Introduced Version
HOUSE BILL No. 1007
_____
DIGEST OF INTRODUCED BILL
Citations Affected: IC 6-3.1-45; IC 8-1-8.2; IC 8-1-8.5.
Synopsis: Energy generation resources. Provides a credit against state
tax liability for expenses incurred in the manufacture of a small
modular nuclear reactor (SMR) in Indiana. Establishes procedures
under which certain energy utilities may request approval for one or
more of the following from the Indiana utility regulatory commission
(IURC): (1) An expedited generation resource plan (EGR plan) to meet
customer load growth that exceeds a specified threshold. (2) A
generation resource submittal for the acquisition of a specific
generation resource in accordance with an approved EGR plan. (3) A
project to serve one or more large load customers. Sets forth: (1) the
requirements for approval of each of these types of requests; (2)
standards for financial assurances by large load customers; and (3) cost
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 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 if a public utility does
(Continued next page)
Effective: Upon passage; January 1, 2025 (retroactive); July 1, 2025.
Soliday, Shonkwiler, Pressel
January 13, 2025, read first time and referred to Committee on Utilities, Energy and
Telecommunications.
2025 IN 1007—LS 7547/DI 101 Digest Continued
not seek: (1) approval of; or (2) cost recovery for; project development
costs for an SMR under the bill's provisions, the IURC may approve the
deferral and amortization of project development costs in accordance
with the statutory procedures set forth for construction costs. 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 100 megawatts. Provides that for any planned retirement or
refueling, the public utility must include 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 credit capacity within the appropriate regional transmission
organization 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 capacity or energy that the electric
generating facility provides. 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 provide reliable electric service or
satisfy both its planning reserve margin requirement and the statute's
prescribed reliability adequacy metrics, the IURC: (1) may conduct an
investigation into the reasons for the public utility's inability to meet
these requirements; or (2) 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, must conduct such an investigation.
Provides that if, after an investigation, the IURC determines that the
capacity resources available to the public utility will not be adequate
to support the public utility's provision of reliable electric service or 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. Makes a technical change to
another Indiana Code section to recognize the redesignation of
subsections within the section containing these provisions.
2025 IN 1007—LS 7547/DI 1012025 IN 1007—LS 7547/DI 101 Introduced
First Regular Session of the 124th General Assembly (2025)
PRINTING CODE. Amendments: Whenever an existing statute (or a section of the Indiana
Constitution) is being amended, the text of the existing provision will appear in this style type,
additions will appear in this style type, and deletions will appear in this style type.
Additions: Whenever a new statutory provision is being enacted (or a new constitutional
provision adopted), the text of the new provision will appear in this style type. Also, the
word NEW will appear in that style type in the introductory clause of each SECTION that adds
a new provision to the Indiana Code or the Indiana Constitution.
Conflict reconciliation: Text in a statute in this style type or this style type reconciles conflicts
between statutes enacted by the 2024 Regular Session of the General Assembly.
HOUSE BILL No. 1007
A BILL FOR AN ACT to amend the Indiana Code concerning
utilities.
Be it enacted by the General Assembly of the State of Indiana:
1 SECTION 1. IC 6-3.1-45 IS ADDED TO THE INDIANA CODE
2 AS A NEW CHAPTER TO READ AS FOLLOWS [EFFECTIVE
3 JANUARY 1, 2025 (RETROACTIVE)]:
4 Chapter 45. Small Modular Nuclear Reactor Manufacturing
5 Expense Tax Credit
6 Sec. 1. This chapter applies to a taxable year beginning after
7 December 31, 2024.
8 Sec. 2. As used in this chapter, "department" refers to the
9 department of state revenue.
10 Sec. 3. As used in this chapter, "qualified investment" means a
11 taxpayer's expenditures incurred in the manufacture of a small
12 modular nuclear reactor in Indiana.
13 Sec. 4. As used in this chapter, "small modular nuclear reactor"
14 means a nuclear reactor that:
15 (1) has a rated electric generating capacity of not more than
2025 IN 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 ten percent (10%) 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
2025 IN 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 installed 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 8-1-8.2 IS ADDED TO THE INDIANA CODE AS
22 A NEW CHAPTER TO READ AS FOLLOWS [EFFECTIVE UPON
23 PASSAGE]:
24 Chapter 8.2. Expedited Generation Resource Plans and Large
25 Load Customers
26 Sec. 1. As used in this chapter, "acquisition" means a project
27 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 Sec. 2. As used in this chapter, "acquisition costs" means the
32 total costs of an acquisition made under an EGR plan, including:
33 (1) planning;
34 (2) construction; and
35 (3) operating;
36 costs related to the acquisition.
37 Sec. 3. As used in this chapter, "appropriate regional
38 transmission organization" has the meaning set forth in
39 IC 8-1-8.5-13(b).
40 Sec. 4. As used in this chapter, "commission" refers to the
41 Indiana utility regulatory commission created by IC 8-1-1-2.
42 Sec. 5. (a) As used in this chapter, "construction and operating
2025 IN 1007—LS 7547/DI 101 4
1 costs" means costs:
2 (1) incurred or to be incurred by an energy utility under this
3 chapter after the issuance of an order by the commission
4 under this chapter; and
5 (2) related to an approved or commission modified acquisition
6 or project.
7 (b) The term includes procurement, contractual, construction,
8 operating, maintenance, financing, legal, regulatory, and planning
9 costs incurred after the issuance of an order by the commission
10 under this chapter.
11 Sec. 6. As used in this chapter, "corporation" refers to the
12 Indiana economic development corporation established by
13 IC 5-28-3-1 or its successor.
14 Sec. 7. As used in this chapter, "energy utility" means an
15 electric utility listed in 170 IAC 4-7-2(a) and any successor in
16 interest to that utility.
17 Sec. 8. As used in this chapter, "expedited generation resource
18 plan", or "EGR plan", means a plan developed by an energy utility
19 for acquiring generation resources to meet load growth that
20 exceeds the lesser of:
21 (1) five percent (5%) of the energy utility's average peak
22 demand over the most recent three (3) calendar years; or
23 (2) one hundred fifty (150) megawatts.
24 Sec. 9. As used in this chapter, "generation resource submittal"
25 means a compliance filing made to the commission for approval of
26 the acquisition of a specific generation resource in accordance with
27 the criteria set forth in an approved EGR plan.
28 Sec. 10. As used in this chapter, "large load customer" means a
29 new or existing customer of an energy utility, or not more than
30 four (4) multiple new or existing customers of an energy utility,
31 that:
32 (1) requests new or additional electricity demand that in the
33 aggregate exceeds the lesser of:
34 (A) five percent (5%) of the energy utility's average peak
35 demand over the most recent three (3) calendar years; or
36 (B) one hundred fifty (150) megawatts;
37 (2) plans to make a capital investment that exceeds five
38 hundred million dollars ($500,000,000) in a new or expanded
39 facility in Indiana; and
40 (3) plans to employ at the new or expanded facility in Indiana
41 at least fifty (50) full-time employees with wages that on
42 average meet or exceed the most recently published annual
2025 IN 1007—LS 7547/DI 101 5
1 national average according to the Bureau of Labor Statistics
2 of the United States Department of Labor.
3 Sec. 11. As used in this chapter, "office" refers to the Indiana
4 office of energy development established by IC 4-3-23-3.
5 Sec. 12. (a) As used in this chapter, "planning costs" mean costs:
6 (1) incurred or to be incurred by an energy utility before the
7 issuance of an order by the commission under this chapter;
8 and
9 (2) related to an acquisition or project.
10 (b) The term includes study, analysis, pre-engineering,
11 engineering, legal, financing, and regulatory costs.
