UNITED STATES
 SECURITIES AND EXCHANGE COMMISSION
 Washington, D.C. 20549
 FORM 10-K

 ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)

 OF THE SECURITIES EXCHANGE ACT OF 1934
 For the fiscal year ended December 31, 2024
 OR

 TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)

 OF THE SECURITIES EXCHANGE ACT OF 1934
 For the transition period from to
 Commission file number 001-16189
 NiSource Inc.
 (Exact name of registrant as specified in its charter)

 DE
 35-2108964

 (State or other jurisdiction of
incorporation or organization)
 (I.R.S. Employer
Identification No.)

 801 East 86th Avenue

 Merrillville,
 IN
 46410

 (Address of principal executive offices)
 (Zip Code)

 (877) 647-5990
 (Registrant's telephone number, including area code)
 Securities registered pursuant to Section 12(b) of the Act:

 Title of Each Class
 Trading
Symbol(s)
 Name of Each Exchange on Which Registered

 Common Stock, par value $0.01 per share
 NI
 NYSE

 Securities registered pursuant to Section 12(g) of the Act: None
 Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes No
 Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. Yes No
 Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
 Yes No
 Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).
 Yes No
 Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definition of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12-b-2 of the Exchange Act.
 Large accelerated filer Accelerated Filer Emerging Growth Company Non-accelerated Filer Smaller Reporting Company
 If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
 Indicate by check mark whether the registrant has filed a report on and attestation to its management's assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.
 If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrants included in the filing reflect the correction of an error to previously issued financial statements.
 Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant's executive officers during the relevant recovery period pursuant to §240. 10D-1(b).
 Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes No
 The aggregate market value of the registrant's common stock, par value $0.01 per share (the "Common Stock") held by non-affiliates was approximately $ 13,022,151,904 based upon the June 30, 2024, closing price of $28.81 on the New York Stock Exchange.

 There were 469,939,639 shares of Common Stock outstanding as of February 5, 2025.
 Documents Incorporated by Reference
 Part III of this report incorporates by reference specific portions of the Registrant's Notice of Annual Meeting and Proxy Statement relating to the Annual Meeting of Stockholders to be held on May 12, 2025.

 CONTENTS

 Page
 No.

 Defined Terms

 Item 1.
 Business

 Item 1A.
 Risk Factors

 Item 1B.
 Unresolved Staff Comments

 Item 1C.

 Cybersecurity

 Item 2.
 Properties

 Item 3.
 Legal Proceedings

 Item 4
 Mine Safety Disclosures

 Item 5.
 Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

 Item 6.
 Reserved

 Item 7.
 Management's Discussion and Analysis of Financial Condition and Results of Operations

 Item 7A.
 Quantitative and Qualitative Disclosures About Market Risk

 Item 8.
 Financial Statements and Supplementary Data

 Item 9.
 Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

 Item 9A.
 Controls and Procedures

 Item 9B.
 Other Information

 Item 9C.
 Disclosure Regarding Foreign Jurisdictions that Prevent Inspections

 Item 10.
 Directors, Executive Officers and Corporate Governance

 Item 11.
 Executive Compensation

 Item 12.
 Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

 Item 13.
 Certain Relationships and Related Transactions, and Director Independence

 Item 14.
 Principal Accounting Fees and Services

 Item 15.
 Exhibits, Financial Statement Schedules

 Item 16.
 Form 10-K Summary

 Signatures

 DEFINED TERMS

 The following is a list of frequently used abbreviations or acronyms that are found in this report:

 NiSource Subsidiaries and Affiliates (not exhaustive)

 Columbia of Kentucky

 Columbia Gas of Kentucky, Inc.

 Columbia of Maryland

 Columbia Gas of Maryland, Inc.

 Columbia Gas of Ohio, Inc.

 Columbia of Pennsylvania

 Columbia Gas of Pennsylvania, Inc.

 Columbia of Virginia

 Columbia Gas of Virginia, Inc.

 NIPSCO

 Northern Indiana Public Service Company LLC

 NIPSCO Holdings I

 NIPSCO Holdings I LLC

 NIPSCO Holdings II

 NIPSCO Holdings II LLC

 NIPSCO Generation

 NIPSCO Generation LLC

 NiSource ("we," "us" or "our")

 NiSource Inc.

 Rosewater
 Rosewater Wind Generation LLC and its wholly owned subsidiary, Rosewater Wind Farm LLC

 Indiana Crossroads Solar

 Indiana Crossroads Solar Generation LLC and its wholly owned subsidiary, Meadow Lake Solar Park LLC

 Indiana Crossroads Wind
 Indiana Crossroads Wind Generation LLC and its wholly owned subsidiary, Indiana Crossroads Wind Farm LLC

 Dunns Bridge I

 Dunns Bridge I Solar Generation LLC and its wholly owned subsidiary, Dunns Bridge Solar Center LLC

 Dunns Bridge II

 Dunns Bridge II Solar Generation LLC

 Gibson

 Gibson Solar Generation LLC

 Fairbanks

 Fairbanks Solar Generation LLC

 Cavalry

 Cavalry Solar Generation LLC

 Abbreviations and Other

 AFUDC

 Allowance for funds used during construction

 AOCI

 Accumulated Other Comprehensive Income (Loss)

 ASC

 Accounting Standards Codification

 ASU
 Accounting Standards Update

 ATM
 At-the-market

 BIP

 BIP Blue Buyer L.L.C

 BIP Blue Buyer VCOC L.L.C
 BIP Blue Buyer VCOC L.L.C., a Delaware limited liability company and also an affiliate of Blackstone

 Blackstone

 Blackstone Infrastructure Partners L.P.

 BTA
 Build-transfer agreement

 CCGT
 Combined Cycle Gas Turbine

 CCRs

 Coal Combustion Residuals

 CEO

 Chief Executive Officer

 CEP
 Capital Expenditure Program

 CERCLA

 Comprehensive Environmental Response Compensation and Liability Act (also known as Superfund)

 CFO

 Chief Financial Officer

 CISA

 Certified Information Systems Auditor

 CISO

 Chief Information Security Officer

 CISSP

 Certified Information Systems Security Professional

 CODM
 Chief Operating Decision Maker

 DEFINED TERMS

 Reportable segment comprised of the results of NiSource Gas Distribution company, including all of its Columbia Gas distribution companies and related subsidiaries

 Corporate Units
 Series A Corporate Units

 CPCN

 Certificate of Public Convenience and Necessity

 CRISC

 Certified in Risk and Information Systems Control

 DSIC
 Distribution System Improvement Charge

 DSM

 Demand Side Management

 EPA

 United States Environmental Protection Agency

 EPS

 Earnings per share

 Equity Units
 Series A Equity Units

 FAC

 Fuel adjustment clause

 FASB

 Financial Accounting Standards Board

 FERC
 Federal Energy Regulatory Commission

 FMCA
 Federally Mandated Cost Adjustment

 GAAP

 Generally Accepted Accounting Principles

 GCA
 Gas cost adjustment

 GCT

 Generation Cost Tracker

 GHG

 Greenhouse gases

 GWh

 Gigawatt hours

 HLBV
 Hypothetical Liquidation at Book Value

 IIJA

 Infrastructure Investment and Jobs Act

 IRA
 Inflation Reduction Act

 IRP

 Infrastructure Replacement Program

 IRS
 Internal Revenue Service

 IURC

 Indiana Utility Regulatory Commission

 JV
 Joint Venture

 LDCs

 Local distribution companies

 LIFO

 Last-in, first-out

 LIHEAP
 Low Income Heating Energy Assistance Programs

 Massachusetts Business
 All of the assets sold to, and liabilities assumed by, Eversource pursuant to the Asset Purchase Agreement

 MGP

 Manufactured Gas Plant

 MISO

 Midcontinent Independent System Operator

 MMDth

 Million dekatherms

 MW
 Megawatts

 MWh

 Megawatt hours

 NERC CIP

 North American Electric Reliability Corporation Critical Infrastructure Protection

 NIPSCO Electric
 The electric generation and transmission activities of the NIPSCO Operations reportable segment

 NIPSCO Gas
 The gas distribution activities of the NIPSCO Operations reportable segment

 NIPSCO Minority Interest Transaction

 A transaction between NiSource, NIPSCO Holdings II (sole owner of NIPSCO) and an affiliate of Blackstone pursuant to a purchase and sale agreement entered into on June 17, 2023, that offered equity interests in NIPSCO Holdings II in exchange for capital contributions by the parties.

 DEFINED TERMS

 Reportable segment comprised of the results of NIPSCO Holdings I, NIPSCO Holdings II, and NIPSCO and all related subsidiaries

 NYMEX
 The New York Mercantile Exchange

 OPEB

 Other Postretirement and Postemployment Benefits

 OT

 Operational Technology

 PCB

 Polychlorinated biphenyls

 PHMSA
 Pipeline and Hazardous Materials Safety Administration

 PPA
 Power Purchase Agreement

 PSC

 Public Service Commission

 PUCO

 Public Utilities Commission of Ohio

 ROE
 Return on Equity

 RNG

 Renewable Natural Gas

 ROU
 Right of Use

 SAVE
 Steps to Advance Virginia's Energy Plan

 Scope 1 GHG Emissions
 Direct emissions from sources owned or controlled by us (e.g., emissions from our combustion of fuel, vehicles, and process emissions and fugitive emissions)

 Scope 2 GHG Emissions
 Indirect emissions from sources owned or controlled by us

 SEC

 Securities and Exchange Commission

 SMRP

 Safety Modification and Replacement Program

 SMS
 Safety Management System

 STRIDE
 Strategic Infrastructure Development and Enhancement

 TCJA
 An Act to provide for reconciliation pursuant to titles II and V of the concurrent resolution on the budget for fiscal year 2018 (commonly known as the Tax Cuts and Jobs Act of 2017)

 TDSIC
 Transmission, Distribution and Storage System Improvement Charge

 TSA

 Transportation Security Administration

 VIE
 Variable Interest Entity

 WAM
 Work and Asset Management enterprise resourcing system

 Note regarding forward-looking statements
 This Annual Report on Form 10-K contains "forward-looking statements," within the meaning of Section 27A of the Securities Act of 1933, as amended (the "Securities Act"), and Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). Investors and prospective investors should understand that many factors govern whether any forward-looking statement contained herein will be or can be realized. Any one of those factors could cause actual results to differ materially from those projected. These forward-looking statements include, but are not limited to, statements concerning our plans, strategies, objectives, expected performance, expenditures, recovery of expenditures through rates, stated on either a consolidated or segment basis, and any and all underlying assumptions and other statements that are other than statements of historical fact. Expressions of future goals and expectations and similar expressions, including "may," "will," "should," "could," "would," "aims," "seeks," "expects," "plans," "anticipates," "intends," "believes," "estimates," "predicts," "potential," "targets," "forecast," and "continue," reflecting something other than historical fact are intended to identify forward-looking statements. All forward-looking statements are based on assumptions that management believes to be reasonable; however, there can be no assurance that actual results will not differ materially.

 Factors that could cause actual results to differ materially from the projections, forecasts, estimates and expectations discussed in this Annual Report on Form 10-K include, among other things:
 • our ability to execute our business plan or growth strategy, including utility infrastructure investments, or business opportunities, such as data center development and related generation sources and transmission capabilities to meet potential load growth;
 • our ability to manage data center growth in our service territories;

 • potential incidents and other operating risks associated with our business;
 • our ability to work successfully with our third-party investors;
 • our ability to adapt to, and manage costs related to, advances in technology, including alternative energy sources and changes in laws and regulations;
 • our increased dependency on technology;
 • impacts related to our aging infrastructure;
 • our ability to obtain sufficient insurance coverage and whether such coverage will protect us against significant losses;
 • the success of our electric generation strategy;
 • construction risks and supply risks;
 • fluctuations in demand from residential and commercial customers;
 • fluctuations in the price of energy commodities and related transportation costs or an inability to obtain an adequate, reliable and cost-effective fuel supply to meet customer demand;
 • our ability to attract, retain or re-skill a qualified, diverse workforce and maintain good labor relations;
 • our ability to manage new initiatives and organizational changes;
 • the performance and quality of third-party suppliers and service providers;
 • our ability to manage the financial and operational risks related to achieving our carbon emission reduction goals, including our Net Zero Goal (as defined below), including any future associated impact from business opportunities such as data center development as those opportunities evolve;
 • potential cybersecurity attacks or security breaches;
 • increased requirements and costs related to cybersecurity;
 • the actions of activist stockholders;
 • any damage to our reputation;
 • the impacts of natural disasters, potential terrorist attacks or other catastrophic events;
 • the physical impacts of climate change and the transition to a lower carbon future;
 • our debt obligations;
 • any changes to our credit rating or the credit rating of certain of our subsidiaries;
 • adverse economic and capital market conditions, including increases in inflation or interest rates, recession, or changes in investor sentiment;
 • economic regulation and the impact of regulatory rate reviews;
 • our ability to obtain expected financial or regulatory outcomes;
 • economic conditions in certain industries;
 • the reliability of customers and suppliers to fulfill their payment and contractual obligations;
 • the ability of our subsidiaries to generate cash;
 • pension funding obligations;
 • potential impairments of goodwill;
 • the outcome of legal and regulatory proceedings, investigations, incidents, claims and litigation;
 • compliance with changes in, or new interpretations of applicable laws, regulations and tariffs;
 • the cost of compliance with environmental laws and regulations and the costs of associated liabilities;
 • changes in tax laws or the interpretation thereof;
 • and other matters set forth in Item 1, "Business," Item 1A, "Risk Factors" and Part II, Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations," of this report, some of which risks are beyond our control.

 In addition, the relative contributions to profitability by each business segment, and the assumptions underlying the forward-looking statements relating thereto, may change over time.

 All forward-looking statements are expressly qualified in their entirety by the foregoing cautionary statements. We undertake no obligation to, and expressly disclaim any such obligation to, update or revise any forward-looking statements to reflect changed assumptions, the occurrence of anticipated or unanticipated events or changes to the future results over time or otherwise, except as required by law.

 Business
 NiSource Inc. is an energy holding company under the Public Utility Holding Company Act of 2005 whose primary subsidiaries are fully regulated natural gas and electric utility companies, serving approximately 3.8 million customers in six states. NiSource is the successor to an Indiana corporation organized in 1987 under the name of NIPSCO Industries, Inc., which changed its name to NiSource Inc. on April 14, 1999.
 NiSource's principal subsidiaries include NiSource Gas Distribution Group, Inc. (a holding company that owns Columbia of Kentucky, Columbia of Maryland, Columbia of Ohio, Columbia of Pennsylvania, and Columbia of Virginia), and NIPSCO Holdings I (a holding company that owns a controlling interest in NIPSCO, a gas and electric utility). NiSource derives substantially all of its revenues and earnings from the operating results of these rate-regulated businesses.
 Business Strategy
 Our business strategy focuses on providing safe and reliable service through our core, rate-regulated, asset-based utilities, with the goal of adding value to all of our stakeholders. Our utilities continue to advance our core safety, infrastructure and environmental investment programs, supported by complementary regulatory and customer initiatives across the six states in which we operate. Our goal is to develop strategies that (i) support long-term infrastructure investment and safety programs to better serve our customers, (ii) align our tariff structures with our cost structure, and (iii) drive value and enable growth in an evolving energy ecosystem. These strategies focus on improving safety and reliability, enhancing customer experience, pursuing regulatory and legislative initiatives to increase accessibility for customers currently not on our gas and electric service, ensuring customer affordability and reducing emissions while generating sustainable returns.
 We remain committed to the advancement of our SMS for the safety of our customers, communities and employees. Our SMS is the established operating model within NiSource. NiSource continues to maintain its certification to the American Petroleum Institute Recommended Practice 1173, which serves as the guiding practice for our SMS. In 2024, NiSource was recognized with the ISO 55001 certification from LRQA, one of the world's leading providers of professional engineering and technology services. Achieving this international certification for asset management systems recognizes NiSource's commitment to safety for our people, systems and customers. These certifications are important milestones for our SMS and NiSource's ongoing journey towards operational excellence.
 NiSource has two reportable segments: Columbia Operations and NIPSCO Operations. The remainder of our operations, which are not significant enough on a stand-alone basis to warrant treatment as an operating segment, consist of our centralized corporate activities and are primarily comprised of interest expense on holding company debt and unallocated corporate costs and activities. The following is a summary of the business for each reporting segment. Refer to Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations" and Note 21, "Business Segment Information," in the Notes to Consolidated Financial Statements for additional information related to each segment.
 Columbia Operations provides natural gas to approximately 2.4 million residential, commercial and industrial customers in Ohio, Pennsylvania, Virginia, Kentucky, and Maryland. We operate approximately 37,200 miles of distribution main pipeline plus the associated individual customer service lines and 330 miles of transmission main pipeline located in our service areas described above. Throughout our service areas we also have gate stations and other operations support facilities. See below for information on our owned operating facilities. There were no significant disruptions to our system or facilities during 2024.

 Facility Name
 Location
 Type
 Storage Capacity (MCF)

 Blackhawk Underground Storage(1)

 Beaver Falls, PA
 Natural Gas
 1,700,000

 Eagle Cove Propane
 Petersburgh, VA
 Propane Gas

 South Wales Propane
 Jeffersonton, VA
 Propane Gas

 Portsmouth Propane-Air
 Portsmouth, VA
 Propane-Air Gas
 17,300

 Total Capacity
 1,719,026

 (1)NiSource has entered into an agreement to sell this facility, subject to approval by the Pennsylvania Public Utility Commission.

