IN
Indiana House Bill HB1007

Indiana 2025 Regular Session

Indiana House Bill HB1007 Compare Versions

OldNewDifferences
1+*EH1007.3*
2+Reprinted
3+April 11, 2025
4+ENGROSSED
5+HOUSE BILL No. 1007
6+_____
7+DIGEST OF HB 1007 (Updated April 10, 2025 4:22 pm - DI 101)
8+Citations Affected: IC 6-3.1; IC 8-1.
9+Synopsis: Energy generation resources. Provides a credit against state
10+tax liability for expenses incurred in the manufacture of a small
11+modular nuclear reactor (SMR) in Indiana. Establishes procedures
12+under which certain energy utilities may request approval for one or
13+more of the following from the Indiana utility regulatory commission
14+(Continued next page)
15+Effective: Upon passage; January 1, 2025 (retroactive); July 1, 2025.
16+Soliday, Shonkwiler, Pressel, Bartels, Lauer,
17+Heaton, May, Lucas, Smith H, DeVon,
18+Karickhoff, Heine, Smaltz, Teshka, Snow,
19+Jordan, Thompson, Steuerwald, Olthoff,
20+Zimmerman, Haggard, Aylesworth, Miller D,
21+Commons, Judy, Hall, Lehman, Prescott,
22+Culp, Borders, Baird, Wesco, Lopez,
23+Carbaugh, McNamara, Jeter, Abbott
24+(SENATE SPONSORS — KOCH, ROGERS)
25+January 13, 2025, read first time and referred to Committee on Utilities, Energy and
26+Telecommunications.
27+January 29, 2025, amended, reported — Do Pass. Referred to Committee on Ways and
28+Means pursuant to Rule 126.3.
29+February 6, 2025, reported — Do Pass.
30+February 10, 2025, read second time, amended, ordered engrossed.
31+February 11, 2025, engrossed.
32+February 13, 2025, read third time, passed. Yeas 67, nays 25.
33+SENATE ACTION
34+February 19, 2025, read first time and referred to Committee on Utilities.
35+March 27, 2025, amended, reported favorably — Do Pass; reassigned to Committee on Tax
36+and Fiscal Policy.
37+April 8, 2025, reported favorably — Do Pass.
38+April 10, 2025, read second time, amended, ordered engrossed.
39+EH 1007—LS 7547/DI 101 Digest Continued
40+(IURC): (1) An expedited generation resource plan (EGR plan) to meet
41+customer load growth that exceeds a specified threshold. (2) A
42+generation resource submittal for the acquisition of a specific
43+generation resource in accordance with an approved EGR plan. (3) A
44+project to serve one or more large load customers. Sets forth: (1) the
45+requirements for approval of each of these types of requests; (2)
46+standards for financial assurances by large load customers; and (3) cost
47+recovery mechanisms for certain acquisition costs or project costs
48+incurred by energy utilities. Amends the statute concerning public
49+utilities' annual electric resource planning reports to the IURC to
50+provide that for an annual report submitted after December 31, 2025,
51+a public utility must include information as to the amount of generating
52+resource capacity or energy that the public utility plans to retire or
53+refuel with respect to any electric generation resource of at least 125
54+megawatts. Provides that for any planned retirement or refueling, the
55+public utility must include, along with other specified information,
56+information as to the public utility's plans with respect to the following:
57+(1) For a retirement, the amount of replacement capacity identified to
58+provide approximately the same accredited capacity within the
59+appropriate regional transmission organization (RTO) as the capacity
60+of the facility to be retired. (2) For a refueling, the extent to which the
61+refueling will maintain or increase the current generating resource
62+accredited capacity or energy that the electric generating facility
63+provides, so as to provide approximately the same accredited capacity
64+within the appropriate RTO. Requires IURC staff to prepare a staff
65+report for each public utility report that includes a planned electric
66+generation resource retirement. Provides that if, after reviewing a
67+public utility's report and any related staff report, the IURC is not
68+satisfied that the public utility can satisfy both its planning reserve
69+margin requirement and the statute's prescribed reliability adequacy
70+metrics, the IURC shall conduct an investigation into the reasons for
71+the public utility's inability to meet these requirements. Provides that
72+if the public utility's report indicates that the public utility plans to
73+retire an electric generating facility within one year of the date of the
74+report, the IURC must conduct such an investigation. Provides that: (1)
75+a public utility may request, not earlier than three years before the
76+planned retirement date of an electric generation facility, that the IURC
77+conduct an investigation into the planned retirement; and (2) if the
78+IURC conducts an investigation at the request of the public utility
79+within that three year period, the IURC may not conduct a subsequent
80+investigation that would otherwise be required under the bill's
81+provisions unless the IURC is not satisfied that the public utility can
82+satisfy both its planning reserve margin requirement and the statutory
83+reliability adequacy metrics as of the time the investigation would
84+otherwise be required. Provides that if a CPCN is granted by the IURC
85+for a facility intended to repower or replace a generation unit that is
86+planned for retirement, and the CPCN includes findings that the project
87+will result in at least equivalent accredited capacity and will provide
88+economic benefit to ratepayers as compared to the continued operation
89+of the generating unit to be retired, the CPCN constitutes approval by
90+the IURC for purposes of an investigation that would otherwise be
91+required. Provides that if, after an investigation, the IURC determines
92+that the capacity resources available to the public utility will not be
93+adequate to allow the public utility to satisfy both its planning reserve
94+margin requirements and the statute's prescribed reliability adequacy
95+metrics, the IURC shall issue an order: (1) directing the public utility
96+to acquire or construct; or (2) prohibiting the retirement or refueling of;
97+such capacity resources that are reasonable and necessary to enable the
98+public utility to meet these requirements. Provides that if the IURC
99+does not issue an order in an investigation within 120 days after the
100+initiation of the investigation, the public utility is considered to be able
101+to satisfy both its planning reserve margin requirement and the
102+(Continued next page)
103+EH 1007—LS 7547/DI 101EH 1007—LS 7547/DI 101 Digest Continued
104+statutory reliability adequacy metrics with respect to the retirement of
105+the facility under investigation. Provides that if the IURC issues an
106+order to prohibit the retirement or refueling of an electric generation
107+resource, the IURC shall create a sub-docket to authorize the public
108+utility to recover in rates the costs of the continued operation of the
109+electric generation resource proposed to be retired or refueled, subject
110+to a finding by the IURC that the continued costs of operation are just
111+and reasonable. Makes a technical change to another Indiana Code
112+section to recognize the redesignation of subsections within the section
113+containing these provisions.
114+EH 1007—LS 7547/DI 101EH 1007—LS 7547/DI 101 Reprinted
115+April 11, 2025
1116 First Regular Session of the 124th General Assembly (2025)
2117 PRINTING CODE. Amendments: Whenever an existing statute (or a section of the Indiana
3118 Constitution) is being amended, the text of the existing provision will appear in this style type,
4119 additions will appear in this style type, and deletions will appear in this style type.
5120 Additions: Whenever a new statutory provision is being enacted (or a new constitutional
6121 provision adopted), the text of the new provision will appear in this style type. Also, the
7122 word NEW will appear in that style type in the introductory clause of each SECTION that adds
8123 a new provision to the Indiana Code or the Indiana Constitution.
9124 Conflict reconciliation: Text in a statute in this style type or this style type reconciles conflicts
10125 between statutes enacted by the 2024 Regular Session of the General Assembly.
11-HOUSE ENROLLED ACT No. 1007
12-AN ACT to amend the Indiana Code concerning utilities.
126+ENGROSSED
127+HOUSE BILL No. 1007
128+A BILL FOR AN ACT to amend the Indiana Code concerning
129+utilities.
13130 Be it enacted by the General Assembly of the State of Indiana:
14-SECTION 1. IC 6-3.1-45 IS ADDED TO THE INDIANA CODE
15-AS A NEW CHAPTER TO READ AS FOLLOWS [EFFECTIVE
16-JANUARY 1, 2025 (RETROACTIVE)]:
17-Chapter 45. Small Modular Nuclear Reactor Manufacturing
18-Expense Tax Credit
19-Sec. 1. This chapter applies to a taxable year beginning after
20-December 31, 2024.
21-Sec. 2. As used in this chapter, "department" refers to the
22-department of state revenue.
23-Sec. 3. As used in this chapter, "qualified investment" means a
24-taxpayer's expenditures incurred in the manufacture of a small
25-modular nuclear reactor in Indiana.
26-Sec. 4. As used in this chapter, "small modular nuclear reactor"
27-means a nuclear reactor that:
28-(1) has a rated electric generating capacity of not more than
29-four hundred seventy (470) megawatts;
30-(2) is capable of being constructed and operated, either:
31-(A) alone; or
32-(B) in combination with one (1) or more similar reactors if
33-additional reactors are, or become, necessary;
34-at a single site; and
35-HEA 1007 — Concur 2
36-(3) is required to be licensed by the United States Nuclear
37-Regulatory Commission.
38-The term includes a nuclear reactor that is described in this section
39-and that uses a process to produce hydrogen that can be used for
40-energy storage, as a fuel, or for other uses.
41-Sec. 5. As used in this chapter, "state tax liability" means a
42-taxpayer's total tax liability that is incurred under:
43-(1) IC 6-3-1 through IC 6-3-7 (the adjusted gross income tax);
44-(2) IC 6-5.5 (the financial institutions tax); and
45-(3) IC 27-1-18-2 (the insurance premiums tax);
46-as computed after the application of the credits that under
47-IC 6-3.1-1-2 are to be applied before the credit provided by this
48-chapter.
49-Sec. 6. As used in this chapter, "taxpayer" means a person,
50-corporation, partnership, or other entity that makes a qualified
51-investment.
52-Sec. 7. A taxpayer is entitled to a credit against the taxpayer's
53-state tax liability in the taxable year in which the taxpayer makes
54-a qualified investment. The amount of the credit provided by this
55-section is equal to twenty percent (20%) of the amount of the
56-taxpayer's qualified investment.
57-Sec. 8. (a) If the amount determined under section 7 of this
58-chapter for a taxpayer in a taxable year exceeds the taxpayer's
59-state tax liability for that taxable year, the taxpayer may carry the
60-excess over to the following taxable years. The amount of the credit
61-carryover from a taxable year shall be reduced to the extent that
62-the carryover is used by the taxpayer to obtain a credit under this
63-chapter for any subsequent taxable year.
64-(b) A taxpayer is not entitled to a carryback or refund of any
65-unused credit.
66-Sec. 9. (a) If a pass through entity is entitled to a credit under
67-section 7 of this chapter but does not have state tax liability against
68-which the tax credit may be applied, an individual who is a
69-shareholder, partner, or member of the pass through entity is
70-entitled to a tax credit equal to:
71-(1) the tax credit determined for the pass through entity for
72-the taxable year; multiplied by
73-(2) the percentage of the pass through entity's distributive
74-income to which the shareholder, partner, or member is
75-entitled.
76-(b) The credit provided under subsection (a) is in addition to a
77-tax credit to which a shareholder, partner, or member of a pass
78-HEA 1007 — Concur 3
79-through entity is otherwise entitled under this chapter. However,
80-a pass through entity and an individual who is a shareholder,
81-partner, or member of the pass through entity may not claim more
82-than one (1) credit for the same qualified investment.
83-Sec. 10. To receive the credit provided by this chapter, a
84-taxpayer must claim the credit on the taxpayer's annual state tax
85-return or returns in the manner prescribed by the department. The
86-taxpayer shall submit to the department:
87-(1) information verifying that the taxpayer's qualified
88-investment was made with respect to a small modular nuclear
89-reactor that will be manufactured in Indiana; and
90-(2) all information that the department determines is
91-necessary for the calculation of the credit provided by this
92-chapter.
93-SECTION 2. IC 8-1-7.9 IS ADDED TO THE INDIANA CODE AS
94-A NEW CHAPTER TO READ AS FOLLOWS [EFFECTIVE UPON
95-PASSAGE]:
96-Chapter 7.9. Expedited Generation Resource Plans and Large
97-Load Customers
98-Sec. 1. (a) As used in this chapter, "acquisition" means a project
99-or an arrangement that is undertaken:
100-(1) by an energy utility to construct, purchase, lease, or
101-otherwise acquire a generation resource; and
102-(2) in accordance with an approved EGR plan.
103-(b) The term includes the purchase of energy or capacity
104-through a power purchase agreement.
105-Sec. 2. As used in this chapter, "acquisition costs" means the
106-total costs of an acquisition made under an EGR plan, including:
107-(1) planning;
108-(2) construction; and
109-(3) operating;
110-costs related to the acquisition.
111-Sec. 3. As used in this chapter, "appropriate regional
112-transmission organization" has the meaning set forth in
113-IC 8-1-8.5-13(b).
114-Sec. 4. As used in this chapter, "commission" refers to the
115-Indiana utility regulatory commission created by IC 8-1-1-2.
116-Sec. 5. (a) As used in this chapter, "construction and operating
117-costs" means costs:
118-(1) incurred or to be incurred by an energy utility under this
119-chapter after the issuance of an order by the commission
120-under this chapter; and
121-HEA 1007 — Concur 4
122-(2) related to an approved or commission modified acquisition
123-or project.
124-(b) The term includes procurement, contractual, construction,
125-operating, maintenance, financing, legal, regulatory, and project
126-evaluation, analysis, and development costs incurred after the
127-issuance of an order by the commission under this chapter.
128-Sec. 6. As used in this chapter, "corporation" refers to the
129-Indiana economic development corporation established by
130-IC 5-28-3-1 or its successor.
131-Sec. 7. As used in this chapter, "energy utility" means:
131+1 SECTION 1. IC 6-3.1-45 IS ADDED TO THE INDIANA CODE
132+2 AS A NEW CHAPTER TO READ AS FOLLOWS [EFFECTIVE
133+3 JANUARY 1, 2025 (RETROACTIVE)]:
134+4 Chapter 45. Small Modular Nuclear Reactor Manufacturing
135+5 Expense Tax Credit
136+6 Sec. 1. This chapter applies to a taxable year beginning after
137+7 December 31, 2024.
138+8 Sec. 2. As used in this chapter, "department" refers to the
139+9 department of state revenue.
140+10 Sec. 3. As used in this chapter, "qualified investment" means a
141+11 taxpayer's expenditures incurred in the manufacture of a small
142+12 modular nuclear reactor in Indiana.
143+13 Sec. 4. As used in this chapter, "small modular nuclear reactor"
144+14 means a nuclear reactor that:
145+15 (1) has a rated electric generating capacity of not more than
146+EH 1007—LS 7547/DI 101 2
147+1 four hundred seventy (470) megawatts;
148+2 (2) is capable of being constructed and operated, either:
149+3 (A) alone; or
150+4 (B) in combination with one (1) or more similar reactors if
151+5 additional reactors are, or become, necessary;
152+6 at a single site; and
153+7 (3) is required to be licensed by the United States Nuclear
154+8 Regulatory Commission.
155+9 The term includes a nuclear reactor that is described in this section
156+10 and that uses a process to produce hydrogen that can be used for
157+11 energy storage, as a fuel, or for other uses.
158+12 Sec. 5. As used in this chapter, "state tax liability" means a
159+13 taxpayer's total tax liability that is incurred under:
160+14 (1) IC 6-3-1 through IC 6-3-7 (the adjusted gross income tax);
161+15 (2) IC 6-5.5 (the financial institutions tax); and
162+16 (3) IC 27-1-18-2 (the insurance premiums tax);
163+17 as computed after the application of the credits that under
164+18 IC 6-3.1-1-2 are to be applied before the credit provided by this
165+19 chapter.
166+20 Sec. 6. As used in this chapter, "taxpayer" means a person,
167+21 corporation, partnership, or other entity that makes a qualified
168+22 investment.
169+23 Sec. 7. A taxpayer is entitled to a credit against the taxpayer's
170+24 state tax liability in the taxable year in which the taxpayer makes
171+25 a qualified investment. The amount of the credit provided by this
172+26 section is equal to twenty percent (20%) of the amount of the
173+27 taxpayer's qualified investment.
174+28 Sec. 8. (a) If the amount determined under section 7 of this
175+29 chapter for a taxpayer in a taxable year exceeds the taxpayer's
176+30 state tax liability for that taxable year, the taxpayer may carry the
177+31 excess over to the following taxable years. The amount of the credit
178+32 carryover from a taxable year shall be reduced to the extent that
179+33 the carryover is used by the taxpayer to obtain a credit under this
180+34 chapter for any subsequent taxable year.
181+35 (b) A taxpayer is not entitled to a carryback or refund of any
182+36 unused credit.
183+37 Sec. 9. (a) If a pass through entity is entitled to a credit under
184+38 section 7 of this chapter but does not have state tax liability against
185+39 which the tax credit may be applied, an individual who is a
186+40 shareholder, partner, or member of the pass through entity is
187+41 entitled to a tax credit equal to:
188+42 (1) the tax credit determined for the pass through entity for
189+EH 1007—LS 7547/DI 101 3
190+1 the taxable year; multiplied by
191+2 (2) the percentage of the pass through entity's distributive
192+3 income to which the shareholder, partner, or member is
193+4 entitled.
194+5 (b) The credit provided under subsection (a) is in addition to a
195+6 tax credit to which a shareholder, partner, or member of a pass
196+7 through entity is otherwise entitled under this chapter. However,
197+8 a pass through entity and an individual who is a shareholder,
198+9 partner, or member of the pass through entity may not claim more
199+10 than one (1) credit for the same qualified investment.
200+11 Sec. 10. To receive the credit provided by this chapter, a
201+12 taxpayer must claim the credit on the taxpayer's annual state tax
202+13 return or returns in the manner prescribed by the department. The
203+14 taxpayer shall submit to the department:
204+15 (1) information verifying that the taxpayer's qualified
205+16 investment was made with respect to a small modular nuclear
206+17 reactor that will be manufactured in Indiana; and
207+18 (2) all information that the department determines is
208+19 necessary for the calculation of the credit provided by this
209+20 chapter.