12 Sec. 13. As used in this chapter, "pre-filing meeting" means a
13 meeting to review and discuss a filing or submittal by an energy
14 utility in accordance with:
15 (1) section 18 of this chapter;
16 (2) section 20 of this chapter; or
17 (3) section 22 of this chapter;
18 as applicable.
19 Sec. 14. As used in this chapter, "project" refers to a project
20 relating to energy infrastructure and generation resources that:
21 (1) are required primarily to serve a large load customer of an
22 energy utility; and
23 (2) may be designed to serve more than one (1) large load
24 customer of the energy utility or to meet other customer
25 demand or energy needs.
26 Sec. 15. As used in this chapter, "project costs" means the total
27 costs of a project, including:
28 (1) planning costs; and
29 (2) construction and operating costs;
30 related to the project.
31 Sec. 16. As used in this chapter, "reasonable risk premium"
32 means compensation:
33 (1) negotiated between an energy utility and a large load
34 customer; and
35 (2) paid by the large load customer.
36 Sec. 17. (a) The commission may expedite, in accordance with
37 this chapter, the review of filings and submittals made by an
38 energy utility to meet the energy infrastructure and generation
39 resource needs of customers. An energy utility may request an
40 expedited review by the commission under either or both of the
41 following:
42 (1) Sections 18 through 21 of this chapter (concerning EGR
2025 IN 1007—LS 7547/DI 101 6
1 plans).
2 (2) Sections 22 through 24 of this chapter (concerning large
3 load customer projects).
4 (b) This chapter does not preclude an energy utility from
5 petitioning the commission under other applicable statutes for
6 approval of a generation resource acquisition to meet the needs of
7 its customers.
8 (c) This chapter does not preclude an energy utility from
9 petitioning the commission under, or in conjunction with, other
10 applicable statutes, including:
11 (1) IC 8-1-2-24;
12 (2) IC 8-1-2-42;
13 (3) IC 8-1-2.5;
14 (4) IC 8-1-8.5;
15 (5) IC 8-1-8.8; or
16 (6) IC 8-1-39;
17 for approval of a project to meet the needs of large load customers.
18 Sec. 18. (a) This section applies to an energy utility that petitions
19 the commission for approval of an EGR plan.
20 (b) An energy utility may file a petition with the commission for
21 approval of an EGR plan to acquire generation resources to meet
22 the extraordinary needs for electricity by the energy utility's
23 customers.
24 (c) In petition under this section, an energy utility must do the
25 following:
26 (1) Describe the energy utility's EGR plan for acquiring
27 generation resources to meet the anticipated extraordinary
28 growth in the load of its customers.
29 (2) Demonstrate a need for generation capacity that exceeds
30 the lesser of:
31 (A) five percent (5%) of the energy utility's average peak
32 demand over the most recent three (3) calendar years; or
33 (B) one hundred fifty (150) megawatts.
34 (3) Provide a load growth forecast for a minimum of five (5)
35 years from the date of the petition.
36 (4) Describe the status of customer contracts and
37 commitments that support the load growth forecast described
38 in subdivision (3).
39 (5) Explain how the EGR plan is consistent with or differs
40 from the energy utility's most recent integrated resource plan.
41 (6) Propose the accounting authority needed from the
42 commission to support the EGR plan.
2025 IN 1007—LS 7547/DI 101 7
1 (7) Propose the manner in which the capital costs and
2 operating and maintenance expenses related to the EGR plan
3 will be included in the energy utility's revenue requirement.
4 (8) Identify the type and amount of capacity and energy:
5 (A) that is included in the EGR plan;
6 (B) that does not exceed seventy-five percent (75%) of the
7 energy utility's peak capacity over the forecast period
8 described in subdivision (3); and
9 (C) with respect to which the energy utility may request
10 expedited approval in a subsequent generation resource
11 submittal.
12 (9) Identify the criteria to be included in a generation
13 resource submittal that must be met for the acquisition to be
14 approved by the commission.
15 (10) Certify that at least thirty (30) days before the filing of
16 the petition the energy utility held a pre-filing meeting with
17 the commission and the office of utility consumer counselor to
18 review the EGR plan.
19 (11) Describe how the energy utility considered implementing
20 grid enhancing technologies to defer or minimize the need for
21 additional investment in generation.
22 (12) Describe how the EGR plan will support the provision of
23 electric utility service with the attributes set forth in
24 IC 8-1-2-0.6, including:
25 (A) reliability;
26 (B) affordability;
27 (C) resiliency;
28 (D) stability; and
29 (E) environmental sustainability.
30 (13) Describe how the EGR plan reasonably protects existing
31 and future customers and is consistent with:
32 (A) the provision of safe, reliable, and affordable electric
33 utility service; and
34 (B) economical rates.
35 (14) Include:
36 (A) verified testimony; and
37 (B) exhibits;
38 supporting the petition and constituting the energy utility's
39 case in chief.
40 (15) Include a proposed order for the petition.
41 Sec. 19. (a) This section applies to an energy utility that petitions
42 the commission for approval of an EGR plan.
2025 IN 1007—LS 7547/DI 101 8
1 (b) Notwithstanding IC 8-1-8.5 or any other statute, the
2 commission may approve an energy utility's EGR plan to
3 construct, purchase, lease, or otherwise acquire generation
4 resources under this chapter for purposes of meeting the needs of
5 the energy utility's customers. The commission shall make its
6 decision based on whether the relief requested is just, reasonable,
7 and in the public interest.
8 (c) The commission may:
9 (1) approve the energy utility's petition in its entirety;
10 (2) deny the energy utility's petition in its entirety; or
11 (3) modify the petition, subject to the energy utility's
12 acceptance of the modification.
13 (d) The commission shall issue a final order on the petition not
14 later than ninety (90) days after receiving the energy utility's
15 complete petition. A petition is considered:
16 (1) complete unless the commission provides a notice of
17 deficiency to the energy utility not later than five (5) business
18 days after the filing of the petition; and
19 (2) approved if the commission does not issue a final order on
20 the petition within the ninety (90) day period set forth in this
21 subsection.
22 Sec. 20. (a) This section applies to an energy utility that submits
23 to the commission for approval a generation resource submittal in
24 accordance with an approved EGR plan.
25 (b) An energy utility may submit a generation resource
26 submittal to the commission for approval of an acquisition that the
27 energy utility intends to make in accordance with an approved
28 EGR plan.
29 (c) In a generation resource submittal under this section, an
30 energy utility must do the following:
31 (1) Describe:
32 (A) the type of technology used in the generation resource
33 to be acquired;
34 (B) the amount of capacity and energy to be acquired;
35 (C) key contractual terms for the acquisition; and
36 (D) the estimated acquisition costs.
37 (2) Demonstrate that the acquisition meets the criteria set
38 forth in the energy utility's approved EGR plan.
39 (3) Explain how the acquisition is consistent with or differs
40 from the energy utility's most recent integrated resource plan.
41 (4) Detail the status of customer contracts and commitments
42 that support the acquisition.
2025 IN 1007—LS 7547/DI 101 9
1 (5) Certify that at least thirty (30) days before the filing of the
2 generation resource submittal the energy utility held a
3 pre-filing meeting with the commission and the office of utility
4 consumer counselor to review the acquisition.
5 (6) Describe how the energy utility considered implementing
6 grid enhancing technologies to defer or minimize the need for
7 additional investment in generation.
8 (7) Describe how the acquisition will support the provision of
9 electric utility service with the attributes set forth in
10 IC 8-1-2-0.6, including:
11 (A) reliability;
12 (B) affordability;
13 (C) resiliency;
14 (D) stability; and
15 (E) environmental sustainability.