 Competition. Due to open access and the deregulation of natural gas supplies, our LDC customers can purchase gas directly from producers and marketers in an open, competitive market. Certain of our subsidiaries are involved in programs that provide our residential and commercial customers the opportunity to purchase their natural gas requirements from third parties and use our subsidiaries for transportation services. As of December 31, 2024, 33.9% of our residential customers and 41.2% of our commercial customers participated in such programs.
 We compete with (i) investor-owned, municipal, and cooperative electric utilities throughout our service areas, (ii) other regulated and unregulated natural gas intra and interstate pipelines and (iii) other alternate fuels, such as propane and fuel oil. We continue to be a well-positioned competitor in the energy markets in which we operate due to customer preference for natural gas.
 Additionally, we are subject to seasonal fluctuations in sales. Revenues from our gas distribution operations are more significant during the heating season, which is from October through May. Please refer to Part II, Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations - Results and Discussion of Operations - Columbia Operations," for additional information.

 NIPSCO Gas
 NIPSCO Gas distributes natural gas to approximately 0.9 million customers in northern Indiana. We operate approximately 17,900 miles of distribution main pipeline plus the associated individual customer service lines and 690 miles of transmission main pipeline located in our northern Indiana service areas. Throughout northern Indiana, we also have gate stations and other operations support facilities. See below for information on our owned operating facilities. There were no significant disruptions to our system or facilities during 2024.

 Facility Name

 Location

 Type

 Storage Capacity (MCF)

 Royal Center Underground Storage

 Royal Center, IN

 Natural Gas

 7,240,000

 Rolling Prairie LNG

 Rolling Prairie, IN

 Liquified Natural Gas

 4,000,000

 Total Capacities

 11,240,000

 Competition. Similar to the Columbia Operations segment, NIPSCO Gas also operates in an open and competitive market which allows retail customers to purchase gas directly from producers and marketers. As of December 31, 2024, 6.7% of our residential customers and 17.6% of our commercial customers participated in such programs.
 We compete with (i) investor-owned, municipal, and cooperative electric utilities throughout our northern Indiana service area, (ii) other regulated and unregulated natural gas intra and interstate pipelines and (iii) other alternate fuels, such as propane and fuel oil.
 Additionally, we are subject to seasonal fluctuations in sales. Revenues from our gas distribution operations are more significant during the heating season, which is from October through May. Please refer to Part II, Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations - Results and Discussion of Operations - NIPSCO Operations," for additional information.

 NIPSCO Electric
 We generate, transmit and distribute electricity to approximately 0.5 million customers in 20 counties in the northern part of Indiana and also engage in wholesale electric and transmission transactions. Our transmission system, has voltages from 69,000 to 765,000 volts, and consists of approximately 3,000 circuit miles. We are interconnected with eight neighboring electric utilities. We operate 66 transmission and 250 distribution substations, and own approximately 311,300 poles. We own and operate generation assets as well as source power through PPAs. We continue to transition our generation portfolio from coal-fired generation to lower-emission sources. We currently have six owned renewable generation facilities in service: Rosewater, Indiana Crossroads Wind, Indiana Crossroads Solar, Dunns Bridge I Solar, Cavalry Solar and Storage and Dunns Bridge II Solar and Storage. Cavalry Solar and Storage went into service May 2024 and Dunns Bridge II Solar and Storage went into service in January 2025. As of December 31, 2024, we have multiple PPAs that provide 600 MW of capacity, with contracts expiring between 2038 and 2040. We also operate two hydro electric generation facilities, a CCGT, and two coal generation facilities. The R.M. Schahfer coal facility is scheduled to be retired by the end of 2025 and the Michigan City coal facility is scheduled to be retired by the end of 2028. Our generating facilities had no material unplanned interruptions during 2024. See below for information on our owned generating facilities:

 Facility Name
 Location
 Fuel Type
 Generating Capacity (MW)(1)

 R.M. Schahfer
 Wheatfield, IN
 Steam - Coal

 Michigan City
 Michigan City, IN
 Steam - Coal

 Sugar Creek(2)

 West Terre Haute, IN
 CCGT

 R.M. Schahfer
 Wheatfield, IN
 Natural Gas

 Oakdale
 Carroll County, IN
 Hydro

 Norway
 Hydro

 Rosewater(3)

 Wind

 Indiana Crossroads Wind(3)

 Wind

 Dunns Bridge I(3)

 Jasper County, IN

 Solar

 Indiana Crossroads Solar(3)

 Solar

 Cavalry Solar and Storage(4)

 Solar and Storage

 Dunns Bridge II(4)

 Jasper County, IN

 Solar and Storage

 Total MW Capacity
 3,430

 (1)Represents current net generating capability of each fossil fuel and hydro generating facility. Nameplate capacity is listed for wind and solar generating facilities.
 (2)Represents capacity as of December 31, 2024. Sugar Creek is expected to further increase capacity pending MISO approval in 2025.
 (3)NIPSCO is the managing partner of these JVs. Refer to Note 4, "Noncontrolling Interests," in the Notes to Consolidated Financial Statements for more information.
 (4)Cavalry Solar and Storage has installed battery storage capacity of 45MW over a four-hour duration. Dunns Bridge has installed battery storage capacity of 56MW over a four-hour duration.

 NIPSCO's 2024 Integrated Resource Plan ("2024 Plan") was submitted to the IURC in December 2024. The 2024 Plan informs future generation investments required to ensure reliability for NIPSCO's customers and incorporated factors such as anticipated load growth from data centers and other economic development opportunities, new EPA emissions rules, and evolving MISO resource accreditation rules. The 2024 Plan maintains the retirement decisions and capacity additions identified in the 2018 and 2021 Integrated Resource Plans and calls for additional generation resources through 2029 to support capacity requirements. In addition, if significant new data center load is contracted, the 2024 Plan calls for additional gas-fired resources to support that additional capacity. Refer to Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations" for further discussion of these plans.

 NIPSCO participates in the MISO transmission service and wholesale energy market. MISO is a nonprofit organization created in compliance with FERC regulations to improve the flow of electricity in the regional marketplace and to enhance electric reliability. Additionally, MISO is responsible for managing energy markets, transmission constraints and the day-ahead, real-time, Financial Transmission Rights and ancillary markets. NIPSCO has transferred functional control of its electric transmission assets to MISO, and transmission service for NIPSCO occurs under the MISO Open Access Transmission Tariff. NIPSCO generating units are dispatched by MISO which takes into account economics, reliability of the MISO system and unit availability. During the year ended December 31, 2024, NIPSCO generating units, inclusive of its owned renewable generation facilities, were dispatched to meet 55.4% of its overall system load, and the remainder of the overall system load was procured through PPAs and the MISO market.
 Competition. Our NIPSCO Electric utility generally has exclusive service areas under Indiana regulations and retail electric customers in Indiana do not have the ability to choose their electric supplier. NIPSCO faces non-utility competition from other energy sources, such as self-generation by large industrial customers and other distributed energy sources.
 Our NIPSCO Operations are subject to seasonal fluctuations in sales. Revenues from electric operations are more significant during the cooling season, which is primarily from June through September. Please refer to Part II, Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations - Results and Discussion of Operations - NIPSCO Operations," for additional information.

 Regulatory
 The regulatory landscape, at both the state and federal levels, continues to evolve, impacting the operations and financial results of our operating companies. Management continually seeks new ways to be more competitive and efficient in this environment, while keeping service and affordability for customers at the forefront. We believe we are, in all material respects, in compliance with such laws and regulations and do not expect future compliance requirements to have a material impact on our capital expenditures, earnings, or competitive position. While we continue to monitor existing and pending laws and regulations, the impact of regulatory changes cannot be predicted with certainty.
 Rate Case Actions. The following table describes current rate case actions as applicable in each of our jurisdictions. See "Cost Recovery and Trackers" below for further detail on trackers.

 Company
 Approved ROE
 Requested Incremental Revenue
 Approved Incremental Revenue
 Filing Date

 Rates
Effective

 Approved Rates Cases

 Columbia of Pennsylvania(1)

 None specified
 $
 124.1
 $
 74.0
 March 15, 2024
 December 2024

 Columbia of Maryland(1)

 None specified
 $
 6.5
 $
 3.9
 May 12, 2023
 December 2023

 Columbia of Kentucky

 9.75
 %
 $
 23.8
 $
 14.3
 May 16, 2024
 January 2025

 Columbia of Virginia(2)

 None specified
 $
 40.5
 $
 25.8
 April 29, 2022
 October 2022

 9.60
 %
 $
 221.4
 $
 68.3
 June 30, 2021
 March 2023

 NIPSCO - Gas(3)

 9.75
 %
 $
 161.9
 $
 120.9
 October 25, 2023
 August 2024

 NIPSCO - Electric(4)

 9.80
 %
 $
 291.8
 $
 261.9
 September 19, 2022
 August 2023

 Pending Rate Cases

 NIPSCO - Electric(5)

 $
 368.7

 September 12, 2024
 September 2025

 Columbia of Virginia(6)

 $
 37.2
 April 29, 2024
 October 2024

 Columbia of Maryland

 $
 10.7

 September 24, 2024
 April 2025

 (1) No approved ROE is identified for this matter since the approved revenue increase is the result of a black box settlement under which parties agree upon the amount of increase.
 (2)The approved rate case resulted in a black box settlement, representing a settlement to a specific revenue increase but not a specified ROE. The settlement provides use of a 9.70% ROE for future SAVE filings.
 (3)New rates were implemented in 2 steps, with implementation of Step 1 rates effective in August 2024 and Step 2 rates to be effective no later than March 2025.
 (4)New rates were implemented in 2 steps, with implementation of Step 1 rates in August 2023 and Step 2 rates effective in March 2024.
 (5)On February 7, 2025, NIPSCO and certain intervening parties filed a Joint Stipulation and Settlement Agreement with the IURC reflecting an annual revenue increase of $257.0 million. New rates proposed to be implemented in 2 steps, with implementation of Step 1 rates effective no later than September 2025 and Step 2 rates to be effective no later than March 2026.
 (6)Rates are effective on an as filed basis and subject to refund. Columbia of Virginia and certain intervening parties, filed a Joint Stipulation and Proposed Recommendation for settlement on December 5, 2024, for an annual revenue increase of $28.2 million, net of SAVE.

 FERC. Our service company and operating companies are subject to varying degrees of regulation by the FERC. NiSource Corporate Services files a FERC Form 60 annual report with its financial information as a FERC jurisdictional centralized service company. NiSource also files an annual FERC Form 61 which contains a narrative description of the service company's functions during the prior calendar year.

 As natural gas LDCs, Columbia of Maryland, Columbia of Ohio, Columbia of Pennsylvania, Columbia of Virginia, Columbia of Kentucky and NIPSCO have limited jurisdictional certificates to transport gas in their respective service territories and into interstate commerce.

 As an electric company, NIPSCO has Market Based Rate authority and is a Transmission Owner subject to FERC jurisdiction. NIPSCO files the following reports annually:

 • FERC Form 1, which is a comprehensive financial and operating report,
 • FERC Form 566, which is a list of its 20 largest purchases of electricity over the past three years,
 • FERC Form 715, which is its Annual Transmission Planning and Evaluation Report and the base case power flow data from the Eastern Interconnection Reliability Assessment Group Multiregional Modeling Working Group, which was used by NIPSCO for transmission planning and,
 • FERC Form 730, which is NIPSCO's Report of Transmission Investment Activity.

 As a Transmission Owner subject to the MISO Transmission Owners Agreement and Tariff, NIPSCO has various FERC jurisdictional obligations such as maintaining its Attachment O formula rates and corresponding protocols. NIPSCO also has FERC approvals to make affiliate transactions between itself and various JVs. NIPSCO's officers, on the electric side, are also subject to FERC's interlocking directorate rules and reporting requirements.

 Regulatory Framework. The gas distribution activities of our Columbia and NIPSCO Operations have pursued non-traditional revenue sources within the evolving natural gas marketplace. These efforts include (i) gas supply cost incentive mechanisms for service to their core markets, and (ii) the sale of on-system services in the companies' service territories. The on-system services are offered by us to customers and include products such as the transportation and balancing of gas on the gas distribution operations utility's system. The incentive mechanisms give the gas distribution operations utilities an opportunity to share in the savings created from such situations as gas purchases made below an agreed upon benchmark price and the remarketing of unused pipeline capacity to reduce overall pipeline costs.
 We recognize that energy efficiency reduces emissions, conserves natural resources and saves our customers money. Our gas distribution companies offer programs such as energy efficiency upgrades, home checkups and weatherization services. The increased efficiency of natural gas appliances and improvements in home building codes and standards contribute to a long-term trend of declining average use per customer. While we are looking to expand offerings so the energy efficiency programs can benefit as many customers as possible, our gas distribution operations utilities have pursued changes in rate design to more effectively match recoveries with costs incurred. Columbia of Ohio has adopted a straight fixed variable rate design for residential and small commercial customers that closely links the recovery of fixed costs with fixed charges. Columbia of Maryland and Columbia of Virginia have regulatory approval for weather and revenue normalization adjustments for certain customer classes, which adjust monthly revenues that exceed or fall short of approved levels. Columbia of Pennsylvania continues to operate its pilot residential weather normalization adjustment and also has a fixed customer charge. This weather normalization adjustment only adjusts revenues when actual weather compared to normal varies by more than 3%. Columbia of Kentucky incorporates a weather normalization adjustment for certain customer classes and also has a fixed customer charge. NIPSCO Gas and Electric include a fixed customer charge for residential and small commercial and industrial customer classes. NIPSCO Gas has also received approval and implemented a weather normalization adjustment for certain of its customer classes.
 While increased efficiency of electric appliances and improvements in home building codes and standards have similarly impacted the average use per electric customer in recent years, NIPSCO expects future growth in per customer usage as a result of increasing electric applications, such as electric vehicles. These ongoing changes in use of electricity will likely lead to development of innovative rate designs, and NIPSCO will continue efforts to design rates that increase the certainty of recovery of fixed costs.

 Cost Recovery and Trackers. Comparability of our operating results is impacted by regulatory trackers that allow for the recovery in rates of certain costs. Certain approved regulatory tracker mechanisms allow for abbreviated regulatory proceedings in order for the operating companies to quickly implement revised rates and recover associated costs.
 A portion of the NIPSCO Operations' and Columbia Operations' gas distribution revenue is related to the recovery of gas costs through GCA's, the review of which occurs through standard regulatory proceedings. All states in our operating area require periodic review of actual gas procurement activity to determine prudence and confirm the recovery of prudently incurred energy commodity costs supplied to customers.
 A portion of the NIPSCO Operations' revenue is related to the recovery of fuel costs to generate power and the fuel costs related to purchased power. These costs are recovered through a FAC, which is updated quarterly to reflect actual costs incurred to supply electricity to customers.
 Political Action
 The NiSource Political Action Committee ("NiPAC") provides our employees a voice in the political process. NiPAC is a voluntary, employee driven and funded political action committee, and NiPAC makes bipartisan political contributions to local, state and federal candidates where permitted and in accordance with established guidelines. Consistent with our commitments and our approach to engagement, the NiPAC leadership committee members evaluate candidates for support on issues important to our business.

 Environmental and Safety Matters
 PHMSA Legislation and Regulations
 To fulfill our vision of being a trusted energy provider, we follow safety practices required by regulations and we implement our Safety Management System ("SMS"). SMS serves as the framework to identify and reduce risks and ensure consistent safety processes, procedures and operations across the organization.

 As directed by law in the Protecting Our Infrastructure of Pipelines and Enhancing Safety (PIPES) Act of 2020, PHMSA has revised, and continues to revise, the pipeline safety regulations focused on public safety and environmental hazard mitigation. Specific areas of focus for upcoming rulemaking include leak detection and repair criteria (the "LDAR" rule) and regulations that require operators to upgrade their existing low-pressure regulating stations with enhanced safeguards and update distribution integrity management plans, emergency response plans, and operation and maintenance plans (the Safety of Gas Distribution Pipelines, or "SGDP" rule).
 In May 2023, PHMSA proposed regulatory revisions under the PIPES Act of 2020 to minimize methane emissions and improve public safety. Under the proposed revisions, our subsidiaries would be required to detect and repair an increased number of gas leaks, reduce the time to repair leaks, increase leak survey, and expand our existing advanced leak detection program. In January 2025, PHMSA submitted a final LDAR rule to the Federal Register and is currently suspended.
 In September 2023, PHMSA proposed additional regulatory revisions under the PIPES Act of 2020 to enhance distribution system safety through equipment and procedural expectations in the form of the SGDP rule. Operators will be required to incorporate additional protections for low pressure distribution systems that prevent over-pressurization, amend construction procedures designed to minimize the risk of incidents caused by system over-pressurization, and update distribution integrity management programs to cover and prepare for over-pressurization incidents. PHMSA did not progress the SGDP rulemaking in 2024.
 We continue to evaluate and monitor PHMSA legislation and regulations but cannot predict the impact of changing pipeline safety regulations on our business at this time.
 Climate Change Issues
 Physical Climate Risks. Increased frequency of severe and extreme weather events associated with climate change could materially impact our facilities, energy sales, and results of operations. We are unable to predict these events. However, we perform assessments of physical risk, including physical climate risk, to our business. More extreme and volatile temperatures, increased storm intensity and flooding, and more volatile precipitation leading to changes in lake and river levels are among the weather events that are most likely to impact our business. Efforts to mitigate these physical risks continue to be implemented.