210+21 SECTION 2. IC 8-1-7.9 IS ADDED TO THE INDIANA CODE AS
211+22 A NEW CHAPTER TO READ AS FOLLOWS [EFFECTIVE UPON
212+23 PASSAGE]:
213+24 Chapter 7.9. Expedited Generation Resource Plans and Large
214+25 Load Customers
215+26 Sec. 1. (a) As used in this chapter, "acquisition" means a project
216+27 or an arrangement that is undertaken:
217+28 (1) by an energy utility to construct, purchase, lease, or
218+29 otherwise acquire a generation resource; and
219+30 (2) in accordance with an approved EGR plan.
220+31 (b) The term includes the purchase of energy or capacity
221+32 through a power purchase agreement.
222+33 Sec. 2. As used in this chapter, "acquisition costs" means the
223+34 total costs of an acquisition made under an EGR plan, including:
224+35 (1) planning;
225+36 (2) construction; and
226+37 (3) operating;
227+38 costs related to the acquisition.
228+39 Sec. 3. As used in this chapter, "appropriate regional
229+40 transmission organization" has the meaning set forth in
230+41 IC 8-1-8.5-13(b).
231+42 Sec. 4. As used in this chapter, "commission" refers to the
232+EH 1007—LS 7547/DI 101 4
233+1 Indiana utility regulatory commission created by IC 8-1-1-2.
234+2 Sec. 5. (a) As used in this chapter, "construction and operating
235+3 costs" means costs:
236+4 (1) incurred or to be incurred by an energy utility under this
237+5 chapter after the issuance of an order by the commission
238+6 under this chapter; and
239+7 (2) related to an approved or commission modified acquisition
240+8 or project.
241+9 (b) The term includes procurement, contractual, construction,
242+10 operating, maintenance, financing, legal, regulatory, and project
243+11 evaluation, analysis, and development costs incurred after the
244+12 issuance of an order by the commission under this chapter.
245+13 Sec. 6. As used in this chapter, "corporation" refers to the
246+14 Indiana economic development corporation established by
247+15 IC 5-28-3-1 or its successor.
248+16 Sec. 7. As used in this chapter, "energy utility" means:
249+17 (1) an electric utility listed in 170 IAC 4-7-2(a) and any
250+18 successor in interest to that utility; or
251+19 (2) a corporation organized under IC 8-1-13.
252+20 Sec. 8. As used in this chapter, "expedited generation resource
253+21 plan", or "EGR plan", means a plan developed by an energy utility
254+22 for acquiring generation resources to meet load growth that
255+23 exceeds the lesser of:
256+24 (1) five percent (5%) of the energy utility's average peak
257+25 demand over the most recent three (3) calendar years; or
258+26 (2) one hundred fifty (150) megawatts.
259+27 Sec. 9. As used in this chapter, "generation resource submittal"
260+28 means a compliance filing made to the commission for approval of
261+29 the acquisition of a specific generation resource in accordance with
262+30 the criteria set forth in an approved EGR plan.
263+31 Sec. 10. As used in this chapter, "large load customer" means a
264+32 new or existing customer of an energy utility, or not more than
265+33 four (4) multiple new or existing customers of an energy utility,
266+34 that:
267+35 (1) requests new or additional electricity demand that in the
268+36 aggregate exceeds the lesser of:
269+37 (A) five percent (5%) of the energy utility's average peak
270+38 demand over the most recent three (3) calendar years; or
271+39 (B) one hundred fifty (150) megawatts;
272+40 (2) plans to make a capital investment that exceeds five
273+41 hundred million dollars ($500,000,000) in a new or expanded
274+42 facility in Indiana; and
275+EH 1007—LS 7547/DI 101 5
276+1 (3) plans to employ at the new or expanded facility in Indiana
277+2 at least fifty (50) full-time employees with wages that on
278+3 average meet or exceed the most recently published annual
279+4 national average according to the Bureau of Labor Statistics
280+5 of the United States Department of Labor.
281+6 Sec. 11. As used in this chapter, "office" refers to the Indiana
282+7 office of energy development established by IC 4-3-23-3.
283+8 Sec. 12. (a) As used in this chapter, "planning costs" means
284+9 costs:
285+10 (1) incurred or to be incurred by an energy utility before the
286+11 issuance of an order by the commission under this chapter;
287+12 and
288+13 (2) related to an acquisition or project.
289+14 (b) The term includes study, analysis, pre-engineering,
290+15 engineering, legal, financing, and regulatory costs.
291+16 Sec. 13. As used in this chapter, "pre-filing meeting" means a
292+17 meeting to review and discuss a filing or submittal by an energy
293+18 utility in accordance with:
294+19 (1) section 18 of this chapter;
295+20 (2) section 20 of this chapter; or
296+21 (3) section 22 of this chapter;
297+22 as applicable.
298+23 Sec. 14. As used in this chapter, "project" refers to a project
299+24 relating to energy infrastructure and generation resources that:
300+25 (1) are required primarily to serve a large load customer of an
301+26 energy utility; and
302+27 (2) may be designed to serve more than one (1) large load
303+28 customer of the energy utility or to meet other customer
304+29 demand or energy needs.
305+30 Sec. 15. As used in this chapter, "project costs" means the total
306+31 costs of a project, including:
307+32 (1) planning costs; and
308+33 (2) construction and operating costs;
309+34 related to the project.
310+35 Sec. 16. As used in this chapter, "reasonable risk premium"
311+36 means compensation:
312+37 (1) negotiated between an energy utility and a large load
313+38 customer; and
314+39 (2) paid by the large load customer.
315+40 Sec. 17. (a) The commission may expedite, in accordance with
316+41 this chapter, the review of filings and submittals made by an
317+42 energy utility to meet the energy infrastructure and generation
318+EH 1007—LS 7547/DI 101 6
319+1 resource needs of customers. An energy utility may request an
320+2 expedited review by the commission under either or both of the
321+3 following:
322+4 (1) Sections 18 through 21 of this chapter (concerning EGR
323+5 plans).
324+6 (2) Sections 22 through 24 of this chapter (concerning large
325+7 load customer projects).
326+8 (b) This chapter does not preclude an energy utility from
327+9 petitioning the commission under other applicable statutes for
328+10 approval of a generation resource acquisition to meet the needs of
329+11 its customers.
330+12 (c) This chapter does not preclude an energy utility from
331+13 petitioning the commission under, or in conjunction with, other
332+14 applicable statutes, including:
333+15 (1) IC 8-1-2-24;
334+16 (2) IC 8-1-2-42;
335+17 (3) IC 8-1-2.5;
336+18 (4) IC 8-1-8.5;
337+19 (5) IC 8-1-8.8; or
338+20 (6) IC 8-1-39;
339+21 for approval of a project to meet the needs of large load customers.
340+22 Sec. 18. (a) This section applies to an energy utility that petitions
341+23 the commission for approval of an EGR plan.
342+24 (b) An energy utility may file a petition with the commission for
343+25 approval of an EGR plan to acquire generation resources to meet
344+26 the extraordinary needs for electricity by the energy utility's
345+27 customers.
346+28 (c) In a petition under this section, an energy utility must do the
347+29 following:
348+30 (1) Describe the energy utility's EGR plan for acquiring
349+31 generation resources to meet the anticipated extraordinary
350+32 growth in the load of its customers.
351+33 (2) Demonstrate a need for generation capacity that exceeds
352+34 the lesser of:
353+35 (A) five percent (5%) of the energy utility's average peak
354+36 demand over the most recent three (3) calendar years; or
355+37 (B) one hundred fifty (150) megawatts.
356+38 (3) Provide a load growth forecast for a minimum of five (5)
357+39 years from the date of the petition.
358+40 (4) Describe the status of customer contracts and
359+41 commitments that support the load growth forecast described
360+42 in subdivision (3).
361+EH 1007—LS 7547/DI 101 7
362+1 (5) Explain how the EGR plan is consistent with or differs
363+2 from the energy utility's most recent integrated resource plan.
364+3 (6) Propose the accounting authority needed from the
365+4 commission to support the EGR plan.
366+5 (7) Propose the manner in which the capital costs and
367+6 operating and maintenance expenses related to the EGR plan
368+7 will be included in the energy utility's revenue requirement.
369+8 (8) Identify the type and amount of capacity and energy:
370+9 (A) that is included in the EGR plan;
371+10 (B) that does not exceed seventy-five percent (75%) of the
372+11 energy utility's peak capacity over the forecast period
373+12 described in subdivision (3); and
374+13 (C) with respect to which the energy utility may request
375+14 expedited approval in a subsequent generation resource
376+15 submittal.
377+16 (9) Identify the criteria to be included in a generation
378+17 resource submittal that must be met for the acquisition to be
379+18 approved by the commission.
380+19 (10) Certify that at least thirty (30) days before the filing of
381+20 the petition the energy utility held a pre-filing meeting with
382+21 the commission and the office of utility consumer counselor to
383+22 review the EGR plan.
384+23 (11) Describe how the energy utility considered implementing
385+24 grid enhancing technologies to defer or minimize the need for
386+25 additional investment in generation.
387+26 (12) Describe how the EGR plan will support the provision of
388+27 electric utility service with the attributes set forth in
389+28 IC 8-1-2-0.6, including:
390+29 (A) reliability;
391+30 (B) affordability;
392+31 (C) resiliency;
393+32 (D) stability; and
394+33 (E) environmental sustainability.
395+34 (13) Describe how the EGR plan reasonably protects existing
396+35 and future customers and is consistent with:
397+36 (A) the provision of safe, reliable, and affordable electric
398+37 utility service; and
399+38 (B) economical rates.
400+39 (14) Include:
401+40 (A) verified testimony; and
402+41 (B) exhibits;
403+42 supporting the petition and constituting the energy utility's
404+EH 1007—LS 7547/DI 101 8
405+1 case in chief.
406+2 (15) Include a proposed order for the petition.
407+3 Sec. 19. (a) This section applies to an energy utility that petitions
408+4 the commission for approval of an EGR plan.
409+5 (b) Notwithstanding IC 8-1-8.5 or any other statute, the
410+6 commission may approve an energy utility's EGR plan to
411+7 construct, purchase, lease, or otherwise acquire generation
412+8 resources under this chapter for purposes of meeting the needs of
413+9 the energy utility's customers. The commission shall make its
414+10 decision based on whether the relief requested is just, reasonable,
415+11 and in the public interest.
416+12 (c) The commission may:
417+13 (1) approve the energy utility's petition in its entirety;
418+14 (2) deny the energy utility's petition in its entirety; or
419+15 (3) modify the petition, subject to the energy utility's
420+16 acceptance of the modification.
421+17 (d) The commission shall issue a final order on the petition not
422+18 later than ninety (90) days after receiving the energy utility's
423+19 complete petition. A petition is considered:
424+20 (1) complete unless the commission provides a notice of
425+21 deficiency to the energy utility not later than five (5) business
426+22 days after the filing of the petition; and
427+23 (2) approved if the commission does not issue a final order on
428+24 the petition within the ninety (90) day period set forth in this
429+25 subsection.
430+26 Sec. 20. (a) This section applies to an energy utility that submits
431+27 to the commission for approval a generation resource submittal in
432+28 accordance with an approved EGR plan.
433+29 (b) An energy utility may submit a generation resource
434+30 submittal to the commission for approval of an acquisition that the
435+31 energy utility intends to make in accordance with an approved
436+32 EGR plan.
437+33 (c) In a generation resource submittal under this section, an
438+34 energy utility must do the following:
439+35 (1) Describe:
440+36 (A) the type of technology used in the generation resource
441+37 to be acquired;
442+38 (B) the amount of capacity and energy to be acquired;
443+39 (C) key contractual terms for the acquisition; and
444+40 (D) the estimated acquisition costs.
445+41 (2) Demonstrate that the acquisition meets the criteria set
446+42 forth in the energy utility's approved EGR plan.
447+EH 1007—LS 7547/DI 101 9
448+1 (3) Explain how the acquisition is consistent with or differs
449+2 from the energy utility's most recent integrated resource plan.
450+3 (4) Detail the status of customer contracts and commitments
451+4 that support the acquisition.
452+5 (5) Certify that at least thirty (30) days before the filing of the
453+6 generation resource submittal the energy utility held a
454+7 pre-filing meeting with the commission and the office of utility
455+8 consumer counselor to review the acquisition.
456+9 (6) Describe how the energy utility considered implementing
457+10 grid enhancing technologies to defer or minimize the need for
458+11 additional investment in generation.
459+12 (7) Describe how the acquisition will support the provision of
460+13 electric utility service with the attributes set forth in
461+14 IC 8-1-2-0.6, including:
462+15 (A) reliability;
463+16 (B) affordability;
464+17 (C) resiliency;
465+18 (D) stability; and
466+19 (E) environmental sustainability.
467+20 (8) Describe how the acquisition reasonably protects existing
468+21 and future customers and is consistent with:
469+22 (A) the provision of safe, reliable, and affordable electric
470+23 utility service; and
471+24 (B) economical rates.
472+25 (9) Include supporting affidavits and exhibits.
473+26 (10) Include a proposed order for the submittal.
474+27 Sec. 21. (a) This section applies to an energy utility that submits
475+28 to the commission for approval a generation resource submittal in
476+29 accordance with an approved EGR plan.
477+30 (b) Notwithstanding IC 8-1-8.5 or any other statute, the
478+31 commission may approve an energy utility's generation resource
479+32 submittal to construct, purchase, lease, or otherwise acquire
480+33 generation resources under this chapter for purposes of meeting
481+34 the needs of the energy utility's customers. The commission shall
482+35 make its decision based solely on whether the submittal meets the
483+36 criteria and requirements set forth in the energy utility's approved
484+37 EGR plan.
485+38 (c) The commission may:
486+39 (1) approve the energy utility's generation resource submittal
487+40 in its entirety;
488+41 (2) deny the energy utility's generation resource submittal in
489+42 its entirety; or
490+EH 1007—LS 7547/DI 101 10
491+1 (3) modify the energy utility's generation resource submittal,
492+2 subject to the energy utility's acceptance of the modification.
493+3 (d) The commission shall issue a final order on the energy
494+4 utility's generation resource submittal not later than:
495+5 (1) sixty (60) days after receiving the energy utility's complete
496+6 generation resource submittal, if the acquisition is a clean
497+7 energy project (as defined in IC 8-1-8.8-2); or
498+8 (2) one hundred twenty (120) days after receiving the energy
499+9 utility's complete generation resource submittal, if the
500+10 acquisition would otherwise require a certificate under
501+11 IC 8-1-8.5-2.
502+12 A generation resource submittal is considered complete unless the
503+13 commission provides a notice of deficiency to the energy utility not
504+14 later than five (5) business days after the filing of the generation
505+15 resource submittal. A generation resource submittal is considered
506+16 approved if the commission does not issue a final order on the
507+17 generation resource submittal within the period set forth in
508+18 subdivision (1) or (2), as applicable.
509+19 Sec. 22. (a) This section applies to an energy utility that petitions
510+20 the commission for approval of a project to serve a large load
511+21 customer.
512+22 (b) An energy utility may submit to the commission a petition
513+23 for approval of a project to serve a large load customer only if the
514+24 following are satisfied:
515+25 (1) The petition concerns serving the energy needs of a large
516+26 load customer.
517+27 (2) The large load customer commits to significant and
518+28 meaningful financial assurances that must:
519+29 (A) include reimbursement by the large load customer of
520+30 at least eighty percent (80%) of the project costs
521+31 reasonably allocable to the large load customer; and
522+32 (B) afford protections for the energy utility's existing and
523+33 future customers from project costs reasonably allocable
524+34 to the large load customer regardless of whether the large
525+35 load customer ultimately takes service in the anticipated
526+36 amount and within the anticipated time frame.
527+37 (3) At least thirty (30) days before the energy utility's
528+38 submission of the petition to the commission, the energy
529+39 utility held at least one (1) pre-filing meeting with:
530+40 (A) the corporation;
531+41 (B) the office;
532+42 (C) the office of utility consumer counselor;
533+EH 1007—LS 7547/DI 101 11
534+1 (D) the appropriate regional transmission organization;
535+2 and
536+3 (E) the large load customer;
537+4 to review the project.
538+5 (c) An energy utility may petition the commission for approval
539+6 of a project to serve:
540+7 (1) one (1) or more large load customers at one (1) or more
541+8 locations; or
542+9 (2) not more than four (4) customers whose aggregate demand
543+10 satisfies the amount set forth in section 10(1) of this chapter.
544+11 In any case in which more than one (1) large load customer is to be
545+12 served by a project, a reference in this chapter to one (1) large load
546+13 customer is a reference to all large load customers to be served by
547+14 the project, in accordance with IC 1-1-4-1(3).
548+15 (d) In submitting a petition to the commission under this section,
549+16 an energy utility must demonstrate that the large load customer
550+17 and the associated projects meet the requirements of this chapter.
551+18 Sec. 23. (a) This section applies to an energy utility that petitions
552+19 the commission for approval of a project to serve a large load
553+20 customer.
554+21 (b) In a petition under this section, an energy utility must
555+22 include, at a minimum, the following:
556+23 (1) The energy utility's complete case in chief, which must
557+24 include, at a minimum, the following:
558+25 (A) An agreement from the large load customer that
559+26 describes the financial assurances:
560+27 (i) that afford protections for the energy utility's existing
561+28 and future customers; and
562+29 (ii) to which the large load customer has committed
563+30 regardless of whether the large load customer ultimately
564+31 takes service in the anticipated amount and within the
565+32 anticipated time frame.
566+33 (B) A description of:
567+34 (i) the demand side management and self-generation
568+35 options reviewed with the large load customer; and
569+36 (ii) the investments the large load customer will
570+37 undertake to reasonably minimize the amount of
571+38 incremental and other costs incurred by the energy
572+39 utility.