16 (8) Describe how the acquisition reasonably protects existing
17 and future customers and is consistent with:
18 (A) the provision of safe, reliable, and affordable electric
19 utility service; and
20 (B) economical rates.
21 (9) Include supporting affidavits and exhibits.
22 Sec. 21. (a) This section applies to an energy utility that submits
23 to the commission for approval a generation resource submittal in
24 accordance with an approved EGR plan.
25 (b) Notwithstanding IC 8-1-8.5 or any other statute, the
26 commission may approve an energy utility's generation resource
27 submittal to construct, purchase, lease, or otherwise acquire
28 generation resources under this chapter for purposes of meeting
29 the needs of the energy utility's customers. The commission shall
30 make its decision based solely on whether the submittal meets the
31 criteria and requirements set forth in the energy utility's approved
32 EGR plan.
33 (c) The commission may:
34 (1) approve the energy utility's generation resource submittal
35 in its entirety;
36 (2) deny the energy utility's generation resource submittal in
37 its entirety; or
38 (3) modify the energy utility's generation resource submittal,
39 subject to the energy utility's acceptance of the modification.
40 (d) The commission shall issue a final order on the energy
41 utility's generation resource submittal not later than:
42 (1) sixty (60) days after receiving the energy utility's complete
2025 IN 1007—LS 7547/DI 101 10
1 generation resource submittal, if the acquisition is a clean
2 energy project (as defined in IC 8-1-8.8-2); or
3 (2) one hundred twenty (120) days after receiving the energy
4 utility's complete generation resource submittal, if the
5 acquisition would otherwise require a certificate under
6 IC 8-1-8.5-2.
7 A generation resource submittal is considered complete unless the
8 commission provides a notice of deficiency to the energy utility not
9 later than five (5) business days after the filing of the generation
10 resource submittal. A generation resource submittal is considered
11 approved if the commission does not issue a final order on the
12 generation resource submittal within the period set forth in
13 subdivision (1) or (2), as applicable.
14 Sec. 22. (a) This section applies to an energy utility that petitions
15 the commission for approval of a project to serve a large load
16 customer.
17 (b) An energy utility may submit to the commission a petition
18 for approval of a project to serve a large load customer only if the
19 following are satisfied:
20 (1) The petition concerns serving the energy needs of a large
21 load customer.
22 (2) The large load customer commits to significant and
23 meaningful financial assurances that must:
24 (A) include reimbursement by the large load customer of
25 at least seventy-five percent (75%) of the project costs
26 reasonably allocable to the large load customer; and
27 (B) afford protections for the energy utility's existing and
28 future customers from project costs reasonably allocable
29 to the large load customer regardless of whether the large
30 load customer ultimately takes service in the anticipated
31 amount and within the anticipated time frame.
32 (3) At least thirty (30) days before the energy utility's
33 submission of the petition to the commission, the energy
34 utility held at least one (1) pre-filing meeting with:
35 (A) the corporation;
36 (B) the office;
37 (C) the office of utility consumer counselor;
38 (D) the appropriate regional transmission organization;
39 and
40 (E) the large load customer;
41 to review the project.
42 (c) An energy utility may petition the commission for approval
2025 IN 1007—LS 7547/DI 101 11
1 of a project to serve:
2 (1) one (1) or more large customers at one (1) or more
3 locations; or
4 (2) not more than four (4) customers whose aggregate demand
5 satisfies the amount set forth in section 10(1) of this chapter.
6 In any case in which more than one (1) large load customer is to be
7 served by a project, a reference in this chapter to one (1) large load
8 customer is a reference to all large load customers to be served by
9 the project, in accordance with IC 1-1-4-1(3).
10 (d) In submitting a petition to the commission under this section,
11 an energy utility must demonstrate that the large load customer
12 and the associated projects meet the requirements of this chapter.
13 Sec. 23. (a) This section applies to an energy utility that petitions
14 the commission for approval of a project to serve a large load
15 customer.
16 (b) In a petition under this section, an energy utility must
17 include, at a minimum, the following:
18 (1) The energy utility's complete case in chief, which must
19 include, at a minimum, the following:
20 (A) An agreement from the large load customer that
21 describes the financial assurances:
22 (i) that afford protections for the energy utility's existing
23 and future customers; and
24 (ii) to which the large load customer has committed
25 regardless of whether the large load customer ultimately
26 takes service in the anticipated amount and within the
27 anticipated time frame.
28 (B) A description of:
29 (i) the demand side management and self-generation
30 options reviewed with the large load customer; and
31 (ii) the investments the large load customer will
32 undertake to reasonably minimize the amount of
33 incremental and other costs incurred by the energy
34 utility.
35 (C) A description of how the energy utility considered
36 implementing grid enhancing technologies to defer or
37 minimize the need for additional investment in generation.
38 (D) A description of how the energy utility may provide for
39 the requisite amount of electricity needed by the large load
40 customer, including the estimated project costs.
41 (E) A description of how the expected project solution will
42 support the provision of electric utility service with the
2025 IN 1007—LS 7547/DI 101 12
1 attributes set forth in IC 8-1-2-0.6, including:
2 (i) reliability;
3 (ii) affordability;
4 (iii) resiliency;
5 (iv) stability; and
6 (v) environmental sustainability.
7 (F) A description of how the expected project solution and
8 its implementation, if approved by the commission,
9 reasonably protects existing and future customers and is
10 consistent with:
11 (i) the provision of safe, reliable, and affordable electric
12 utility service; and
13 (ii) economical rates.
14 (G) A description of the changes that the energy utility will
15 make to the energy utility's:
16 (i) submissions under IC 8-1-8.5; or
17 (ii) filings under IC 8-1-39;
18 or both, that are necessary to update the energy utility's
19 plans under those statutes to incorporate the project.
20 (H) Information concerning each:
21 (i) large load customer; and
22 (ii) economic development project;
23 included in the petition.
24 (I) A letter to the energy utility from the corporation
25 supporting the petition's request.
26 (J) A letter to the energy utility from the office certifying
27 that a pre-filing meeting took place and that at the
28 meeting:
29 (i) the large load customer's proposed project; and
30 (ii) the expected project solution proposed by the energy
31 utility;
32 were adequately discussed.
33 (K) A description of the communications and information
34 sharing that:
35 (i) took place with the appropriate regional transmission
36 organization before the pre-filing meeting described in
37 clause (J); and
38 (ii) concerned the capacity and energy needs of each
39 large load customer included in the petition.
40 (L) A proposed order for the petition.
41 (2) A copy of a notice of filing with:
42 (A) the corporation;
2025 IN 1007—LS 7547/DI 101 13
1 (B) the office;
2 (C) the office of utility consumer counselor; and
3 (D) the appropriate regional transmission organization.
4 A notice that is delivered electronically to the parties set forth
5 in this subdivision satisfies the notice requirement under this
6 subdivision.
7 Sec. 24. (a) This section applies to an energy utility that petitions
8 the commission for approval of a project to serve a large load
9 customer.
10 (b) The commission may approve a petition in whole or in part.
11 The commission shall make its decision based on whether the relief
12 requested is just, reasonable, and in the public interest. The
13 commission shall issue its final order on the petition not later than
14 one hundred fifty (150) days after receiving the energy utility's
15 complete petition and case in chief. A petition is considered:
16 (1) complete unless the commission provides a notice of
17 deficiency to the energy utility not later than seven (7)
18 business days after the filing of the petition; and
19 (2) approved if the commission does not issue a final order on
20 the petition within the one hundred (150) day period set forth
21 in this subsection.
