Indiana Utility Commission TDSIC Rate Schedule Order

STATE OF INDIANA

INDIANA UTILITY REGULATORY COMMISSION

) FOR (1) APPROVAL OF AN ADJUSTMENT TO ) ) ) STORAGE SYSTEM IMPROVEMENT CHARGE ) (“TDSIC”) RATE SCHEDULE; (2) AUTHORITY ) TO DEFER 20% OF THE APPROVED CAPITAL ) CAUSE NO. 45330 TDSIC 10 ) ) APPROVED: ) OF PETITIONER’S UPDATED 2020-2025 TDSIC ) PLAN, INCLUDING ACTUAL AND PROPOSED ) ESTIMATED ) TDSIC COSTS THAT EXCEED THE APPROVED ) AMOUNTS IN CAUSE NO. 45330-TDSIC-9, ALL )

ORDER OF THE COMMISSION Presiding Officers: Anthony F. Swinger, Commissioner Sean Gorman, Administrative Law Judge

On November 25, 2025, Northern Indiana Public Service Company LLC (“Petitioner”) filed its Verified Petition with the Indiana Utility Regulatory Commission (“Commission”) for approval of a new Transmission, Distribution, and Storage System Improvement Charge (“TDSIC”) pursuant to Indiana Code § 8-1-39-9. Also on November 25, 2025, Petitioner filed its direct testimonies and exhibits of Gregory

1. Berning, Thomas P. Harmon, Ryan T. Carr, and Ryan Hutnick. VERIFIED PETITION OF NORTHERN ) On January 27, 2026, the Indiana Office of Utility Consumer Counselor (“OUCC”) filed INDIANA PUBLIC SERVICE COMPANY LLC the direct testimonies and exhibits of Mohab M. Noureldin and Jared J. Hoff. On February 2, 2026,

Petitioner filed a notice of intent not to file rebuttal testimony. Also on February 2, 2026, Petitioner ITS GAS SERVICE RATES THROUGH ITS submitted a revised Attachment 3. TRANSMISSION, DISTRIBUTION, AND

The Commission conducted an evidentiary hearing at 1:30 p.m. on February 23, 2026, in Room 222 of the PNC Center, 101 West Washington Street, Indianapolis, Indiana. The Presiding Commissioner asked clarifying questions of Petitioner’s witnesses Berning and Carr. Petitioner, EXPENDITURES AND TDSIC COSTS FOR by counsel, offered the testimony and exhibits of its witnesses and they were admitted into RECOVERY IN PETITIONER’S NEXT evidence without objection. The OUCC participated in the evidentiary hearing by counsel, during GENERAL RATE CASE; AND (3) APPROVAL ORIGINAL CommissionerYes No

Zay CAPITAL EXPENDITURES AND Deig ger SwinVeleta Not MAR 25 2026 PURSUANT TO IND. CODE § 8-1-39-9. ) Ziegner Participating √ √ √ √ √

which the testimonies and exhibits of the OUCC’s witnesses were admitted into evidence without objection. Based on the applicable law and evidence presented, the Commission now finds: 1. Notice and Jurisdiction. Notice of the hearing in this Cause was given and published as required by law. Petitioner is a public utility as that term is defined in Ind. Code §§ 8-1-2-1(a) and 8-1-39-4. Under Ind. Code ch. 8-1-39, the Commission has jurisdiction over a public utility’s petition requesting approval of rate schedules that establish a TDSIC that will allow for the periodic automatic adjustment of the public utility’s basic rates and charges to provide for timely recovery of 80% of approved capital expenditures and TDSIC costs. Therefore, the Commission has jurisdiction over Petitioner and the subject matter of this proceeding. 2. Petitioner’s Characteristics. Petitioner is a public utility organized and existing under the laws of the state of Indiana, with its principal office at 801 E. 86 Avenue, Merrillville, thIndiana. Petitioner renders electric and natural gas public utility service in the state of Indiana and owns, operates, manages, and controls, among other things, plant and equipment in Indiana used for the generation, transmission, distribution, and furnishing of such service to the public. Petitioner provides gas utility service to more than 871,000 residential, commercial, and industrial gas customers in northern Indiana. 3. Background and Relief Requested. On July 22, 2020, the Commission issued an Order in Cause No. 45330 (“45330 Order”), approving Petitioner’s 2020-2025 TDSIC Plan for eligible transmission, distribution, and storage system improvements pursuant to Ind. Code §§ 8- 1-39-10 and 11. Through the 45330 Order, the Commission approved Petitioner’s proposal to include all rural customers in the updated estimate and to provide an 80% credit to the TDSIC tracker for actual margins received from all new customers added under the rural extension projects. The Commission authorized Petitioner to defer 20% of the TDSIC costs incurred in connection with the approved eligible improvements, including ongoing carrying charges based on the current overall weighted average cost of capital, and recover those deferred costs in base rates. Subsequent to the 45330 Order, the Commission issued Orders in TDSIC Causes that approved updates to the 2020-2025 TDSIC Plan and associated rate making treatment. On July 27, 2022, the Commission issued an Order in Cause No. 45621 changing Petitioner’s base rates and charges. In its October 26, 2022 Order in Cause No. 45330 TDSIC 5 S1, the commission approved a targeted economic development project to provide gas service to an electric vehicle battery production facility to be located in Kokomo, Indiana for inclusion in the 2020-2025 TDSIC Plan. Petitioner was authorized by the Commission to recover 80% of the costs incurred in connection with this project through the TDSIC and to defer 20% of the costs incurred, including ongoing carrying charges on all deferred costs, for recovery in its next general rate case. On July 31, 2024, the Commission issued an Order in Cause No. 45967 changing Petitioner’s base rates and charges.