 Transition Climate Risks and Opportunities. We actively engage with and monitor the impact that proposed legislative and regulatory programs related to GHG emissions would have on our business. Refer to Item 1A. Risk Factors, "Operational Risks," of this Annual Report on Form 10-K for further detail.
 Regarding federal policies, we continue to monitor the status of climate change-related legislation and regulation, including the IIJA, IRA, and EPA's Waste Emissions Charge for Petroleum and Natural Gas systems. We have identified and pursued potential opportunities associated with the IIJA and the IRA that align with our strategy. These opportunities include tax incentives for renewable generation and storage projects, tax credit transferability and grant funding for grid resiliency, hydrogen hubs and leak detection. The new federal administration has signaled through executive actions a desire to roll-back several climate-related policies including funding for IIJA and IRA programs. We continue to evaluate and monitor how these changes will impact our business.
 In May 2024, the EPA published final greenhouse gas standards and guidelines for fossil fuel-fired power plants. The rules are not expected to impact NIPSCO's existing electric generation, but, depending on the outcome of ongoing litigation and potential future changes to the rules, may impose certain operational limitations on other existing and new electric generation. Through the 2024 NIPSCO IRP process, we assessed that cost to electric customers would be approximately $675 million greater due to these rules.

 We also continue to monitor evolving state policies related to GHG emissions. The Climate Solutions Now Act of 2022 requires Maryland to reduce GHG emissions by 60% by 2031 (from 2006 levels), and it requires the state to reach net zero emissions by 2045. The Maryland Department of the Environment ("MDE") adopted a plan to achieve its 2031 goal and is required to adopt a plan for their 2045 net zero goal by 2030. The Act also enacts a state policy to move to broader electrification of both existing buildings and new construction. In December 2024, the Maryland Department of the Environment issued updated final Building Energy Performance Standards, which would require net zero direct greenhouse gas emissions from large buildings by 2040 with interim targets, or payments of an alternative compliance fee. Columbia of Maryland is advocating for compliance pathways that use RNG, hydrogen, new technologies and emissions offsets. Under an executive order, Maryland is also developing a Clean Heat Standard and a Zero-Emission Heating Equipment Standard that are intended to transition gas appliances to electric heat pumps. Separately, the PSC has also initiated a proceeding related to Near-Term, Priority Actions and Comprehensive, Long-Term Planning for Maryland's Gas Companies. Columbia of Maryland cannot predict the final impact of these policies on our business at this time.
 Net Zero Goal. In November 2022, we announced a goal of net zero greenhouse gas emissions by 2040, covering both Scope 1 and Scope 2 GHG emissions ("Net Zero Goal"). Our Net Zero Goal builds on greenhouse gas emission reductions achieved to-date. We plan to achieve our Net Zero Goal primarily through the continuation and enhancement of existing programs, such as retiring and replacing coal-fired electric generation with low- or zero-emission electric generation, ongoing pipe replacement and modernization programs, and deployment of advanced leak-detection technologies. In addition, we plan to advance other low- or zero-emission energy resources and technologies, which may include hydrogen, renewable natural gas, long-duration storage, and/or deployment of carbon capture and utilization technologies, if and when these become technologically and economically feasible. Carbon offsets and renewable energy credits may also be used to support achievement of our Net Zero Goal. As of the end of 2023, we had reduced Scope 1 GHG emissions by approximately 72% from 2005 levels.
 Our greenhouse gas emissions projections, including achieving a Net Zero Goal, are subject to various assumptions that involve risks and uncertainties, and did not include any assumptions related to data center development and associated load growth. We remain committed to our Net Zero Goal, however, certain of our interim goals may evolve as we assess and respond to business opportunities such as data centers. Achievement of our Net Zero Goal by 2040 will require supportive regulatory and legislative policies, favorable stakeholder environments and advancement of technologies that are not currently economically or technologically feasible to deploy at scale, as well as execution of our business plan. Otherwise, our actual results or ability to achieve our Net Zero Goal, including by 2040, may differ materially.
 As discussed in Management's Discussion within "Results and Discussion of Operations - NIPSCO Operations," NIPSCO continues to execute its electric generation transition consistent with the preferred pathways identified in its 2018, 2021 and 2024 Integrated Resource Plans. Additionally, as discussed in Management's Discussion within "Executive Summary - Energy Transition" and "Liquidity and Capital Resources - Regulatory Capital Programs," our natural gas distribution companies are lowering methane emissions by replacing aging infrastructure, which also increases safety and reliability for customers and communities.

 Human Capital
 Human Capital Management Governance and Organizational Practices. The Compensation and Human Capital Committee ("C&HC Committee") of our Board of Directors (the "Board") is primarily responsible for assisting the Board in overseeing our human capital management practices. The C&HC Committee reviews our human capital management function and programs. The review of related procedures, programs, policies and practices allows the committee to make recommendations to management with respect to equal employment opportunity, employee engagement, organizational health, and talent management.

 Human Capital Goals and Objectives. We have aligned our human capital goals to achieve overall company strategic and operational objectives by driving an enhanced talent strategy, elevating support for front-line leaders, fostering a culture of rigor and accountability, and strengthening our human resource function. We aspire to be an employer of choice, in part, through embedding inclusion throughout the enterprise and creating an enviable employee experience.

 Workforce Composition. As of December 31, 2024, we had 7,687 full-time and 59 part-time active employees (i.e., not interns, not on leave or disability). Of our total workforce, 32% were subject to collective bargaining agreements with various labor unions. These collective bargaining agreements were renegotiated in 2021 and 2023 and expire in 2026 and 2027, respectively.

 We foster an enviable work environment where all employees are energized. In efforts to become an employer of choice, we have developed sourcing strategies to attract and retain the most qualified talent. Our executive leadership team is characterized by a diverse composition, with 75% representation from both people of color ("POC") and females. We have increased our overall population of females and POC in 2024.

 In 2024, our Diversity of Slate process supported our talent acquisition team filling 1,565 roles with 831 external candidates. These external hires included 34% being filled with POC and 40% being filled with female candidates. These sourcing efforts led our organization across all businesses to make progress toward a workforce composition that embraces different perspectives.

 Our employee resource groups (ERGs) serve to create a culture of inclusion through their engagement of all employees throughout the year. We continue to develop ERG leaders to equip employees with the necessary tools to further support our efforts for advancement and strengthen our inclusive workplace. A key area for us has been our implementation and development of programs to drive higher retention and engagement of our employees, focusing on inclusive leadership training for Directors and Managers in the organization. Our commitment is grounded in the core belief that our purpose extends far beyond our primary role as a utility company.

 We are committed to providing equal employment opportunities in each of our companies to all employees and applicants without regard to race, color, religion, national origin or ancestry, veteran status, disability, gender, age, marital status, sexual orientation, gender identity, genetic information, or any protected group status as defined by law. The input provided by our increasingly diverse workforce will continue to strengthen our corporate culture as well as drive constructive changes within our company to improve our operational strategies, enhance the quality of the services we provide, and increase revenue.

 Talent Attraction. To recruit and hire individuals with a variety of skills, talents, backgrounds and experiences, we value and cultivate relationships with community and diversity outreach partners. We also target job fairs, including those focused on people of color, veteran, and female candidates while also partnering with local colleges and universities to identify and recruit qualified applicants.

 Similar to other companies, we have focused on creating a flexible, agile model for roles that can be performed in a more remote setting. Our hybrid model recognizes differing ways of working; onsite, hybrid and remote. Most of our workforce is onsite and our hybrid and remote roles provide different avenues of working and seeking talent across our footprint. Hybrid employees work in a NiSource facility at least twice a week. This in-office presence supports colleague connection, development, in-person mentoring, and broader team building.
 Talent Development and Retention. We offer leadership development programs to enhance the behaviors and skills of our existing and future leaders. In 2024, we had participation from employees of all levels. We also offer extensive technical and non-technical employee development training programs.

 We strive to provide promotion and advancement opportunities for employees. In 2024, for all leadership positions at the supervisor and above level posted externally, we filled 64% with internal employees. We also develop and implement targeted development action plans to increase succession candidate readiness for leadership roles. Additionally, we monitor the risk and potential impact of talent loss and take action to increase retention of top talent. Retention in 2024 was 93%. We calculate retention as 100 minus the total number of separations divided by the average headcount for the annual period. These separations break down into involuntary separations (2%), resignations (3%), and retirements (2%).
 Succession Planning. We perform succession planning annually for officer level positions to ensure that we develop and sustain a strong bench of talent capable of performing at the highest levels. Talent is identified, and potential paths of development are discussed, to ensure that employees have an opportunity to build their skills to be well-prepared for future roles. We maintain formal succession plans for our CEO and key officers. The succession plan for our CEO is reviewed by the Environmental, Social, Nominating and Governance Committee and the succession plans for key officers (other than the CEO) and critical roles are reviewed by the Compensation and Human Capital Committee annually or more frequently as needed.
 Employee and Workplace Health and Safety. We have several programs to support employees, and their families' well-being. These programs include competitive medical, dental, vision, life and long-term disability programs, including employee health savings account company contributions, telemedicine services, Employee Assistance Program, Integrated Health Management navigation services, and paid time off including wellness, sick/disability, parental leave, and illness in family days.
 We also have a robust program to support employees, contractors and public safety, which is led by our Chief Safety Officer and is under the oversight of the Safety, Operations, Regulatory and Policy Committee of our Board.
 Culture and Engagement. Our culture is another important aspect of our ability to advance our strategic and operational objectives. In addition to recruiting, development and retention programs described above, we also invest in internal communications programs, including in-person and virtual learning and networking opportunities, as well as regular town hall communications to employees. We measure and monitor organizational health and employee engagement through various channels including employee lifecycle, pulse, and census surveys.
 To instill and reinforce our values and culture, we require our employees to participate in regular training on ethics and compliance topics each year, including raising concerns, treating others with respect, preventing discrimination in the workplace, anti-bribery and corruption, data protection, unconscious biases, harassment, conflicts of interest, and how to use the anonymous ethics and compliance hotline. All employees receive training on our Code of Business Conduct annually or more frequently if there is a material change in content. Because of this training and other programs, we have learned from our most recent employee survey that our employees know what ethical violations look like and how to report them. Our Code of Business Conduct is designed to ensure that our employees adhere to legal and regulatory requirements, mitigate risks, and promote ethical behavior. Our ethics program is led by leadership tone at the top, policies and procedures, regular training and communication, monitoring and auditing, and a system for reporting and addressing violations. Our business ethics program, including the employee training program, is reviewed annually by our executive leadership team and the Audit Committee of our Board of Directors.

 Our Compensation and Human Capital Committee reviews reports from our Chief Human Resources Officer on employee engagement and corporate culture. Our Board reviews results and action plans related to our enterprise-wide comprehensive employee engagement survey. Our executive leadership team, including our CEO, communicates directly and regularly with all employees on timely ethics topics through electronic messages, coffee chats, and all-employee town hall meetings. These communications emphasize the importance of our values and culture in the workplace.

 INFORMATION ABOUT OUR EXECUTIVE OFFICERS

 The following is a list of our Executive Officers, including their names, ages, offices held and other recent business experience.

 Name
 Age
 Office(s) Held in Past 5 Years

 Lloyd M. Yates
 President and Chief Executive Officer of NiSource since February 2022 and Director since March 2020

 Executive Vice President, Customer and Delivery Operations, and President, Carolinas Region, of Duke Energy Corporation from 2014 to 2019

 Shawn Anderson
 Executive Vice President and Chief Financial Officer of NiSource since March 2023

 Senior Vice President and Chief Strategy and Risk Officer from June 2020 to March 2023

 Vice President, Strategy and Chief Risk Officer from January 2019 to May 2020

 Melody Birmingham
 Executive Vice President, and President, NiSource Utilities of NiSource since March 2023

 Executive Vice President, Chief Innovation Officer of NiSource from July 2022 to March 2023

 Senior Vice President and Chief Administrator Officer of Duke Energy Corporation from May 2021 to June 2022

 Senior Vice President, Supply Chain and Chief Procurement Officer of Duke Energy Indiana from 2018 to April 2021

 William Jefferson, Jr
 Executive Vice President, Chief Operating and Safety Officer of NiSource since May 2024

 Executive Vice President, Operations and Chief Safety Officer of NiSource from July 2022 to May 2024

 Station Director at STPNOC, Wadsworth, Texas, from 2020 to May 2022 and Vice President in 2022

 Michael S. Luhrs

 Executive Vice President, Strategy and Risk and Chief Commercial Officer of NiSource since March 2023

 Senior Vice President at Alliant Energy from 2022 to March 2023

 Vice President at Duke Energy Corporation from 2013 to 2022

 Kimberly S. Cuccia
 Senior Vice President, General Counsel and Corporate Secretary of NiSource since April 2022

 Vice President, Interim General Counsel and Corporate Secretary of NiSource from December 2021 to April 2022

 Vice President and Deputy General Counsel, Regulatory, of NiSource Corporate Services Company, from January 2021 to December 2021

 Vice President and General Counsel of Columbia Gas of Massachusetts and of NiSource Corporate Services Company, from 2019 to 2020

 Melanie B. Berman
 Chief Human Resources Officer and Senior Vice President, Administration of NiSource since May 2024

 Senior Vice President and Chief Human Resources Officer of NiSource from June 2021 to May 2024

 Executive Vice President and Chief Human Resources Officer of The Michaels Companies, Inc. from 2020 to 2021

 Gunnar J. Gode

 Vice President, Chief Accounting Officer and Controller of NiSource since July 2020

 Vice President and Controller of Washington Gas from March 2019 to 2020

 Our operations and financial results are subject to various risks and uncertainties, including those described below, that could adversely affect our business, financial condition, results of operations, cash flows, and the market price of our common stock.

 OPERATIONAL RISKS
 We may not be able to execute our business plan or growth strategy, including utility infrastructure investments, or business opportunities, such as data center development and related generation sources and transmission capabilities to meet potential load growth.
 Operational, financial or regulatory conditions may result in our inability to execute our business plan or growth strategy, including investments related to natural gas and electric distribution and transmission infrastructure investments and our electric generation projects. Additionally, operational, financial or regulatory conditions may result in our inability to manage the development and implementation connected to the complex business opportunity associated with growing interest in data centers from existing and potential customers.

 Our enterprise-wide transformation roadmap initiatives identify and enable long-term sustainable capability enhancements, cost optimization improvements, technology investments and work process optimization, and these initiatives have increased the volume and pace of change and may not be effective as it continues. Our customer and regulatory initiatives may not achieve planned results. Utility infrastructure investments may not materialize, may cease to be achievable or economically viable and may not be successfully completed. Furthermore, we are evaluating the potential for data center development in our service territories, including ways to effectively manage the potential power demand, generation sources, and transmission capabilities to meet potential load growth from any data center customer, while at the same time focusing on our environmental goals. We expect that management of load growth would require new generation and transmission capabilities. Natural gas may cease to be viewed as an economically and environmentally attractive fuel. Certain environmental activist groups, investors and governmental entities continue to oppose natural gas delivery and infrastructure investments because of perceived environmental impacts associated with the natural gas supply chain and end use. Energy conservation, energy efficiency, distributed generation, energy storage, policies favoring electric heat over gas heat and other factors may reduce demand for natural gas and electricity. In addition, we consider acquisitions or dispositions of assets or businesses, JVs, and mergers from time to time as we execute on our business plan and growth strategy. As data center opportunities evolve and develop, we may also enter into arrangements and agreements with customers and potential customers that require us to invest capital related to the data center development and related generation sources and transmission capabilities before we receive any potential return. Any of these circumstances could adversely affect our business, results of operations and growth prospects. Even if our business plan, growth strategy, and/or business opportunities are executed, there is still risk of, among other things, human error in maintenance, installation or operations, shortages or delays in obtaining equipment, including as a result of transportation delays and availability, labor availability and performance below expected levels (in addition to the other risks discussed in this section). We are currently experiencing, and expect to continue to experience, supply chain challenges, including labor availability issues, impacting our ability to obtain materials for our gas and electric projects, as well as our ability to ensure timely completion.

 Data center growth in our service territories, including a focus on northern Indiana, while providing growth opportunities that enhance our business strategy, provide significant financial, operational, and regulatory risks that must be effectively managed.
 As we evaluate business opportunities presented by the data center development in our territories, including a focus on northern Indiana, we face a variety of challenges including accurately predicting future power needs of data centers due to rapidly changing technology and market dynamics, managing the potential power demand, generation sources, and transmission capabilities to meet potential load growth from any data center customer, financing the capital investment needed to build and maintain the necessary infrastructure to support data center development, managing the possible environmental impact of the potential increased power demand while remaining focused on our Net Zero Goal, and evaluating and complying with evolving regulations related to data center development. As we evaluate the potential for data center development in our service territories, we must effectively manage these financial, operational and regulatory risks.

 Our distribution, transmission and generation activities involve a variety of inherent hazards and operating risks, including potential public safety risks.
 Our gas distribution and transmission, electric generation, transmission and distribution activities, involve a variety of inherent hazards and operating risks, including, but not limited to, gas leaks and over-pressurization, downed power lines, stray electrical voltage, excavation or vehicular damage to our infrastructure, outages, environmental spills, mechanical problems, damage from weather events, and other incidents, which could cause substantial financial losses. These hazards and risks have resulted and may result in serious injury or loss of life to employees and/or the general public, significant damage to property,

 environmental pollution, impairment of our operations, adverse regulatory rulings and reputational harm, which in turn could lead to substantial business and financial losses. The location of pipeline facilities, including regulator stations, liquefied natural gas and underground storage, or generation, transmission, substation and distribution facilities near populated areas, including residential areas, commercial business centers and industrial sites, could increase the level of damages resulting from such incidents. Hazardous incidents have subjected and may subject us to both civil and criminal litigation or administrative or other legal proceedings from time to time, which could result in substantial monetary judgments, fines, or penalties against us, be resolved on unfavorable terms, and require us to incur significant operational expenses. The occurrence of incidents has in certain instances adversely affected and could in the future adversely affect our reputation, cash flows, financial position and/or results of operations. We maintain insurance against some, but not all, of these risks and losses.