22 (c) If an energy utility files a petition that includes one (1) or
23 more large load customers and one (1) or more proposed projects,
24 the commission may:
25 (1) approve the energy utility's petition in its entirety;
26 (2) deny the energy utility's petition in its entirety; or
27 (3) modify the petition, subject to the energy utility's
28 acceptance of the modification.
29 (d) The commission may approve a reasonable risk premium for
30 a project if requested in an energy utility's petition and if the
31 commission finds that the reasonable risk premium is appropriate.
32 If the commission approves a reasonable risk premium:
33 (1) the large load customer is responsible for the amount of
34 the reasonable risk premium; and
35 (2) the reasonable risk premium may not be:
36 (A) included in the energy utility's:
37 (i) revenue requirement;
38 (ii) authorized net operating income; or
39 (iii) calculations under IC 8-1-2-42(d)(3) or
40 IC 8-1-2-42(g)(3)(C); or
41 (B) otherwise considered for purposes of setting the
42 authorized return in any future general rate case or other
2025 IN 1007—LS 7547/DI 101 14
1 regulatory proceeding involving the energy utility.
2 (e) The commission may approve an energy utility's request to
3 construct, purchase, lease, or otherwise acquire an energy
4 generation resource under this chapter (notwithstanding and
5 instead of under IC 8-1-2.5, IC 8-1-8.5, or IC 8-1-8.8) for the
6 purpose of serving one (1) or more large load customers. In
7 approving an energy utility's request under this chapter to acquire
8 an energy generation resource to serve one (1) or more large load
9 customers, the commission must find that:
10 (1) the information provided by the energy utility under
11 section 23 of this chapter is complete;
12 (2) reasonable and demonstrable consideration was given to
13 non-generation alternatives by the parties involved;
14 (3) existing and future customers of the energy utility will be
15 adequately protected if the request is granted; and
16 (4) the energy utility has considered the impact of the request
17 on the energy utility's preferred resource portfolio in the
18 energy utility's most recent integrated resource plan.
19 (f) An energy utility shall promptly notify the commission if,
20 after the commission has approved a petition under subsection (e),
21 one (1) or more of the large load customers with respect to whom
22 the petition was approved:
23 (1) no longer requires service from the energy utility or
24 materially alters or terminates the large load customer's
25 service requirements; and
26 (2) the project is incomplete.
27 (g) The commission may, not later than sixty (60) days after
28 receiving a notice under subsection (f), conduct an investigation
29 under IC 8-1-2-58 through IC 8-1-2-60 to determine whether the
30 public interest would still be served by completion of the project.
31 An investigation under this subsection does not preclude the energy
32 utility from continuing construction of the project to serve the
33 large load customer or from continuing to serve the large load
34 customer. If the commission finds that completion of the project is
35 no longer in the public interest, the commission may modify or
36 revoke the order approving the petition.
37 Sec. 25. (a) The commission shall review an energy utility's:
38 (1) estimated acquisition costs submitted under section
39 20(c)(1)(D) of this chapter; or
40 (2) estimated project costs filed under section 23(b)(1)(D) of
41 this chapter;
42 as applicable.
2025 IN 1007—LS 7547/DI 101 15
1 (b) If the commission approves, with or without modification, an
2 energy utility's generation resource submittal or petition for
3 approval of a project, the energy utility may recover:
4 (1) acquisition costs; or
5 (2) project costs;
6 as applicable, that have been reviewed and found reasonable by the
7 commission, with a return at the energy utility's weighted average
8 cost of capital.
9 (c) If the commission denies an energy utility's generation
10 resource submittal or petition for approval of a project, the energy
11 utility may recover planning costs that have been reviewed and
12 found reasonable by the commission, without a return.
13 (d) Absent fraud, concealment, or gross mismanagement, an
14 energy utility may recover:
15 (1) acquisition costs; or
16 (2) project costs;
17 as applicable, with a return at the energy utility's weighted average
18 cost of capital, that the energy utility has incurred or contractually
19 will incur in reliance on a commission order issued under this
20 chapter.
21 Sec. 26. (a) Upon request by an energy utility, the commission
22 shall determine whether the information and related materials
23 filed or submitted, or to be filed or submitted, by an energy utility
24 under this chapter:
25 (1) are confidential under IC 5-14-3-4 or are trade secrets
26 under IC 24-2-3;
27 (2) are exempt from public access and disclosure by Indiana
28 law; and
29 (3) must be treated as confidential and protected from public
30 access and disclosure by the commission.
31 (b) The parties to a pre-filing meeting under this chapter shall
32 execute a nondisclosure agreement to review or discuss
33 information or materials considered confidential under IC 5-14-3-4
34 or to be trade secrets under IC 24-2-3.
35 (c) If the corporation determines that any potential economic
36 development project or any potential investment in a new or
37 expanded facility in Indiana will result in one (1) or more new
38 large load customers that will require electricity from an energy
39 utility, the corporation shall notify the affected energy utility not
40 later than fifteen (15) days after making the determination. Upon
41 the corporation's provision of the notice required by this
42 subsection, any subsequent:
2025 IN 1007—LS 7547/DI 101 16
1 (1) meeting;
2 (2) pre-filing meeting;
3 (3) communications; or
4 (4) information sharing;
5 involving the corporation, the affected energy utility, or one (1) or
6 more potential new large load customers may be subject to a
7 nondisclosure agreement with respect to information or materials
8 considered confidential under IC 5-14-3-4 or to be trade secrets
9 under IC 24-2-3.
10 (d) An energy utility may request, and the commission may
11 approve, financial incentives under IC 8-1-8.8-11(a) for:
12 (1) an acquisition; or
13 (2) a project;
14 that qualifies as a clean energy project (as defined in IC 8-1-8.8-2).
15 (e) An energy utility may request that review of an arrangement
16 under IC 8-1-2-42 and any related rates and charges under
17 IC 8-1-2-43 that are:
18 (1) submitted with a generation resource submittal; or
19 (2) filed with a petition for a project;
20 under this chapter be reviewed and approved or denied by the
21 commission not later than ninety (90) dates after the date of
22 submittal or filing, as applicable.
23 (f) Notwithstanding IC 8-1-8.5 or any other applicable statute,
24 an energy utility may begin construction of an acquisition or a
25 project before filing a petition or submittal under this chapter.
26 (g) The commission may require an energy utility to file with the
27 commission progress reports and updates with respect to an
28 acquisition or project under this chapter. Any required progress
29 reports or updates under this subsection shall be made in a form
30 and at a frequency that the commission determines to be
31 reasonable.
32 SECTION 3. IC 8-1-8.5-2.1, AS AMENDED BY THE
33 TECHNICAL CORRECTIONS BILL OF THE 2025 GENERAL
34 ASSEMBLY, IS AMENDED TO READ AS FOLLOWS [EFFECTIVE
35 JULY 1, 2025]: Sec. 2.1. (a) This section does not apply to the
36 retirement, sale, or transfer of:
37 (1) a public utility's electric generation facility if the retirement,
38 sale, or transfer is necessary in order for the public utility to
39 comply with a federal consent decree; or
40 (2) an electric generation facility that generates electricity for sale
41 exclusively to the wholesale market.
42 (b) A public utility shall notify the commission if:
2025 IN 1007—LS 7547/DI 101 17
1 (1) the public utility intends or decides to retire, sell, or transfer
2 an electric generation facility with a capacity of at least eighty
3 (80) megawatts; and
4 (2) the retirement, sale, or transfer:
5 (A) was not set forth in; or
6 (B) is to take place on a date earlier than the date specified in;
7 the public utility's short term action plan in the public utility's
8 most recently filed integrated resource plan.