573+40 (C) A description of how the energy utility considered
574+41 implementing grid enhancing technologies to defer or
575+42 minimize the need for additional investment in generation.
576+EH 1007—LS 7547/DI 101 12
577+1 (D) A description of how the energy utility may provide for
578+2 the requisite amount of electricity needed by the large load
579+3 customer, including the estimated project costs.
580+4 (E) A description of how the expected project solution will
581+5 support the provision of electric utility service with the
582+6 attributes set forth in IC 8-1-2-0.6, including:
583+7 (i) reliability;
584+8 (ii) affordability;
585+9 (iii) resiliency;
586+10 (iv) stability; and
587+11 (v) environmental sustainability.
588+12 (F) A description of how the expected project solution and
589+13 its implementation, if approved by the commission,
590+14 reasonably protects existing and future customers and is
591+15 consistent with:
592+16 (i) the provision of safe, reliable, and affordable electric
593+17 utility service; and
594+18 (ii) economical rates.
595+19 (G) A description of the changes that the energy utility will
596+20 make to the energy utility's:
597+21 (i) submissions under IC 8-1-8.5; or
598+22 (ii) filings under IC 8-1-39;
599+23 or both, that are necessary to update the energy utility's
600+24 plans under those statutes to incorporate the project.
601+25 (H) Information concerning each:
602+26 (i) large load customer; and
603+27 (ii) economic development project;
604+28 included in the petition.
605+29 (I) A letter to the energy utility from the corporation
606+30 supporting the petition's request.
607+31 (J) A letter to the energy utility from the office certifying
608+32 that a pre-filing meeting took place and that at the
609+33 meeting:
610+34 (i) the large load customer's proposed project; and
611+35 (ii) the expected project solution proposed by the energy
612+36 utility;
613+37 were adequately discussed.
614+38 (K) A description of the communications and information
615+39 sharing that:
616+40 (i) took place with the appropriate regional transmission
617+41 organization before the pre-filing meeting described in
618+42 clause (J); and
619+EH 1007—LS 7547/DI 101 13
620+1 (ii) concerned the capacity and energy needs of each
621+2 large load customer included in the petition.
622+3 (L) A proposed order for the petition.
623+4 (2) A copy of a notice of filing with:
624+5 (A) the corporation;
625+6 (B) the office;
626+7 (C) the office of utility consumer counselor; and
627+8 (D) the appropriate regional transmission organization.
628+9 A notice that is delivered electronically to the parties set forth
629+10 in this subdivision satisfies the notice requirement under this
630+11 subdivision.
631+12 Sec. 24. (a) This section applies to an energy utility that petitions
632+13 the commission for approval of a project to serve a large load
633+14 customer.
634+15 (b) The commission may approve a petition in whole or in part.
635+16 The commission shall make its decision based on whether the relief
636+17 requested is just, reasonable, and in the public interest. The
637+18 commission shall issue its final order on the petition not later than
638+19 one hundred fifty (150) days after receiving the energy utility's
639+20 complete petition and case in chief. A petition is considered:
640+21 (1) complete unless the commission provides a notice of
641+22 deficiency to the energy utility not later than seven (7)
642+23 business days after the filing of the petition; and
643+24 (2) approved if the commission does not issue a final order on
644+25 the petition within the one hundred fifty (150) day period set
645+26 forth in this subsection.
646+27 (c) If an energy utility files a petition that includes one (1) or
647+28 more large load customers and one (1) or more proposed projects,
648+29 the commission may:
649+30 (1) approve the energy utility's petition in its entirety;
650+31 (2) deny the energy utility's petition in its entirety; or
651+32 (3) modify the petition, subject to the energy utility's
652+33 acceptance of the modification.
653+34 (d) The commission may approve a reasonable risk premium for
654+35 a project if requested in an energy utility's petition and if the
655+36 commission finds that the reasonable risk premium is appropriate.
656+37 If the commission approves a reasonable risk premium:
657+38 (1) the large load customer is responsible for the amount of
658+39 the reasonable risk premium; and
659+40 (2) the reasonable risk premium may not be:
660+41 (A) included in the energy utility's:
661+42 (i) revenue requirement;
662+EH 1007—LS 7547/DI 101 14
663+1 (ii) authorized net operating income; or
664+2 (iii) calculations under IC 8-1-2-42(d)(3) or
665+3 IC 8-1-2-42(g)(3)(C); or
666+4 (B) otherwise considered for purposes of setting the
667+5 authorized return in any future general rate case or other
668+6 regulatory proceeding involving the energy utility.
669+7 (e) The commission may approve an energy utility's request to
670+8 construct, purchase, lease, or otherwise acquire an energy
671+9 generation resource under this chapter (notwithstanding and
672+10 instead of under IC 8-1-2.5, IC 8-1-8.5, or IC 8-1-8.8) for the
673+11 purpose of serving one (1) or more large load customers. In
674+12 approving an energy utility's request under this chapter to acquire
675+13 an energy generation resource to serve one (1) or more large load
676+14 customers, the commission must find that:
677+15 (1) the information provided by the energy utility under
678+16 section 23 of this chapter is complete;
679+17 (2) reasonable and demonstrable consideration was given to
680+18 nongeneration alternatives by the parties involved;
681+19 (3) existing and future customers of the energy utility will be
682+20 adequately protected if the request is granted; and
683+21 (4) the energy utility has considered the impact of the request
684+22 on the energy utility's preferred resource portfolio in the
685+23 energy utility's most recent integrated resource plan.
686+24 (f) An energy utility shall promptly notify the commission if,
687+25 after the commission has approved a petition under subsection (e),
688+26 one (1) or more of the large load customers with respect to whom
689+27 the petition was approved:
690+28 (1) no longer requires service from the energy utility or
691+29 materially alters or terminates the large load customer's
692+30 service requirements; and
693+31 (2) the project is incomplete.
694+32 (g) The commission may, not later than sixty (60) days after
695+33 receiving a notice under subsection (f), conduct an investigation
696+34 under IC 8-1-2-58 through IC 8-1-2-60 to determine whether the
697+35 public interest would still be served by completion of the project.
698+36 An investigation under this subsection does not preclude the energy
699+37 utility from continuing construction of the project to serve the
700+38 large load customer or from continuing to serve the large load
701+39 customer. If the commission finds that completion of the project is
702+40 no longer in the public interest, the commission may modify or
703+41 revoke the order approving the petition.
704+42 Sec. 25. (a) The commission shall review an energy utility's:
705+EH 1007—LS 7547/DI 101 15
706+1 (1) estimated acquisition costs submitted under section
707+2 20(c)(1)(D) of this chapter; or
708+3 (2) estimated project costs filed under section 23(b)(1)(D) of
709+4 this chapter;
710+5 as applicable.
711+6 (b) If the commission approves, with or without modification, an
712+7 energy utility's generation resource submittal or petition for
713+8 approval of a project, the energy utility may recover:
714+9 (1) acquisition costs; or
715+10 (2) project costs;
716+11 as applicable, that have been reviewed and found reasonable by the
717+12 commission, with a return at the energy utility's weighted average
718+13 cost of capital.
719+14 (c) If the commission denies an energy utility's generation
720+15 resource submittal or petition for approval of a project, the energy
721+16 utility may recover planning costs that have been reviewed and
722+17 found reasonable by the commission, without a return.
723+18 (d) Absent fraud, concealment, or gross mismanagement, an
724+19 energy utility may recover:
725+20 (1) acquisition costs; or
726+21 (2) project costs;
727+22 as applicable, with a return at the energy utility's weighted average
728+23 cost of capital, that the energy utility has incurred or contractually
729+24 will incur in reliance on a commission order issued under this
730+25 chapter.
731+26 Sec. 26. (a) Upon request by an energy utility, the commission
732+27 shall determine whether the information and related materials
733+28 filed or submitted, or to be filed or submitted, by an energy utility
734+29 under this chapter:
735+30 (1) are confidential under IC 5-14-3-4 or are trade secrets
736+31 under IC 24-2-3;
737+32 (2) are exempt from public access and disclosure by Indiana
738+33 law; and
739+34 (3) must be treated as confidential and protected from public
740+35 access and disclosure by the commission.
741+36 (b) The parties to a pre-filing meeting under this chapter shall
742+37 execute a nondisclosure agreement to review or discuss
743+38 information or materials considered confidential under IC 5-14-3-4
744+39 or to be trade secrets under IC 24-2-3.
745+40 (c) If the corporation is in negotiations with an industrial,
746+41 research, or commercial prospect about a potential economic
747+42 development project and, based on communications related to
748+EH 1007—LS 7547/DI 101 16
749+1 those negotiations, determines that the potential economic
750+2 development project for a new or expanded facility in Indiana may
751+3 result in the economic development project requiring new or
752+4 increased energy demand of at least twenty (20) megawatts, the
753+5 corporation shall notify the affected energy utility not later than
754+6 fifteen (15) days after making the determination. All
755+7 communications of the corporation, including notice under this
756+8 section to an affected energy utility, regarding a potential economic
757+9 development project are considered confidential and exempt from
758+10 disclosure under IC 5-14-3-4(b)(5). Upon the corporation's
759+11 provision of the notice required by this subsection, any subsequent:
760+12 (1) meeting;
761+13 (2) pre-filing meeting;
762+14 (3) communications; or
763+15 (4) information sharing;
764+16 involving the corporation, the affected energy utility, or the
765+17 industrial, research, or commercial prospect about a potential
766+18 economic development project may be subject to a nondisclosure
767+19 agreement with respect to information or materials considered
768+20 confidential under IC 5-14-3-4 or to be trade secrets under
769+21 IC 24-2-3.
770+22 (d) An energy utility may request, and the commission may
771+23 approve, financial incentives under IC 8-1-8.8-11(a) for:
772+24 (1) an acquisition; or
773+25 (2) a project;
774+26 that qualifies as a clean energy project (as defined in IC 8-1-8.8-2).
775+27 (e) An energy utility may request that review of an arrangement
776+28 under IC 8-1-2-24 and any related rates and charges under
777+29 IC 8-1-2-25 that are:
778+30 (1) submitted with a generation resource submittal; or
779+31 (2) filed with a petition for a project;
780+32 under this chapter be reviewed and approved or denied by the
781+33 commission not later than ninety (90) days after the date of
782+34 submittal or filing, as applicable.
783+35 (f) Notwithstanding IC 8-1-8.5 or any other applicable statute,
784+36 an energy utility may begin construction of an acquisition or a
785+37 project before filing a petition or submittal under this chapter.
786+38 (g) The commission may require an energy utility to file with the
787+39 commission progress reports and updates with respect to an
788+40 acquisition or project under this chapter. Any required progress
789+41 reports or updates under this subsection shall be made in a form
790+42 and at a frequency that the commission determines to be
791+EH 1007—LS 7547/DI 101 17
792+1 reasonable.
793+2 SECTION 3. IC 8-1-8.5-2.1, AS AMENDED BY THE
794+3 TECHNICAL CORRECTIONS BILL OF THE 2025 GENERAL
795+4 ASSEMBLY, IS AMENDED TO READ AS FOLLOWS [EFFECTIVE
796+5 JULY 1, 2025]: Sec. 2.1. (a) This section does not apply to the
797+6 retirement, sale, or transfer of:
798+7 (1) a public utility's electric generation facility if the retirement,
799+8 sale, or transfer is necessary in order for the public utility to
800+9 comply with a federal consent decree; or
801+10 (2) an electric generation facility that generates electricity for sale
802+11 exclusively to the wholesale market.
803+12 (b) A public utility shall notify the commission if:
804+13 (1) the public utility intends or decides to retire, sell, or transfer
805+14 an electric generation facility with a capacity of at least eighty
806+15 (80) megawatts; and
807+16 (2) the retirement, sale, or transfer:
808+17 (A) was not set forth in; or
809+18 (B) is to take place on a date earlier than the date specified in;
810+19 the public utility's short term action plan in the public utility's
811+20 most recently filed integrated resource plan.
812+21 (c) Upon receiving notice from a public utility under subsection (b),
813+22 the commission shall consider and may investigate, under IC 8-1-2-58
814+23 through IC 8-1-2-60, the public utility's intention or decision to retire,
815+24 sell, or transfer the electric generation facility. In considering the public
816+25 utility's intention or decision under this subsection, the commission
817+26 shall examine the impact the retirement, sale, or transfer would have on
818+27 the public utility's ability to meet:
819+28 (1) the public utility's planning reserve margin requirements or
820+29 other federal reliability requirements that the public utility is
821+30 obligated to meet, as described in section 13(i)(4) 13(n)(6) of this
822+31 chapter; and
823+32 (2) the reliability adequacy metrics set forth in section 13(e) 13(h)
824+33 of this chapter.
825+34 (d) Before July 1, 2026, if:
826+35 (1) a public utility intends or decides to retire, sell, or transfer an
827+36 electric generation facility with a capacity of at least eighty (80)
828+37 megawatts; and
829+38 (2) the retirement, sale, or transfer:
830+39 (A) was not set forth in; or
831+40 (B) is to take place on a date earlier than the date specified in;
832+41 the public utility's short term action plan in the public utility's
833+42 most recently filed integrated resource plan;
834+EH 1007—LS 7547/DI 101 18
835+1 the commission shall not permit the public utility's depreciation rates,
836+2 as established under IC 8-1-2-19, to be amended to reflect the
837+3 accelerated date for the retirement, sale, or transfer of the electric
838+4 generation asset unless the commission finds that such an adjustment
839+5 is necessary to ensure the ability of the public utility to provide reliable
840+6 service to its customers, and that the unamended depreciation rates
841+7 would cause an unjust and unreasonable impact on the public utility
842+8 and its ratepayers.
843+9 (e) The commission may issue a general administrative order to
844+10 implement this section.
845+11 (f) This section expires July 1, 2026.
846+12 SECTION 4. IC 8-1-8.5-13, AS AMENDED BY P.L.93-2024,
847+13 SECTION 68, IS AMENDED TO READ AS FOLLOWS [EFFECTIVE
848+14 JULY 1, 2025]: Sec. 13. (a) The general assembly finds that it is in the
849+15 public interest to support the reliability, availability, and diversity of
850+16 electric generating capacity in Indiana for the purpose of providing
851+17 reliable and stable electric service to customers of public utilities.
852+18 (b) As used in this section, "appropriate regional transmission
853+19 organization", with respect to a public utility, refers to the regional
854+20 transmission organization approved by the Federal Energy Regulatory
855+21 Commission for the control area that includes the public utility's
856+22 assigned service area (as defined in IC 8-1-2.3-2).
857+23 (c) As used in this section, "capacity market" means an auction
858+24 conducted by an appropriate regional transmission organization to
859+25 determine a market clearing price for capacity based on the planning
860+26 reserve margin requirements established by the appropriate regional
861+27 transmission organization for a planning year with respect to which an
862+28 auction has not yet been conducted.
863+29 (d) As used in this section, "fall unforced capacity", or "fall UCAP",
864+30 with respect to an electric generating facility, means:
865+31 (1) the capacity value of the electric generating facility's installed
866+32 capacity rate adjusted for the electric generating facility's average
867+33 forced outage rate for the fall period, calculated as required by the
868+34 appropriate regional transmission organization or by the Federal
869+35 Energy Regulatory Commission;
870+36 (2) a metric that is similar to the metric described in subdivision
871+37 (1) and that is required by the appropriate regional transmission
872+38 organization; or
873+39 (3) if the appropriate regional transmission organization does not
874+40 require a metric described in subdivision (1) or (2), a metric that:
875+41 (A) can be used to demonstrate that a public utility has
876+42 sufficient capacity to:
877+EH 1007—LS 7547/DI 101 19
878+1 (i) provide reliable electric service to Indiana customers for
879+2 the fall period; and
880+3 (ii) meet its planning reserve margin requirement and other
881+4 federal reliability requirements described in subsection
882+5 (l)(4); (n)(6); and
883+6 (B) is acceptable to the commission.
884+7 (e) As used in this section, "MISO" refers to the regional
885+8 transmission organization known as the Midcontinent Independent
886+9 System Operator that operates the bulk power transmission system
887+10 serving most of the geographic territory in Indiana.
888+11 (f) As used in this section, "planning reserve margin requirement",
889+12 with respect to a public utility for a particular resource planning year,
890+13 means the planning reserve margin requirement for that planning year
891+14 that the public utility is obligated to meet in accordance with the public
892+15 utility's membership in the appropriate regional transmission
893+16 organization.
894+17 (g) As used in this section, "refuel" or "refueling" means a
895+18 planned fuel conversion from one fuel source to another fuel source
896+19 with respect to an electric generation resource with a nameplate
897+20 capacity of at least one hundred twenty-five (125) megawatts by a
898+21 public utility.
899+22 (g) (h) As used in this section, "reliability adequacy metrics", with
900+23 respect to a public utility, means calculations used to demonstrate all
901+24 of the following:
902+25 (1) Subject to subsection (q)(2)(B), (u)(2), that the public utility:
903+26 (A) has in place sufficient summer UCAP; or
904+27 (B) can reasonably acquire not more than:
905+28 (i) thirty percent (30%) of its total summer UCAP from
906+29 capacity markets, with respect to a report filed with the
907+30 commission under subsection (l) (n) before July 1, 2023; or
908+31 (ii) fifteen percent (15%) of its total summer UCAP from
909+32 capacity markets, with respect to a report filed with the
910+33 commission under subsection (l) (n) after June 30, 2023;
911+34 such that it will have sufficient summer UCAP;
912+35 to provide reliable electric service to Indiana customers, and to
913+36 meet its planning reserve margin requirement and other federal
914+37 reliability requirements described in subsection (l)(4). (n)(6).