In the current Cause, Petitioner requests that the Commission (a) approve an adjustment to its gas rates to go into effect on April 1, 2026, to effectuate the timely recovery of 80% of approved capital expenditures and TDSIC costs incurred through September 30, 2025; (2) authorize Petitioner to defer, as a regulatory asset, 20% of eligible and approved capital expenditures and TDSIC costs and record ongoing carrying charges based on the current overall weighted average cost of capital on all deferred TDSIC costs until such costs are included for recovery in base rates; (3) approve Petitioner’s updated TDSIC plan (“Plan Update-10”), including actual and proposed estimated capital expenditures and TDSIC costs that exceed the amounts previously approved; and (4) approve deferral and recovery of 80% of eligible and approved capital expenditures and TDSIC costs in connection with the updated plan through the TDSIC and deferral of 20% of eligible and approved capital expenditures and TDSIC costs in connection with the updated TDSIC plan, for recovery in base rates. 4. Evidence Presented. A. Petitioner’s Case-In-Chief. 1. Gregory P. Berning. In his prefiled testimony, Mr. Berning, Manager of Regulatory Policy for Petitioner, testified to the relief Petitioner seeks in this filing as well as Petitioner’s statutory compliance with Ind. Code § 8-1-39-9. He stated that all TDSIC projects included for recovery in this filing were or will be undertaken for the purpose of safety, reliability, system modernization, or economic development. Mr. Berning stated that Petitioner is seeking approval of actual and estimated capital expenditures or TDSIC costs beyond what the Commission has previously approved. He also noted that the rural extension projects were undertaken for the purpose of extending gas service in rural areas. He testified that none of these projects were included in Petitioner’s rate base in Cause No. 45967. He testified that Petitioner has complied with the requirement in Ind. Code § 8-1-39-9(e) because Petitioner petitioned the Commission for review of its basic gas rates and charges before the expiration of the TDSIC 2020- 2025 Plan in Cause Nos. 45621 (September 9, 2021) and 45967 (October 25, 2023). He further testified to Petitioner’s most recent TDSIC adjustment filing in Plan Update-9. Mr. Berning testified that Petitioner met with the OUCC and NIPSCO Industrial Group on October 28, 2025 to review the proposed Plan Update-10 prior to filing with the Commission. During that meeting, Petitioner identified known changes to projects approved in Plan Update-9. He concluded his testimony by stating that all updates to Plan Update-10 were provided to its stakeholders and that at the time of the filing, Petitioner was not aware of any unresolved issues. At the evidentiary hearing, and in response to questions from the Presiding Commissioner, Mr. Berning testified generally about the TDSIC Plan update process and explained that over the multi-year period of a TDSIC Plan, cost estimates change as the project scopes sharpen and economic factors such as price volatility cause cost fluctuations. He emphasized the importance of the project update filings and testified regarding ongoing stakeholder feedback, the transparency of project cost estimates in each semi-annual update filing, and Petitioner’s consideration of customer affordability when addressing and managing TDSIC projects.