9 (c) Upon receiving notice from a public utility under subsection (b),
10 the commission shall consider and may investigate, under IC 8-1-2-58
11 through IC 8-1-2-60, the public utility's intention or decision to retire,
12 sell, or transfer the electric generation facility. In considering the public
13 utility's intention or decision under this subsection, the commission
14 shall examine the impact the retirement, sale, or transfer would have on
15 the public utility's ability to meet:
16 (1) the public utility's planning reserve margin requirements or
17 other federal reliability requirements that the public utility is
18 obligated to meet, as described in section 13(i)(4) 13(n)(6) of this
19 chapter; and
20 (2) the reliability adequacy metrics set forth in section 13(e) 13(h)
21 of this chapter.
22 (d) Before July 1, 2026, if:
23 (1) a public utility intends or decides to retire, sell, or transfer an
24 electric generation facility with a capacity of at least eighty (80)
25 megawatts; and
26 (2) the retirement, sale, or transfer:
27 (A) was not set forth in; or
28 (B) is to take place on a date earlier than the date specified in;
29 the public utility's short term action plan in the public utility's
30 most recently filed integrated resource plan;
31 the commission shall not permit the public utility's depreciation rates,
32 as established under IC 8-1-2-19, to be amended to reflect the
33 accelerated date for the retirement, sale, or transfer of the electric
34 generation asset unless the commission finds that such an adjustment
35 is necessary to ensure the ability of the public utility to provide reliable
36 service to its customers, and that the unamended depreciation rates
37 would cause an unjust and unreasonable impact on the public utility
38 and its ratepayers.
39 (e) The commission may issue a general administrative order to
40 implement this section.
41 (f) This section expires July 1, 2026.
42 SECTION 4. IC 8-1-8.5-12.1, AS AMENDED BY P.L.93-2024,
2025 IN 1007—LS 7547/DI 101 18
1 SECTION 67, IS AMENDED TO READ AS FOLLOWS [EFFECTIVE
2 JULY 1, 2025]: Sec. 12.1. (a) As used in this section, "project
3 development costs" means costs that have been incurred, or are
4 reasonably estimated to be incurred, in the development of one (1)
5 or more small modular nuclear reactors, including:
6 (1) evaluation, design, and engineering costs;
7 (2) costs for federal approvals and licensing;
8 (3) costs for environmental analyses and permitting;
9 (4) early site permit (as defined in 10 CFR 52.1) costs;
10 (5) equipment procurement costs; and
11 (6) authorized carrying costs.
12 (a) (b) As used in this section, "small modular nuclear reactor"
13 means a nuclear reactor that:
14 (1) has a rated electric generating capacity of not more than four
15 hundred seventy (470) megawatts;
16 (2) is capable of being constructed and operated, either:
17 (A) alone; or
18 (B) in combination with one (1) or more similar reactors if
19 additional reactors are, or become, necessary;
20 at a single site; and
21 (3) is required to be licensed by the United States Nuclear
22 Regulatory Commission.
23 The term includes a nuclear reactor that is described in this subsection
24 and that uses a process to produce hydrogen that can be used for energy
25 storage, as a fuel, or for other uses.
26 (b) (c) Not later than July 1, 2023, the commission, in consultation
27 with the department of environmental management, shall adopt rules
28 under IC 4-22-2 concerning the granting of certificates under this
29 chapter for the construction, purchase, or lease of small modular
30 nuclear reactors:
31 (1) in Indiana for the generation of electricity to be directly or
32 indirectly used to furnish public utility service to Indiana
33 customers; or
34 (2) at the site of a nuclear energy production or generating facility
35 that supplies electricity to Indiana retail customers on July 1,
36 2011.
37 (c) (d) Rules adopted by the commission under this section must
38 provide for the following:
39 (1) That in acting on a public utility's petition for the construction,
40 purchase, or lease of one (1) or more small modular nuclear
41 reactors, as described in subsection (b), (c), the commission shall
42 consider the following:
2025 IN 1007—LS 7547/DI 101 19
1 (A) Whether, and to what extent, the one (1) or more small
2 modular nuclear reactors proposed by the public utility will
3 replace a loss of generating capacity in the public utility's
4 portfolio resulting from the retirement or planned retirement
5 of one (1) or more of the public utility's existing electric
6 generating facilities that:
7 (i) are located in Indiana; and
8 (ii) use coal or natural gas as a fuel source.
9 (B) Whether one (1) or more of the small modular nuclear
10 reactors that will replace an existing facility will be located on
11 the same site as or near the existing facility and, if so, potential
12 opportunities for the public utility to:
13 (i) make use of any land and existing infrastructure or
14 facilities already owned or under the control of the public
15 utility; or
16 (ii) create new employment opportunities for workers who
17 have been, or would be, displaced as a result of the
18 retirement of the existing facility.
19 (2) That the commission may grant a certificate under this chapter
20 under circumstances and for locations other than those described
21 in subdivision (1).
22 (3) That the commission may not grant a certificate under this
23 chapter unless the owner or operator of a proposed small modular
24 nuclear reactor provides evidence of a plan to apply for all
25 licenses or permits to construct or operate the proposed small
26 modular nuclear reactor as may be required by:
27 (A) the United States Nuclear Regulatory Commission;
28 (B) the department of environmental management; or
29 (C) any other relevant state or federal regulatory agency with
30 jurisdiction over the construction or operation of nuclear
31 generating facilities.
32 (4) That any:
33 (A) reports;
34 (B) notices of violations; or
35 (C) other notifications;
36 sent to or from the United States Nuclear Regulatory Commission
37 by or to the owner or operator of a proposed small nuclear reactor
38 must be submitted by the owner or operator to the commission
39 within such times as prescribed by the commission, subject to the
40 commission's duty to treat as confidential and protect from public
41 access and disclosure any information that is contained in a report
42 or notice and that is considered confidential or exempt from
2025 IN 1007—LS 7547/DI 101 20
1 public access and disclosure under state or federal law.
2 (5) That any person that owns or operates a small modular nuclear
3 reactor in Indiana may not store:
4 (A) spent nuclear fuel (as defined in IC 13-11-2-216); or
5 (B) high level radioactive waste (as defined in
6 IC 13-11-2-102);
7 from the small modular nuclear reactor on the site of the small
8 modular nuclear reactor without first meeting all applicable
9 requirements of the United States Nuclear Regulatory
10 Commission.
11 (d) In adopting the rules required by this section, the commission
12 may adopt rules under IC 4-22-2.
13 (e) A public utility may petition the commission for approval to
14 incur, before obtaining a certificate under this chapter, project
15 development costs for the development of one (1) or more small
16 modular nuclear reactors. The public utility must file with the
17 petition the public utility's case in chief, which must contain the
18 information and supporting documentation regarding the factors
19 the commission must consider under this subsection. In reviewing
20 a petition and the supporting case in chief under this subsection,
21 the commission shall consider the following:
22 (1) Whether a project by the utility to construct, purchase, or
23 lease a small modular nuclear reactor is reasonably consistent
24 with:
25 (A) this section and rules adopted by the commission under
26 this section; and
27 (B) the purposes set forth in IC 8-1-8.8-1(b), as applicable.
28 (2) The following factors with respect to the project
29 development costs and the project for which they are to be
30 incurred:
31 (A) The amount of project development costs the public
32 utility anticipates incurring.
33 (B) The anticipated timeline for incurring the project
34 development costs.
35 (C) The anticipated date by which the public utility will
36 make a decision as to whether to seek a certificate under
37 this chapter.