915+38 (2) Subject to subsection (q)(2)(B), (u)(2), that the public utility:
916+39 (A) has in place sufficient winter UCAP; or
917+40 (B) can reasonably acquire not more than:
918+41 (i) thirty percent (30%) of its total winter UCAP from
919+42 capacity markets, with respect to a report filed with the
920+EH 1007—LS 7547/DI 101 20
921+1 commission under subsection (l) (n) before July 1, 2023; or
922+2 (ii) fifteen percent (15%) of its total winter UCAP from
923+3 capacity markets, with respect to a report filed with the
924+4 commission under subsection (l) (n) after June 30, 2023;
925+5 such that it will have sufficient winter UCAP;
926+6 to provide reliable electric service to Indiana customers, and to
927+7 meet its planning reserve margin requirement and other federal
928+8 reliability requirements described in subsection (l)(4). (n)(6).
929+9 (3) Subject to subsection (q)(2)(B), (u)(2), with respect to a report
930+10 filed with the commission under subsection (l) (n) after June 30,
931+11 2026, that the public utility:
932+12 (A) has in place sufficient spring UCAP; or
933+13 (B) can reasonably acquire not more than fifteen percent
934+14 (15%) of its total spring UCAP from capacity markets, such
935+15 that it will have sufficient spring UCAP;
936+16 to provide reliable electric service to Indiana customers, and to
937+17 meet its planning reserve margin requirement and other federal
938+18 reliability requirements described in subsection (l)(4). (n)(6).
939+19 (4) Subject to subsection (q)(2)(B), (u)(2), with respect to a report
940+20 filed with the commission under subsection (l) (n) after June 30,
941+21 2026, that the public utility:
942+22 (A) has in place sufficient fall UCAP; or
943+23 (B) can reasonably acquire not more than fifteen percent
944+24 (15%) of its total fall UCAP from capacity markets, such that
945+25 it will have sufficient fall UCAP;
946+26 to provide reliable electric service to Indiana customers, and to
947+27 meet its planning reserve margin requirement and other federal
948+28 reliability requirements described in subsection (l)(4). (n)(6).
949+29 (i) As used in this section, "retire" or retirement" means a
950+30 planned permanent ceasing of electric generation operations with
951+31 respect to an electric generation resource with a nameplate
952+32 capacity of at least one hundred twenty-five (125) megawatts by a
953+33 public utility.
954+34 (h) (j) As used in this section, "spring unforced capacity", or "spring
955+35 UCAP", with respect to an electric generating facility, means:
956+36 (1) the capacity value of the electric generating facility's installed
957+37 capacity rate adjusted for the electric generating facility's average
958+38 forced outage rate for the spring period, calculated as required by
959+39 the appropriate regional transmission organization or by the
960+40 Federal Energy Regulatory Commission;
961+41 (2) a metric that is similar to the metric described in subdivision
962+42 (1) and that is required by the appropriate regional transmission
963+EH 1007—LS 7547/DI 101 21
964+1 organization; or
965+2 (3) if the appropriate regional transmission organization does not
966+3 require a metric described in subdivision (1) or (2), a metric that:
967+4 (A) can be used to demonstrate that a public utility has
968+5 sufficient capacity to:
969+6 (i) provide reliable electric service to Indiana customers for
970+7 the spring period; and
971+8 (ii) meet its planning reserve margin requirement and other
972+9 federal reliability requirements described in subsection
973+10 (l)(4); (n)(6); and
974+11 (B) is acceptable to the commission.
975+12 (i) (k) As used in this section, "summer unforced capacity", or
976+13 "summer UCAP", with respect to an electric generating facility, means:
977+14 (1) the capacity value of the electric generating facility's installed
978+15 capacity rate adjusted for the electric generating facility's average
979+16 forced outage rate for the summer period, calculated as required
980+17 by the appropriate regional transmission organization or by the
981+18 Federal Energy Regulatory Commission; or
982+19 (2) a metric that is similar to the metric described in subdivision
983+20 (1) and that is required by the appropriate regional transmission
984+21 organization.
985+22 (j) (l) As used in this section, "winter unforced capacity", or "winter
986+23 UCAP", with respect to an electric generating facility, means:
987+24 (1) the capacity value of the electric generating facility's installed
988+25 capacity rate adjusted for the electric generating facility's average
989+26 forced outage rate for the winter period, calculated as required by
990+27 the appropriate regional transmission organization or by the
991+28 Federal Energy Regulatory Commission;
992+29 (2) a metric that is similar to the metric described in subdivision
993+30 (1) and that is required by the appropriate regional transmission
994+31 organization; or
995+32 (3) if the appropriate regional transmission organization does not
996+33 require a metric described in subdivision (1) or (2), a metric that:
997+34 (A) can be used to demonstrate that a public utility has
998+35 sufficient capacity to:
999+36 (i) provide reliable electric service to Indiana customers for
1000+37 the winter period; and
1001+38 (ii) meet its planning reserve margin requirement and other
1002+39 federal reliability requirements described in subsection
1003+40 (l)(4); (n)(6); and
1004+41 (B) is acceptable to the commission.
1005+42 (k) (m) A public utility that owns and operates an electric
1006+EH 1007—LS 7547/DI 101 22
1007+1 generating facility serving customers in Indiana shall operate and
1008+2 maintain the facility using good utility practices and in a manner:
1009+3 (1) reasonably intended to support the provision of reliable and
1010+4 economic electric service to customers of the public utility; and
1011+5 (2) reasonably consistent with the resource reliability
1012+6 requirements of MISO or any other appropriate regional
1013+7 transmission organization; and
1014+8 (3) reasonably maximizes the economic value of the electric
1015+9 generating facility.
1016+10 (l) (n) Not later than thirty (30) days after the deadline for
1017+11 submitting an annual planning reserve margin report to MISO, each
1018+12 public utility providing electric service to Indiana customers shall,
1019+13 regardless of whether the public utility is required to submit an annual
1020+14 planning reserve margin report to MISO, file with the commission a
1021+15 report, in a form specified by the commission, that provides the
1022+16 following information for each of the next three (3) resource planning
1023+17 years, beginning with the planning year covered by the planning
1024+18 reserve margin report to MISO described in this subsection:
1025+19 (1) The:
1026+20 (A) capacity;
1027+21 (B) location; and
1028+22 (C) fuel source;
1029+23 for each electric generating facility that is owned and operated by
1030+24 the electric utility and that will be used to provide electric service
1031+25 to Indiana customers.
1032+26 (2) With respect to a report submitted to the commission after
1033+27 December 31, 2025, the amount of generating resource
1034+28 capacity or energy, or both, that the public utility plans to
1035+29 retire and that is owned and operated by the public utility and
1036+30 used to provide retail electric service in Indiana, including
1037+31 the:
1038+32 (A) capacity;
1039+33 (B) location;
1040+34 (C) fuel source; and
1041+35 (D) planned retirement date;
1042+36 for each electric generating facility. The public utility must
1043+37 include information as to whether the planned retirement is
1044+38 required in order to comply with environmental laws,
1045+39 regulations, or court orders, including consent decrees, that
1046+40 are or will be in effect at the time of the planned retirement.
1047+41 In addition, the public utility must provide its economic
1048+42 rationale for the planned retirement, including anticipated
1049+EH 1007—LS 7547/DI 101 23
1050+1 ratepayer impacts, and information concerning the public
1051+2 utility's plan or plans with respect to the amount of
1052+3 replacement capacity identified to provide approximately the
1053+4 same accredited capacity within the appropriate regional
1054+5 transmission organization as the amount of capacity of the
1055+6 facility to be retired.
1056+7 (3) With respect to a report submitted to the commission after
1057+8 December 31, 2025, the amount of generating resource
1058+9 capacity or energy, or both, that the public utility plans to
1059+10 refuel, including the:
1060+11 (A) capacity;
1061+12 (B) location;
1062+13 (C) existing fuel source;
1063+14 (D) proposed fuel source; and
1064+15 (E) planned completion date of the refueling;
1065+16 with respect to each electric generating facility that the public
1066+17 utility plans to refuel. The public utility must provide its
1067+18 economic rationale for the planned refueling, including
1068+19 anticipated ratepayer impacts, and information concerning
1069+20 the public utility's plan or plans with respect to the extent to
1070+21 which the refueling will maintain or increase the current
1071+22 generating resource accredited capacity or energy, or both,
1072+23 that the electric generating facility provides, so as to provide
1073+24 approximately the same accredited capacity within the
1074+25 appropriate regional transmission organization.
1075+26 (2) (4) The amount of generating resource capacity or energy, or
1076+27 both, that the public utility has procured under contract and that
1077+28 will be used to provide electric service to Indiana customers,
1078+29 including the:
1079+30 (A) capacity;
1080+31 (B) location; and
1081+32 (C) fuel source;
1082+33 for each electric generating facility that will supply capacity or
1083+34 energy under the contract, to the extent known by the public
1084+35 utility.
1085+36 (3) (5) The amount of demand response resources available to the
1086+37 public utility under contracts and tariffs.
1087+38 (4) (6) The following:
1088+39 (A) The planning reserve margin requirements established by
1089+40 MISO for the planning years covered by the report, to the
1090+41 extent known by the public utility with respect to any
1091+42 particular planning year covered by the report.
1092+EH 1007—LS 7547/DI 101 24
1093+1 (B) If applicable, any other planning reserve margin
1094+2 requirement that:
1095+3 (i) applies to the planning years covered by the report; and
1096+4 (ii) the public utility is obligated to meet in accordance with
1097+5 the public utility's membership in an appropriate regional
1098+6 transmission organization;
1099+7 to the extent known by the public utility with respect to any
1100+8 particular planning year covered by the report.
1101+9 (C) Other federal reliability requirements that the public utility
1102+10 is obligated to meet in accordance with its membership in an
1103+11 appropriate regional transmission organization with respect to
1104+12 the planning years covered by the report, to the extent known
1105+13 by the public utility with respect to any particular planning
1106+14 year covered by the report.
1107+15 For each planning reserve margin requirement reported under
1108+16 clause (A) or (B), the public utility shall include a comparison of
1109+17 that planning reserve margin requirement to the planning reserve
1110+18 margin requirement established by the same regional transmission
1111+19 organization for the 2021-2022 planning year.
1112+20 (5) (7) The reliability adequacy metrics of the public utility, as
1113+21 forecasted for the three (3) planning years covered by the report.
1114+22 (m) (o) Upon request by a public utility, the commission shall
1115+23 determine whether information provided in a report filed by the public
1116+24 utility under subsection (l): (n):
1117+25 (1) is confidential under IC 5-14-3-4 or is a trade secret under
1118+26 IC 24-2-3;
1119+27 (2) is exempt from public access and disclosure by Indiana law;
1120+28 and
1121+29 (3) shall be treated as confidential and protected from public
1122+30 access and disclosure by the commission.
1123+31 (n) (p) A joint agency created under IC 8-1-2.2 may file the report
1124+32 required under subsection (l) (n) as a consolidated report on behalf of
1125+33 any or all of the municipally owned utilities that make up its
1126+34 membership.
1127+35 (o) (q) A:
1128+36 (1) corporation organized under IC 23-17 that is an electric
1129+37 cooperative and that has at least one (1) member that is a
1130+38 corporation organized under IC 8-1-13; or
1131+39 (2) general district corporation within the meaning of
1132+40 IC 8-1-13-23;
1133+41 may file the report required under subsection (l) (n) as a consolidated
1134+42 report on behalf of any or all of the cooperatively owned electric
1135+EH 1007—LS 7547/DI 101 25
1136+1 utilities that it serves.
1137+2 (p) (r) In reviewing a report filed by a public utility under
1138+3 subsection (l), (n), the commission may request technical assistance
1139+4 from MISO or any other appropriate regional transmission organization
1140+5 in determining:
1141+6 (1) the planning reserve margin requirements or other federal
1142+7 reliability requirements that the public utility is obligated to meet,
1143+8 as described in subsection (l)(4); (n)(6); and
1144+9 (2) whether the resources available to the public utility under
1145+10 subsections (l)(1) (n)(1) through (l)(3) (n)(5) will be adequate to
1146+11 support the provision of reliable electric service to the public
1147+12 utility's Indiana customers.
1148+13 (s) With respect to a report submitted under subsection (n) after
1149+14 December 31, 2025, commission staff shall review the reports
1150+15 submitted by public utilities and shall, not later than ninety (90)
1151+16 days after the date of submission of the reports, submit to the
1152+17 commission a staff report concerning any planned retirements
1153+18 included in the reports under subsection (n)(2). The report must
1154+19 make recommendations to the commission based on whether each
1155+20 planned retirement:
1156+21 (1) is consistent with the standards set forth in subsection (m);
1157+22 (2) will be replaced with an amount of replacement capacity
1158+23 that will provide approximately the same accredited capacity
1159+24 within the appropriate regional transmission organization as
1160+25 the amount of capacity of the facility to be retired;
1161+26 (3) will not adversely and unreasonably impact a public
1162+27 utility's ability to provide safe, reliable, and economical
1163+28 electric utility service to the public utility's customers;
1164+29 (4) will result in the provision to Indiana customers of electric
1165+30 utility service with the attributes of:
1166+31 (A) reliability;
1167+32 (B) affordability;
1168+33 (C) resiliency;
1169+34 (D) stability; and
1170+35 (E) environmental sustainability;
1171+36 as set forth in IC 8-1-2-0.6; and
1172+37 (5) is required in order to comply with environmental laws,
1173+38 regulations, or court orders, including consent decrees, that
1174+39 are or will be in effect at the time of the planned retirement.
1175+40 (t) The commission shall make the staff reports prepared under
1176+41 subsection (s) publicly available by posting the staff reports on the
1177+42 commission's website. Upon the posting of a staff report on the
1178+EH 1007—LS 7547/DI 101 26
1179+1 commission's website, the commission shall accept public
1180+2 comments on the report for a period not to exceed thirty (30) days
1181+3 after the date of posting.
1182+4 (q) (u) If, after reviewing a report filed by a public utility under
1183+5 subsection (l), (n) and any staff report prepared with respect to the
1184+6 public utility under subsection (s), the commission is not satisfied
1185+7 that the public utility can either:
1186+8 (1) provide reliable electric service to the public utility's Indiana
1187+9 customers; or
1188+10 (2) either:
1189+11 (A) (1) satisfy both:
1190+12 (i) (A) its planning reserve margin requirement or other
1191+13 federal reliability requirements that the public utility is
1192+14 obligated to meet, as described in subsection (l)(4); (n)(6); and
1193+15 (ii) (B) the reliability adequacy metrics set forth in subsection
1194+16 (g); (h); or
1195+17 (B) (2) provide sufficient reason as to why the public utility is
1196+18 unable to satisfy both:
1197+19 (i) (A) its planning reserve margin requirement or other
1198+20 federal reliability requirements that the public utility is
1199+21 obligated to meet, as described in subsection (l)(4); (n)(6); and
1200+22 (ii) (B) the reliability adequacy metrics set forth in subsection
1201+23 (g); (h);
1202+24 during one (1) more of the planning years covered by the report, the
1203+25 commission may shall conduct an investigation under IC 8-1-2-58
1204+26 through IC 8-1-2-60 as to the reasons for the public utility's potential
1205+27 inability to meet the requirements described in subdivision (1) or (2),
1206+28 or both. provide sufficient reason as to that inability, as described
1207+29 in subdivision (2). In addition, if the public utility has indicated in
1208+30 its report under subsection (n)(2) that it plans to retire an electric
1209+31 generating facility within one (1) year of the date of the report, the
1210+32 commission must conduct an investigation under IC 8-1-2-58
1211+33 through IC 8-1-2-60 as to the reasons for the public utility's
1212+34 potential inability to meet the requirements described in
1213+35 subdivision (1) or provide sufficient reason as to that inability, as
1214+36 described in subdivision (2). However, a public utility may request,
1215+37 not earlier than three (3) years before the planned retirement date
1216+38 of an electric generation facility, that the commission conduct an
1217+39 investigation under IC 8-1-2-58 through IC 8-1-2-60, for the
1218+40 purposes described in this subsection, with respect to the planned
1219+41 retirement. If the commission conducts an investigation at the
1220+42 request of a public utility within the three (3) year period before
1221+EH 1007—LS 7547/DI 101 27
1222+1 the planned retirement date of an electric generation facility, the
1223+2 commission may not conduct a subsequent investigation that would
1224+3 otherwise be required under this subsection with respect to the
1225+4 retirement of that same electric generation facility unless the
1226+5 commission is not satisfied, as of the time that an investigation
1227+6 would otherwise be required under this subsection, that the public
1228+7 utility can meet the requirements described in subdivision (1) or
1229+8 provide sufficient reason as to that inability, as described in
1230+9 subdivision (2). If a certificate is granted by the commission under
1231+10 this chapter for a facility intended to repower or replace a
1232+11 generation unit that is planned for retirement, and the certificate
1233+12 includes findings that the project will result in at least equivalent
1234+13 accredited capacity and will provide economic benefit to
1235+14 ratepayers as compared to the continued operation of the
1236+15 generating unit to be retired, the certificate under this chapter
1237+16 constitutes approval by the commission for purposes of an
1238+17 investigation required by this subsection. However, if the
1239+18 commission finds that facts and circumstances regarding the
1240+19 planned retirement have changed significantly since the certificate
1241+20 was granted and that those changes concern the public utility's
1242+21 ability to meet the requirements described in subdivision (1), the
1243+22 commission may conduct an investigation into the planned
1244+23 retirement of the unit.
1245+24 (r) (v) If, upon investigation under IC 8-1-2-58 through IC 8-1-2-60,
1246+25 and after notice and hearing, as required by IC 8-1-2-59, the
1247+26 commission determines that the capacity resources available to the
1248+27 public utility under subsections (l)(1) (n)(1) through (l)(3) (n)(5) will
1249+28 not be adequate to support the provision of reliable electric service to
1250+29 the public utility's Indiana customers, or to allow the public utility to
1251+30 satisfy both its planning reserve margin requirements or other federal
1252+31 reliability requirements that the public utility is obligated to meet (as
1253+32 described in subsection (l)(4)) (n)(6)) and the reliability adequacy
1254+33 metrics set forth in subsection (g), (h), the commission shall issue an
1255+34 order:
1256+35 (1) directing the public utility to acquire or construct; or
1257+36 (2) prohibiting the retirement or refueling of;
1258+37 such capacity resources that are reasonable and necessary to enable the
1259+38 public utility to provide reliable electric service to its Indiana
1260+39 customers, and to satisfy both its planning reserve margin requirements
1261+40 or other federal reliability requirements described in subsection (l)(4)
1262+41 (n)(6) and the reliability adequacy metrics set forth in subsection (g).