 We currently conduct and may conduct in the future certain operations through a JV arrangement involving third- party investors that may result in operational impasses or litigation, including business delays as a result of such arrangements.
 We have and may enter into JV arrangements involving third-party investors, including the NIPSCO Minority Interest Transaction. As part of a JV arrangement, third-party investors may hold certain protective rights that may impact our ability to make certain decisions, restricting our operational and corporate flexibility. Any such third-party investors may have interests and objectives which may differ from ours, we may be unable to cause these third parties to take action that we believe would be in the JV's best interest, and, accordingly, disputes may arise that may result in operational impasses or litigation, including business delays.

 Failure to adapt to advances in technology, including alternative energy sources, and changes in laws or regulations to support such advances in technology or alternative energy sources, and our ability to manage such related costs could make us less competitive.
 A key element of our electric business model includes generating power at central station power plants and transmitting that power to customers to achieve economies of scale and produce power at a competitive cost. We continue to transition our generation portfolio in order to implement new and diverse technologies including renewable energy, distributed generation, energy storage, and implement energy efficiency programs for customers. Advances in technology and potential competition supported by changes in laws or regulations could reduce the cost of electric generation and provide retail alternatives causing power sales to decline and the value of our generating, transmission and distribution facilities to decline.

 Our natural gas business model depends on widespread utilization of natural gas for space heating as a core driver of revenues. Alternative energy sources, new technologies or alternatives to natural gas space heating, including cold climate heat pumps and/or efficiency of other products, and potential competition supported by changes in laws or regulations could reduce demand and increase customer attrition, which could impact our ability to recover on our investments in our gas distribution assets.

 Our future success will depend, in part, on our ability to anticipate and successfully adapt to technological changes, to offer services that meet customer demands and evolving industry standards, including environmental impacts associated with our products and services, and to recover all, or a significant portion of, remaining investments in retired assets. A failure by us to effectively adapt to changes in technology, successfully implement such changes, and manage the related costs could harm the ability of our products and services to remain competitive in the marketplace and could have a material adverse impact on our business, results of operations and financial condition. Furthermore, if these changes do not provide the anticipated benefits or meet customer demands, such failure could materially adversely affect our business model as well as impact results of operations and financial condition.

 Increased dependency on technology may hinder our business operations and adversely affect our financial condition and results of operation if such technology fails.
 We use a variety of technological tools and systems including both Company-owned information technology and technological services provided by outside parties. These tools and systems support critical functions including scheduling and dispatching of service technicians, automated meter reading systems, customer care and billing, operational plant logistics, management reporting and external financial reporting. The failure of these or other similarly important technologies, or our inability to have these technologies supported, updated, expanded, recovered (including timely recovered), or integrated into other technologies, could hinder our business operations and adversely impact its financial condition and results of operations. Although the Company has, when possible, developed alternative sources of technology and built redundancy into its computer networks and tools, there can be no assurance that these efforts would protect against all potential issues related to the loss of any such technologies.

 Aging infrastructure may lead to disruptions in operations and increased capital expenditures and maintenance costs.
 We have risks associated with aging electric and gas infrastructure. These risks can be driven by threats such as, but not limited to, electrical faults, mechanical failure, internal corrosion, external corrosion, ground movement and stress corrosion and/or cracking. The age of these assets may result in a need for replacement, a higher level of maintenance costs or unscheduled outages, despite efforts by us to properly maintain or upgrade these assets through inspection, scheduled maintenance and capital investment. In addition, the nature of the information available on aging infrastructure assets, which in some cases is incomplete, may make the operation of the infrastructure, inspections, maintenance, upgrading and replacement of the assets particularly challenging. Missing or incorrect infrastructure data may lead to (1) difficulty properly locating facilities, which can result in excavator damage and operational or emergency response issues, (2) configuration and control risks associated with the modification of system operating pressures in connection with turning off or turning on service to customers, which can result in unintended outages or operating pressures and (3) other potential risks related to missing or incorrect infrastructure data. Also, additional maintenance and inspections are required in some instances to improve infrastructure information and records and address emerging regulatory or risk management requirements, resulting in increased costs.

 Supply chain issues related to shortages of materials, labor and transportation logistics may lead to delays in the maintenance and replacement of aging or damaged infrastructure, which could increase the probability and/or impact of a public safety incident. We lack diversity in suppliers of some gas materials. While we have implemented contractual protections with suppliers and stockpile some materials in inventory for such supply risks, we may not be effective in ensuring that we can obtain adequate emergency supply on a timely basis in each state, that no compromises are being made on quality and that we have alternate suppliers available. The failure to operate our assets as desired could result in interruption of electric service, major component failure at generating facilities and electric substations, gas leaks and other incidents, and an inability to meet firm service and compliance obligations, which could adversely impact revenues, and could also result in increased capital expenditures and maintenance costs, which, if not fully recovered from customers, could negatively impact our financial results.

 We may be unable to obtain insurance on acceptable terms or at all, and the insurance coverage we do obtain may not provide protection against all significant losses.
 Our ability to obtain insurance, as well as the cost and coverage of such insurance, is impacted by various events and developments affecting our industry and the financial condition and underwriting considerations of insurers. For example, some insurers have discontinued underwriting certain carbon-intensive energy-related businesses such as those in the coal industry or excluded coverage for specific perils such as wildfires or punitive damage risks. Certain perils, such as cyber liability, are now being excluded from some master policies for property and casualty insurance, requiring, where we have the ability, procurement of additional policies to maintain consistent coverage at an additional cost. Specific natural catastrophe events, such as hail and tornado, may not be covered with the same limits as other perils in certain property policies, as full coverage for these events is unavailable in the marketplace without costly specialty policies. Insurance coverage may not continue to be available at limits, rates or terms acceptable to us. In addition, our insurance is not sufficient or effective under all circumstances and against all hazards or liabilities to which we are subject. Certain types of damages, expenses or claimed costs, such as fines and penalties, have been and in the future may be excluded under the policies. In addition, insurers providing insurance to us may raise defenses to coverage under the terms and conditions of the respective insurance policies that could result in a denial of coverage or limit the amount of insurance proceeds available to us. Any losses for which we are not fully insured or that are not covered by insurance at all could materially adversely affect our results of operations, cash flows and financial position.

 Aspects of the implementation of our electric generation strategy, including the timing of the retirement of our coal generation units or the addition of new generation resources, may be delayed and may not achieve intended results.
 We intend to retire the remaining two coal units at R.M. Schahfer Generating Station by the end of 2025, two natural gas-fired peaking units at R.M. Schahfer Generating Station by the end of 2027, and the coal unit at Michigan City Generating Station by the end of 2028. These units are being replaced with a diverse, flexible, and scalable mix of incremental resources, including short-term contracted capacity resources, expanded demand side management programs, wind, solar, battery energy storage, and new natural gas peaking resources. Macro supply chain issues and U.S. federal policy actions could create uncertainty around the availability of key input materials necessary to develop and place our electric generation projects in service.

 We expect renewable generation, battery energy storage and natural gas generation to be the primary ways in which we will meet our electric generation capacity and reliability obligations to the MISO market and reliably serve our customers when we retire our coal generation capacity. Any delays in the completion of such projects could create significant risks for us to reliably meet our capacity and energy obligations to MISO and to provide reliable and affordable energy to our customers. Delays to the

 completion dates of our projects could also include delays in the financial return of certain investments and impact the overall timing of our electric generation transition.

 Our electric generation strategy may require additional investment to meet our MISO obligations and may require significant future capital expenditures, operating costs and charges to earnings that may negatively impact our financial position, financial results and cash flows. An inability to secure and deliver on electric generation projects has negatively impacted, and could in the future negatively impact, our generation transition timeline and could negatively impact our achievement of decarbonization goals and reputation.

 Our capital projects and programs subject us to construction and supply risks, and are subject to regulatory oversight, including requirements for permits, approvals and certificates from various governmental agencies.
 Our business requires substantial capital expenditures for investments in, among other things, capital improvements to our electric generating facilities, electric and natural gas transmission and distribution infrastructure, natural gas storage and other projects, including projects for environmental compliance. As we undertake these projects and programs, we may be unable to complete them on schedule or at the anticipated costs. Additionally, we may construct or purchase some of these projects and programs to capture anticipated future growth, which may not materialize, and may cause the construction to occur over an extended period of time.

 Construction risks include, but are not limited to, changes in the availability or costs of materials, equipment, commodities or labor (including changes to tariffs on materials), delays caused by construction incidents or injuries, work stoppages, poor initial cost estimates, unforeseen engineering issues, and general contractors and subcontractors not performing as required under their contracts.

 We are monitoring risks related to increasing delivery lead times for certain construction and other materials, increasing risk associated with the unavailability of materials due to global shortages in raw materials and issues with transportation logistics, and risk of decreased construction labor productivity in the event of disruptions in the availability of materials critical to our gas and electric operations. Our efforts to enhance our resiliency to supply chain shortages may not be effective. We continue to see increasing prices associated with certain materials, equipment and products, which impacts our ability to complete major capital projects at the cost that was planned and approved. To the extent that delays occur, costs increase, costs become unrecoverable or recovery is delayed, or we otherwise become unable to effectively manage our affordability and complete our capital projects, our business operations, results of operations, cash flows, and financial condition may be adversely affected. In addition, to the extent that delays occur on projects that target system integrity, the risk of an operational incident could increase.

 Our existing and planned capital projects require numerous permits, approvals and certificates from federal, state, and local governmental agencies, including obtaining necessary rights-of-way, easements and transmissions connections, as well as complying with various environmental statutes, rules and regulations, among other items. If there is a delay in obtaining any required regulatory approvals or if we fail to obtain or maintain any required approvals or to comply with any applicable laws or regulations, we may not be able to construct or operate our facilities, we may be forced to incur additional costs or we may be unable to recover any or all amounts invested in a project. We also may not receive the anticipated increases in revenue and cash flows resulting from such projects and programs until after their completion.

 A significant portion of the gas and electricity we sell is used by residential and commercial customers for heating and air conditioning. Accordingly, fluctuations in weather, gas and electricity commodity costs, and economic conditions impact customer demand.
 Energy sales are sensitive to variations in weather. Forecasts of energy sales are based on "normal" weather, which represents a long-term historical average. Significant variations from normal weather resulting from climate change or other factors could have, and have had, a material impact on energy sales. Additionally, residential usage, and to some degree commercial usage, is sensitive to fluctuations in commodity costs for gas and electricity (which volatility is described in more detail in the below risk factor), whereby usage declines with increased costs which could affect our financial results. Rising gas costs could heighten regulator and stakeholder sensitivity relative to the impact of base rate increases on customer affordability. Lastly, residential and commercial customers' usage is sensitive to economic conditions and factors such as recession, inflation, unemployment, demand and consumer confidence. Therefore, prevailing economic conditions affecting the demand of our customers may in turn affect our financial results.

 Fluctuations in the price of energy commodities or their related transportation costs, or an inability to obtain an adequate, reliable and cost- effective fuel supply may impact our ability to meet customer demand.
 Our current electric generating fleet has dependencies on coal and natural gas for fuel, and our gas distribution operations purchase and resell a portion of the natural gas we deliver to our customers. These energy commodities are subject to price fluctuations and fluctuations in associated transportation costs. We use physical hedging through the use of storage assets and use financial products in certain jurisdictions in order to offset fluctuations in commodity supply prices. We rely on regulatory recovery mechanisms in the various jurisdictions in order to fully recover the commodity costs incurred in selling energy to our customers. While we have historically been successful in the recovery of costs related to such commodity prices, there can be no assurance that such costs will be fully recovered through rates in a timely manner.

 In addition, we depend on electric transmission lines, natural gas pipelines, and other transportation and storage facilities owned and operated by third parties to deliver the electricity and natural gas we sell to wholesale markets, supply natural gas to our gas storage and electric generation facilities, and provide retail energy services to our customers. If transportation is disrupted, if capacity is inadequate or if supply is interrupted due to issues at the wellhead, we may be unable to sell and deliver our gas and electric services to some or all of our customers. As a result, we may be required to procure additional or alternative electricity and/or natural gas supplies at then-current market rates, which, if recovery of related costs is disallowed, could have a material adverse effect on our businesses, financial condition, cash flows, results of operations and/or prospects.

 Failure to attract, retain or re-skill an appropriately qualified workforce, and maintain good labor relations, could adversely impact safety, service reliability, and customer satisfaction.
 We face increased competition for talent which may result in longer hire times or increased cost due to the competitive nature of certain positions.

 We operate in an industry that requires many of our employees and contractors to possess unique technical skill sets. An aging workforce without appropriate replacements, the mismatch of skill sets to future needs, the unavailability of talent for internal positions and the unavailability of contract resources may lead to operating challenges or increased costs. These operating challenges include lack of resources, loss of knowledge and a lengthy time period associated with skill development. For example, certain skills, such as those related to construction, maintenance and repair of transmission and distribution systems, are in high demand and have a limited supply. Current and prospective employees may determine that they do not wish to work for us due to market, economic, employment or other conditions, including those related to organizational changes as described in the risk factor below.

 Further, as part of our strategic plan, which includes enhanced technology, transmission and distribution investments, and a reduction in reliance on coal-fired generation, we will need to attract and retain personnel that are qualified to implement such a strategy and may need to retrain or re-skill certain employees to support our long-term objectives. Additionally, successful implementation of our strategic plan is dependent on our ability to recruit and retain key executive officers to oversee its progress.

 A significant portion of our workforce is subject to collective bargaining agreements. Our collective bargaining agreements are generally negotiated on an operating company basis with some companies having multiple bargaining agreements, which may span different geographies. Any failure to reach an agreement on new labor contracts or to renegotiate these labor contracts might result in strikes, boycotts or other labor disruptions. Our workforce continuity plans may not be effective in avoiding work stoppages that may result from labor negotiations or mass resignations. Labor disruptions, strikes or significant negotiated wage and benefit increases, whether due to union activities, employee turnover or otherwise, could have a material adverse effect on our businesses, results of operations and/or cash flows.

 Failure to attract, retain, or re-skill qualified employees, including the ability to transfer significant internal historical knowledge and expertise to the new employees, could result in a loss of momentum, loss of high-level employees to our peers and could materially adversely affect our business, results of operations, cash flow and financial condition. If we are unable to successfully attract and retain an appropriately qualified workforce and maintain satisfactory labor relations, safety, service reliability, and customer satisfaction, our results of operations could be adversely affected.

 If we cannot effectively manage new initiatives and organizational changes, we will be unable to address the opportunities and challenges presented by our strategy and the business and regulatory environment.
 In order to execute on our sustainable growth strategy and enhance our culture of ongoing continuous improvement, we must effectively manage the complexity and frequency of new initiatives and organizational changes. The organizational changes

 from our transformation initiatives have put short-term pressure on employees due to the volume and pace of change and, in some cases, the loss of personnel. Front-line workers are being impacted by the variety of process and technology changes that are currently in progress.

 If we are unable to make decisions quickly, assess our opportunities and risks, and successfully implement new governance, managerial and organizational processes as needed to execute our strategy in this increasingly dynamic and competitive business and regulatory environment, our financial condition, results of operations and relationships with our business partners, regulators, customers, employees and stockholders may be negatively impacted.

 Actions of activist stockholders could negatively affect our business and stock price and cause us to incur significant expenses.
 We may be subject to actions or proposals from activist stockholders or others that may not be aligned with our long-term strategy or the interests of our other stockholders. Our response to suggested actions, proposals, director nominations and contests for the election of directors by activist stockholders could disrupt our business and operations, divert the attention of our board of directors, management and employees, and be costly and time consuming. Potential actions by activist stockholders or others may interfere with our ability to execute our strategic plans; create perceived uncertainties as to the future direction of our business or strategy; cause uncertainty with our regulators; make it more difficult to attract and retain qualified personnel; and adversely affect our relationships with our existing and potential business partners. Any of the foregoing could adversely affect our business, financial condition and results of operations. Also, we may be required to incur significant fees and other expenses related to responding to stockholder activism, including for third-party advisors. Moreover, our stock price could be subject to significant fluctuation or otherwise be adversely affected by the events, risks and uncertainties of any stockholder activism.

 We outsource certain business functions to third-party suppliers and service providers, and may be impacted by substandard performance or quality by third parties.
 Utilities rely on extensive networks of business partners and suppliers to support critical enterprise capabilities across their organizations. Like other companies in the utilities industry, we outsource certain services to third parties in areas including construction services, information technology, materials, fleet, environmental, operational services, corporate and other areas. We have seen, and may see in the future, slowing deliveries from suppliers and in some cases materials and labor shortages. In addition to delays and unavailability, at times, outsourcing of services to third parties could expose us to inferior service quality or substandard deliverables, which may result in non-compliance (including with applicable legal requirements and industry standards), interruption of service, accidents, or reputational harm, which could negatively impact our business, financial condition and results of operations. The nature of indirect supply chain, including a potential lack of control or certain visibility into sourcing by vendors, may also impact our ability to serve customers in a safe, reliable and cost-effective manner. These risks include the risk of operational failure, reputation damage, disruption due to new supply chain disruptions, exposure to significant commercial losses and fines and poorly positioned and distressed suppliers. If we continue to see delayed deliveries and shortages or if any other difficulties in the operations of these third-party suppliers and service providers, including their systems, were to occur, they could adversely affect our results of operations, or adversely affect our ability to work with regulators, unions, customers, or employees.