1. Thomas P. Harmon. Mr. Harmon, Manager of Regulatory for NiSource Corporate Services Company, testified regarding Petitioner’s proposed ratemaking treatment. He stated that the total cost of the eligible improvements upon which Petitioner requests authority to earn a return is $90,179,419. This amount includes an allowance of funds used during construction (“AFUDC”), other indirect costs, and is net of accumulated depreciation, incurred through September 30, 2025. Mr. Harmon explained the manner in which Petitioner calculated its revenue requirement, proposed “return on” portion of the revenue requirement, AFUDC, depreciation, post-in-service carrying charges, and revenue conversion factor used to compute Petitioner’s pre-tax revenue requirement. He provided information regarding projected depreciation expense and property taxes for the period April through September 2026. Mr. Harmon explained the reconciliation of the Cause No. 45330 TDSIC 8 revenue requirement against the actual revenues billed to customers during September 2024 through September 2025, results in an over-collection of $269,711. Mr. Harmon testified that the proposed TDSIC factors will not result in an average aggregate increase in Petitioner’s total retail revenue of more than 2% for the 12-month period ending September 30, 2025. Mr. Harmon stated that the estimated average monthly bill impact of Petitioner’s requested relief in this Cause for a typical residential customer using 71 therms per month is a charge of $1.47, which is an increase of $1.08 from the factor currently in effect. 3. Ryan T. Carr. In his prefiled testimony, Mr. Carr, Manager of Gas TDSIC Engineering and Construction (E&C) Program for Petitioner, described project cost moves and provided specific justification for cost increases greater than $100,000 or 20%, whichever is greater. Mr. Carr testified that Plan Update-10 reflects actual costs through September 30, 2025. He stated that for projects scheduled for completion in 2025, estimates are based on unit costs, or costs based on actual experience. Mr. Carr showed the total projected capital spending, including indirect capital costs and AFUDC, for Plan Update-10 compared to the Commission-approved Plan Update-9, as follows:

4 Plan Update-9 Plan Update-10 Variance PLAN TOTAL $78,325,368 $78,325,368 $0 $129,632,098 $129,632,098 $0 $176,558,638 $176,558,638 $0 $279,886,011 $279,886,011 $0 $70,856,340 $70,856,340 $0 $102,036,436 $92,772,966 $(9,263,470) $837,294,891 $828,031,421 $(9,263,470)

As shown in the table above, Plan Update-10 reflects an overall decrease in direct costs of $9,263,470 in 2025. Mr. Carr provided specific justification for four projects (Project IDs IM24, IM25, IM42, and SLNG4) showing a cost increase greater than $100,000 or 20% (whichever is greater), as follows: a. Corrosion Rectifiers Install/Replace [Project ID IM24]. Petitioner’s approved estimate of costs assumed completion of three units a year. For 2025, Petitioner is on track to complete six units, instead of three, due to circumstances discovered during work being performed. Specifically, three additional units are now required to replace additional failing equipment (rectifier, ground bed, and a reverse current switch) to protect assets against corrosion risks in accordance with federal code on those three units. The estimated cost of the increase is based on proposals from a qualified contractor frequently used by Petitioner for this specialized work, indicating the labor and material rates are in line with market prices and previous projects they have performed, which accounts for approximately (72.8%) of the total increase, inclusive of related project support costs. The proposals were carefully reviewed and found to be reasonable by internal subject matter experts. The remainder of the increase is attributable to NIPSCO’s experience of the average unit costs being greater than the unit costs that were included in the project estimate (prepared in 2019 for 2025). The remaining amount relates to other miscellaneous support costs like survey, inspection, and environmental. b. Corrosion Moisture Monitoring [Project ID IM25]. Mr. Carr testified that the increase is driven by (1) an increase in material costs that could not be foreseen at the time of estimating, and (2) the opportunity to complete one additional unit to take advantage of a gas supplier’s planned outage, resulting in lower labor costs and coordination efforts than if the work was performed in the future, under a separate NIPSCO-driven supplier outage. He stated the decision to add one unit was a prudent, cost-efficient way to perform the work that was needed and will reduce future costs as a result. Material costs in 2025 were higher than the unit costs used to calculate the approved cost estimate prepared in 2019 for 2025. Mr. Carr testified the escalator and contingency estimated in 2019 could not account for cost increases to this extent. Using the per unit increase for the three units that were completed in 2025 accounts for 47% of the total variance. The cost for the additional unit was approximately 42% of the variance. The remaining 11% relates to other miscellaneous support costs such as project controls and internal labor for commissioning. c. Cleveland Cliffs Burns Harbor #2 [Project ID IM42]. In preparing its plan update in this filing, NIPSCO discovered that it had erroneously requested a decrease in TDSIC-9, as that work was planned to be completed in 2025 and is needed now to cover costs for that work. This amount represents 58.8% of the increase. Further, the original project estimate was based on a similar project (Project ID IM41 – Cleveland Cliffs Burns Harbor #1), which was further along in engineering. As Harbor #2 progressed through the engineering process, NIPSCO spent significant time and effort working with the customer to determine a mutually agreeable site for the new station. Four parcels or parcel 5