38 The commission shall review a petition submitted under this
39 subsection and issue a final order approving or denying the petition
40 not later than one hundred eighty (180) days after receiving the
41 petition and complete case in chief. However, if the commission
42 makes a docket entry extending the procedural schedule and the
2025 IN 1007—LS 7547/DI 101 21
1 public utility does not object to the entered extension, the
2 commission may extend the one hundred eighty (180) day time
3 frame for issuing a final order under this subsection for the
4 amount of time set forth in the docket entry. In an order approving
5 a petition, the commission must make a finding as to the best
6 estimate and reasonableness of project development costs based on
7 the evidence of record.
8 (f) If a public utility has received approval from the commission
9 under subsection (e) to incur project development costs, the public
10 utility may petition the commission at any time before or during
11 the development and execution of a small modular nuclear reactor
12 project for the approval of a rate schedule that periodically adjusts
13 the public utility's rates and charges to provide for the timely
14 recovery of project development costs. A petition under this
15 subsection must describe any efforts by the public utility to pursue
16 funding opportunities from the United States Department of
17 Energy to offset the project development costs that the public
18 utility seeks to recover under the proposed rate schedule.
19 (g) If, after reviewing a public utility's proposed rate schedule
20 in a petition submitted under subsection (f), the commission
21 determines that the public utility has incurred or will incur project
22 development costs that are:
23 (1) reasonable in amount;
24 (2) necessary to support the construction, purchase, or lease
25 of a small modular nuclear reactor; and
26 (3) consistent with the commission's finding as to the best
27 estimate of project development costs in the commission's
28 order of approval under subsection (e);
29 the commission shall approve the recovery of the project
30 development costs, subject to subsections (h) and (i). However, a
31 public utility may not file adjustments to a rate schedule to adjust
32 for cost recovery approved under this subsection more than one (1)
33 time every twelve (12) months.
34 (h) A public utility that recovers project development costs
35 under subsection (g) shall recover eighty percent (80%) of the
36 approved project development costs under the rate schedule
37 approved under subsection (g) and shall defer the remaining
38 twenty percent (20%) of approved project development costs,
39 including, to the extent applicable, depreciation, allowance for
40 funds used during construction, and post in service carrying costs,
41 based on the overall cost of capital most recently approved by the
42 commission, and shall recover those project development costs as
2025 IN 1007—LS 7547/DI 101 22
1 part of the next general rate case that the public utility files with
2 the commission. Actual project development costs that are
3 incurred by a public utility and that exceed the public utility's
4 approved project development costs may not be included in rates
5 unless shown by the public utility to be necessary and prudent in
6 supporting the construction, purchase, or lease of the small
7 modular nuclear reactor for which they were incurred, and unless
8 approved by the commission.
9 (i) The recovery of a public utility's project development costs
10 through a periodic rate adjustment mechanism approved by the
11 commission under subsection (g) must occur over a period that is
12 equal to:
13 (1) the period over which the approved project development
14 costs are incurred; or
15 (2) three (3) years;
16 whichever is less.
17 (j) Reasonable and necessary project development costs that are
18 consistent with the commission's finding as to the best estimate of
19 project development costs in the commission's order of approval
20 under subsection (e) shall be recovered by a public utility by
21 inclusion in the public utility's rates and charges regardless of
22 whether:
23 (1) a certificate is issued under this chapter with respect to the
24 small modular nuclear reactor for which the project
25 development costs are incurred; or
26 (2) the project is canceled or completed.
27 If a public utility does not seek approval of, or cost recovery for,
28 project development costs under subsections (e) through (i), the
29 commission may approve the deferral and amortization of project
30 development costs in accordance with the procedures set forth in
31 section 6.5 of this chapter with respect to construction costs.
32 (k) The commission may adopt rules under IC 4-22-2 to
33 implement subsections (e) through (j).
34 (e) (l) This section shall not be construed to affect the authority of
35 the United States Nuclear Regulatory Commission.
36 SECTION 5. IC 8-1-8.5-13, AS AMENDED BY P.L.93-2024,
37 SECTION 68, IS AMENDED TO READ AS FOLLOWS [EFFECTIVE
38 JULY 1, 2025]: Sec. 13. (a) The general assembly finds that it is in the
39 public interest to support the reliability, availability, and diversity of
40 electric generating capacity in Indiana for the purpose of providing
41 reliable and stable electric service to customers of public utilities.
42 (b) As used in this section, "appropriate regional transmission
2025 IN 1007—LS 7547/DI 101 23
1 organization", with respect to a public utility, refers to the regional
2 transmission organization approved by the Federal Energy Regulatory
3 Commission for the control area that includes the public utility's
4 assigned service area (as defined in IC 8-1-2.3-2).
5 (c) As used in this section, "capacity market" means an auction
6 conducted by an appropriate regional transmission organization to
7 determine a market clearing price for capacity based on the planning
8 reserve margin requirements established by the appropriate regional
9 transmission organization for a planning year with respect to which an
10 auction has not yet been conducted.
11 (d) As used in this section, "fall unforced capacity", or "fall UCAP",
12 with respect to an electric generating facility, means:
13 (1) the capacity value of the electric generating facility's installed
14 capacity rate adjusted for the electric generating facility's average
15 forced outage rate for the fall period, calculated as required by the
16 appropriate regional transmission organization or by the Federal
17 Energy Regulatory Commission;
18 (2) a metric that is similar to the metric described in subdivision
19 (1) and that is required by the appropriate regional transmission
20 organization; or
21 (3) if the appropriate regional transmission organization does not
22 require a metric described in subdivision (1) or (2), a metric that:
23 (A) can be used to demonstrate that a public utility has
24 sufficient capacity to:
25 (i) provide reliable electric service to Indiana customers for
26 the fall period; and
27 (ii) meet its planning reserve margin requirement and other
28 federal reliability requirements described in subsection
29 (l)(4); (n)(6); and
30 (B) is acceptable to the commission.
31 (e) As used in this section, "MISO" refers to the regional
32 transmission organization known as the Midcontinent Independent
33 System Operator that operates the bulk power transmission system
34 serving most of the geographic territory in Indiana.
35 (f) As used in this section, "planning reserve margin requirement",
36 with respect to a public utility for a particular resource planning year,
37 means the planning reserve margin requirement for that planning year
38 that the public utility is obligated to meet in accordance with the public
39 utility's membership in the appropriate regional transmission
40 organization.
41 (g) As used in this section, "refuel" or "refueling" means a
42 planned fuel conversion from one fuel source to another fuel source
2025 IN 1007—LS 7547/DI 101 24
1 with respect to an electric generation resource of at least one
2 hundred (100) megawatts by a public utility.
3 (g) (h) As used in this section, "reliability adequacy metrics", with
4 respect to a public utility, means calculations used to demonstrate all
5 of the following:
6 (1) Subject to subsection (q)(2)(B), (u)(2)(B), that the public
7 utility:
8 (A) has in place sufficient summer UCAP; or
9 (B) can reasonably acquire not more than:
10 (i) thirty percent (30%) of its total summer UCAP from
11 capacity markets, with respect to a report filed with the
12 commission under subsection (l) (n) before July 1, 2023; or
13 (ii) fifteen percent (15%) of its total summer UCAP from
14 capacity markets, with respect to a report filed with the
15 commission under subsection (l) (n) after June 30, 2023;
16 such that it will have sufficient summer UCAP;
17 to provide reliable electric service to Indiana customers, and to
18 meet its planning reserve margin requirement and other federal
19 reliability requirements described in subsection (l)(4). (n)(6).