1263+42 (h). The commission shall issue an order under this subsection not
1264+EH 1007—LS 7547/DI 101 28
1265+1 later than one hundred twenty (120) days after the initiation of the
1266+2 investigation under subsection (u). If the commission does not issue
1267+3 an order within the one hundred twenty (120) day period
1268+4 prescribed by this subsection, the public utility is considered to be
1269+5 able to meet the requirements described in subsection (u)(1) with
1270+6 respect to the retirement of the electric generation facility under
1271+7 investigation. Not later than ninety (90) days after the date of the
1272+8 commission's an order by the commission under this subsection, the
1273+9 public utility shall file for approval with the commission a plan to
1274+10 comply with the commission's order. Notwithstanding IC 8-1-3 or
1275+11 any other law, any appeal of an order by the commission under this
1276+12 subsection is entitled to priority review and shall be given
1277+13 expedited consideration in accordance with Rule 21 of the Indiana
1278+14 Rules of Appellate Procedure.
1279+15 (w) With respect to a report submitted under subsection (n)
1280+16 after December 31, 2025, if the commission issues an order under
1281+17 subsection (v) to prohibit the retirement or refueling of an electric
1282+18 generation resource, the commission shall create a sub-docket to
1283+19 authorize the public utility to recover in rates the costs of the
1284+20 continued operation of the electric generation resource that was
1285+21 proposed to be retired or refueled. The commission must find that
1286+22 the continued costs of operation are just and reasonable before
1287+23 authorizing their recovery in the public utility's rates. The creation
1288+24 of a sub-docket under this subsection is not subject to the one
1289+25 hundred twenty (120) day time frame for the commission to issue
1290+26 an order under subsection (v).
1291+27 The (x) A public utility's plan under subsection (v) may include:
1292+28 (1) a request for a certificate of public convenience and necessity
1293+29 under this chapter; or
1294+30 (2) an application under IC 8-1-8.8;
1295+31 or both.
1296+32 (s) (y) Beginning in 2022, the commission shall include in its annual
1297+33 report under IC 8-1-1-14 the following information:
1298+34 (1) The commission's analysis regarding the ability of public
1299+35 utilities to:
1300+36 (A) provide reliable electric service to Indiana customers; and
1301+37 (B) satisfy both:
1302+38 (i) their planning reserve margin requirements or other
1303+39 federal reliability requirements; and
1304+40 (ii) the reliability adequacy metrics set forth in subsection
1305+41 (g); (h);
1306+42 for the next three (3) utility resource planning years, based on the
1307+EH 1007—LS 7547/DI 101 29
1308+1 most recent reports filed by public utilities under subsection (l).
1309+2 (n).
1310+3 (2) A summary of:
1311+4 (A) the projected demand for retail electricity in Indiana over
1312+5 the next calendar year; and
1313+6 (B) the amount and type of capacity resources committed to
1314+7 meeting the projected demand;
1315+8 (C) beginning with the commission's annual report due
1316+9 before October 1, 2026, and in each subsequent annual
1317+10 report, the planned retirements or refuelings of electric
1318+11 generation resources and the plans to replace or retain the
1319+12 capacity or energy, or both, of the electric generation
1320+13 resources planned to be retired or refueled; and
1321+14 (D) beginning with the commission's annual report due
1322+15 before October 1, 2026, and in each subsequent annual
1323+16 report, the reports of commission staff under subsection
1324+17 (s).
1325+18 In preparing the summary required under this subdivision, the
1326+19 commission may consult with the forecasting group established
1327+20 under section 3.5 of this chapter.
1328+21 (3) Beginning with the commission's annual report filed under
1329+22 IC 8-1-1-14 in 2025, the commission's analysis regarding the
1330+23 appropriate percentage or portion of:
1331+24 (A) total spring UCAP that public utilities should be
1332+25 authorized to acquire from capacity markets under subsection
1333+26 (g)(3)(B); (h)(3)(B); and
1334+27 (B) total fall UCAP that public utilities should be authorized
1335+28 to acquire from capacity markets under subsection (g)(4)(B).
1336+29 (h)(4)(B).
1337+30 (t) (z) The commission may adopt rules under IC 4-22-2 to
1338+31 implement this section.
1339+32 SECTION 5. An emergency is declared for this act.
1340+EH 1007—LS 7547/DI 101 30
1341+COMMITTEE REPORT
1342+Mr. Speaker: Your Committee on Utilities, Energy and
1343+Telecommunications, to which was referred House Bill 1007, has had
1344+the same under consideration and begs leave to report the same back
1345+to the House with the recommendation that said bill be amended as
1346+follows:
1347+Page 2, line 26, delete "ten percent (10%)" and insert "twenty
1348+percent (20%)".
1349+Page 3, line 17, delete "installed" and insert "manufactured".
1350+Page 3, line 26, after "1." insert "(a)".
1351+Page 3, line 26, after "project" insert "or an arrangement".
1352+Page 3, between lines 30 and 31, begin a new paragraph and insert:
1353+"(b) The term includes the purchase of energy or capacity
1354+through a power purchase agreement.".
1355+Page 4, line 8, delete "planning" and insert "project evaluation,
1356+analysis, and development".
1357+Page 4, line 14, delete "means an" and insert "means:
1321358 (1) an electric utility listed in 170 IAC 4-7-2(a) and any
1331359 successor in interest to that utility; or
134-(2) a corporation organized under IC 8-1-13.
135-Sec. 8. As used in this chapter, "expedited generation resource
136-plan", or "EGR plan", means a plan developed by an energy utility
137-for acquiring generation resources to meet load growth that
138-exceeds the lesser of:
139-(1) five percent (5%) of the energy utility's average peak
140-demand over the most recent three (3) calendar years; or
141-(2) one hundred fifty (150) megawatts.
142-Sec. 9. As used in this chapter, "generation resource submittal"
143-means a compliance filing made to the commission for approval of
144-the acquisition of a specific generation resource in accordance with
145-the criteria set forth in an approved EGR plan.
146-Sec. 10. As used in this chapter, "large load customer" means a
147-new or existing customer of an energy utility, or not more than
148-four (4) multiple new or existing customers of an energy utility,
149-that:
150-(1) requests new or additional electricity demand that in the
151-aggregate exceeds the lesser of:
152-(A) five percent (5%) of the energy utility's average peak
153-demand over the most recent three (3) calendar years; or
154-(B) one hundred fifty (150) megawatts;
155-(2) plans to make a capital investment that exceeds five
156-hundred million dollars ($500,000,000) in a new or expanded
157-facility in Indiana; and
158-(3) plans to employ at the new or expanded facility in Indiana
159-at least fifty (50) full-time employees with wages that on
160-average meet or exceed the most recently published annual
161-national average according to the Bureau of Labor Statistics
162-of the United States Department of Labor.
163-Sec. 11. As used in this chapter, "office" refers to the Indiana
164-HEA 1007 — Concur 5
165-office of energy development established by IC 4-3-23-3.
166-Sec. 12. (a) As used in this chapter, "planning costs" means
167-costs:
168-(1) incurred or to be incurred by an energy utility before the
169-issuance of an order by the commission under this chapter;
170-and
171-(2) related to an acquisition or project.
172-(b) The term includes study, analysis, pre-engineering,
173-engineering, legal, financing, and regulatory costs.
174-Sec. 13. As used in this chapter, "pre-filing meeting" means a
175-meeting to review and discuss a filing or submittal by an energy
176-utility in accordance with:
177-(1) section 18 of this chapter;
178-(2) section 20 of this chapter; or
179-(3) section 22 of this chapter;
180-as applicable.
181-Sec. 14. As used in this chapter, "project" refers to a project
182-relating to energy infrastructure and generation resources that:
183-(1) are required primarily to serve a large load customer of an
184-energy utility; and
185-(2) may be designed to serve more than one (1) large load
186-customer of the energy utility or to meet other customer
187-demand or energy needs.
188-Sec. 15. As used in this chapter, "project costs" means the total
189-costs of a project, including:
190-(1) planning costs; and
191-(2) construction and operating costs;
192-related to the project.
193-Sec. 16. As used in this chapter, "reasonable risk premium"
194-means compensation:
195-(1) negotiated between an energy utility and a large load
196-customer; and
197-(2) paid by the large load customer.
198-Sec. 17. (a) The commission may expedite, in accordance with
199-this chapter, the review of filings and submittals made by an
200-energy utility to meet the energy infrastructure and generation
201-resource needs of customers. An energy utility may request an
202-expedited review by the commission under either or both of the
203-following:
204-(1) Sections 18 through 21 of this chapter (concerning EGR
205-plans).
206-(2) Sections 22 through 24 of this chapter (concerning large
207-HEA 1007 — Concur 6
208-load customer projects).
209-(b) This chapter does not preclude an energy utility from
210-petitioning the commission under other applicable statutes for
211-approval of a generation resource acquisition to meet the needs of
212-its customers.
213-(c) This chapter does not preclude an energy utility from
214-petitioning the commission under, or in conjunction with, other
215-applicable statutes, including:
216-(1) IC 8-1-2-24;
217-(2) IC 8-1-2-42;
218-(3) IC 8-1-2.5;
219-(4) IC 8-1-8.5;
220-(5) IC 8-1-8.8; or
221-(6) IC 8-1-39;
222-for approval of a project to meet the needs of large load customers.
223-Sec. 18. (a) This section applies to an energy utility that petitions
224-the commission for approval of an EGR plan.
225-(b) An energy utility may file a petition with the commission for
226-approval of an EGR plan to acquire generation resources to meet
227-the extraordinary needs for electricity by the energy utility's
228-customers.
229-(c) In a petition under this section, an energy utility must do the
230-following:
231-(1) Describe the energy utility's EGR plan for acquiring
232-generation resources to meet the anticipated extraordinary
233-growth in the load of its customers.
234-(2) Demonstrate a need for generation capacity that exceeds
235-the lesser of:
236-(A) five percent (5%) of the energy utility's average peak
237-demand over the most recent three (3) calendar years; or
238-(B) one hundred fifty (150) megawatts.
239-(3) Provide a load growth forecast for a minimum of five (5)
240-years from the date of the petition.
241-(4) Describe the status of customer contracts and
242-commitments that support the load growth forecast described
243-in subdivision (3).
244-(5) Explain how the EGR plan is consistent with or differs
245-from the energy utility's most recent integrated resource plan.
246-(6) Propose the accounting authority needed from the
247-commission to support the EGR plan.
248-(7) Propose the manner in which the capital costs and
249-operating and maintenance expenses related to the EGR plan
250-HEA 1007 — Concur 7
251-will be included in the energy utility's revenue requirement.
252-(8) Identify the type and amount of capacity and energy:
253-(A) that is included in the EGR plan;
254-(B) that does not exceed seventy-five percent (75%) of the
255-energy utility's peak capacity over the forecast period
256-described in subdivision (3); and
257-(C) with respect to which the energy utility may request
258-expedited approval in a subsequent generation resource
259-submittal.
260-(9) Identify the criteria to be included in a generation
261-resource submittal that must be met for the acquisition to be
262-approved by the commission.
263-(10) Certify that at least thirty (30) days before the filing of
264-the petition the energy utility held a pre-filing meeting with
265-the commission and the office of utility consumer counselor to
266-review the EGR plan.
267-(11) Describe how the energy utility considered implementing
268-grid enhancing technologies to defer or minimize the need for
269-additional investment in generation.
270-(12) Describe how the EGR plan will support the provision of
271-electric utility service with the attributes set forth in
272-IC 8-1-2-0.6, including:
273-(A) reliability;
274-(B) affordability;
275-(C) resiliency;
276-(D) stability; and
277-(E) environmental sustainability.
278-(13) Describe how the EGR plan reasonably protects existing
279-and future customers and is consistent with:
280-(A) the provision of safe, reliable, and affordable electric
281-utility service; and
282-(B) economical rates.
283-(14) Include:
284-(A) verified testimony; and
285-(B) exhibits;
286-supporting the petition and constituting the energy utility's
287-case in chief.
288-(15) Include a proposed order for the petition.
289-Sec. 19. (a) This section applies to an energy utility that petitions
290-the commission for approval of an EGR plan.
291-(b) Notwithstanding IC 8-1-8.5 or any other statute, the
292-commission may approve an energy utility's EGR plan to
293-HEA 1007 — Concur 8
294-construct, purchase, lease, or otherwise acquire generation
295-resources under this chapter for purposes of meeting the needs of
296-the energy utility's customers. The commission shall make its
297-decision based on whether the relief requested is just, reasonable,
298-and in the public interest.
299-(c) The commission may:
300-(1) approve the energy utility's petition in its entirety;
301-(2) deny the energy utility's petition in its entirety; or
302-(3) modify the petition, subject to the energy utility's
303-acceptance of the modification.
304-(d) The commission shall issue a final order on the petition not
305-later than ninety (90) days after receiving the energy utility's
306-complete petition. A petition is considered:
307-(1) complete unless the commission provides a notice of
308-deficiency to the energy utility not later than five (5) business
309-days after the filing of the petition; and
310-(2) approved if the commission does not issue a final order on
311-the petition within the ninety (90) day period set forth in this
312-subsection.
313-Sec. 20. (a) This section applies to an energy utility that submits
314-to the commission for approval a generation resource submittal in
315-accordance with an approved EGR plan.
316-(b) An energy utility may submit a generation resource
317-submittal to the commission for approval of an acquisition that the
318-energy utility intends to make in accordance with an approved
319-EGR plan.
320-(c) In a generation resource submittal under this section, an
321-energy utility must do the following:
322-(1) Describe:
323-(A) the type of technology used in the generation resource
324-to be acquired;
325-(B) the amount of capacity and energy to be acquired;
326-(C) key contractual terms for the acquisition; and
327-(D) the estimated acquisition costs.
328-(2) Demonstrate that the acquisition meets the criteria set
329-forth in the energy utility's approved EGR plan.
330-(3) Explain how the acquisition is consistent with or differs
331-from the energy utility's most recent integrated resource plan.
332-(4) Detail the status of customer contracts and commitments
333-that support the acquisition.
334-(5) Certify that at least thirty (30) days before the filing of the
335-generation resource submittal the energy utility held a
336-HEA 1007 — Concur 9
337-pre-filing meeting with the commission and the office of utility
338-consumer counselor to review the acquisition.
339-(6) Describe how the energy utility considered implementing
340-grid enhancing technologies to defer or minimize the need for
341-additional investment in generation.
342-(7) Describe how the acquisition will support the provision of
343-electric utility service with the attributes set forth in
344-IC 8-1-2-0.6, including:
345-(A) reliability;
346-(B) affordability;
347-(C) resiliency;
348-(D) stability; and
349-(E) environmental sustainability.
350-(8) Describe how the acquisition reasonably protects existing
351-and future customers and is consistent with:
352-(A) the provision of safe, reliable, and affordable electric
353-utility service; and
354-(B) economical rates.
355-(9) Include supporting affidavits and exhibits.
356-(10) Include a proposed order for the submittal.
357-Sec. 21. (a) This section applies to an energy utility that submits
358-to the commission for approval a generation resource submittal in
359-accordance with an approved EGR plan.
360-(b) Notwithstanding IC 8-1-8.5 or any other statute, the
361-commission may approve an energy utility's generation resource
362-submittal to construct, purchase, lease, or otherwise acquire
363-generation resources under this chapter for purposes of meeting
364-the needs of the energy utility's customers. The commission shall
365-make its decision based solely on whether the submittal meets the
366-criteria and requirements set forth in the energy utility's approved
367-EGR plan.
368-(c) The commission may:
369-(1) approve the energy utility's generation resource submittal
370-in its entirety;
371-(2) deny the energy utility's generation resource submittal in
372-its entirety; or
373-(3) modify the energy utility's generation resource submittal,
374-subject to the energy utility's acceptance of the modification.
375-(d) The commission shall issue a final order on the energy
376-utility's generation resource submittal not later than:
377-(1) sixty (60) days after receiving the energy utility's complete
378-generation resource submittal, if the acquisition is a clean
379-HEA 1007 — Concur 10
380-energy project (as defined in IC 8-1-8.8-2); or
381-(2) one hundred twenty (120) days after receiving the energy
382-utility's complete generation resource submittal, if the
383-acquisition would otherwise require a certificate under
384-IC 8-1-8.5-2.
385-A generation resource submittal is considered complete unless the
386-commission provides a notice of deficiency to the energy utility not
387-later than five (5) business days after the filing of the generation
388-resource submittal. A generation resource submittal is considered
389-approved if the commission does not issue a final order on the
390-generation resource submittal within the period set forth in
391-subdivision (1) or (2), as applicable.
392-Sec. 22. (a) This section applies to an energy utility that petitions
393-the commission for approval of a project to serve a large load
394-customer.
395-(b) An energy utility may submit to the commission a petition
396-for approval of a project to serve a large load customer only if the
397-following are satisfied:
398-(1) The petition concerns serving the energy needs of a large
399-load customer.
400-(2) The large load customer commits to significant and
401-meaningful financial assurances that must:
402-(A) include reimbursement by the large load customer of
403-at least eighty percent (80%) of the project costs
404-reasonably allocable to the large load customer; and
405-(B) afford protections for the energy utility's existing and
406-future customers from project costs reasonably allocable
407-to the large load customer regardless of whether the large
408-load customer ultimately takes service in the anticipated
409-amount and within the anticipated time frame.