adjustments were pursued over the course of at least 18 months involving significant surveying, records research and verification of existing third part easements. This work delayed engineering of Harbor #2 until the final site was selected and acquired. Engineering of Harbor #2 determined that an adjustment to the original design requirements of the station was required to meet the customer’s gas demands and pressure requirements for the Harbor #2 station. The Harbor #2 station has both a higher inlet and outlet pressure, larger inlet piping, and larger regulators, and the expected flow through the station is approximately 1.5 times that of Harbor #1. Given these facts, the Harbor #2 station requires a substantially larger heater, filter, and meter than Harbor #1, with these costs representing the balance of the variance amount. d. LNG – Replace Unit #2 Purification Sys. Regen. Gas Heater [Project ID SLNG4]. This increase relates to an unexpected change in scope. The project scope of work called for new heater tie-ins on existing pipe; however, when existing insulation was pulled to expose the existing piping in preparation for making field tie-ins, the piping was significantly pitted and unsuitable. Further exposure of the existing pipe was necessary to locate a suitable tie-in location, which extended an additional approximately 200 feet. The pitted piping and insulation both require replacement. The balance is related to a change order from a different contractor to drain, purge, and refill heat transfer fluids for the system. The estimates for the work as described herein were carefully reviewed and found to be consistent with market prices and reasonable by internal subject matter experts. Mr. Carr testified that Plan Update-10 provides information to support Petitioner’s best estimate of the actual costs or updated cost estimates for projects included in the Plan, including project change requests supporting any project variance that is in excess of $30,000 or 15%, whichever is greater, or any variance that exceeds $100,000 for any project whether or not it meets the 15% threshold, a summary of unit cost estimates, and rural extensions estimates. He stated Petitioner’s best estimate of the costs rests on a sound factual and analytical foundation and is reasonable. He testified the cost increases were driven primarily by discoveries made during project engineering and/or construction that required additional work and materials, as well as significant increases in material and unit costs consistent with market pricing due to unavailability of material and other factors (including inflation and tariffs) beyond Petitioner’s control. He stated the proposed project adjustments that have significant impact on costs are typically peer reviewed with relevant internal subject matter experts which may be composed of other gas Major Projects project managers, representatives from impacted departments, and management level representation, and are reviewed for reasonableness, compared to recently experienced material costs and established labor rates, and discussed to see if any other alternative solutions may be possible. Mr. Carr testified the eligible improvements included in Plan Update-10 will serve the public convenience and necessity by making investments for safety, reliability, system modernization, and economic development consistent with public policy and the public interest. Mr. Carr testified that the eligible improvements included in Plan Update-10 are essential in protecting the integrity, safety, and reliable operation of the system and enhance the ability of Petitioner’s customers to take advantage of the rapid development of alternative natural gas supply 6

and delivery options and also position Petitioner’s system to remain reliable and flexible in the event of significant changes to the economic and operational climate for natural gas. Additionally, he stated that the extension of gas service to rural areas will allow some residents in Petitioner’s service territory to access natural gas services for the first time. Mr. Carr testified that the estimated costs of the eligible improvements included in the Plan Update-10 are justified by incremental benefits attributable to the TDSIC Plan. He stated that Plan Update-10 focuses on maintaining safe, reliable service for Petitioner’s customers in a cost- effective manner. Mr. Carr stated that the rural extensions projects included in Plan Update-10 will continue to increase the number of rural customers served over the life of the TDSIC Plan. Mr. Carr concluded that Plan Update-10 cost effectively addresses safety, reliability, system modernization, and the extension of gas service into rural areas, and provides incremental benefits to Petitioner’s customers. He testified that Petitioner has prioritized and optimized the incremental benefits of Plan Update-10 and shown a sound basis for the proposed projects and associated costs. He testified that Plan Update-10 is proposed to reduce the risk of asset failure, improve public safety, promote economic development, and maintain service reliability and, in doing so, Plan Update-10 provides incremental benefits compared to how the future would otherwise unfold. At the evidentiary hearing, and in response to questions from the Presiding Commissioner, Mr. Carr testified that one way Petitioner addresses customer affordability through the TDSIC Plan is by selecting the right projects to increase reliability for its customers and correctly scoping the projects so not to go beyond what is needed. Additionally, Petitioner utilizes project management processes whereby project cost reviews ensure the proposals to perform work are reasonable. He stated that Petitioner also adds controls to its cost management process to ensure the work is being performed as expected. Mr. Carr stated the Tassinong and 483 loop large projects illustrate the rigor Petitioner has put in place around costs, as both projects came in below the approved amount. Finally, Mr. Carr stated that Petitioner, the OUCC and the Industrial Group have open and fair communication about projects and that Petitioner values their feedback. 4. Ryan Hutnick. Mr. Hutnick, Manager of New Business for Petitioner, stated the forecast in the 2020-2025 TDSIC Plan represents the costs associated with designing and installing gas main and service projects to reach rural areas. He testified that Petitioner will continue to update the average service installation cost in future filings based on Petitioner’s ongoing experience. He explained how Petitioner administers the rural gas extension process. He explained the two primary methods Petitioner uses to determine whether a new rural business project is eligible for TDSIC treatment. He testified that the rural extension projects included in Plan Update-10 are projected to pass the 20-year test identified in Ind. Code § 8-1-39-