20 (2) Subject to subsection (q)(2)(B), (u)(2)(B), that the public
21 utility:
22 (A) has in place sufficient winter UCAP; or
23 (B) can reasonably acquire not more than:
24 (i) thirty percent (30%) of its total winter UCAP from
25 capacity markets, with respect to a report filed with the
26 commission under subsection (l) (n) before July 1, 2023; or
27 (ii) fifteen percent (15%) of its total winter UCAP from
28 capacity markets, with respect to a report filed with the
29 commission under subsection (l) (n) after June 30, 2023;
30 such that it will have sufficient winter UCAP;
31 to provide reliable electric service to Indiana customers, and to
32 meet its planning reserve margin requirement and other federal
33 reliability requirements described in subsection (l)(4). (n)(6).
34 (3) Subject to subsection (q)(2)(B), (u)(2)(B), with respect to a
35 report filed with the commission under subsection (l) (n) after
36 June 30, 2026, that the public utility:
37 (A) has in place sufficient spring UCAP; or
38 (B) can reasonably acquire not more than fifteen percent
39 (15%) of its total spring UCAP from capacity markets, such
40 that it will have sufficient spring UCAP;
41 to provide reliable electric service to Indiana customers, and to
42 meet its planning reserve margin requirement and other federal
2025 IN 1007—LS 7547/DI 101 25
1 reliability requirements described in subsection (l)(4). (n)(6).
2 (4) Subject to subsection (q)(2)(B), (u)(2)(B), with respect to a
3 report filed with the commission under subsection (l) (n) after
4 June 30, 2026, that the public utility:
5 (A) has in place sufficient fall UCAP; or
6 (B) can reasonably acquire not more than fifteen percent
7 (15%) of its total fall UCAP from capacity markets, such that
8 it will have sufficient fall UCAP;
9 to provide reliable electric service to Indiana customers, and to
10 meet its planning reserve margin requirement and other federal
11 reliability requirements described in subsection (l)(4). (n)(6).
12 (i) As used in this section, "retire" or retirement" means a
13 planned permanent ceasing of electric generation operations with
14 respect to an electric generation resource of at least one hundred
15 (100) megawatts by a public utility.
16 (h) (j) As used in this section, "spring unforced capacity", or "spring
17 UCAP", with respect to an electric generating facility, means:
18 (1) the capacity value of the electric generating facility's installed
19 capacity rate adjusted for the electric generating facility's average
20 forced outage rate for the spring period, calculated as required by
21 the appropriate regional transmission organization or by the
22 Federal Energy Regulatory Commission;
23 (2) a metric that is similar to the metric described in subdivision
24 (1) and that is required by the appropriate regional transmission
25 organization; or
26 (3) if the appropriate regional transmission organization does not
27 require a metric described in subdivision (1) or (2), a metric that:
28 (A) can be used to demonstrate that a public utility has
29 sufficient capacity to:
30 (i) provide reliable electric service to Indiana customers for
31 the spring period; and
32 (ii) meet its planning reserve margin requirement and other
33 federal reliability requirements described in subsection
34 (l)(4); (n)(6); and
35 (B) is acceptable to the commission.
36 (i) (k) As used in this section, "summer unforced capacity", or
37 "summer UCAP", with respect to an electric generating facility, means:
38 (1) the capacity value of the electric generating facility's installed
39 capacity rate adjusted for the electric generating facility's average
40 forced outage rate for the summer period, calculated as required
41 by the appropriate regional transmission organization or by the
42 Federal Energy Regulatory Commission; or
2025 IN 1007—LS 7547/DI 101 26
1 (2) a metric that is similar to the metric described in subdivision
2 (1) and that is required by the appropriate regional transmission
3 organization.
4 (j) (l) As used in this section, "winter unforced capacity", or "winter
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 winter 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 winter 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 (k) (m) A public utility that owns and operates an electric
25 generating facility serving customers in Indiana shall operate and
26 maintain the facility using good utility practices and in a manner:
27 (1) reasonably intended to support the provision of reliable and
28 economic electric service to customers of the public utility; and
29 (2) reasonably consistent with the resource reliability
30 requirements of MISO or any other appropriate regional
31 transmission organization; and
32 (3) reasonably maximizes the economic value of the electric
33 generating facility.
34 (l) (n) Not later than thirty (30) days after the deadline for
35 submitting an annual planning reserve margin report to MISO, each
36 public utility providing electric service to Indiana customers shall,
37 regardless of whether the public utility is required to submit an annual
38 planning reserve margin report to MISO, file with the commission a
39 report, in a form specified by the commission, that provides the
40 following information for each of the next three (3) resource planning
41 years, beginning with the planning year covered by the planning
42 reserve margin report to MISO described in this subsection:
2025 IN 1007—LS 7547/DI 101 27
1 (1) The:
2 (A) capacity;
3 (B) location; and
4 (C) fuel source;
5 for each electric generating facility that is owned and operated by
6 the electric utility and that will be used to provide electric service
7 to Indiana customers.
8 (2) With respect to a report submitted to the commission after
9 December 31, 2025, the amount of generating resource
10 capacity or energy, or both, that the public utility plans to
11 retire, including the:
12 (A) capacity;
13 (B) location;
14 (C) fuel source; and
15 (D) planned retirement date;
16 for each electric generating facility that the public utility
17 plans to retire. The public utility must provide its economic
18 rationale for the planned retirement, including anticipated
19 ratepayer impacts, and information concerning the public
20 utility's plan or plans with respect to the amount of
21 replacement capacity identified to provide approximately the
22 same credit capacity within the appropriate regional
23 transmission organization as the amount of capacity of the
24 facility to be retired.
25 (3) With respect to a report submitted to the commission after
26 December 31, 2025, the amount of generating resource
27 capacity or energy, or both, that the public utility plans to
28 refuel, including the:
29 (A) capacity;
30 (B) location;
31 (C) existing fuel source;
32 (D) proposed fuel source; and
33 (E) planned completion date of the refueling;
34 with respect to each electric generating facility that the public
35 utility plans to refuel. The public utility must provide its
36 economic rationale for the planned refueling, including
37 anticipated ratepayer impacts, and information concerning
38 the public utility's plan or plans with respect to the extent to
39 which the refueling will maintain or increase the current
40 generating resource capacity or energy, or both, that the
41 electric generating facility provides.
42 (2) (4) The amount of generating resource capacity or energy, or
2025 IN 1007—LS 7547/DI 101 28
1 both, that the public utility has procured under contract and that
2 will be used to provide electric service to Indiana customers,
3 including the:
4 (A) capacity;
5 (B) location; and
6 (C) fuel source;
7 for each electric generating facility that will supply capacity or
8 energy under the contract, to the extent known by the public
9 utility.
10 (3) (5) The amount of demand response resources available to the
11 public utility under contracts and tariffs.
12 (4) (6) The following:
13 (A) The planning reserve margin requirements established by
14 MISO for the planning years covered by the report, to the
15 extent known by the public utility with respect to any
16 particular planning year covered by the report.
17 (B) If applicable, any other planning reserve margin
18 requirement that:
19 (i) applies to the planning years covered by the report; and
20 (ii) the public utility is obligated to meet in accordance with
21 the public utility's membership in an appropriate regional
22 transmission organization;
23 to the extent known by the public utility with respect to any
24 particular planning year covered by the report.
25 (C) Other federal reliability requirements that the public utility
26 is obligated to meet in accordance with its membership in an
27 appropriate regional transmission organization with respect to
28 the planning years covered by the report, to the extent known
29 by the public utility with respect to any particular planning
30 year covered by the report.
31 For each planning reserve margin requirement reported under
32 clause (A) or (B), the public utility shall include a comparison of
33 that planning reserve margin requirement to the planning reserve
34 margin requirement established by the same regional transmission
35 organization for the 2021-2022 planning year.
36 (5) (7) The reliability adequacy metrics of the public utility, as
37 forecasted for the three (3) planning years covered by the report.