410-(3) At least thirty (30) days before the energy utility's
411-submission of the petition to the commission, the energy
412-utility held at least one (1) pre-filing meeting with:
413-(A) the corporation;
414-(B) the office;
415-(C) the office of utility consumer counselor;
416-(D) the appropriate regional transmission organization;
417-and
418-(E) the large load customer;
419-to review the project.
420-(c) An energy utility may petition the commission for approval
421-of a project to serve:
422-HEA 1007 — Concur 11
423-(1) one (1) or more large load customers at one (1) or more
424-locations; or
425-(2) not more than four (4) customers whose aggregate demand
426-satisfies the amount set forth in section 10(1) of this chapter.
427-In any case in which more than one (1) large load customer is to be
428-served by a project, a reference in this chapter to one (1) large load
429-customer is a reference to all large load customers to be served by
430-the project, in accordance with IC 1-1-4-1(3).
431-(d) In submitting a petition to the commission under this section,
432-an energy utility must demonstrate that the large load customer
433-and the associated projects meet the requirements of this chapter.
434-Sec. 23. (a) This section applies to an energy utility that petitions
435-the commission for approval of a project to serve a large load
436-customer.
437-(b) In a petition under this section, an energy utility must
438-include, at a minimum, the following:
439-(1) The energy utility's complete case in chief, which must
440-include, at a minimum, the following:
441-(A) An agreement from the large load customer that
442-describes the financial assurances:
443-(i) that afford protections for the energy utility's existing
444-and future customers; and
445-(ii) to which the large load customer has committed
446-regardless of whether the large load customer ultimately
447-takes service in the anticipated amount and within the
448-anticipated time frame.
449- (B) A description of:
450-(i) the demand side management and self-generation
451-options reviewed with the large load customer; and
452-(ii) the investments the large load customer will
453-undertake to reasonably minimize the amount of
454-incremental and other costs incurred by the energy
455-utility.
456-(C) A description of how the energy utility considered
457-implementing grid enhancing technologies to defer or
458-minimize the need for additional investment in generation.
459-(D) A description of how the energy utility may provide for
460-the requisite amount of electricity needed by the large load
461-customer, including the estimated project costs.
462-(E) A description of how the expected project solution will
463-support the provision of electric utility service with the
464-attributes set forth in IC 8-1-2-0.6, including:
465-HEA 1007 — Concur 12
466-(i) reliability;
467-(ii) affordability;
468-(iii) resiliency;
469-(iv) stability; and
470-(v) environmental sustainability.
471-(F) A description of how the expected project solution and
472-its implementation, if approved by the commission,
473-reasonably protects existing and future customers and is
474-consistent with:
475-(i) the provision of safe, reliable, and affordable electric
476-utility service; and
477-(ii) economical rates.
478-(G) A description of the changes that the energy utility will
479-make to the energy utility's:
480-(i) submissions under IC 8-1-8.5; or
481-(ii) filings under IC 8-1-39;
482-or both, that are necessary to update the energy utility's
483-plans under those statutes to incorporate the project.
484-(H) Information concerning each:
485-(i) large load customer; and
486-(ii) economic development project;
487-included in the petition.
488-(I) A letter to the energy utility from the corporation
489-supporting the petition's request.
490-(J) A letter to the energy utility from the office certifying
491-that a pre-filing meeting took place and that at the
492-meeting:
493-(i) the large load customer's proposed project; and
494-(ii) the expected project solution proposed by the energy
495-utility;
496-were adequately discussed.
497-(K) A description of the communications and information
498-sharing that:
499-(i) took place with the appropriate regional transmission
500-organization before the pre-filing meeting described in
501-clause (J); and
502-(ii) concerned the capacity and energy needs of each
503-large load customer included in the petition.
504-(L) A proposed order for the petition.
505-(2) A copy of a notice of filing with:
506-(A) the corporation;
507-(B) the office;
508-HEA 1007 — Concur 13
509-(C) the office of utility consumer counselor; and
510-(D) the appropriate regional transmission organization.
511-A notice that is delivered electronically to the parties set forth
512-in this subdivision satisfies the notice requirement under this
513-subdivision.
514-Sec. 24. (a) This section applies to an energy utility that petitions
515-the commission for approval of a project to serve a large load
516-customer.
517-(b) The commission may approve a petition in whole or in part.
518-The commission shall make its decision based on whether the relief
519-requested is just, reasonable, and in the public interest. The
520-commission shall issue its final order on the petition not later than
521-one hundred fifty (150) days after receiving the energy utility's
522-complete petition and case in chief. A petition is considered:
523-(1) complete unless the commission provides a notice of
524-deficiency to the energy utility not later than seven (7)
525-business days after the filing of the petition; and
526-(2) approved if the commission does not issue a final order on
527-the petition within the one hundred fifty (150) day period set
528-forth in this subsection.
529-(c) If an energy utility files a petition that includes one (1) or
530-more large load customers and one (1) or more proposed projects,
531-the commission may:
532-(1) approve the energy utility's petition in its entirety;
533-(2) deny the energy utility's petition in its entirety; or
534-(3) modify the petition, subject to the energy utility's
535-acceptance of the modification.
536-(d) The commission may approve a reasonable risk premium for
537-a project if requested in an energy utility's petition and if the
538-commission finds that the reasonable risk premium is appropriate.
539-If the commission approves a reasonable risk premium:
540-(1) the large load customer is responsible for the amount of
541-the reasonable risk premium; and
542-(2) the reasonable risk premium may not be:
543-(A) included in the energy utility's:
544-(i) revenue requirement;
545-(ii) authorized net operating income; or
546-(iii) calculations under IC 8-1-2-42(d)(3) or
547-IC 8-1-2-42(g)(3)(C); or
548-(B) otherwise considered for purposes of setting the
549-authorized return in any future general rate case or other
550-regulatory proceeding involving the energy utility.
551-HEA 1007 — Concur 14
552-(e) The commission may approve an energy utility's request to
553-construct, purchase, lease, or otherwise acquire an energy
554-generation resource under this chapter (notwithstanding and
555-instead of under IC 8-1-2.5, IC 8-1-8.5, or IC 8-1-8.8) for the
556-purpose of serving one (1) or more large load customers. In
557-approving an energy utility's request under this chapter to acquire
558-an energy generation resource to serve one (1) or more large load
559-customers, the commission must find that:
560-(1) the information provided by the energy utility under
561-section 23 of this chapter is complete;
562-(2) reasonable and demonstrable consideration was given to
563-nongeneration alternatives by the parties involved;
564-(3) existing and future customers of the energy utility will be
565-adequately protected if the request is granted; and
566-(4) the energy utility has considered the impact of the request
567-on the energy utility's preferred resource portfolio in the
568-energy utility's most recent integrated resource plan.
569-(f) An energy utility shall promptly notify the commission if,
570-after the commission has approved a petition under subsection (e),
571-one (1) or more of the large load customers with respect to whom
572-the petition was approved:
573-(1) no longer requires service from the energy utility or
574-materially alters or terminates the large load customer's
575-service requirements; and
576-(2) the project is incomplete.
577-(g) The commission may, not later than sixty (60) days after
578-receiving a notice under subsection (f), conduct an investigation
579-under IC 8-1-2-58 through IC 8-1-2-60 to determine whether the
580-public interest would still be served by completion of the project.
581-An investigation under this subsection does not preclude the energy
582-utility from continuing construction of the project to serve the
583-large load customer or from continuing to serve the large load
584-customer. If the commission finds that completion of the project is
585-no longer in the public interest, the commission may modify or
586-revoke the order approving the petition.
587-Sec. 25. (a) The commission shall review an energy utility's:
588-(1) estimated acquisition costs submitted under section
589-20(c)(1)(D) of this chapter; or
590-(2) estimated project costs filed under section 23(b)(1)(D) of
591-this chapter;
592-as applicable.
593-(b) If the commission approves, with or without modification, an
594-HEA 1007 — Concur 15
595-energy utility's generation resource submittal or petition for
596-approval of a project, the energy utility may recover:
597-(1) acquisition costs; or
598-(2) project costs;
599-as applicable, that have been reviewed and found reasonable by the
600-commission, with a return at the energy utility's weighted average
601-cost of capital.
602-(c) If the commission denies an energy utility's generation
603-resource submittal or petition for approval of a project, the energy
604-utility may recover planning costs that have been reviewed and
605-found reasonable by the commission, without a return.
606-(d) Absent fraud, concealment, or gross mismanagement, an
607-energy utility may recover:
608-(1) acquisition costs; or
609-(2) project costs;
610-as applicable, with a return at the energy utility's weighted average
611-cost of capital, that the energy utility has incurred or contractually
612-will incur in reliance on a commission order issued under this
613-chapter.
614-Sec. 26. (a) Upon request by an energy utility, the commission
615-shall determine whether the information and related materials
616-filed or submitted, or to be filed or submitted, by an energy utility
617-under this chapter:
618-(1) are confidential under IC 5-14-3-4 or are trade secrets
619-under IC 24-2-3;
620-(2) are exempt from public access and disclosure by Indiana
621-law; and
622-(3) must be treated as confidential and protected from public
623-access and disclosure by the commission.
624-(b) The parties to a pre-filing meeting under this chapter shall
625-execute a nondisclosure agreement to review or discuss
626-information or materials considered confidential under IC 5-14-3-4
627-or to be trade secrets under IC 24-2-3.
628-(c) If the corporation is in negotiations with an industrial,
1360+(2) a corporation organized under IC 8-1-13.".
1361+Page 4, delete lines 15 through 16.
1362+Page 9, between lines 21 and 22, begin a new line block indented
1363+and insert:
1364+"(10) Include a proposed order for the submittal.".
1365+Page 15, line 35, delete "determines that any potential economic"
1366+and insert "is in negotiations with an industrial, research, or
1367+commercial prospect about a potential economic development
1368+project and, based on communications related to those
1369+negotiations, determines that the potential economic development
1370+project for a new or expanded facility in Indiana may result in the
1371+economic development project requiring new or increased energy
1372+demand of at least twenty (20) megawatts, the corporation shall
1373+notify the affected energy utility not later than fifteen (15) days
1374+after making the determination. All communications of the
1375+corporation, including notice under this section to an affected
1376+energy utility, regarding a potential economic development project
1377+are considered confidential and exempt from disclosure under
1378+IC 5-14-3-4(b)(5).".
1379+Page 15, delete lines 36 through 39.
1380+Page 15, line 40, delete "later than fifteen (15) days after making the
1381+determination.".
1382+EH 1007—LS 7547/DI 101 31
1383+Page 16, line 5, delete "one (1) or" and insert "the industrial,
6291384 research, or commercial prospect about a potential economic
630-development project and, based on communications related to
631-those negotiations, determines that the potential economic
632-development project for a new or expanded facility in Indiana may
633-result in the economic development project requiring new or
634-increased energy demand of at least twenty (20) megawatts, the
635-corporation shall notify the affected energy utility not later than
636-fifteen (15) days after making the determination. All
637-HEA 1007 — Concur 16
638-communications of the corporation, including notice under this
639-section to an affected energy utility, regarding a potential economic
640-development project are considered confidential and exempt from
641-disclosure under IC 5-14-3-4(b)(5). Upon the corporation's
642-provision of the notice required by this subsection, any subsequent:
643-(1) meeting;
644-(2) pre-filing meeting;
645-(3) communications; or
646-(4) information sharing;
647-involving the corporation, the affected energy utility, or the
648-industrial, research, or commercial prospect about a potential
649-economic development project may be subject to a nondisclosure
650-agreement with respect to information or materials considered
651-confidential under IC 5-14-3-4 or to be trade secrets under
652-IC 24-2-3.
653-(d) An energy utility may request, and the commission may
654-approve, financial incentives under IC 8-1-8.8-11(a) for:
655-(1) an acquisition; or
656-(2) a project;
657-that qualifies as a clean energy project (as defined in IC 8-1-8.8-2).
658-(e) An energy utility may request that review of an arrangement
659-under IC 8-1-2-24 and any related rates and charges under
660-IC 8-1-2-25 that are:
661-(1) submitted with a generation resource submittal; or
662-(2) filed with a petition for a project;
663-under this chapter be reviewed and approved or denied by the
664-commission not later than ninety (90) days after the date of
665-submittal or filing, as applicable.
666-(f) Notwithstanding IC 8-1-8.5 or any other applicable statute,
667-an energy utility may begin construction of an acquisition or a
668-project before filing a petition or submittal under this chapter.
669-(g) The commission may require an energy utility to file with the
670-commission progress reports and updates with respect to an
671-acquisition or project under this chapter. Any required progress
672-reports or updates under this subsection shall be made in a form
673-and at a frequency that the commission determines to be
674-reasonable.
675-SECTION 3. IC 8-1-8.5-2.1, AS AMENDED BY THE
676-TECHNICAL CORRECTIONS BILL OF THE 2025 GENERAL
677-ASSEMBLY, IS AMENDED TO READ AS FOLLOWS [EFFECTIVE
678-JULY 1, 2025]: Sec. 2.1. (a) This section does not apply to the
679-retirement, sale, or transfer of:
680-HEA 1007 — Concur 17
681-(1) a public utility's electric generation facility if the retirement,
682-sale, or transfer is necessary in order for the public utility to
683-comply with a federal consent decree; or
684-(2) an electric generation facility that generates electricity for sale
685-exclusively to the wholesale market.
686-(b) A public utility shall notify the commission if:
687-(1) the public utility intends or decides to retire, sell, or transfer
688-an electric generation facility with a capacity of at least eighty
689-(80) megawatts; and
690-(2) the retirement, sale, or transfer:
691-(A) was not set forth in; or
692-(B) is to take place on a date earlier than the date specified in;
693-the public utility's short term action plan in the public utility's
694-most recently filed integrated resource plan.
695-(c) Upon receiving notice from a public utility under subsection (b),
696-the commission shall consider and may investigate, under IC 8-1-2-58
697-through IC 8-1-2-60, the public utility's intention or decision to retire,
698-sell, or transfer the electric generation facility. In considering the public
699-utility's intention or decision under this subsection, the commission
700-shall examine the impact the retirement, sale, or transfer would have on
701-the public utility's ability to meet:
702-(1) the public utility's planning reserve margin requirements or
703-other federal reliability requirements that the public utility is
704-obligated to meet, as described in section 13(i)(4) 13(n)(6) of this
705-chapter; and
706-(2) the reliability adequacy metrics set forth in section 13(e) 13(h)
707-of this chapter.
708-(d) Before July 1, 2026, if:
709-(1) a public utility intends or decides to retire, sell, or transfer an
710-electric generation facility with a capacity of at least eighty (80)
711-megawatts; and
712-(2) the retirement, sale, or transfer:
713-(A) was not set forth in; or
714-(B) is to take place on a date earlier than the date specified in;
715-the public utility's short term action plan in the public utility's
716-most recently filed integrated resource plan;
717-the commission shall not permit the public utility's depreciation rates,
718-as established under IC 8-1-2-19, to be amended to reflect the
719-accelerated date for the retirement, sale, or transfer of the electric
720-generation asset unless the commission finds that such an adjustment
721-is necessary to ensure the ability of the public utility to provide reliable
722-service to its customers, and that the unamended depreciation rates
723-HEA 1007 — Concur 18
724-would cause an unjust and unreasonable impact on the public utility
725-and its ratepayers.
726-(e) The commission may issue a general administrative order to
727-implement this section.
728-(f) This section expires July 1, 2026.
729-SECTION 4. IC 8-1-8.5-13, AS AMENDED BY P.L.93-2024,
730-SECTION 68, IS AMENDED TO READ AS FOLLOWS [EFFECTIVE
731-JULY 1, 2025]: Sec. 13. (a) The general assembly finds that it is in the
732-public interest to support the reliability, availability, and diversity of
733-electric generating capacity in Indiana for the purpose of providing
734-reliable and stable electric service to customers of public utilities.
735-(b) As used in this section, "appropriate regional transmission
736-organization", with respect to a public utility, refers to the regional
737-transmission organization approved by the Federal Energy Regulatory
738-Commission for the control area that includes the public utility's
739-assigned service area (as defined in IC 8-1-2.3-2).
740-(c) As used in this section, "capacity market" means an auction
741-conducted by an appropriate regional transmission organization to
742-determine a market clearing price for capacity based on the planning
743-reserve margin requirements established by the appropriate regional
744-transmission organization for a planning year with respect to which an
745-auction has not yet been conducted.
746-(d) As used in this section, "fall unforced capacity", or "fall UCAP",
747-with respect to an electric generating facility, means:
748-(1) the capacity value of the electric generating facility's installed
749-capacity rate adjusted for the electric generating facility's average
750-forced outage rate for the fall period, calculated as required by the
751-appropriate regional transmission organization or by the Federal
752-Energy Regulatory Commission;
753-(2) a metric that is similar to the metric described in subdivision
754-(1) and that is required by the appropriate regional transmission
755-organization; or
756-(3) if the appropriate regional transmission organization does not
757-require a metric described in subdivision (1) or (2), a metric that:
758-(A) can be used to demonstrate that a public utility has
759-sufficient capacity to:
760-(i) provide reliable electric service to Indiana customers for
761-the fall period; and
762-(ii) meet its planning reserve margin requirement and other
763-federal reliability requirements described in subsection
764-(l)(4); (n)(6); and
765-(B) is acceptable to the commission.
766-HEA 1007 — Concur 19
767-(e) As used in this section, "MISO" refers to the regional
768-transmission organization known as the Midcontinent Independent
769-System Operator that operates the bulk power transmission system
770-serving most of the geographic territory in Indiana.
771-(f) As used in this section, "planning reserve margin requirement",
772-with respect to a public utility for a particular resource planning year,
773-means the planning reserve margin requirement for that planning year
774-that the public utility is obligated to meet in accordance with the public
775-utility's membership in the appropriate regional transmission
776-organization.