In accordance with the June 16, 2021 Order in Cause No. 45330 TDSIC 2, Mr. Hutnick sponsored an annual summary of Project ID RE1 as of December 31, 2023 and December 31, 2024 showing: (1) the estimated and actual customers connected annually; and (2) a margin test for actual customers connected with Rural Extensions. Mr. Hutnick noted that the Order issued in Cause No. 45330 TDSIC 2 also directed that the data be updated annually. 7

1. OUCC’s Case-in-Chief. In his prefiled testimony, Mr. Hoff, a Utility Analyst in the OUCC’s Natural Gas Division, provided an overview of Petitioner’s case-in-chief and revised testimony and attachments. He also provided an analysis of Plan Update-10 costs and project updates included in this filing. Based on his review, he found cost increases were specifically justified and recommended that the Commission approve Petitioner’s Plan Update-10. In his prefiled testimony, Mr. Noureldin, a Utility Analyst in the OUCC’s Natural Gas Division, reviewed Petitioner’s TDSIC cost recovery and revenue calculations and recommended approval of the rate factor calculations in this Cause as shown in Petitioner’s Exhibit 1. He confirmed that Petitioner’s schedules and calculations included in the attachments to the Verified Petition are consistent with the findings in the Commission’s previous Orders in this Cause. Mr. Noureldin stated that he performed a comprehensive analysis of the calculations and data flow contained in Petitioner’s TDSIC rate schedules. He testified that he tied specific data to source documentation provided by Petitioner, verified calculations, and compared the schedules to those schedules approved in Petitioner’s prior TDSIC filings. He stated he also verified customer counts and total therms billed with summary documentation, reviewed work order documentation to verify completed capital projects, and inquired into the calculation and procedures for indirect costs and AFUDC. Mr. Noureldin stated he verified the calculation for Petitioner’s cost of long- term debt and reconciled cost of capital balances with Petitioner’s balance sheet. He also verified the public utility fee and tax rates. Mr. Noureldin testified that the customer class revenue allocation percentages are set forth in Joint Exhibit C of the Stipulation and Settlement Agreement in Cause No. 45967, Petitioner’s most recent rate case. He also reviewed and verified the calculations and allocation of the revenue requirement components and totals presented in Petitioner’s Exhibit 1. Mr. Noureldin testified that Petitioner’s 2% cap test reflected in Petitioner’s Exhibit 1 is calculated correctly. He stated that he traced pertinent numbers to accompanying schedules and verified the calculations provided by Petitioner. He stated that the calculation complies with the provisions of Ind. Code § 8-1-39-14(a) and that Petitioner’s proposed annualized revenue requirement does not exceed the 2% retail revenue cap for the 12 months ended September 30,

2025.

Mr. Noureldin testified that Petitioner’s Exhibit 1 presents the calculation and allocation of the TDSIC rate adjustment factors. He stated that he reviewed the calculations and flow of inputs from other schedules and that Petitioner’s Exhibit 1 accurately reflects the methodology of calculating the TDSIC rate factors. Mr. Noureldin testified that Petitioner’s Exhibit 1 shows the reconciliation of the revenue requirement approved in Cause No. 45330 TDSIC 8 with actual revenue collected during the billing period of September 2024 through September 2025. He stated that the result is an over- recovery in the amount of $269,711, which will be subtracted from the revenue requirement to be collected from customers through the TDSIC rate calculation in this Cause.

Mr. Noureldin testified that Petitioner’s Exhibit 1 reflects the cumulative total deferred revenue requirements, showing the 20% deferred amounts for the past and current TDSIC filings. He stated that prior to Petitioner’s Plan Update-10 filing, much of the deferred revenue requirements from past TDSIC filings were rolled into base rates in the Step 2 compliance filing in Cause No. 45967. He testified that the remaining deferred revenue requirements from the Cause No. 45330 TDSIC 8 Step 2 Compliance Filing are added to Cause No. 45330 TDSIC 9 and 10 deferred revenue requirements to be deferred for recovery in Petitioner’s next rate case. Mr. Noureldin stated that he traced all data input in Petitioner’s Exhibit 1 to the source schedules in the current and previous filings, and compliance filings in Cause No. 45967, and verified the accuracy of Petitioner’s calculations. Mr. Noureldin agreed with the rural extension margin credit calculated on Petitioner’s Exhibit 1. He stated that the margin credit balances the interests of the utility and the ratepayers and the OUCC continues to support Petitioner’s approved 80% margin credit for rural extensions for each TDSIC filing. 5. Commission Discussion and Findings.