 A cyber-attack or security breach on any of our or certain third-party technology systems, including but not limited to information systems, infrastructure, software and hardware, upon which we rely may adversely affect our ability to operate, could lead to a loss or misuse of confidential and proprietary information, or potential liability.
 We are reliant on technology to run our business, which is dependent upon technology systems to process critical information necessary to conduct various elements of our business, including the generation, transmission and distribution of electricity; operation of our gas pipeline facilities; and the recording and reporting of commercial and financial transactions to regulators, investors and other stakeholders. In addition to general information and cybersecurity risks that all large corporations face (e.g., ransomware, malware, unauthorized access attempts, phishing attacks, malicious intent by insiders, third-party software vulnerabilities and inadvertent disclosure of sensitive information), the utility industry faces evolving and increasingly complex cybersecurity risks associated with protecting electric grid and natural gas infrastructure as well as sensitive and confidential customer and employee information. Deployment of new business technologies, along with maintaining legacy technology, represents a large-scale opportunity for attacks on our information systems and confidential customer and employee information, as well as on the integrity of the electric grid and the natural gas infrastructure. Increasing large-scale corporate cyber-attacks in conjunction with more sophisticated threats continue to challenge utility companies. Additionally, international conflicts, as well as increased surveillance activity from global threat actors, has increased the likelihood of a cyber-attack or security breach on critical infrastructure systems.

 Additionally, our information systems experience ongoing, often sophisticated, cyber-attacks or security breaches by a variety of sources, including foreign sources, with the apparent aim to breach our cyber-defenses. While we have implemented and maintain a cybersecurity program designed to protect our information technology, operational technology, and data systems from such cyber-attacks or security breaches, our cybersecurity program does not prevent all breaches, cyber-attack or security breach incidents. We have experienced an increase in the number of attempts by external parties to access our networks or our company data without authorization. We have experienced, and expect to continue to experience, cybersecurity intrusions and attacks or security breaches to our information systems. To our knowledge, none of these intrusions or attacks have resulted in a material cybersecurity intrusion or data breach. The risk of a disruption or breach of our operational technology, or the compromise of the data processed in connection with our operations, through cybersecurity breach or ransomware attack has increased as attempted cyber-attacks or security breaches have advanced in sophistication and number around the world. Technological complexities combined with advanced cyber-attack or security breach techniques, lack of cybersecurity hygiene and human error can result in a cybersecurity incident, such as a ransomware attack. Supplier non-compliance with cybersecurity controls can also result in a cybersecurity incident. We are aware of vendor cybersecurity incidents that have impacted our business, although no such events have had a material impact. Cyber-attacks or security breaches can occur at any point in the supply chain or with any suppliers, and future supplier non-compliance with cybersecurity controls could result in material cybersecurity incidents. In addition, we use unmanned aircraft systems (UAS) or drones in our business operations. UASs are also being used for malicious activities and the cybersecurity risk in connection with operating UASs is increasing.

 In addition, we collect and retain personally identifiable information of our customers and employees. Customers and employees expect that we will adequately protect their personal information.

 A cybersecurity breach of our information systems or operational technology, or a cybersecurity breach of the information systems of our customers, suppliers or others with whom we do business, could, among other things, (i) adversely impact our ability to safely and reliably deliver electricity and natural gas to our customers through our generation, transmission and distribution systems and potentially negatively impact our compliance with certain mandatory reliability and gas flow standards, (ii) subject us to reputational and other harm or liabilities associated with theft or inappropriate release of certain types of information such as system operating information or information, personal or otherwise, relating to our customers or employees, (iii) impact our ability to manage our businesses, and/or (iv) subject us to legal and regulatory proceedings and claims from third parties, in addition to remediation costs, any of which, in turn, could have a material adverse effect on our businesses, cash flows, financial condition and/or results of operations. Although we do maintain cybersecurity insurance, it is possible that such insurance will not adequately cover any losses or liabilities we may incur as a result of a cybersecurity incident.

 Compliance with and changes in cybersecurity requirements have a cost and operational impact on our business, and failure to comply with such laws and regulations could adversely impact our reputation, results of operations, financial condition and/or cash flows.
 The legal and regulatory environment surrounding cybersecurity and privacy is increasingly demanding. As cyber-attacks or security breaches are becoming more sophisticated, critical infrastructure assets, including pipelines and electric infrastructure, may be specifically targeted. In 2021, the TSA announced two new cybersecurity directives in response to a ransomware attack on the Colonial Pipeline that occurred earlier in the year. These directives, including updates or amendments to such TSA directives, require critical pipeline owners to comply with mandatory reporting measures, designate a cybersecurity coordinator, provide vulnerability assessments, and ensure compliance with certain cybersecurity requirements. In November 2024, the TSA issued a Notice of Proposed Rulemaking (NPRM) that would mandate cyber risk management and reporting requirements for the pipeline industry. Such directives or additional legal requirements may require expenditure of significant additional resources to respond to cyber-attacks or security breaches, to continue to modify or enhance protective measures, or to assess, investigate and remediate any critical infrastructure security vulnerabilities. Increased costs and the operational impacts of compliance and changes in cybersecurity requirements, including any failure to comply with government regulations or any failure in our cybersecurity protective measures may result in enforcement actions, all of which may have a material adverse effect on our business, results of operations and financial condition. In addition, there is no certainty that costs incurred related to securing against threats will be recovered through rates.

 The impacts of natural disasters, acts of terrorism, acts of war, civil unrest, accidents, public health emergencies or other catastrophic events may disrupt operations and reduce the ability to service customers.
 A disruption or failure of natural gas distribution systems, or within electric generation, transmission or distribution systems, in the event of a hurricane, tornado, wildfire, flood, or other major weather event, or terrorist attack, acts of war, international

 military invasions, including the political and economic disruption and uncertainty related to such terrorist attack, acts of war, or international military invasions, civil unrest, accident, public health emergency (e.g. pandemic), or other catastrophic event could cause delays in completing sales, providing services, or performing other critical functions. We have experienced disruptions in the past from tornadoes, hurricanes and remnants of hurricanes and other events of this nature. Also, companies in our industry face a heightened risk of exposure to and have experienced acts of terrorism and vandalism. Our electric and gas physical infrastructure may be targets of physical security threats or terrorist activities that could disrupt our operations. We have increased security given the current environment and may be required by regulators or by the future threat environment to make investments in security that we cannot currently predict. In addition, the supply chain constraints that we are experiencing could impact our ability to timely restore services. The occurrence of such events could materially adversely affect our business, financial position and results of operations. In accordance with customary industry practice, we maintain insurance against some, but not all, of these risks and losses. As a result, the amount and scope of insurance coverage maintained against losses resulting from any such event may not be sufficient to cover such losses or otherwise adequately compensate for any business disruptions that could result.

 We are exposed to significant reputational risks, which make us vulnerable to a loss of cost recovery, increased litigation and negative public perception.
 As a utility company, we are subject to adverse publicity focused on the actual or perceived reliability or affordability of our services, the speed with which we are able to respond effectively to electric outages, natural gas leaks or events and related accidents and similar interruptions caused by storm damage, physical or cybersecurity incidents, or other unanticipated events, as well as our own or third parties' actions or failure to act. We are subject to prevailing labor markets and potential high attrition, which may impact the speed of our customer service response. We are also facing supply chain challenges, the impacts of which may adversely impact our reputation in several areas as described elsewhere in these risk factors. We are also subject to adverse publicity related to actual or perceived environmental practices or impacts, including our ability to meet the challenges posed by climate change and achieve our carbon emission reduction goals, as well as negative opinions regarding the appropriateness of such goals. If customers, legislators or regulators have or develop a negative opinion of us, this could result in less favorable legislative and regulatory outcomes or increased regulatory oversight, increased litigation and negative public perception. The foregoing may have adverse effects on our business, results of operations, cash flow and financial condition.

 The physical impacts of climate change and the transition to a lower carbon future are impacting our business and could materially adversely affect our results of operations.
 Climate change is exacerbating risks to our physical infrastructure by increasing the frequency of extreme weather, including temperature stresses to our electric and gas systems and equipment and storms and floods that damage infrastructure. In addition, climate change is likely to cause lake and river level changes that affect the manner in which services are currently provided and droughts or other limits on water used to supply services, and other extreme weather conditions. We have adapted and will continue to evolve our infrastructure and operations to meet current and future needs of our stakeholders. With higher frequency of these and other possible extreme weather events it may become more costly for us to safely and reliably deliver certain products and services to our customers. Further, as our generation profile increases geographically, it is potentially more vulnerable to certain weather hazards than centralized generation, thereby increasing the frequency of weather impacts to overall electric reliability. Some of these costs may not be recovered. To the extent that we are unable to recover those costs, or if higher rates arising from recovery of such costs result in reduced demand for services, our future financial results may be adversely impacted. Further, as the intensity and frequency of significant weather events increases, insurers may reprice or remove themselves from insuring risks for which the company has historically maintained insurance, resulting in increased cost or risk to us.

 Our strategy may be impacted by policy and legal, technology, market and reputational risks and opportunities that are associated with the transition to a lower-carbon economy, as disclosed in other risk factors in this section. As a result of increased awareness regarding climate change, coupled with economic considerations, availability of alternative energy sources, including private solar, microturbines, fuel cells, energy-efficient buildings and energy storage devices, and regulations restricting, or imposing fees on, emissions, some consumers and companies may use less energy, meet their own energy needs through alternative energy sources or avoid expansions of their facilities, including natural gas facilities, which may result in less demand for our services. As these technologies become a more cost-competitive option, whether through cost effectiveness or government incentives and subsidies, certain customers may choose to meet their own energy needs and subsequently decrease usage of our systems and services, which may result in, among other things, our facilities becoming less competitive and economical. Further, evolving investor sentiment related to the use of fossil fuels and initiatives to restrict continued production of fossil fuels could result in a significant impact on our electric generation and natural gas businesses in the future.

 We are unable to forecast the future of commodity markets. Some of our generation is dependent on natural gas and coal, and we pass through the costs for these energy sources to our customers. In addition, in our gas distribution business, we procure natural gas on behalf of certain customers, and we pass through the actual cost of the gas consumed. Diminished investor interest in funding fossil fuel development could reduce the amount of exploration and production of natural gas or coal, or investment in gas transmission pipelines. Reduced production and transportation of natural gas could, in the long-term, lead to supply shortages leading to baseload generation outages. Given that we pass through commodity costs to customers, this could also create the potential for regulatory questions resulting from increased customer costs, reduced fossil fuel investment, due to evolving investor sentiment, could lead to higher commodity prices and shortages impacting our generation and our reputation with regulators. Conversely, demand for our services may increase as a result of customer changes in response to climate change. For example, as the utilization of electric vehicles increases, demand for electricity may increase, resulting in increased usage of our systems and services.

 Any negative views with respect to our environmental practices or our ability to meet the challenges posed by climate change from regulators, customers, investors or legislators could not only harm our reputation, but could adversely affect the perceived value of our products and services. Changes in policy to combat climate change, and technology advancement, each of which can also accelerate the implications of a transition to a lower carbon economy, may materially adversely impact our business, financial position, results of operations, and cash flows. For example, Maryland is considering policies related to the planning, practices, and future operations of natural gas suppliers in its state which could impact our business in the future.

 We are subject to operational and financial risks and liabilities associated with the implementation and efforts to achieve our carbon emission reduction goals.
 In November 2022, we announced our goal of reaching net zero Scope 1 and 2 greenhouse gas emissions by 2040 (the "Net Zero Goal"). Achieving the Net Zero Goal will require supportive regulatory and legislative policies, favorable stakeholder environments and advancement of technologies that are not currently economically or technologically feasible to deploy at scale, of which, the impacts and costs are not currently fully understood. NIPSCO's electric generation transition, which is outlined in the 2024 Plan, is a key element of the Net Zero Goal. Our analysis and plan for execution requires us to make a number of assumptions. These goals and underlying assumptions involve risks and uncertainties and are not guarantees. Should one or more of our underlying assumptions prove incorrect, our actual results and ability to achieve our emissions goal could differ materially from our expectations. Certain of the assumptions that could impact our ability to meet our emissions goal include, but are not limited to: the accuracy of current emission measurements, the ability to complete and implement generation alternatives to NIPSCO's coal generation and retire NIPSCO's coal facilities; the ability to implement our modernization plans for our natural gas pipelines and facilities, including construction of new pipelines and facilities; customer demand and capacity needs remaining in line with current expectations, including impacts from energy efficiency and technological innovation and adoption of alternative energy sources; the ability to effectively manage business opportunities from data center development; the ability to manage costs and supply chain risks associated with construction of electric and natural gas assets; technological innovation and costs of energy generation technologies such as wind, solar, thermal and energy storage, and of carbon abatement technologies such carbon capture solutions; regulatory approval; impacts of potential future environmental regulations or legislation, including potential GHG pricing regimes such as a carbon tax or methane fee; price, availability and regulation of carbon offsets; and price of natural gas and alternative fuels such as hydrogen. Any negative opinions with respect to these goals or our environmental practices, including our ability to meet the challenges posed by climate change and our ability to achieve our carbon emission reduction goals, or a scaling back of these goals, formed by regulators, customers, investors or legislators could harm our reputation and have an adverse effect on our financial condition.

 FINANCIAL, ECONOMIC AND MARKET RISKS
 We have substantial indebtedness which could adversely affect our financial condition.
 Our business is capital intensive and we rely significantly on long-term debt to fund a portion of our capital expenditures and repay outstanding debt, and on short-term borrowings to fund a portion of day-to-day business operations. We had total consolidated indebtedness of $13,960.3 million outstanding as of December 31, 2024. Our substantial indebtedness could have important consequences. For example, it could:
 • limit our ability to borrow additional funds or increase the cost of borrowing additional funds;
 • reduce the availability of cash flow from operations to fund working capital, capital expenditures and other general corporate purposes;
 • limit our flexibility in planning for, or reacting to, changes in the business and the industries in which we operate;
 • lead parties with whom we do business to require additional credit support, such as letters of credit, in order for us to transact such business;
 • place us at a competitive disadvantage compared to competitors that are less leveraged;

 • increase vulnerability to general adverse economic and industry conditions; and
 • limit our ability to execute on our growth strategy, which is dependent upon access to capital to fund our substantial infrastructure investment program.

 Some of our debt obligations contain financial covenants related to debt-to-capital ratios and cross-default provisions. Our failure to comply with any of these covenants could result in an event of default, which, if not cured or waived, could result in the acceleration of outstanding debt obligations. Additionally, non-compliance with debt covenants could adversely affect our ability to obtain future borrowings and as a result materially adversely affect our business, financial condition, results of operations, and liquidity.

 A drop in our credit ratings could adversely impact our cash flows, results of operation, financial condition and liquidity.
 The availability and cost of credit for our businesses may be greatly affected by credit ratings. The credit rating agencies periodically review our ratings, taking into account factors such as our capital structure, earnings profile, liabilities, and overall shifts in the economy or business environment. We are committed to maintaining investment grade credit ratings; however, there is no assurance we will be able to do so in the future. Our credit ratings could be lowered or withdrawn entirely by a rating agency if, in its judgment, the circumstances warrant. Any negative rating action could adversely affect our ability to access capital at rates and on terms that are attractive. A negative rating action could also adversely impact our business relationships with suppliers and operating partners, who may be less willing to extend credit or offer us similarly favorable terms as secured in the past under such circumstances.

 Certain of our subsidiaries have agreements that contain "ratings triggers" that require increased collateral in the form of cash, a letter of credit or other forms of security for new and existing transactions if our credit ratings (including the standalone credit ratings of certain of our subsidiaries) are dropped below investment grade. These agreements are primarily for insurance purposes and for the physical purchase or sale of gas or power. As of December 31, 2024, the collateral requirement that would be required in the event of a downgrade below the ratings trigger levels would amount to approximately $115.5 million. In addition to agreements with ratings triggers, there are other agreements that contain "adequate assurance" or "material adverse change" provisions that could necessitate additional credit support such as letters of credit and cash collateral to transact business.

 If our or certain of our subsidiaries' credit ratings were downgraded, especially below investment grade, financing costs and the principal amount of borrowings would likely increase due to the additional risk of our debt and because certain counterparties may require additional credit support as described above. Such amounts may be material and could adversely affect our cash flows, results of operations and financial condition. Losing investment grade credit ratings may also result in more restrictive covenants and reduced flexibility on repayment terms in debt issuances, lower share price and greater stockholder dilution from common equity issuances, in addition to reputational damage within the investment community.

 Adverse economic and market conditions, including increases in inflation or interest rates, recession or changes in investor sentiment could materially and adversely affect our business, results of operations, cash flows, financial condition and liquidity.
 Deteriorating, sluggish or volatile economic conditions in our operating jurisdictions could adversely impact our ability to maintain or grow our customer base and collect revenues from customers, which could reduce our revenue or growth rate and increase operating costs. A continued economic downturn or recession, or slowing or stalled recovery from such economic downturn or recession, may have a material adverse effect on our business, financial condition, or results of operations.