777-(g) As used in this section, "refuel" or "refueling" means a
778-planned fuel conversion from one fuel source to another fuel source
779-with respect to an electric generation resource with a nameplate
780-capacity of at least one hundred twenty-five (125) megawatts by a
781-public utility.
782-(g) (h) As used in this section, "reliability adequacy metrics", with
783-respect to a public utility, means calculations used to demonstrate all
784-of the following:
785-(1) Subject to subsection (q)(2)(B), (u)(2), that the public utility:
786-(A) has in place sufficient summer UCAP; or
787-(B) can reasonably acquire not more than:
788-(i) thirty percent (30%) of its total summer UCAP from
789-capacity markets, with respect to a report filed with the
790-commission under subsection (l) (n) before July 1, 2023; or
791-(ii) fifteen percent (15%) of its total summer UCAP from
792-capacity markets, with respect to a report filed with the
793-commission under subsection (l) (n) after June 30, 2023;
794-such that it will have sufficient summer UCAP;
795-to provide reliable electric service to Indiana customers, and to
796-meet its planning reserve margin requirement and other federal
797-reliability requirements described in subsection (l)(4). (n)(6).
798-(2) Subject to subsection (q)(2)(B), (u)(2), that the public utility:
799-(A) has in place sufficient winter UCAP; or
800-(B) can reasonably acquire not more than:
801-(i) thirty percent (30%) of its total winter UCAP from
802-capacity markets, with respect to a report filed with the
803-commission under subsection (l) (n) before July 1, 2023; or
804-(ii) fifteen percent (15%) of its total winter UCAP from
805-capacity markets, with respect to a report filed with the
806-commission under subsection (l) (n) after June 30, 2023;
807-such that it will have sufficient winter UCAP;
808-to provide reliable electric service to Indiana customers, and to
809-HEA 1007 — Concur 20
810-meet its planning reserve margin requirement and other federal
811-reliability requirements described in subsection (l)(4). (n)(6).
812-(3) Subject to subsection (q)(2)(B), (u)(2), with respect to a report
813-filed with the commission under subsection (l) (n) after June 30,
814-2026, that the public utility:
815-(A) has in place sufficient spring UCAP; or
816-(B) can reasonably acquire not more than fifteen percent
817-(15%) of its total spring UCAP from capacity markets, such
818-that it will have sufficient spring UCAP;
819-to provide reliable electric service to Indiana customers, and to
820-meet its planning reserve margin requirement and other federal
821-reliability requirements described in subsection (l)(4). (n)(6).
822-(4) Subject to subsection (q)(2)(B), (u)(2), with respect to a report
823-filed with the commission under subsection (l) (n) after June 30,
824-2026, that the public utility:
825-(A) has in place sufficient fall UCAP; or
826-(B) can reasonably acquire not more than fifteen percent
827-(15%) of its total fall UCAP from capacity markets, such that
828-it will have sufficient fall UCAP;
829-to provide reliable electric service to Indiana customers, and to
830-meet its planning reserve margin requirement and other federal
831-reliability requirements described in subsection (l)(4). (n)(6).
832-(i) As used in this section, "retire" or retirement" means a
833-planned permanent ceasing of electric generation operations with
834-respect to an electric generation resource with a nameplate
835-capacity of at least one hundred twenty-five (125) megawatts by a
836-public utility.
837-(h) (j) As used in this section, "spring unforced capacity", or "spring
838-UCAP", with respect to an electric generating facility, means:
839-(1) the capacity value of the electric generating facility's installed
840-capacity rate adjusted for the electric generating facility's average
841-forced outage rate for the spring period, calculated as required by
842-the appropriate regional transmission organization or by the
843-Federal Energy Regulatory Commission;
844-(2) a metric that is similar to the metric described in subdivision
845-(1) and that is required by the appropriate regional transmission
846-organization; or
847-(3) if the appropriate regional transmission organization does not
848-require a metric described in subdivision (1) or (2), a metric that:
849-(A) can be used to demonstrate that a public utility has
850-sufficient capacity to:
851-(i) provide reliable electric service to Indiana customers for
852-HEA 1007 — Concur 21
853-the spring period; and
854-(ii) meet its planning reserve margin requirement and other
855-federal reliability requirements described in subsection
856-(l)(4); (n)(6); and
857-(B) is acceptable to the commission.
858-(i) (k) As used in this section, "summer unforced capacity", or
859-"summer UCAP", with respect to an electric generating facility, means:
860-(1) the capacity value of the electric generating facility's installed
861-capacity rate adjusted for the electric generating facility's average
862-forced outage rate for the summer period, calculated as required
863-by the appropriate regional transmission organization or by the
864-Federal Energy Regulatory Commission; or
865-(2) a metric that is similar to the metric described in subdivision
866-(1) and that is required by the appropriate regional transmission
867-organization.
868-(j) (l) As used in this section, "winter unforced capacity", or "winter
869-UCAP", with respect to an electric generating facility, means:
870-(1) the capacity value of the electric generating facility's installed
871-capacity rate adjusted for the electric generating facility's average
872-forced outage rate for the winter period, calculated as required by
873-the appropriate regional transmission organization or by the
874-Federal Energy Regulatory Commission;
875-(2) a metric that is similar to the metric described in subdivision
876-(1) and that is required by the appropriate regional transmission
877-organization; or
878-(3) if the appropriate regional transmission organization does not
879-require a metric described in subdivision (1) or (2), a metric that:
880-(A) can be used to demonstrate that a public utility has
881-sufficient capacity to:
882-(i) provide reliable electric service to Indiana customers for
883-the winter period; and
884-(ii) meet its planning reserve margin requirement and other
885-federal reliability requirements described in subsection
886-(l)(4); (n)(6); and
887-(B) is acceptable to the commission.
888-(k) (m) A public utility that owns and operates an electric
889-generating facility serving customers in Indiana shall operate and
890-maintain the facility using good utility practices and in a manner:
891-(1) reasonably intended to support the provision of reliable and
892-economic electric service to customers of the public utility; and
893-(2) reasonably consistent with the resource reliability
894-requirements of MISO or any other appropriate regional
895-HEA 1007 — Concur 22
896-transmission organization; and
897-(3) reasonably maximizes the economic value of the electric
898-generating facility.
899-(l) (n) Not later than thirty (30) days after the deadline for
900-submitting an annual planning reserve margin report to MISO, each
901-public utility providing electric service to Indiana customers shall,
902-regardless of whether the public utility is required to submit an annual
903-planning reserve margin report to MISO, file with the commission a
904-report, in a form specified by the commission, that provides the
905-following information for each of the next three (3) resource planning
906-years, beginning with the planning year covered by the planning
907-reserve margin report to MISO described in this subsection:
908-(1) The:
909-(A) capacity;
910-(B) location; and
911-(C) fuel source;
912-for each electric generating facility that is owned and operated by
913-the electric utility and that will be used to provide electric service
914-to Indiana customers.
915-(2) With respect to a report submitted to the commission after
916-December 31, 2025, the amount of generating resource
917-capacity or energy, or both, that the public utility plans to
918-retire and that is owned and operated by the public utility and
919-used to provide retail electric service in Indiana, including
920-the:
921-(A) capacity;
922-(B) location;
923-(C) fuel source; and
924-(D) planned retirement date;
925-for each electric generating facility. The public utility must
926-include information as to whether the planned retirement is
927-required in order to comply with environmental laws,
928-regulations, or court orders, including consent decrees, that
929-are or will be in effect at the time of the planned retirement.
930-In addition, the public utility must provide its economic
931-rationale for the planned retirement, including anticipated
932-ratepayer impacts, and information concerning the public
933-utility's plan or plans with respect to the amount of
934-replacement capacity identified to provide approximately the
935-same accredited capacity within the appropriate regional
936-transmission organization as the amount of capacity of the
937-facility to be retired.
938-HEA 1007 — Concur 23
939-(3) With respect to a report submitted to the commission after
940-December 31, 2025, the amount of generating resource
941-capacity or energy, or both, that the public utility plans to
942-refuel, including the:
943-(A) capacity;
944-(B) location;
945-(C) existing fuel source;
946-(D) proposed fuel source; and
947-(E) planned completion date of the refueling;
948-with respect to each electric generating facility that the public
949-utility plans to refuel. The public utility must provide its
950-economic rationale for the planned refueling, including
951-anticipated ratepayer impacts, and information concerning
952-the public utility's plan or plans with respect to the extent to
953-which the refueling will maintain or increase the current
954-generating resource accredited capacity or energy, or both,
955-that the electric generating facility provides, so as to provide
956-approximately the same accredited capacity within the
957-appropriate regional transmission organization.
958-(2) (4) The amount of generating resource capacity or energy, or
959-both, that the public utility has procured under contract and that
960-will be used to provide electric service to Indiana customers,
961-including the:
962-(A) capacity;
963-(B) location; and
964-(C) fuel source;
965-for each electric generating facility that will supply capacity or
966-energy under the contract, to the extent known by the public
967-utility.
968-(3) (5) The amount of demand response resources available to the
969-public utility under contracts and tariffs.
970-(4) (6) The following:
971-(A) The planning reserve margin requirements established by
972-MISO for the planning years covered by the report, to the
973-extent known by the public utility with respect to any
974-particular planning year covered by the report.
975-(B) If applicable, any other planning reserve margin
976-requirement that:
977-(i) applies to the planning years covered by the report; and
978-(ii) the public utility is obligated to meet in accordance with
979-the public utility's membership in an appropriate regional
980-transmission organization;
981-HEA 1007 — Concur 24
982-to the extent known by the public utility with respect to any
983-particular planning year covered by the report.
984-(C) Other federal reliability requirements that the public utility
985-is obligated to meet in accordance with its membership in an
986-appropriate regional transmission organization with respect to
987-the planning years covered by the report, to the extent known
988-by the public utility with respect to any particular planning
989-year covered by the report.
990-For each planning reserve margin requirement reported under
991-clause (A) or (B), the public utility shall include a comparison of
992-that planning reserve margin requirement to the planning reserve
993-margin requirement established by the same regional transmission
994-organization for the 2021-2022 planning year.
995-(5) (7) The reliability adequacy metrics of the public utility, as
996-forecasted for the three (3) planning years covered by the report.
997-(m) (o) Upon request by a public utility, the commission shall
998-determine whether information provided in a report filed by the public
999-utility under subsection (l): (n):
1000-(1) is confidential under IC 5-14-3-4 or is a trade secret under
1001-IC 24-2-3;
1002-(2) is exempt from public access and disclosure by Indiana law;
1003-and
1004-(3) shall be treated as confidential and protected from public
1005-access and disclosure by the commission.
1006-(n) (p) A joint agency created under IC 8-1-2.2 may file the report
1007-required under subsection (l) (n) as a consolidated report on behalf of
1008-any or all of the municipally owned utilities that make up its
1009-membership.
1010-(o) (q) A:
1011-(1) corporation organized under IC 23-17 that is an electric
1012-cooperative and that has at least one (1) member that is a
1013-corporation organized under IC 8-1-13; or
1014-(2) general district corporation within the meaning of
1015-IC 8-1-13-23;
1016-may file the report required under subsection (l) (n) as a consolidated
1017-report on behalf of any or all of the cooperatively owned electric
1018-utilities that it serves.
1019-(p) (r) In reviewing a report filed by a public utility under
1020-subsection (l), (n), the commission may request technical assistance
1021-from MISO or any other appropriate regional transmission organization
1022-in determining:
1023-(1) the planning reserve margin requirements or other federal
1024-HEA 1007 — Concur 25
1025-reliability requirements that the public utility is obligated to meet,
1026-as described in subsection (l)(4); (n)(6); and
1027-(2) whether the resources available to the public utility under
1028-subsections (l)(1) (n)(1) through (l)(3) (n)(5) will be adequate to
1029-support the provision of reliable electric service to the public
1030-utility's Indiana customers.
1031-(s) With respect to a report submitted under subsection (n) after
1032-December 31, 2025, commission staff shall review the reports
1033-submitted by public utilities and shall, not later than ninety (90)
1034-days after the date of submission of the reports, submit to the
1035-commission a staff report concerning any planned retirements
1036-included in the reports under subsection (n)(2). The report must
1037-make recommendations to the commission based on whether each
1038-planned retirement:
1039-(1) is consistent with the standards set forth in subsection (m);
1040-(2) will be replaced with an amount of replacement capacity
1041-that will provide approximately the same accredited capacity
1042-within the appropriate regional transmission organization as
1043-the amount of capacity of the facility to be retired;
1044-(3) will not adversely and unreasonably impact a public
1045-utility's ability to provide safe, reliable, and economical
1046-electric utility service to the public utility's customers;
1047-(4) will result in the provision to Indiana customers of electric
1048-utility service with the attributes of:
1049-(A) reliability;
1050-(B) affordability;
1051-(C) resiliency;
1052-(D) stability; and
1053-(E) environmental sustainability;
1054-as set forth in IC 8-1-2-0.6; and
1385+development project".
1386+Page 16, line 6, delete "more potential new large load customers".
1387+Page 22, line 2, delete "Actual project development costs that are".
1388+Page 22, delete lines 3 through 8.
1389+Page 22, line 17, delete "Reasonable and necessary project
1390+development costs that are" and insert "Project development costs
1391+that are found by the commission to be reasonable, necessary, and
1392+consistent with the best estimate of project development costs in
1393+the commission's order of approval under subsection (e) shall be
1394+recovered by a public utility by inclusion in the public utility's
1395+rates and charges. Project development costs that are incurred by
1396+a public utility and that exceed the best estimate of project
1397+development costs under subsection (e) may not be included in the
1398+public utility's rates and charges unless found by the commission
1399+to be reasonable, necessary, and prudent in supporting the
1400+construction, purchase, or lease of the small modular nuclear
1401+reactor for which they were incurred. Project development costs
1402+that are incurred by a public utility for a project that is canceled
1403+or not completed may be recovered by the public utility if found by
1404+the commission to be reasonable, necessary, and prudently
1405+incurred, but such costs shall be recovered without a return unless
1406+the commission also finds that:
1407+(1) the decision to cancel or not complete the project was
1408+prudently made for good cause;
1409+(2) the project development costs incurred will be offset, as
1410+applicable, by:
1411+(A) funding opportunities from the United States
1412+Department of Energy that are pursued in good faith by
1413+the public utility;
1414+(B) a recoupment of revenues received by the public utility
1415+from one (1) or more third parties for the transfer of assets
1416+created through the costs incurred; or
1417+(C) a reimbursement of costs by a single customer or
1418+prospective customer at whose request the project was
1419+pursued; and
1420+(3) a return on the project development costs incurred is
1421+appropriate under the circumstances to avoid harm to the
1422+public utility and its customers.
1423+(k) A public utility may elect not to seek approval of, or cost
1424+recovery for, project development costs under subsections (e)
1425+EH 1007—LS 7547/DI 101 32
1426+through (i) and instead seek approval from the commission to defer
1427+and amortize project development costs in accordance with the
1428+procedures set forth in section 6.5 of this chapter with respect to
1429+construction costs.".
1430+Page 22, delete lines 18 through 31.
1431+Page 22, line 32, delete "(k)" and insert "(l)".
1432+Page 22, line 33, delete "(j)." and insert "(k).".
1433+Page 22, line 34, delete "(l)" and insert "(m)".
1434+Page 24, line 1, delete "of at least one" and insert "with a
1435+nameplate capacity of at least one hundred twenty-five (125)
1436+megawatts by a public utility.".
1437+Page 24, delete line 2.
1438+Page 24, line 6, delete "(u)(2)(B)," and insert "(u)(2),".
1439+Page 24, line 20, delete "(u)(2)(B)," and insert "(u)(2),".
1440+Page 24, line 34, delete "(u)(2)(B)," and insert "(u)(2),".
1441+Page 25, line 2, delete "(u)(2)(B)," and insert "(u)(2),".
1442+Page 25, line 14, delete "of at least one hundred" and insert "with
1443+a nameplate capacity of at least one hundred twenty-five (125)
1444+megawatts by a public utility.".
1445+Page 25, delete line 15.
1446+Page 27, line 11, delete "retire," and insert "retire and that is
1447+owned and operated by the public utility and used to provide retail
1448+electric service in Indiana,".
1449+Page 27, line 16, delete "facility that the public utility" and insert
1450+"facility. The public utility must include information as to whether
1451+the planned retirement is required in order to comply with
1452+environmental laws, regulations, or court orders, including consent
1453+decrees, that are or will be in effect at the time of the planned
1454+retirement.".
1455+Page 27, line 17, delete "plans to retire. The" and insert "In
1456+addition, the".
1457+Page 27, line 22, delete "credit" and insert "accredited".
1458+Page 27, line 40, after "resource" insert "accredited".
1459+Page 27, line 41, delete "provides." and insert "provides, so as to
1460+provide approximately the same accredited capacity within the
1461+appropriate regional transmission organization.".
1462+Page 29, line 29, delete "Commission" and insert "With respect to
1463+a report submitted under subsection (n) after December 31, 2025,
1464+commission".
1465+Page 29, line 30, delete "under subsection (n)".
1466+Page 29, line 38, delete "capacity credit" and insert "accredited
1467+capacity".
1468+EH 1007—LS 7547/DI 101 33
1469+Page 30, line 1, delete "and".
1470+Page 30, line 9, delete "IC 8-1-2-0.6." and insert "IC 8-1-2-0.6; and
10551471 (5) is required in order to comply with environmental laws,
10561472 regulations, or court orders, including consent decrees, that
1057-are or will be in effect at the time of the planned retirement.
1058-(t) The commission shall make the staff reports prepared under
1059-subsection (s) publicly available by posting the staff reports on the
1060-commission's website. Upon the posting of a staff report on the
1061-commission's website, the commission shall accept public
1062-comments on the report for a period not to exceed thirty (30) days
1063-after the date of posting.