1. Compliance with Ind. Code § 8-1-39-9.

2. Ind. Code § 8-1-39-9(a). In this proceeding, Petitioner seeks
   approval of TDSIC factors that will allow for the periodic automatic adjustment of its base rates and charges to provide for timely recovery of 80% of the approved capital expenditures and TDSIC costs. Ind. Code § 8-1-39-9(a) requires that Petitioner’s request (1) use the customer class revenue allocation factor based on firm load approved in Petitioner’s most recent retail base rate case order, (2) include its Commission-approved TDSIC Plan, and (3) include the projected effects of the TDSIC factors on retail rates and charges. Based on the evidence of record, we find that Petitioner has complied with these requirements. 2. Ind. Code § 8-1-39-9(b). Ind. Code § 8-1-39-9(b) provides that a

public utility shall update its TDSIC plan at least annually and may include a request for approval of transmission, distribution, and storage system improvements not described in its TDSIC Plan most recently approved by the Commission under Section 10 of the TDSIC statute. Petitioner’s TDSIC Plan was approved by the 45330 Order which also approved Petitioner’s proposal to update its TDSIC Plan semi-annually. Based on the evidence of record, we find that Petitioner has complied with the requirements of Ind. Code § 8-1-39-9(b). 3. Ind. Code § 8-1-39-9(c). This statutory subsection requires a public

utility that recovers capital expenditures and TDSIC costs under Ind. Code § 8-1-39-9(a) to defer 20% of approved capital expenditures and TDSIC costs, including depreciation, AFUDC, and post in service carrying costs for recovery as part of the utility’s next general rate case. Petitioner therefore proposes to defer, as a regulatory asset, 20% of eligible and approved capital expenditures and TDSIC costs and to record ongoing carrying charges based on the current overall weighted average cost of capital on all deferred TDSIC costs until such costs are included for recovery in Petitioner’s next general rate case. The evidence of record demonstrates that Petitioner has reflected the revenue requirement components on an after-tax basis in the TDSIC revenue 9

requirement, as shown in Petitioner’s Exhibit 1. Based on the evidence of record, we find that Petitioner has complied with the requirements of Ind. Code § 8-1-39-9(c). 4. Ind. Code § 8-1-39-9(d). Petitioner filed its Verified Petition in this

Cause pursuant to Ind. Code § 8-1-39-9(a). Aside from an exception that does not apply, Ind. Code § 8-1-39-9(d) prohibits a utility from filing such a petition within nine months of the date when the Commission issued an Order changing the public utility’s basic rates and charges with respect to the same type of utility service. The Commission issued its Final Order in Petitioner’s most recent rate case (Cause No. 45967) on July 31, 2024. Petitioner filed its Verified Petition in the current Cause on November 25, 2025. Therefore, we find that Petitioner filed its Verified Petition in compliance with Ind. Code § 8-1-39-9(d). 5. Ind. Code § 8-1-39-9(e). Ind. Code § 8-1-39-9(e) states “a public

utility that implements a TDSIC under this chapter shall, before the expiration of the public utility’s approved TDSIC plan, petition the commission for review and approval of the public utility’s basic rates and charges with respect to the same type of utility service.” Petitioner petitioned the Commission for review and approval of its gas basic rates and charges before the December 31, 2025 expiration of its 2020-2025 TDSIC Plan in Cause No. 45621 (September 9, 2021) and 45967 (October 25, 2023). The Commission finds that Petitioner is in compliance with Ind. Code § 8-1- 39-9(e). 6. Ind. Code § 8-1-39-9(f). Ind. Code § 8-1-39-9(f) provides that a

public utility may file a petition under this section not more than one time every six months. Petitioner’s previous filing for timely recovery of its TDSIC costs was May 23, 2025. The Commission finds Petitioner is in compliance with Ind. Code § 8-1-39-9(f). 7. Ind. Code § 8-1-39-9(g). Ind. Code § 8-1-39-9(g) states that

“[a]ctual capital expenditures and TDSIC costs that exceed the approved capital expenditures and TDSIC costs require specific justification by the public utility and specific approval by the commission before being authorized for recovery in customer rates.” Mr. Carr provided the total actual capital expenditures and TDSIC costs that exceed the approved capital expenditures and TDSIC costs associated with Petitioner’s TDSIC Plan as of the September 30, 2025, cutoff date for this filing and described the projects with specific justification to satisfy this requirement. Mr. Harmon provided the in-service costs for the TDSIC projects placed into service by September 30,