 We rely on access to the capital markets to finance our liquidity and long-term capital requirements, including expenditures for our utility infrastructure and to comply with future regulatory requirements, to the extent not satisfied by the cash flow generated by our operations. We have historically relied on long-term debt and on the issuance of equity securities to fund a portion of our capital expenditures and repay outstanding debt, and on short-term borrowings to fund a portion of day-to-day business operations. There may be external factors such as inflation, monetary policy or other market conditions which could impact our cost of borrowing and could make it more difficult to obtain financing for our operations or investments on favorable terms. Successful implementation of our long-term business strategies, including capital investment, is dependent upon our ability to access the capital and credit markets, including the banking and commercial paper markets, on competitive terms and rates. An economic downturn or uncertainty, market turmoil, changes in interest rates, changes in tax policy, challenges faced by financial institutions, changes in our credit ratings, or a change in investor sentiment toward us or the utilities industry generally could adversely affect our ability to raise additional capital or refinance debt. For example, because

 NIPSCO's current generating facilities substantially rely on coal for its operations, certain financial institutions may choose not to participate in our financing arrangements. In addition, investors may choose to sell or choose not to purchase our stock due to environmental, social and governance or sustainability concerns. Reduced access to capital markets, increased borrowing costs, and/or lower equity valuation levels could reduce future earnings per share and cash flows. In addition, any rise in interest rates may lead to higher borrowing costs, which may adversely impact reported earnings, cost of capital and capital holdings.

 We may face limits, or the inability, to access credit and capital markets or may experience significant increases in the cost of capital, which could limit our ability to implement or increase the costs of implementing, our business plan, which, in turn, could materially and adversely affect our results of operations, cash flows, financial condition and liquidity.

 Most of our revenues are subject to economic regulation and are exposed to the impact of regulatory rate reviews and proceedings.
 Most of our revenues are subject to economic regulation at either the federal or state level. As such, the revenues generated by us are subject to regulatory review by the applicable federal or state authority. These rate reviews determine the rates charged to customers and directly impact revenues. Our financial results are dependent on frequent regulatory proceedings in order to ensure timely recovery of costs and investments. As described in more detail in the risk factor below, the outcomes of these proceedings are uncertain, potentially lengthy and could be influenced by many factors, some of which may be outside of our control, including the cost of providing service, the necessity of expenditures, regulatory interpretations, customer intervention, economic conditions, the political environment and customer affordability. Further, the rate orders are subject to appeal, which creates additional uncertainty as to the rates that will ultimately be allowed to be charged for services.

 The actions of regulators and legislators could result in outcomes that may adversely affect our earnings and liquidity.
 The rates that our electric and natural gas companies charge their customers are determined by their state regulatory commissions and by the FERC. These state regulatory commissions also regulate the companies' accounting, operations, the issuance of certain securities and certain other matters. The FERC also regulates the transmission of electric energy, the sale of electric energy at wholesale, accounting, issuance of certain securities and certain other matters, including reliability standards through the North American Electric Reliability Corporation (NERC).

 Under state and federal law, our electric and natural gas companies are entitled to charge rates that are sufficient to allow them an opportunity to recover their prudently incurred operating and capital costs and a reasonable rate of return on invested capital, to attract needed capital and maintain their financial integrity, while also protecting relevant public interests. Our electric and natural gas companies are required to engage in regulatory approval proceedings as a part of the process of establishing the terms and rates for their respective services. Each of these companies prepares and submits periodic rate filings with their respective regulatory commissions for review and approval, which allows for various entities to challenge our current or future rates, structures or mechanisms and could alter or limit the rates we are allowed to charge our customers. These proceedings typically involve multiple parties, including governmental bodies and officials, consumer advocacy groups, and various consumers of energy, who have differing interests. Any change in rates, including changes in allowed rate of return, are subject to regulatory approval proceedings that can be contentious, lengthy, and subject to appeal. This may lead to uncertainty as to the ultimate result of those proceedings. Established rates are also subject to subsequent prudency reviews by state regulators, whereby various portions of rates could be adjusted, subject to refund or disallowed, including cost recovery mechanisms. The ultimate outcome and timing of regulatory rate proceedings could have a significant effect on our ability to recover costs or earn an adequate return. Adverse decisions in our proceedings could adversely affect our financial position, results of operations and cash flows.

 There can be no assurance that regulators will approve the recovery of all operating and capital costs incurred by our electric and natural gas companies, including, but not limited to, costs for construction, operation and maintenance, and compliance with current and future changes in environmental, federal pipeline safety, critical infrastructure and cybersecurity laws and regulations. Further, we face regulatory challenges when our electric and gas companies seek regulatory recovery of increases to materials and other costs as a result of inflationary pressures, including accounting for inflationary pricing in plans and assumptions and ensuring there is a regulatory recovery model. There is debate among state regulators and other stakeholders over how to transition to a decarbonized economy and prudency arguments relative to investing in natural gas assets when the depreciable life of the assets may be shortened due to electrification. The inability to recover a significant amount of operating or capital costs could have an adverse effect on a company's financial position, results of operations and cash flows.

 Changes to rates may occur at times different from when costs are incurred. Additionally, catastrophic events at other utilities could result in our regulators and legislators imposing additional requirements that may lead to additional costs or operational requirements for the companies.

 In addition to the risk of disallowance of incurred costs, regulators may also impose downward adjustments in a company's allowed ROE as well as assess penalties and fines. Regulators may reduce ROE to mitigate potential customer bill increases due to items unrelated to capital investments. These actions would have an adverse effect on our financial position, results of operations and cash flows.

 Our electric business is subject to mandatory reliability and critical infrastructure protection standards established by NERC and enforced by the FERC. The critical infrastructure protection standards focus on controlling access to critical physical and cybersecurity assets. Compliance with the mandatory reliability standards could subject our electric utilities to higher operating costs. In addition, compliance with PHMSA regulations, including the expected final ruling around leak detection and repair requirements could subject our gas utilities to higher operating costs and divert business resources from other activities in order to remain compliant. If our businesses are found to be in noncompliance, we could be subject to sanctions, including substantial monetary penalties, or damage to our reputation.

 Changes in tax laws, as well as the potential tax effects of business decisions, could negatively impact our business, results of operations (including our expected project returns from our planned renewable energy projects), financial condition and cash flows.

 Our business operations are subject to economic conditions in certain industries.
 Business operations throughout our service territories have been and may continue to be adversely affected by economic events at the national and local level where our businesses operate. In particular, sales to large industrial customers, such as those in the steel, oil refining, industrial gas and related industries, are impacted by economic downturns and recession; geographic or technological shifts in production or production methods; and consumer demand for environmentally friendly products and practices. The U.S. manufacturing industry continues to adjust to changing market conditions including international competition, inflation and increasing costs, government and societal pressure to decarbonization, and fluctuating demand for its products.

 We are exposed to risk that customers will not remit payment for delivered energy or services, and that suppliers or counterparties will not perform under various financial or operating agreements.
 Our extension of credit is governed by a Corporate Credit Risk Management Policy, involves judgment by our employees and is based on an evaluation of customer, supplier, or counterparty's financial condition, credit history and other factors. We monitor our credit risk exposure by obtaining credit reports and updated financial information for customers and suppliers, and by evaluating the financial status of our banking partners and other counterparties by reference to market-based metrics such as credit default swap pricing levels, and to traditional credit ratings provided by the major credit rating agencies. Adverse economic conditions impacting these credit risk exposures could result in an increase in defaults by customers, suppliers and counterparties. We are also exposed to the risk that due to adverse economic conditions one or more suppliers or counterparties may fail or delay the performance of their contractual obligations, such risks could negatively impact our business, financial condition and cash flow.

 We are a holding company and are dependent on cash generated by our subsidiaries to meet our debt obligations and pay dividends on our stock.
 We are a holding company and conduct our operations primarily through our subsidiaries, which are separate and distinct legal entities. Substantially all of our consolidated assets are held by our subsidiaries. Accordingly, our ability to meet our debt obligations or pay dividends on our common stock and preferred stock is largely dependent upon cash generated by these subsidiaries. In the event a major subsidiary is not able to pay dividends or transfer cash flows to us, our ability to service our debt obligations or pay dividends could be negatively affected.

 Capital market performance and other factors may decrease the value of benefit plan assets, which then could require significant additional funding and impact earnings.
 The performance of the capital markets affects the value of the assets that are held in trust to satisfy future obligations under defined benefit pension and other postretirement benefit plans. We have significant obligations in these areas and hold significant assets in these trusts. These assets are subject to market fluctuations and may yield uncertain returns, which could fall below our projected rates of return. A decline in the market value of assets may increase the funding requirements of the

 obligations under the defined benefit pension plans. Additionally, changes in interest rates affect the liabilities under these benefit plans; as interest rates decrease, the liabilities increase, which could potentially increase funding requirements. Further, the funding requirements of the obligations related to these benefits plans may increase due to changes in governmental regulations and participant demographics, including increased numbers of retirements or longer life expectancy assumptions, as well as voluntary early retirements. In addition, lower asset returns result in increased expenses. Ultimately, significant funding requirements and increased pension or other postretirement benefit plan expenses could negatively impact our results of operations and financial position.

 We have significant goodwill. Any future impairments of goodwill could result in a significant charge to earnings in a future period and negatively impact our compliance with certain covenants under financing agreements.
 In accordance with GAAP, we test goodwill for impairment at least annually and review our definite-lived intangible assets for impairment when events or changes in circumstances indicate its fair value might be below its carrying value. Goodwill is also tested for impairment when factors, examples of which include reduced cash flow estimates, a sustained decline in stock price or market capitalization below book value, indicate that the carrying value may not be recoverable and results in a significant charge to earnings. We cannot predict the timing, magnitude, or duration of such changes. In general, the carrying value of goodwill would not be recoverable, in which case we may record a non-cash impairment charge, which could materially impact our results of operations and financial position.

 A significant impairment charge in the future could impact the capitalization ratio covenant under certain financing agreements. We are subject to a financial covenant under our revolving credit facility, which requires us to maintain a debt to capitalization ratio that does not exceed 70%. As of December 31, 2024, the ratio was 52.6%.

 LITIGATION, REGULATORY AND LEGISLATIVE RISKS
 The outcome of legal and regulatory proceedings, investigations, inquiries, claims and litigation related to our business operations may have a material adverse effect on our results of operations, financial position or liquidity.
 We are, or may be, involved in legal and regulatory proceedings, investigations, inquiries, claims and litigation in connection with our business operations, the most significant of which are summarized in, Note 19, "Other Commitments and Contingencies," in the Notes to Consolidated Financial Statements. While we maintain insurance, it may not cover all costs or expenses incurred relating to litigation. Due to the inherent uncertainty of the outcomes of such matters, there can be no assurance that the resolution of any particular claim or proceeding would not have a material adverse effect on our results of operations, financial position or liquidity.

 Our businesses are subject to various federal, state and local laws, regulations, tariffs and policies and a failure to comply with changes in, or new or different interpretations of, such laws, regulations, tariffs and policies could have an adverse impact on our business.
 Our businesses are subject to various federal, state and local laws, regulations, tariffs and policies, including, but not limited to, those relating to natural gas pipeline safety, employee safety, the environment and our energy infrastructure. In particular, we are subject to significant federal, state and local regulations applicable to utility companies, including regulations by the various utility commissions in the states where we serve customers. These regulations significantly influence our operating environment, may affect our ability to recover costs from utility customers, and cause us to incur substantial compliance and other costs. Existing laws, regulations, tariffs and policies may be revised or become subject to new interpretations, and new laws, regulations, tariffs and policies may be adopted or become applicable to us and our operations. In some cases, compliance with new or different laws, regulations, tariffs and policies increases our costs or risks of liability. Supply chain constraints, both direct and indirect, including but not limited to material or labor shortages, may challenge our ability to remain in compliance with these laws, regulations, tariffs and policies and operate our business in a compliant manner. If we fail to comply with laws, regulations and tariffs applicable to us or with any changes in or new interpretations of such laws, regulations, tariffs or policies, our financial condition, results of operations, regulatory outcomes and cash flows may be materially adversely affected.

 Our businesses are regulated under numerous environmental laws and regulations. The cost of compliance with these laws and regulations, and changes to or additions to, or reinterpretations of the laws and regulations, could be significant, and the cost of compliance may not be recoverable. Liability from the failure to comply with existing or changed laws and regulations could have a material adverse effect on our business, results of operations, cash flows and financial condition.
 Our businesses are subject to extensive federal, state and local environmental laws and rules that regulate, among other things, air emissions, water usage and discharges, leak detection and repair, GHG and waste products such as CCR. Compliance with

 these legal obligations require us to make significant expenditures for installation of pollution control equipment, remediation, environmental monitoring, emissions fees, and permits at many of our facilities. Furthermore, if we fail to comply with environmental laws and regulations or are found to have caused damage to the environment or persons, that failure or harm may result in the assessment of civil or criminal penalties and damages against us, injunctions to remedy the failure or harm, and the inability to operate facilities as designed and intended. Further, failing to comply with such laws and regulations or a determination that we have caused damage to the environment or persons, could result in reputational damage.

 Existing environmental laws and regulations may be revised and new laws and regulations may be adopted or become applicable to us, with an increasing focus on the impact of coal and natural gas facilities that may result in significant additional expense and operating restrictions on our facilities, which may not be fully recoverable from customers and could materially affect the continued economic viability of our facilities.

 An area of significant uncertainty and risk are potential changes to the laws concerning emission of GHG. While we have set a Net Zero Goal and continue to execute our plan to reduce our GHG emissions by the increased sourcing of renewable energy, priority pipeline replacement, leak detection and repair, and other methods, GHG emissions are anticipated to be associated with energy delivery for many years. Future GHG legislation and/or regulation related to the generation of electricity or the extraction, production, distribution, transmission, storage and end use of natural gas could materially impact our gas supply, financial position, financial results and cash flows.

 Another area of significant uncertainty and risk are the regulations concerning CCR. The EPA has issued regulations and may promulgate additional regulations concerning the management, storage, use and disposal of CCRs. NIPSCO is also incurring or will incur costs associated with closing, corrective action, and ongoing monitoring of certain CCR impoundments. Further, a release of CCR to the environment could result in remediation costs, penalties, claims, litigation, increased compliance costs, and reputational damage.

 We currently have a pending application with the EPA to continue operation of a CCR impoundment that is tied to operation of R.M. Schahfer Generating Station Units 17 and 18 to the end of 2025, with the CCR impoundment closing by October 2028. In proposed and final EPA actions denying continued operation of CCR impoundments at other utilities, EPA said that CCR impoundments should cease receipt of CCRs within 135 days of final EPA action unless certain conditions are demonstrated, such as potential reliability issues. In the event that approval is not obtained, future operations could be impacted.

 The actual future expenditures to achieve environmental compliance depends on many factors, including the nature and extent of impact, the method of improvement, the cost of raw materials, contractor costs, and requirements established by environmental authorities. Changes or increases in costs and the ability to recover under regulatory mechanisms could affect our financial position, financial results and cash flows.

 Changes in tax laws or the interpretation thereof and challenges to tax positions could adversely affect our financial results.
 We are subject to taxation by the various taxing authorities at the federal, state and local levels where we do business. Legislation or regulation which could affect our tax burden could be enacted or interpreted by any of these governmental authorities. The IRA imposed a 15 percent minimum tax rate on book earnings for corporations with higher than $1 billion of annual income, along with a 1 percent excise tax on corporate stock repurchases while providing tax incentives to promote various clean energy initiatives. Our NIPSCO subsidiary's renewable portfolio is eligible for tax credits associated with the investment in renewable generation assets and production of power from those assets. Statutory changes, a challenge by a taxing authority, changes in taxing authorities' administrative interpretations, decisions, policies and positions, our ability to utilize tax benefits such as carryforwards or tax credits, or a deviation from other tax-related assumptions may cause actual financial results to deviate from previous estimates.

 ITEM 1B. UNRESOLVED STAFF COMMENTS

 None.

 ITEM 1C. CYBERSECURITY
 NiSource has implemented and maintains a comprehensive cybersecurity program that includes a variety of security controls and measures designed to identify, assess, and manage material cybersecurity risks. The program is a part of NiSource's enterprise risk management strategy. The enterprise risk team and the Risk Management Committee review material risks to any NiSource operating company based on perspectives from external experts, peer surveys, and the potential impact to NiSource's enterprise assets and strategic objectives.

 Risk events are classified based on both the timing of impact and NiSource's ability to preventatively mitigate the risk. For the cybersecurity risks that can be preventively mitigated, the enterprise risk team gathers quarterly updates on mitigation gap closure from risk owners. The Risk Management Committee reviews any mitigation gaps identified by risk owners and approves or rejects the pace of mitigation activities as a statement of risk tolerance and then directs that mitigation activities be included in budgets and the business plan as appropriate.

 The NiSource cybersecurity program includes the following key components:

 Risk assessment. NiSource regularly assesses its cybersecurity risks to identify and prioritize the most significant threats. The risk assessment process considers a variety of factors, including those specific to the utility/energy industry, the types of data NiSource collects and stores, and the threats posed by known vulnerabilities. NiSource engages third parties to perform independent assessments of its cybersecurity program, provide intelligence about the threat environment, and to provide operational assistance in managing the program. Annually, a third-party independent assessment is performed to evaluate NiSource cybersecurity maturity against a framework of cybersecurity controls. NiSource also performs bi-annual penetration testing and social engineering assessments performed by a third-party.

 Third-party risk management. NiSource performs cyber assessments periodically on third-party vendors and service providers with whom NiSource shares data, relies on for critical business functions, or provides access to the NiSource network or systems. NiSource's Supply Chain function works with the Legal and Cyber functions to periodically update cybersecurity contractual provisions in its vendor agreements, with deviations from such provisions requiring approval from the Legal and Cyber functions. NiSource's Supplier Code of Business Conduct requires, among other things, that suppliers ensure safe and secure use of information assets, comply with applicable law relating to personal information, and adhering to standards relative to the use and protection of Company information, including that of our employees, customers, vendors and other stakeholders. In addition, all vendors and contractors that have access and/or connectivity to the NiSource environment must complete cybersecurity training annually.