38 (m) (o) Upon request by a public utility, the commission shall
39 determine whether information provided in a report filed by the public
40 utility under subsection (l): (n):
41 (1) is confidential under IC 5-14-3-4 or is a trade secret under
42 IC 24-2-3;
2025 IN 1007—LS 7547/DI 101 29
1 (2) is exempt from public access and disclosure by Indiana law;
2 and
3 (3) shall be treated as confidential and protected from public
4 access and disclosure by the commission.
5 (n) (p) A joint agency created under IC 8-1-2.2 may file the report
6 required under subsection (l) (n) as a consolidated report on behalf of
7 any or all of the municipally owned utilities that make up its
8 membership.
9 (o) (q) A:
10 (1) corporation organized under IC 23-17 that is an electric
11 cooperative and that has at least one (1) member that is a
12 corporation organized under IC 8-1-13; or
13 (2) general district corporation within the meaning of
14 IC 8-1-13-23;
15 may file the report required under subsection (l) (n) as a consolidated
16 report on behalf of any or all of the cooperatively owned electric
17 utilities that it serves.
18 (p) (r) In reviewing a report filed by a public utility under
19 subsection (l), (n), the commission may request technical assistance
20 from MISO or any other appropriate regional transmission organization
21 in determining:
22 (1) the planning reserve margin requirements or other federal
23 reliability requirements that the public utility is obligated to meet,
24 as described in subsection (l)(4); (n)(6); and
25 (2) whether the resources available to the public utility under
26 subsections (l)(1) (n)(1) through (l)(3) (n)(5) will be adequate to
27 support the provision of reliable electric service to the public
28 utility's Indiana customers.
29 (s) Commission staff shall review the reports submitted by
30 public utilities under subsection (n) and shall, not later than ninety
31 (90) days after the date of submission of the reports, submit to the
32 commission a staff report concerning any planned retirements
33 included in the reports under subsection (n)(2). The report must
34 make recommendations to the commission based on whether each
35 planned retirement:
36 (1) is consistent with the standards set forth in subsection (m);
37 (2) will be replaced with an amount of replacement capacity
38 that will provide approximately the same capacity credit
39 within the appropriate regional transmission organization as
40 the amount of capacity of the facility to be retired;
41 (3) will not adversely and unreasonably impact a public
42 utility's ability to provide safe, reliable, and economical
2025 IN 1007—LS 7547/DI 101 30
1 electric utility service to the public utility's customers; and
2 (4) will result in the provision to Indiana customers of electric
3 utility service with the attributes of:
4 (A) reliability;
5 (B) affordability;
6 (C) resiliency;
7 (D) stability; and
8 (E) environmental sustainability;
9 as set forth in IC 8-1-2-0.6.
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:
20 (1) provide reliable electric service to the public utility's Indiana
21 customers; or
22 (2) either:
23 (A) satisfy both:
24 (i) its planning reserve margin requirement or other federal
25 reliability requirements that the public utility is obligated to
26 meet, as described in subsection (l)(4); (n)(6); and
27 (ii) the reliability adequacy metrics set forth in subsection
28 (g); (h); or
29 (B) provide sufficient reason as to why the public utility is
30 unable to satisfy both:
31 (i) its planning reserve margin requirement or other federal
32 reliability requirements that the public utility is obligated to
33 meet, as described in subsection (l)(4); (n)(6); and
34 (ii) 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 conduct an investigation under IC 8-1-2-58 through
38 IC 8-1-2-60 as to the reasons for the public utility's potential inability
39 to meet the requirements described in subdivision (1) or (2), or both.
40 However, if the public utility has indicated in its report under
41 subsection (n) that it plans to retire an electric generating facility
42 within one (1) year of the date of the report, the commission must
2025 IN 1007—LS 7547/DI 101 31
1 conduct an investigation under IC 8-1-2-58 through IC 8-1-2-60 as
2 to the reasons for the public utility's potential inability to meet the
3 requirements described in subdivision (1) or (2), or both.
4 (r) (v) If, upon investigation under IC 8-1-2-58 through IC 8-1-2-60,
5 and after notice and hearing, as required by IC 8-1-2-59, the
6 commission determines that the capacity resources available to the
7 public utility under subsections (l)(1) (n)(1) through (l)(3) (n)(5) will
8 not be adequate to support the provision of reliable electric service to
9 the public utility's Indiana customers, or to allow the public utility to
10 satisfy both its planning reserve margin requirements or other federal
11 reliability requirements that the public utility is obligated to meet (as
12 described in subsection (l)(4)) (n)(6)) and the reliability adequacy
13 metrics set forth in subsection (g), (h), the commission shall issue an
14 order:
15 (1) directing the public utility to acquire or construct; or
16 (2) prohibiting the retirement or refueling of;
17 such capacity resources that are reasonable and necessary to enable the
18 public utility to provide reliable electric service to its Indiana
19 customers, and to satisfy both its planning reserve margin requirements
20 or other federal reliability requirements described in subsection (l)(4)
21 (n)(6) and the reliability adequacy metrics set forth in subsection (g).
22 (h). Not later than ninety (90) days after the date of the commission's
23 order under this subsection, the public utility shall file for approval
24 with the commission a plan to comply with the commission's order.
25 Notwithstanding IC 8-1-3 or any other law, any appeal of an order
26 by the commission under this subsection is entitled to priority
27 review and shall be given expedited consideration in accordance
28 with Rule 21 of the Indiana Rules of Appellate Procedure.
29 The (w) A public utility's plan under subsection (v) may include:
30 (1) a request for a certificate of public convenience and necessity
31 under this chapter; or
32 (2) an application under IC 8-1-8.8;
33 or both.
34 (s) (x) Beginning in 2022, the commission shall include in its annual
35 report under IC 8-1-1-14 the following information:
36 (1) The commission's analysis regarding the ability of public
37 utilities to:
38 (A) provide reliable electric service to Indiana customers; and
39 (B) satisfy both:
40 (i) their planning reserve margin requirements or other
41 federal reliability requirements; and
42 (ii) the reliability adequacy metrics set forth in subsection
2025 IN 1007—LS 7547/DI 101 32
1 (g); (h);
2 for the next three (3) utility resource planning years, based on the
3 most recent reports filed by public utilities under subsection (l).
4 (n).
5 (2) A summary of:
6 (A) the projected demand for retail electricity in Indiana over
7 the next calendar year; and
8 (B) the amount and type of capacity resources committed to
9 meeting the projected demand;
10 (C) beginning with the commission's annual report due
11 before October 1, 2026, and in each subsequent annual
12 report, the planned retirements or refuelings of electric
13 generation resources and the plans to replace or retain the
14 capacity or energy, or both, of the electric generation
15 resources planned to be retired or refueled; and
16 (D) beginning with the commission's annual report due
17 before October 1, 2026, and in each subsequent annual
18 report, the reports of commission staff under subsection
19 (s).
20 In preparing the summary required under this subdivision, the
21 commission may consult with the forecasting group established
22 under section 3.5 of this chapter.
23 (3) Beginning with the commission's annual report filed under
24 IC 8-1-1-14 in 2025, the commission's analysis regarding the
25 appropriate percentage or portion of:
26 (A) total spring UCAP that public utilities should be
27 authorized to acquire from capacity markets under subsection
28 (g)(3)(B); (h)(3)(B); and
29 (B) total fall UCAP that public utilities should be authorized
30 to acquire from capacity markets under subsection (g)(4)(B).
31 (h)(4)(B).
32 (t) (y) The commission may adopt rules under IC 4-22-2 to
33 implement this section.
34 SECTION 6. An emergency is declared for this act.
2025 IN 1007—LS 7547/DI 101