1. We have previously found that plan updates should include a discussion of any changes in an eligible improvement’s best estimate of cost, necessity, and associated incremental benefits upon which the Commission based its determination to approve Petitioner’s proposed Plan as reasonable. a. Cost Estimates. Mr. Carr testified that Plan Update-10 reflects actual costs through September 30, 2025. Mr. Carr testified Plan Update-10 reflects moves in Plan years representing an overall decrease in direct costs in 2025.He stated that Plan Update- 10 provides information to support Petitioner’s best estimate of the actual costs or updated cost estimates for projects included in the Plan, including project change requests supporting any project variance that is in excess of $30,000 or 15%, whichever is greater, or any variance that exceeds $100,000 for any project whether or not it meets the 15% threshold, a summary of unit 10

cost estimates, and rural extensions estimates. He stated that Petitioner’s best estimate of the costs rests on a sound factual and analytical foundation and is reasonable. No party objected to the cost estimates and the OUCC recommended the Commission approve Plan Update-10. Accordingly, we find that Petitioner has provided a sufficient level of detail in support of its Plan Update-10, including specific justification for the cost variances associated with approved projects through its exhibits, and we approve these costs in Plan Update-10. b. Public Convenience and Necessity. Mr. Carr testified that consistent with Petitioner’s approved TDSIC Plan, the eligible improvements included in Plan Update-10 will serve the public convenience and necessity. He explained that Plan Update-10 achieves the TDSIC legislative intent of making investments for the purposes of safety, reliability, system modernization, and economic development, consistent with utility practice, and serves the public interest. Mr. Carr testified Petitioner has a statutory obligation to provide adequate retail service in its certificated gas service territory and that Petitioner performs this obligation for the public convenience and necessity. He testified the eligible improvements included in Plan Update- 10 are essential in protecting the integrity, safety, and reliable operation of the system and enhance the ability of Petitioner’s customers to take advantage of the rapid development of alternative natural gas supply and delivery options and also positions Petitioner’s system to remain reliable and flexible in the event of significant changes to the economic and operational climate for natural gas. Additionally, he stated that the extension of gas service to rural areas will allow some residents in Petitioner’s service territory to access natural gas services for the first time. No evidence was presented in this Cause to contest the continued public convenience and necessity associated with the designated eligible improvements in the Plan. Petitioner has a statutory obligation to provide reasonably adequate retail service in its certificated gas service territory for the public convenience and necessity pursuant to Ind. Code §§ 8-1-2-4, -87, and -87.5. We find that Petitioner has sufficiently supported that the eligible improvements as described in Plan Update-10 are reasonably necessary for it to continue to provide adequate retail service to its customers, and the public convenience and necessity continues to require or will require those eligible improvements. c. Incremental Benefits Attributable to the Updated Plan. Based upon the evidence presented in this proceeding and for the reasons set forth above, we find the estimated costs of the eligible improvements included in Plan Update-10 are justified by the incremental benefits attributable to the Plan and we approve these costs. d. Conclusion. Plan Update-10 includes sufficient evidence for us to determine the best estimate of the cost of the eligible improvements and the public convenience and necessity continues to require or will require the eligible improvements, and the estimated costs of the eligible improvements continue to be justified by the incremental benefits attributable to Plan Update-10. Petitioner’s Plan Update-10 appropriately and reasonably addresses Petitioner’s aging infrastructure through projects intended to enhance, improve, and replace system assets for the provision of safe and reliable natural gas service, as well as the 11

extension of service into rural areas. The testimony of Petitioner’s witnesses Berning and Carr at the evidentiary hearing explained how Petitioner considers customer affordability in developing and implementing the TDSIC Plan and maintaining cost controls. Based on the evidence of record, we find that Petitioner has complied with these requirements; therefore, we approve Petitioner’s Plan Update-10. Petitioner is authorized to defer, as a regulatory asset, and recover 80% of the approved capital expenditures and TDSIC costs incurred in connection with its eligible improvements approved in its rates and charges for gas service in accordance with Petitioner’s TDSIC beginning with the month of April 2026. B. Ind. Code § 8-1-39-11(c). Petitioner has requested Commission approval to extend, on a nondiscriminatory basis, service in rural areas without a deposit or other adequate assurance of performance from the customer, to the extent that the extension of service results in a positive contribution to the utility's overall cost of service over a 20-year period. In its 45330 Order, the Commission approved Petitioner’s proposal to include all rural gas extensions, both those that qualify using the 20-year margin test under Ind. Code § 8-1-39-11 and those that may qualify under Petitioner’s existing line extension policy, and provide an 80% credit to the TDSIC tracker for actual margins received from all new customers added under the rural extensions projects. Mr. Hutnick stated that the forecast in the 2020-2025 TDSIC Plan includes the costs associated with designing and installing gas main and service projects to reach rural areas and explained how Petitioner administers the rural gas extension process. He explained the two primary methods Petitioner uses to determine whether a new rural business project is eligible for TDSIC treatment. He testified that the rural extensions projects included in Plan Update-10 are projected to pass the 20-year test identified in Ind. Code § 8-1-39-11. This request is consistent with the applicable statute and is approved. C. Ind. Code § 8-1-39-13(b). Pursuant to the mandate set forth in Ind. Code § 8-1-39-13(b), Petitioner is authorized to adjust its net operating income to reflect its earnings from the TDSIC tracker for purposes of Ind. Code § 8-1-2-42(g)(3)(c). D. Ind. Code § 8-1-39-14. Ind. Code § 8-1-39-14(a) states that the Commission may not approve a TDSIC that would result in an average aggregate increase in a public utility’s total retail revenues of more than 2% in a 12-month period. If a public utility incurs approved capital expenditures and TDSIC costs under its plan that exceed the percentage increase in a TDSIC approved by the Commission, the public utility shall defer recovery of the capital expenditures and TDSIC costs as set forth in Ind. Code § 8-1-39-9(b). Mr. Harmon addressed the calculation of the aggregate increase in Petitioner’s total retail revenues as a result of this TDSIC tracker filing and demonstrated in Petitioner’s Exhibit 1 that the proposed increase is less than the 2% statutory TDSIC limit set forth in Ind. Code § 8-1-39-14. Thus, we find that Petitioner’s proposed factors in the current Cause will not result in an average aggregate increase in total retail revenues of more than 2% in a 12-month period and therefore complies with Ind. Code § 8-1-39-14.