 Security controls. NiSource has implemented a variety of security controls to mitigate cybersecurity risks. These controls include technical controls, such as firewalls and intrusion detection systems, as well as administrative controls, such as employee training and security awareness programs. To ensure cybersecurity controls, NiSource OT within the electric business adheres to the NERC CIP. Within the natural gas business, cybersecurity controls are managed and monitored based on the TSA Security Directives.

 Incident response. NiSource has a comprehensive incident response plan in place to respond to cybersecurity incidents. The plan includes steps for detection, analysis, containment, eradication, and recovery from incidents, as well as steps for notifying affected individuals and regulators.

 The NiSource Board of Directors' Audit Committee has responsibility for oversight of the cybersecurity program and risks from cybersecurity threats. The Audit Committee regularly reviews NiSource's cybersecurity posture. The CISO briefs the Audit Committee on cybersecurity risks and risk mitigation initiatives and actions. In addition, the Board of Directors remains informed of key and emerging cybersecurity risks and receives updates by the Audit Committee after each of its regularly scheduled meetings.

 At the management level, the CISO leads the cybersecurity program and is responsible for assessing and managing cybersecurity risks. Our CISO has expertise and experience in cybersecurity derived from over 15 years of cyber related work experience and possesses several certifications including CISSP, CRISC, and CISA. The CISO is supported by the NiSource

 ITEM 2. PROPERTIES

 Enterprise Security team which performs the cybersecurity function and engages directly on the prevention, detection, mitigation, and remediation of cybersecurity incidents.

 As of the date of filing this Annual Report on Form 10-K, NiSource is not aware of any material cybersecurity incidents during the past year. NiSource monitors the increasing sophistication of cybersecurity threats and continues to allocate resources to enhance its cybersecurity program to protect its information systems and assets. No cybersecurity program is effective to identify and mitigate all threats and NiSource cannot guarantee that it will be able to prevent all cybersecurity incidents. Such an incident could interrupt our normal operations and require us to incur significant costs to remediate any such incident and could have a material impact on our businesses, operations and financial condition. For more information regarding the risks associated with cybersecurity, refer to "Item 1A. Risk Factors" of this Annual Report on Form 10-K.

 ITEM 2. PROPERTIES
 Discussed below are the principal properties held by us and our subsidiaries as of December 31, 2024.
 Refer to Item 1, "Business - Columbia Operations," of this report for further information on Columbia Operations properties.
 Refer to Item 1, "Business - NIPSCO Operations," of this report for further information on NIPSCO Operations properties.
 Corporate and Other Operations
 We own the Southlake Complex, our 325,000 square foot headquarters building located in Merrillville, Indiana.
 Character of Ownership
 Our principal properties and our subsidiaries' principal properties are owned free from encumbrances, subject to minor exceptions, none of which are of such a nature as to impair substantially the usefulness of such properties. Many of our subsidiary offices in various communities served are occupied under leases. All properties are subject to routine liens for taxes, assessments and undetermined charges (if any) incidental to construction. It is our practice to regularly pay such amounts, as and when due, unless contested in good faith. In general, the electric lines, gas pipelines and related facilities are located on land not owned by us or our subsidiaries, but are covered by necessary consents of various governmental authorities or by appropriate rights obtained from owners of private property. We do not, however, generally have specific easements from the owners of the property adjacent to public highways over, upon or under which our electric lines and gas distribution pipelines are located. At the time each of the principal properties was purchased, a title search was made. In general, no examination of titles as to rights-of-way for electric lines, gas pipelines or related facilities was made, other than examination, in certain cases, to verify the grantors' ownership and the lien status thereof.

 ITEM 3. LEGAL PROCEEDINGS
 For a description of our legal proceedings, see Note 19, "Other Commitments and Contingencies - C. Legal Proceedings," in the Notes to Consolidated Financial Statements.
 ITEM 4. MINE SAFETY DISCLOSURES
 Not applicable.

 ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

 NiSource's common stock is listed and traded on the New York Stock Exchange under the symbol "NI."
 Holders of shares of NiSource's common stock are entitled to receive dividends if and when declared by the Board out of funds legally available. There is no preferred stock outstanding as of December 31, 2024. The policy of the Board has been to declare cash dividends on a quarterly basis payable on or about the 20th day of February, May, August, and November. At its January 23, 2025 meeting, the Board declared a quarterly common dividend of $0.280 per share, payable on February 20, 2025 to holders of record on February 3, 2025.
 Although the Board currently intends to continue the payment of regular quarterly cash dividends on common shares, the timing and amount of future dividends will depend on the earnings of NiSource's subsidiaries, their financial condition, cash requirements, regulatory restrictions, any restrictions in financing agreements and other factors deemed relevant by the Board. There can be no assurance that NiSource will continue to pay such dividends or the amount of such dividends.
 As of February 5, 2025 NiSource had 14,161 common stockholders of record and 469,939,639 shares outstanding.
 The graph below compares the cumulative total shareholder return of NiSource's common stock for the period commencing December 31, 2019 and ending December 31, 2024 with the cumulative total return for the same period of the S&P 500 and the Dow Jones Utility indices.

 The foregoing performance graph is being furnished as part of this Annual Report on Form 10-K solely in accordance with the requirement under Rule 14a-3(b)(9) to furnish stockholders with such information, and therefore, shall not be deemed to be filed or incorporated by reference into any filings by NiSource under the Securities Act or the Exchange Act.
 The total shareholder return for NiSource common stock and the two indices is calculated from an assumed initial investment of $100 and assumes dividend reinvestment.
 Purchases of Equity Securities by Issuer and Affiliated Purchasers. For the three months ended December 31, 2024, no equity securities that are registered by NiSource Inc. pursuant to Section 12 of the Securities Exchange Act of 1934 were purchased by or on behalf of us or any of our affiliated purchasers.

 ITEM 6. RESERVED

 Not applicable.

 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

 Page

 Executive Summary

 Summary of Consolidated Financial Results

 Results and Discussion of Operations

 Liquidity and Capital Resources

 Market Risk Disclosures

 Other Information

 EXECUTIVE SUMMARY

 This Management's Discussion and Analysis of Financial Condition and Results of Operations ("Management's Discussion") includes management's analysis of past financial results and certain potential factors that may affect future results, potential future risks and approaches that may be used to manage those risks. See "Note regarding forward-looking statements" and Item 1A, "Risk Factors" at the beginning of this report for a list of factors that may cause results to differ materially. Refer to the "Business" section under Item 1 of this Annual Report on Form 10-K and Note 21, "Business Segment Information," in the Notes to Consolidated Financial Statements for further discussion of our regulated utility business segments.
 This Management's Discussion is designed to provide an understanding of our operations and financial performance and should be read in conjunction with our Consolidated Financial Statements and related Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
 We are an energy holding company under the Public Utility Holding Company Act of 2005 whose subsidiaries are fully regulated natural gas and electric utility companies serving customers in six states. We generate substantially all of our operating income through these rate-regulated businesses, which are summarized for financial reporting purposes into two primary reportable segments: Columbia Operations and NIPSCO Operations.
 Our vision is to be a premier, innovative and trusted energy partner. We exist to deliver safe, reliable energy that drives value to our customers. In order to achieve this goal, we seek to develop strategies that benefit all stakeholders as we (i) support long-term infrastructure investment and safety programs to better serve our customers, (ii) align our tariff structures with our cost structure, and (iii) drive value and enable growth in an evolving energy ecosystem. These strategies focus on improving safety and reliability, enhancing customer experience, pursuing regulatory and legislative initiatives to increase accessibility for customers currently not on our gas and electric service, ensuring customer affordability and reducing emissions while generating sustainable returns. The safety of our customers, communities and employees remains our focus. Serving as a guiding practice for our SMS, NiSource is certified in conformance to the American Petroleum Institute Recommended Practice 1173, which is the foundation to our journey towards operational excellence.
 2024 Overview: In 2024, we continued to make significant progress on the remaining portfolio of projects that will enable our electric generation transition, including placing one solar and battery project into service and receiving approval of a new gas peaking facility. During the year, we received orders for three rate cases: Columbia of Pennsylvania, Columbia of Kentucky, and NIPSCO Gas. In addition, the Columbia of Virginia, Columbia of Maryland and NIPSCO Electric rate cases filed in 2024 are anticipated to be resolved during 2025 with balanced outcomes supporting all stakeholders. We continued to build and advance our SMS by successfully maintaining our certification of conformance for API 1173 and achieving LRQA's ISO 50001 certification. Between our Columbia and NIPSCO Operating Segments, we added 21,000 customers. We also invested $1.5 billion in infrastructure modernization to enhance safe, reliable service, including replacement of 288 miles of distribution main and service lines, 24 miles of underground cable and 1,240 electric poles. We achieved the first major milestone in our Transformation road map and continue to increase the efficiency of our operating companies.

 The following describes in more detail the advancements we have made in our key strategic initiatives.
 Energy Transition: We are advancing our energy transition strategy primarily through the continuation and enhancement of existing programs, such as retiring and replacing remaining coal-fired electric generation by 2028 with a balanced mix of low or zero-emission electric generation and battery storage, ongoing pipe replacement and modernization programs, and deployment of advanced leak detection and repair. Our electric generation transition, initiated through our 2018 Integrated Resource Plan

 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)

 ("2018 Plan") is well underway, and we are continually adjusting to the dynamic energy landscape. As of December 31, we have placed in service owned renewable and storage projects, developed under BTAs, with combined nameplate capacities of 1,065 MW and 45 MW respectively. Renewable PPA projects with a combined nameplate capacity of 600 MW have also been placed in service. In addition, renewable and storage BTA projects with combined nameplate capacities of 1,085 MW and 56 MW, respectively, and renewable PPA projects with a combined nameplate capacity of 600 MW were under development as of December 31, all of which have received IURC approval. The capacity figure for BTA projects in development includes the Templeton Wind project. In October 2024, NIPSCO contracted with a developer to convert the previously approved Templeton Wind PPA to a BTA and has provided a notice of intent to file a CPCN with the IURC. In 2024, the IURC approved full ownership of the Cavalry, Dunns Bridge II, Fairbanks and Gibson and the cost of the Fairbanks project as contemplated in contractual actions. Full ownership of these projects allows NIPSCO to leverage provisions of the IRA, monetize renewable tax credits more effectively, and provide enhanced benefits to customers as compared to the previous tax equity partnership structure approved by the IURC. We remain on track to retire R.M Schahfer's remaining two coal units by the end of 2025. For additional information, see "Results and Discussion of Operations - NIPSCO Operations," in this Management's Discussion.

 NIPSCO's 2021 Integrated Resource Plan ("2021 Plan") lays out a timeline to retire the Michigan City Generating Station by the end of 2028. The 2021 Plan calls replacing the retiring coal units with a diverse portfolio of resources including demand side management resources, renewables, stand-alone energy storage and upgrades to existing facilities at the Sugar Creek Generating Station, among other steps. In 2024, Sugar Creek completed an Advanced Gas Path Tech upgrade that will enhance its overall production capabilities. Additionally, the 2021 Plan calls for a new natural gas peaking facility to replace existing vintage gas peaking facilities at the R.M. Schahfer Generating Station to support system reliability and resiliency, and upgrades to the electric transmission system. In October 2024, we received approval for the issuance of a CPCN for an approximately 400 MW natural gas peaking generation facility from the IURC. The planned retirement of the two vintage gas peaking facilities at the R.M. Schahfer Generating Station is also expected to occur by the end of 2028. Final retirement dates for these units, as well as Michigan City, will be subject to MISO approval.

 NIPSCO's 2024 Plan was submitted to the IURC on December 9, 2024. The 2024 Plan informs future generation investments required to ensure reliability for NIPSCO's customers and incorporates factors such as anticipated load growth from data centers and other economic development opportunities, new EPA emissions rules, and evolving MISO resource accreditation rules. We have seen an acceleration of customer interest in our northern Indiana service territory in the form of data center development. We believe data center development can enhance our local tax base, diversify the employment base across the state of Indiana, and provide greater value to existing customers and shareholders. We are evaluating the potential for data center development in our service territory, including ways to effectively manage the potential power demand, generation sources, and transmission capabilities to meet potential load growth from any data center customer, while at the same time focusing on our environmental goals. We expect the management of large load growth would require new generation resources, including gas-fired resource, and transmission capabilities. We plan to move as efficiently as possible while maintaining the integrity of our commercial, planning, regulatory, procurement and operational execution processes.

 We continue to enhance safety and reduce methane emissions on our gas systems through modernization programs and utilization of advanced leak detection and repair. In addition, we plan to advance other low- or zero-emission energy resources and technologies, such as hydrogen and renewable natural gas.

 Transformation: Our enterprise-wide transformation roadmap focuses on operational excellence, safety, operation and maintenance management, and unlocking efficiencies. We are committed to identifying and implementing initiatives that will enable us to streamline work and improve processes company-wide. These efforts include investments in proven technologies backed with standardized processes that will change the way we plan, schedule, and execute work in the field and how we engage and provide service to our customers. Taken together, all of our optimization initiatives will prioritize safety and continue to optimize our long-term growth profile. We are making progress towards our transformation goals with a successful completion of the first phase of our WAM program, an enterprise resource planning system that will optimize the scheduling, dispatch, and execution of our field operations. This phase of the program implemented the solution within our electric distribution and transmission operations, while the remaining phases associated with gas distribution and generation operations are anticipated to be completed by the end of 2025.

 Economic Environment: We continue to monitor risks related to order and delivery lead times for construction and other materials, potential unavailability of materials due to global shortages in raw materials, and decreased construction labor productivity in the event of disruptions in the availability of materials. We continue to see increasing prices associated with certain materials and supplies. To the extent that work plan delays occur or our costs increase, our business operations, results

 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)

 of operations, cash flows, and financial condition could be materially adversely affected. Refer to Item 1A. Risk Factors, "Financial, Economic and Market Risks" of this Annual Report on Form 10-K for further detail.
 We are faced with increased competition for employee and contractor talent in the current labor market which has resulted in increased costs to attract and retain talent. We are ensuring that we use all internal human capital programs (development, leadership enablement programs, succession, performance management) to promote retention of our current employees along with having a competitive and attractive appeal for potential recruits. With a focus on workforce planning, we are evaluating our future talent footprint by creating flexible work arrangements where possible to support a broader talent footprint for sourcing needed talent. Refer to Item 1A. Risk Factors, "Operational Risks" of this Annual Report on Form 10-K for further detail.

 The market price of natural gas was stable during 2024 and was very close to levels seen in 2023. Similar to natural gas pricing, electric commodity costs have remained stable due to available supplies of natural gas and coal and the growing influence of renewable generation on power market pricing. Changes in commodity prices do not have a material impact on our results of operations, however higher commodity prices can impact our cash flows and liquidity. For more information on our commodity price impacts, see Item 1A. Risk Factors, "Operational Risks" of this Annual Report on Form 10-K, "Results and Discussion of Segment Operations - Columbia Operations," "Results and Discussion of Segment Operations - NIPSCO Operations," and "Market Risk Disclosures."
 We continue to evaluate our financing plan to manage interest expense and exposure to rates. For more information on interest rate risk, see "Market Risk Disclosures" and Item 1A. Risk Factors, "Financial, Economic and Market Risks" of this Annual Report on Form 10-K.
 NIPSCO Minority Interest Transaction: On December 31, 2023, contemporaneously with the closing of the NIPSCO Minority Interest Transaction, Blackstone, NIPSCO Holdings I, NIPSCO Holdings II, and NiSource entered into an Amended and Restated Limited Liability Company Agreement (the "LLC Agreement") of NIPSCO Holdings II. On January 31, 2024, BIP transferred a 4.5% equity interest in NIPSCO Holdings II to BIP Blue Buyer VCOC L.L.C., a Delaware limited liability company and also an affiliate of Blackstone. Effective upon the closing of this transfer, the members of NIPSCO Holdings II entered into a Second Amended and Restated Limited Liability Company Operating Agreement of NIPSCO Holdings II (the "Amended LLC Agreement"). The two affiliates of Blackstone must vote their equity holdings under the Amended LLC Agreement as one investor. Refer to Note 4, "Noncontrolling Interests," in the Notes to the Consolidated Financial Statements for more information on this transaction.

