: The Senate Committee on Tax and Fiscal Policy, to
which was referred Engrossed House Bill No. 1007, has had the same
under consideration and begs leave to report the same back to the
Senate with the recommendation that said bill DO PASS.
(Reference is to EHB 1007 as printed March 28, 2025.)
HOLDMAN, Chairperson
Committee Vote: Yeas 10, Nays 3
EH 1007—LS 7547/DI 101