1. TDSIC 10 Factors. For the reasons explained above, Petitioner’s proposed
   TDSIC 10 factors as set forth in Petitioner’s Exhibit 1, Attachment 1-A, Attachment 1, Schedule 8, are approved. An average residential customer using 71 therms per month will experience an increase of $1.08 on their monthly bill. 6. Confidentiality. On November 25, 2025, Petitioner filed its Motion for Protection and Nondisclosure of Confidential and Proprietary Information with a supporting affidavit asserting certain information to be submitted to the Commission was trade secret information as defined in Ind. Code § 24-2-3-2 and should be treated as confidential in accordance with Ind. Code §§ 5-14-3-4 and 8-1-2-29. A Docket Entry was issued on December 3, 2025, in which the Presiding Officers determined the information should be held confidential on a preliminary basis, after which such information was submitted under seal. After reviewing the information and consideration of the affidavit, we find the information is trade secret information as defined in Ind. Code 24-2-3-2, is exempt from public access and disclosure pursuant to Ind. Code §§ 5-14-3-4 and 8-1-2-29, and shall be held confidential and protected from public access and disclosure by the Commission. IT IS THEREFORE ORDERED BY THE INDIANA UTILITY REGULATORY COMMISSION that: 1. Petitioner’s Plan Update-10 is approved.

2. Petitioner is authorized to defer, as a regulatory asset, and recover 80% of the
   approved capital expenditures and TDSIC costs incurred in connection with its eligible improvements approved in its rates and charges for gas service in accordance with Petitioner’s TDSIC beginning with the month of April 2026.

3. Petitioner is authorized to adjust its authorized net operating income to reflect any
   approved earnings associated with the TDSIC for purposes of Ind. Code § 8-1-2-42(g)(3)(c) pursuant to Ind. Code § 8-1-39-13(b).

4. Petitioner is authorized to defer, as a regulatory asset, 20% of the TDSIC costs
   incurred in connection with its eligible improvements and recover those deferred costs, including carrying charges, in its next general rate case.

5. Petitioner is authorized to record ongoing carrying charges based on the current
   overall weighted average cost of capital on all deferred capital expenditures and TDSIC costs until such costs are recovered in Petitioner’s base rates as a result of its next general rate case.

6. The TDSIC factors shown in Petitioner’s Exhibit 1, Attachment 1-A, Attachment
   1, Schedule 8, are approved to be effective for gas services rendered on or after April 1, 2026, and will remain in place until a new TDSIC is approved by the Commission in a subsequent proceeding.

7. Prior to implementing the approved TDSIC factors, Petitioner shall file the
   applicable rate schedules under this Cause for approval by the Commission’s Energy Division.

8. The information submitted under seal in this Cause pursuant to Petitioner’s request
   for confidential treatment is determined to be confidential trade secret information as defined in Ind. Code § 24-2-3-2 and shall continue to be held as confidential and exempt from public access and disclosure pursuant to Ind. Code §§ 5-14-3-4 and 8-1-2-29.

9. This Order shall be effective on and after the date of its approval.
   ZAY, DEIG, SWINGER, VELETA, AND ZIEGNER CONCUR: APPROVED: I hereby certify that the above is a true and correct copy of the Order as approved.

______________________________________ on behalf of Dana Kosco Secretary of the Commission

Regina K. 14 Digitally signed by Regina JoynerK. Joyner Date: 2026.03.25 10:19:21 MAR 25 2026 -04'00'