1064-(q) (u) If, after reviewing a report filed by a public utility under
1065-subsection (l), (n) and any staff report prepared with respect to the
1066-public utility under subsection (s), the commission is not satisfied
1067-HEA 1007 — Concur 26
1068-that the public utility can either:
1069-(1) provide reliable electric service to the public utility's Indiana
1070-customers; or
1071-(2) either:
1072-(A) (1) satisfy both:
1073-(i) (A) its planning reserve margin requirement or other
1074-federal reliability requirements that the public utility is
1075-obligated to meet, as described in subsection (l)(4); (n)(6); and
1076-(ii) (B) the reliability adequacy metrics set forth in subsection
1077-(g); (h); or
1078-(B) (2) provide sufficient reason as to why the public utility is
1079-unable to satisfy both:
1080-(i) (A) its planning reserve margin requirement or other
1081-federal reliability requirements that the public utility is
1082-obligated to meet, as described in subsection (l)(4); (n)(6); and
1083-(ii) (B) the reliability adequacy metrics set forth in subsection
1084-(g); (h);
1085-during one (1) more of the planning years covered by the report, the
1086-commission may shall conduct an investigation under IC 8-1-2-58
1087-through IC 8-1-2-60 as to the reasons for the public utility's potential
1088-inability to meet the requirements described in subdivision (1) or (2),
1089-or both. provide sufficient reason as to that inability, as described
1090-in subdivision (2). In addition, if the public utility has indicated in
1091-its report under subsection (n)(2) that it plans to retire an electric
1092-generating facility within one (1) year of the date of the report, the
1093-commission must conduct an investigation under IC 8-1-2-58
1094-through IC 8-1-2-60 as to the reasons for the public utility's
1095-potential inability to meet the requirements described in
1096-subdivision (1) or provide sufficient reason as to that inability, as
1097-described in subdivision (2). However, a public utility may request,
1098-not earlier than three (3) years before the planned retirement date
1099-of an electric generation facility, that the commission conduct an
1100-investigation under IC 8-1-2-58 through IC 8-1-2-60, for the
1101-purposes described in this subsection, with respect to the planned
1102-retirement. If the commission conducts an investigation at the
1103-request of a public utility within the three (3) year period before
1104-the planned retirement date of an electric generation facility, the
1105-commission may not conduct a subsequent investigation that would
1106-otherwise be required under this subsection with respect to the
1107-retirement of that same electric generation facility unless the
1108-commission is not satisfied, as of the time that an investigation
1109-would otherwise be required under this subsection, that the public
1110-HEA 1007 — Concur 27
1111-utility can meet the requirements described in subdivision (1) or
1112-provide sufficient reason as to that inability, as described in
1113-subdivision (2). If a certificate is granted by the commission under
1114-this chapter for a facility intended to repower or replace a
1115-generation unit that is planned for retirement, and the certificate
1116-includes findings that the project will result in at least equivalent
1117-accredited capacity and will provide economic benefit to
1118-ratepayers as compared to the continued operation of the
1119-generating unit to be retired, the certificate under this chapter
1120-constitutes approval by the commission for purposes of an
1121-investigation required by this subsection. However, if the
1122-commission finds that facts and circumstances regarding the
1123-planned retirement have changed significantly since the certificate
1124-was granted and that those changes concern the public utility's
1125-ability to meet the requirements described in subdivision (1), the
1126-commission may conduct an investigation into the planned
1127-retirement of the unit.
1128-(r) (v) If, upon investigation under IC 8-1-2-58 through IC 8-1-2-60,
1129-and after notice and hearing, as required by IC 8-1-2-59, the
1130-commission determines that the capacity resources available to the
1131-public utility under subsections (l)(1) (n)(1) through (l)(3) (n)(5) will
1132-not be adequate to support the provision of reliable electric service to
1133-the public utility's Indiana customers, or to allow the public utility to
1134-satisfy both its planning reserve margin requirements or other federal
1135-reliability requirements that the public utility is obligated to meet (as
1136-described in subsection (l)(4)) (n)(6)) and the reliability adequacy
1137-metrics set forth in subsection (g), (h), the commission shall issue an
1138-order:
1139-(1) directing the public utility to acquire or construct; or
1140-(2) prohibiting the retirement or refueling of;
1141-such capacity resources that are reasonable and necessary to enable the
1142-public utility to provide reliable electric service to its Indiana
1143-customers, and to satisfy both its planning reserve margin requirements
1144-or other federal reliability requirements described in subsection (l)(4)
1145-(n)(6) and the reliability adequacy metrics set forth in subsection (g).
1146-(h). The commission shall issue an order under this subsection not
1147-later than one hundred twenty (120) days after the initiation of the
1148-investigation under subsection (u). If the commission does not issue
1149-an order within the one hundred twenty (120) day period
1150-prescribed by this subsection, the public utility is considered to be
1151-able to meet the requirements described in subsection (u)(1) with
1152-respect to the retirement of the electric generation facility under
1153-HEA 1007 — Concur 28
1154-investigation. Not later than ninety (90) days after the date of the
1155-commission's an order by the commission under this subsection, the
1156-public utility shall file for approval with the commission a plan to
1157-comply with the commission's order. Notwithstanding IC 8-1-3 or
1158-any other law, any appeal of an order by the commission under this
1159-subsection is entitled to priority review and shall be given
1160-expedited consideration in accordance with Rule 21 of the Indiana
1161-Rules of Appellate Procedure.
1162-(w) With respect to a report submitted under subsection (n)
1473+are or will be in effect at the time of the planned retirement.".
1474+Page 30, line 19, after "can" delete ":" and insert "either:".
1475+Page 30, strike lines 20 through 22.
1476+Page 30, line 23, beginning with "(A)" begin a new line block
1477+indented.
1478+Page 30, line 23, strike "(A)" and insert "(1)".
1479+Page 30, line 24, beginning with "(i)" begin a new line double block
1480+indented.
1481+Page 30, line 24, strike "(i)" and insert "(A)".
1482+Page 30, line 27, beginning with "(ii)" begin a new line double block
1483+indented.
1484+Page 30, line 27, strike "(ii)" and insert "(B)".
1485+Page 30, line 29, beginning with "(B)" begin a new line block
1486+indented.
1487+Page 30, line 29, strike "(B)" and insert "(2)".
1488+Page 30, line 31, beginning with "(i)" begin a new line double block
1489+indented.
1490+Page 30, line 31, strike "(i)" and insert "(A)".
1491+Page 30, line 34, beginning with "(ii)" begin a new line double block
1492+indented.
1493+Page 30, line 34, strike "(ii)" and insert "(B)".
1494+Page 30, line 37, strike "may" and insert "shall".
1495+Page 30, line 39, strike "(2), or both." and insert "provide sufficient
1496+reason as to that inability, as described in subdivision (2).".
1497+Page 30, line 40, delete "However," and insert "In addition,".
1498+Page 30, line 41, delete "(n)" and insert "(n)(2)".
1499+Page 31, line 3, delete "(2), or both." and insert "provide sufficient
1500+reason as to that inability, as described in subdivision (2). However,
1501+a public utility may request, not earlier than three (3) years before
1502+the planned retirement date of an electric generation facility, that
1503+the commission conduct an investigation under IC 8-1-2-58
1504+through IC 8-1-2-60, for the purposes described in this subsection,
1505+with respect to the planned retirement. If the commission conducts
1506+an investigation at the request of a public utility within the three
1507+(3) year period before the planned retirement date of an electric
1508+generation facility, the commission may not conduct a subsequent
1509+investigation that would otherwise be required under this
1510+subsection with respect to the retirement of that same electric
1511+EH 1007—LS 7547/DI 101 34
1512+generation facility unless the commission is not satisfied, as of the
1513+time that an investigation would otherwise be required under this
1514+subsection, that the public utility can meet the requirements
1515+described in subdivision (1) or provide sufficient reason as to that
1516+inability, as described in subdivision (2). If a certificate is granted
1517+by the commission under this chapter for a facility intended to
1518+repower or replace a generation unit that is planned for
1519+retirement, and the certificate includes findings that the project
1520+will result in at least equivalent accredited capacity and will
1521+provide economic benefit to ratepayers as compared to the
1522+continued operation of the generating unit to be retired, the
1523+certificate under this chapter constitutes approval by the
1524+commission for purposes of an investigation required by this
1525+subsection. However, if the commission finds that facts and
1526+circumstances regarding the planned retirement have changed
1527+significantly since the certificate was granted and that those
1528+changes concern the public utility's ability to meet the
1529+requirements described in subdivision (1), the commission may
1530+conduct an investigation into the planned retirement of the unit.".
1531+Page 31, line 8, strike "to support the provision of reliable electric
1532+service to".
1533+Page 31, line 9, strike "the public utility's Indiana customers, or".
1534+Page 31, line 22, after "(h)." insert "The commission shall issue an
1535+order under this subsection not later than one hundred twenty
1536+(120) days after the initiation of the investigation under subsection
1537+(u). If the commission does not issue an order within the one
1538+hundred twenty (120) day period prescribed by this subsection, the
1539+public utility is considered to be able to meet the requirements
1540+described in subsection (u)(1) with respect to the retirement of the
1541+electric generation facility under investigation.".
1542+Page 31, line 22, strike "the commission's" and insert "an".
1543+Page 31, line 23, after "order" insert "by the commission".
1544+Page 31, between lines 28 and 29, begin a new paragraph and insert:
1545+"(w) With respect to a report submitted under subsection (n)
11631546 after December 31, 2025, if the commission issues an order under
11641547 subsection (v) to prohibit the retirement or refueling of an electric
11651548 generation resource, the commission shall create a sub-docket to
11661549 authorize the public utility to recover in rates the costs of the
11671550 continued operation of the electric generation resource that was
11681551 proposed to be retired or refueled. The commission must find that
11691552 the continued costs of operation are just and reasonable before
11701553 authorizing their recovery in the public utility's rates. The creation
1554+EH 1007—LS 7547/DI 101 35
11711555 of a sub-docket under this subsection is not subject to the one
11721556 hundred twenty (120) day time frame for the commission to issue
1173-an order under subsection (v).
1174-The (x) A public utility's plan under subsection (v) may include:
1175-(1) a request for a certificate of public convenience and necessity
1176-under this chapter; or
1177-(2) an application under IC 8-1-8.8;
1178-or both.
1179-(s) (y) Beginning in 2022, the commission shall include in its annual
1180-report under IC 8-1-1-14 the following information:
1181-(1) The commission's analysis regarding the ability of public
1182-utilities to:
1183-(A) provide reliable electric service to Indiana customers; and
1184-(B) satisfy both:
1185-(i) their planning reserve margin requirements or other
1186-federal reliability requirements; and
1187-(ii) the reliability adequacy metrics set forth in subsection
1188-(g); (h);
1189-for the next three (3) utility resource planning years, based on the
1190-most recent reports filed by public utilities under subsection (l).
1191-(n).
1192-(2) A summary of:
1193-(A) the projected demand for retail electricity in Indiana over
1194-the next calendar year; and
1195-(B) the amount and type of capacity resources committed to
1196-HEA 1007 — Concur 29
1197-meeting the projected demand;
1198-(C) beginning with the commission's annual report due
1199-before October 1, 2026, and in each subsequent annual
1200-report, the planned retirements or refuelings of electric
1201-generation resources and the plans to replace or retain the
1202-capacity or energy, or both, of the electric generation
1203-resources planned to be retired or refueled; and
1204-(D) beginning with the commission's annual report due
1205-before October 1, 2026, and in each subsequent annual
1206-report, the reports of commission staff under subsection
1207-(s).
1208-In preparing the summary required under this subdivision, the
1209-commission may consult with the forecasting group established
1210-under section 3.5 of this chapter.
1211-(3) Beginning with the commission's annual report filed under
1212-IC 8-1-1-14 in 2025, the commission's analysis regarding the
1213-appropriate percentage or portion of:
1214-(A) total spring UCAP that public utilities should be
1215-authorized to acquire from capacity markets under subsection
1216-(g)(3)(B); (h)(3)(B); and
1217-(B) total fall UCAP that public utilities should be authorized
1218-to acquire from capacity markets under subsection (g)(4)(B).
1219-(h)(4)(B).
1220-(t) (z) The commission may adopt rules under IC 4-22-2 to
1221-implement this section.
1222-SECTION 5. An emergency is declared for this act.
1223-HEA 1007 — Concur Speaker of the House of Representatives
1224-President of the Senate
1225-President Pro Tempore
1226-Governor of the State of Indiana
1227-Date: Time:
1228-HEA 1007 — Concur
1557+an order under subsection (v).".
1558+Page 31, line 29, delete "(w)" and insert "(x)".
1559+Page 31, line 34, delete "(x)" and insert "(y)".
1560+Page 32, line 32, delete "(y)" and insert "(z)".
1561+and when so amended that said bill do pass.
1562+(Reference is to HB 1007 as introduced.)
1563+SOLIDAY
1564+Committee Vote: yeas 9, nays 4.
1565+_____
1566+COMMITTEE REPORT
1567+Mr. Speaker: Your Committee on Ways and Means, to which was
1568+referred House Bill 1007, has had the same under consideration and
1569+begs leave to report the same back to the House with the
1570+recommendation that said bill do pass.
1571+(Reference is to HB 1007 as printed January 29, 2025.)
1572+THOMPSON
1573+Committee Vote: Yeas 16, Nays 7
1574+_____
1575+HOUSE MOTION
1576+Mr. Speaker: I move that House Bill 1007 be amended to read as
1577+follows:
1578+Page 3, between lines 20 and 21, begin a new paragraph and insert:
1579+"SECTION 2. IC 8-1-2-24.5 IS ADDED TO THE INDIANA CODE
1580+AS A NEW SECTION TO READ AS FOLLOWS [EFFECTIVE
1581+UPON PASSAGE]: Sec. 24.5. (a) As used in this section, "energy
1582+utility" means:
1583+(1) an electric utility listed in 170 IAC 4-7-2(a) and any
1584+successor in interest to that utility; or
1585+(2) a corporation organized under IC 8-1-13.
1586+(b) As used in this section, "large load customer" means a new
1587+or existing customer of an energy utility, or not more than four (4)
1588+EH 1007—LS 7547/DI 101 36
1589+multiple new or existing customers of an energy utility, that
1590+requests new or additional electricity demand that in the aggregate
1591+exceeds the lesser of:
1592+(1) five percent (5%) of the energy utility's average peak
1593+demand over the most recent three (3) calendar years; or
1594+(2) one hundred fifty (150) megawatts.
1595+(c) As used in this section, "project" refers to a project relating
1596+to energy infrastructure or generation resources that:
1597+(1) are required primarily to serve a large load customer of an
1598+energy utility; and
1599+(2) may be designed to serve more than one (1) large load
1600+customer of the energy utility or to meet other customer
1601+demand or energy needs.
1602+(d) As used in this section, "project costs" means the total costs
1603+of a project, including:
1604+(1) planning costs; and
1605+(2) construction and operating costs;
1606+related to the project.
1607+(e) Any standard tariff offered by an energy utility after June
1608+30, 2025, to a large load customer of the energy utility must include
1609+a provision that requires reimbursement by the large load
1610+customer of at least eighty percent (80%) of the project costs
1611+reasonably allocable to the large load customer, regardless of
1612+whether the large load customer ultimately takes service in any
1613+anticipated amount and within any anticipated time frame.".
1614+Page 10, line 29, delete "seventy-five percent (75%)" and insert
1615+"eighty percent (80%)".
1616+Page 11, line 6, after "large" insert "load".
1617+Page 13, line 24, after "hundred" insert "fifty".
1618+Renumber all SECTIONS consecutively.
1619+(Reference is to HB 1007 as printed February 6, 2025.)
1620+PIERCE M
1621+_____
1622+COMMITTEE REPORT
1623+Mr. President: The Senate Committee on Utilities, to which was
1624+referred House Bill No. 1007, has had the same under consideration
1625+and begs leave to report the same back to the Senate with the
1626+recommendation that said bill be AMENDED as follows:
1627+EH 1007—LS 7547/DI 101 37
1628+Page 3, delete lines 21 through 42.
1629+Page 4, delete lines 1 through 12.
1630+Page 4, line 13, delete "IC 8-1-8.2" and insert "IC 8-1-7.9".
1631+Page 4, line 16, delete "8.2." and insert "7.9.".
1632+Page 5, line 42, delete "mean" and insert "means".
1633+Page 7, line 19, after "In" insert "a".
1634+Page 15, line 9, delete "non-generation" and insert
1635+"nongeneration".
1636+Page 17, line 19, delete "IC 8-1-2-42" and insert "IC 8-1-2-24".
1637+ Page 17, line 20, delete "IC 8-1-2-43" and insert "IC 8-1-2-25".
1638+Page 17, line 24, delete "dates" and insert "days".
1639+Renumber all SECTIONS consecutively.
1640+and when so amended that said bill do pass and be reassigned to the
1641+Senate Committee on Tax and Fiscal Policy.
1642+(Reference is to HB 1007 as reprinted February 11, 2025.)
1643+KOCH, Chairperson
1644+Committee Vote: Yeas 8, Nays 3.
1645+_____
1646+COMMITTEE REPORT
1647+Mr. President: The Senate Committee on Tax and Fiscal Policy, to
1648+which was referred Engrossed House Bill No. 1007, has had the same
1649+under consideration and begs leave to report the same back to the
1650+Senate with the recommendation that said bill DO PASS.
1651+ (Reference is to EHB 1007 as printed March 28, 2025.)
1652+
1653+HOLDMAN, Chairperson
1654+Committee Vote: Yeas 10, Nays 3
1655+EH 1007—LS 7547/DI 101 38
1656+SENATE MOTION
1657+Mr. President: I move that Engrossed House Bill 1007 be amended
1658+to read as follows:
1659+Page 18, delete lines 12 through 42.
1660+Delete pages 19 through 22.
1661+Page 23, delete lines 1 through 23.
1662+Renumber all SECTIONS consecutively.
1663+(Reference is to EHB 1007 as printed April 9, 2025.)
1664+KOCH
1665+EH 1007—LS 7547/DI 101