 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)

 Summary of Consolidated Financial Results
 A summary of our consolidated financial results for the years ended December 31, 2024, 2023 and 2022, are presented below:

 Year Ended December 31,
 (in millions, except per share amounts)

 2024
 2023
 2022

 $
 5,455.1
 $
 5,505.4
 $
 5,850.6
 $
 (50.3)
 $
 (345.2)

 Operating Expenses

 1,132.2
 1,533.3
 2,110.5
 401.1
 577.2

 Other Operating Expenses
 2,867.4
 2,676.6
 2,474.3
 (190.8)
 (202.3)

 Total Operating Expenses
 3,999.6
 4,209.9
 4,584.8
 210.3
 374.9

 1,455.5
 1,295.5
 1,265.8
 160.0
 29.7

 Total Other Deductions, Net
 (452.7)
 (481.6)
 (309.4)
 28.9
 (172.2)

 158.1
 139.5
 164.6
 (18.6)
 25.1

 844.7
 674.4
 791.8
 170.3
 (117.4)

 Net (loss) income attributable to noncontrolling interest

 84.3
 (39.9)
 (12.3)
 (124.2)
 27.6

 Net Income attributable to NiSource

 760.4
 714.3
 804.1
 46.1
 (89.8)

 Preferred dividends and redemption premium

 (20.7)
 (52.6)
 (55.1)
 31.9
 2.5

 Net Income Available to Common Shareholders

 739.7
 661.7
 749.0
 78.0
 (87.3)

 Basic Earnings Per Share

 $
 1.63
 $
 1.59
 $
 1.84
 $
 0.04
 $
 (0.25)

 Diluted Earnings Per Share

 $
 1.62
 $
 1.48
 $
 1.70
 $
 0.14
 $
 (0.22)

 The majority of the costs of energy in both segments are tracked costs that are passed through directly to the customer, resulting in an equal and offsetting amount reflected in operating revenues.
 The increase in net income available to common shareholders during 2024 was primarily due to higher revenues, net of cost of energy, driven by our continued investment in safety, reliability and low- or zero-emission generation as well as increased AFUDC, reported in Other Deductions, Net, primarily related to NIPSCO's wholly owned Cavalry and Dunns Bridge II projects. The increase in net income available to common shareholders is partially offset by higher depreciation expense attributed to our planned capital expenditures, higher interest expense and higher net income attributable to noncontrolling interest following the consummation of the NIPSCO Minority Interest Transaction. See Note 6, "Equity," for additional information.
 For additional information on operating income variance drivers see "Results and Discussion of Operations" for Columbia Operations and NIPSCO Operations in this Management's Discussion.
 Other Deductions, Net
 The change in Other deductions, net in 2024 compared to 2023 is primarily driven by higher long-term debt interest in 2024 offset by increases in AFUDC. See Note 7, "Short-Term Borrowings,"and Note 8, "Long-Term Debt," in the Notes to Consolidated Financial Statements for additional information.

 The increase in income tax expense in 2024 compared to the same period in 2023 is primarily due to higher pre-tax income, partially offset by the tax effect of non-controlling interest. Refer to Note 15, "Income Taxes," in the Notes to Consolidated Financial Statements for additional information on income taxes and the change in the effective tax rate.

 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)

 RESULTS AND DISCUSSION OF OPERATIONS
 Presentation of Segment Information
 In response to the NIPSCO Minority Interest Transaction, our operations are now evaluated through two primary reportable segments, Columbia Operations and NIPSCO Operations. Our historical segment disclosures have been recast to be consistent with the current presentation. Columbia Operations aggregates the results of the fully regulated and wholly owned subsidiaries of NiSource Gas Distribution Group, Inc. Each Columbia distribution company is an operating segment which we aggregate to form the Columbia Operations reportable segment. NIPSCO Operations aggregates the results of NIPSCO Holdings I, and its majority-owned subsidiaries, including NIPSCO, which has both fully regulated gas and electric operations in northern Indiana. The remainder of our operations, which are not significant enough on a stand-alone basis to warrant treatment as a reportable segment, are presented as "Corporate and Other" within the Notes to the Consolidated Financial Statements and primarily are comprised of interest expense on holding company debt, and unallocated corporate costs and activities.

 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)

 Financial and operational data for the Columbia Operations segment for the years ended December 31, 2024, 2023 and 2022, are presented below:

 2024
 2023
 2022

 $
 2,716.0
 $
 2,746.1
 $
 2,964.4
 $
 (30.1)
 $
 (218.3)

 Operating Expenses

 514.7
 645.0
 978.4
 130.3
 333.4

 Operation and maintenance
 837.5
 792.3
 791.3
 (45.2)
 (1.0)

 409.1
 371.7
 329.4
 (37.4)
 (42.3)

 Loss on impairment of assets
 2.7
 —
 —
 (2.7)
 —

 Loss (gain) on sale of assets, net
 4.7
 —
 (103.9)
 (4.7)
 (103.9)

 Other taxes
 218.6
 198.8
 184.2
 (19.8)
 (14.6)

 Total Operating Expenses
 1,987.3
 2,007.8
 2,179.4
 20.5
 171.6

 $
 728.7
 $
 738.3
 $
 785.0
 $
 (9.6)
 $
 (46.7)

 Revenues

 $
 1,891.5
 $
 1,882.8
 $
 1,918.1
 $
 8.7
 $
 (35.3)

 588.4
 606.2
 674.8
 (17.8)
 (68.6)

 145.2
 139.5
 136.4
 5.7
 3.1

 Off-System
 42.6
 60.7
 192.8
 (18.1)
 (132.1)

 Other
 48.3
 56.9
 42.3
 (8.6)
 14.6

 Total
 $
 2,716.0
 $
 2,746.1
 $
 2,964.4
 $
 (30.1)
 $
 (218.3)

 Sales and Transportation (MMDth)

 153.2
 155.2
 180.2
 (2.0)
 (25.0)

 121.8
 120.4
 134.3
 1.4
 (13.9)

 277.9
 255.3
 243.2
 22.6
 12.1

 Off-System
 23.8
 31.8
 32.3
 (8.0)
 (0.5)

 Other
 0.2
 0.3
 0.3
 (0.1)
 —

 Total
 576.9
 563.0
 590.3
 13.9
 (27.3)

 Heating Degree Days
 4,262
 4,373
 5,195
 (111)
 (822)

 Normal Heating Degree Days
 5,134
 5,137
 5,137
 (3)
 —

 % (Warmer) Colder than Normal

 (17)
 %
 (15)
 %
 %

 % (Warmer) Colder than Prior Year

 (3)
 %
 (16)
 %
 %

 Gas Distribution Customers

 2,225,564
 2,215,293
 2,201,999
 10,271
 13,294

 188,699
 188,561
 188,374

 1,991
 1,986
 1,995
 (9)

 Other

 Total
 2,416,259
 2,405,844
 2,392,371
 10,415
 13,473

 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
 Columbia Operations (continued)

 Comparability of operation and maintenance expenses, depreciation and amortization, and other taxes may be impacted by regulatory, depreciation and tax trackers that allow for the recovery in rates of certain costs.
 The underlying reasons for changes in our operating revenues and expenses from 2024 to 2023 are presented in the respective tables below.

 Changes in Operating Revenues (in millions)

 2024 vs 2023

 New rates from base rate proceedings and regulatory capital programs
 $
 112.5

 The effects of customer growth
 6.2

 The effects of customer usage

 5.9

 The effects of weather in 2024 compared to 2023

 (5.2)

 Other
 (4.2)

 Change in operating revenues (before cost of energy and other tracked items)
 $
 115.2

 Operating revenues offset in operating expense

 Lower cost of energy billed to customers

 (130.3)

 Lower tracker recoveries within operation and maintenance, depreciation, and tax

 (15.0)

 Total change in operating revenues
 $
 (30.1)

 Weather
 In general, we calculate the weather-related revenue variance based on changing customer demand driven by weather variance from normal heating degree days, net of weather normalization mechanisms. Our composite heating degree days reported do not directly correlate to the weather-related dollar impact on the results of Columbia Operations. Heating degree days experienced during different times of the year or in different operating locations may have more or less impact on volume and dollars depending on when and where they occur. When the detailed results are combined for reporting, there may be weather-related dollar impacts on operations when there is not an apparent or significant change in our aggregated composite heating degree day comparison.
 Throughput
 The increase in total volumes sold and transported in 2024 compared to 2023 of 13.9 MMDth is primarily attributable to the increased industrial usage offset by off-system sales.

 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
 Columbia Operations (continued)

 Commodity Price Impact
 Cost of energy for the Columbia Operations segment is principally comprised of the cost of natural gas procured on behalf of and sold to customers while providing transportation and distribution services. All of our Columbia Operations companies have state-approved recovery mechanisms that provide a means for full recovery of prudently incurred gas costs. These are tracked costs that are passed through directly to the customer, and the gas costs included in revenues are matched with the gas cost expense recorded in the period. Any difference in actual costs incurred and amounts billed to customers is recorded on the Consolidated Balance Sheets as under-recovered or over-recovered gas cost to be included in future customer billings. Therefore, increases in these tracked operating expenses are offset by increases in operating revenues and have essentially no impact on net income. Certain Columbia Operations companies continue to offer choice opportunities, where customers can choose to purchase gas from a third-party supplier, through regulatory initiatives in their respective jurisdictions.

 Changes in Operating Expenses (in millions)

 2024 vs 2023

 Higher employee related expenses

 $
 (47.5)

 Higher depreciation and amortization expense
 (37.4)

 Higher property tax

 (17.2)

 Loss on sale of assets and impairments

 (7.4)

 Higher materials and supplies expense
 (7.0)

 Other
 (8.3)

 Change in operating expenses (before cost of energy and other tracked items)
 $
 (124.8)

 Operating expenses offset in operating revenue

 Lower cost of energy billed to customers

 130.3

 Higher tracker recoveries within operation and maintenance, depreciation, and tax

 15.0

 Total change in operating expense
 $
 20.5

 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)

 Financial and operational data for the NIPSCO Operations segment, which services both gas and electric customers, for the years ended December 31, 2024, 2023 and 2022, are presented below:

 2024
 2023
 2022

 $
 2,752.0
 $
 2,771.6
 $
 2,887.1
 $
 (19.6)
 $
 (115.5)

 Operating Expenses

 617.5
 888.3
 1,132.1
 270.8
 243.8

 Operation and maintenance
 761.4
 787.7
 740.4
 26.3
 (47.3)

 590.3
 493.8
 449.4
 (96.5)
 (44.4)

 Loss on impairment of assets
 0.4
 —
 —
 (0.4)
 —

 Loss (gain) on sale of assets, net
 (1.7)
 2.2
 —
 3.9
 (2.2)

 Other taxes
 64.3
 57.9
 72.1
 (6.4)
 14.2

 Total Operating Expenses
 2,032.2
 2,229.9
 2,394.0
 197.7
 164.1

 $
 719.8
 $
 541.7
 $
 493.1
 $
 178.1
 $
 48.6

 2024
 2023
 2022

 NIPSCO Electric

 Revenues

 $
 649.9
 $
 583.9
 $
 592.4
 $
 66.0
 $
 (8.5)

 620.4
 578.1
 571.0
 42.3
 7.1

 500.0
 475.0
 561.4
 25.0
 (86.4)

 38.3
 32.0
 13.5
 6.3
 18.5

 Other
 105.0
 116.0
 93.4
 (11.0)
 22.6

 Total
 $
 1,913.6
 $
 1,785.0
 $
 1,831.7
 $
 128.6
 $
 (46.7)

 Sales (GWh)

 3,404.9
 3,262.9
 3,482.9
 142.0
 (220.0)

 3,697.9
 3,614.2
 3,682.4
 83.7
 (68.2)

 7,984.8
 7,820.3
 7,915.3
 164.5
 (95.0)

 889.7
 556.4
 50.0
 333.3
 506.4

 Other
 85.2
 78.9
 89.5
 6.3
 (10.6)

 Total
 16,062.5
 15,332.7
 15,220.1
 729.8
 112.6

 Cooling Degree Days
 (232)

 Normal Cooling Degree Days
 —

 % Warmer (Colder) than Normal

 %
 (15)
 %
 %

 % Warmer (Colder) than prior year

 %
 (25)
 %
 (8)
 %

 NIPSCO Electric Customers

 430,648
 427,217
 424,735
 3,431
 2,482

 59,214
 58,779
 58,374

 2,121
 2,126
 2,130
 (5)
 (4)

 (3)
 (2)

 Other
 (1)
 —

 Total
 492,690
 488,833
 485,952
 3,857
 2,881

 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)

 2024
 2023
 2022

 NIPSCO Gas

 Revenues

 $
 540.9
 $
 634.9
 $
 691.5
 $
 (94.0)
 $
 (56.6)

 202.4
 249.1
 267.6
 (46.7)
 (18.5)

 79.0
 86.9
 85.1
 (7.9)
 1.8

 Other
 16.1
 15.7
 11.2
 0.4
 4.5

 Total
 $
 838.4
 $
 986.6
 $
 1,055.4
 $
 (148.2)
 $
 (68.8)

 Sales and Transportation Volumes (MMDth)

 58.2
 60.3
 68.8
 (2.1)
 (8.5)

 42.5
 43.9
 47.0
 (1.4)
 (3.1)

 256.8
 261.8
 247.5
 (5.0)
 14.3

 Total
 357.5
 366.0
 363.3
 (8.5)
 2.7

 Heating Degree Days

 4,975
 5,198
 6,133
 (223)
 (935)

 Normal Heating Degree Days

 6,001
 5,954
 5,985
 (31)

 % (Warmer) Colder than Normal

 (17)
 %
 (13)
 %
 %

 % (Warmer) Colder than prior year

 (4)
 %
 (15)
 %
 %

 NIPSCO Gas Customers

 801,740
 795,656
 789,914
 6,084
 5,742

 66,633
 66,305
 66,062

 2,734
 2,808
 2,875
 (74)
 (67)

 Total
 871,107
 864,769
 858,851
 6,338
 5,918

 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
 NIPSCO Operations (continued)

 Comparability of operation and maintenance expenses and depreciation and amortization may be impacted by regulatory and depreciation trackers that allow for the recovery in rates of certain costs.
 The underlying reasons for changes in our operating revenues and expenses from 2024 to 2023 are presented in the respective tables below.

 Changes in Operating Revenues (in millions)

 2024 vs 2023

 New rates from base rate proceedings, regulatory capital, and DSM programs

 $
 238.4

 Renewable Joint Venture revenue, fully offset by Joint Venture operating expense and noncontrolling interest net income (loss)

 17.5

 The effects of customer usage

 11.9

 The effects of customer growth
 11.2

 Decreased fuel handling costs
 9.7

 Other
 (6.2)

 Change in operating revenues (before cost of energy and other tracked items)
 $
 282.5

 Operating revenues offset in operating expense

 Lower cost of energy billed to customers

 (270.8)

 Lower tracker deferrals within operation and maintenance, depreciation and tax

 (32.4)

 Reduction in gross receipts tax, offset in operating expenses

 1.1

 Total change in operating revenues
 $
 (19.6)

 Weather
 The results of operations for the NIPSCO Operations segment include income from both electric and gas service lines. In general, we calculate the weather-related revenue variance based on changing customer demand driven by weather variance from normal cooling degree days and normal heating degree days, net of weather normalization mechanisms. Our composite cooling and heating degree days reported do not directly correlate to the weather-related dollar impact on the results of NIPSCO Operations. Cooling and heating degree days experienced during different times of the year or in different operating locations may have more or less impact on volume and dollars depending on when they occur. When the detailed results are combined for reporting, there may be weather-related dollar impacts on operations when there is not an apparent or significant change in our aggregated composite cooling and heating degree day comparison.
 Sales
 The increase in total volumes sold to electric customers for twelve months ended December 31, 2024 compared to the same period in 2023 was primarily attributable to increased usage by wholesale, industrial, and residential customers. NIPSCO Electric results remains closely linked to the performance of the steel industry. MWh sales to steel-related industries accounted for approximately 49.4% and 49.6% of the total industrial MWh sales for the years ended December 31, 2024 and 2023, respectively.
 The decrease in total volumes sold to gas customers for the twelve months ended December 31, 2024 compared to the same period in 2023 was primarily attributable to decreased usage by industrial customers.
 Commodity Price Impact
 Cost of energy for the NIPSCO Operations segment's electric activities is principally comprised of the cost of coal, natural gas purchased for internal generation of electricity, transportation of coal and natural gas, and the cost of power purchased from generators of electricity for its generation an d transmission activities. For its gas distribution activities, NIPSCO Operations' cost of energy is principally comprised of the cost of natural gas procured on behalf of and sold to customers while providing transportation and distribution services. NIPSCO Operations has a state-approved recovery mechanism that provides a means for full recovery of prudently incurred costs of energy. The majority of these costs of energy are passed through directly to the customer, and the costs of energy included in operating revenues are matched with the cost of energy expense recorded in the period. Any difference in actual costs incurred and amounts billed to customers is recorded on the Consolidated Balance Sheets

 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
 NIPSCO Operations (continued)

 as under-recovered or over-recovered fuel and gas cost to be included in future customer billings. Therefore, increases in these tracked operating expenses are offset by increases in operating revenues and have essentially no impact on net income.

 Changes in Operating Expenses (in millions)

 2024 vs 2023

 Higher depreciation and amortization expense driven by new base rates

 $
 (91.1)

 Higher employee and administrative expenses

 (21.8)

 Higher outside services expenses

 (8.6)

 Higher environmental remediation costs

 (4.7)

 Lower materials and supplies

 8.9

 Renewable Joint Venture operating expense, partially offset by Joint Venture operating revenues

 7.6

 Other
 5.3

 Change in operating expenses (before cost of energy and other tracked items)
 $
 (104.4)

 Operating expenses offset in operating revenue

 Lower cost of energy billed to customers

 270.8

 Higher tracker deferrals within operation and maintenance, depreciation and tax

 32.4

 Reduction in gross receipts tax, offset in operating revenues

 (1.1)

 Total change in operating expense
 $
 197.7

 Electric Supply and Generation Transition
 NIPSCO continues to execute on an electric generation transition consistent with the 2018 Plan and 2021 Plan and maintained in the 2024 Plan, which outlines the path to retire the remaining two coal units at R.M. Schahfer by the end of 2025 and the remaining coal-fired generation at Michigan City by the end of 2028, to be replaced by lower-cost, reliable and cleaner options. See "Liquidity and Capital Resources" in this Management's Discussion for additional information on our capital investment spend.
 NIPSCO continues to await EPA decision on an administrative approval associated with the operation of R.M. Schahfer's remaining two coal units, which are expected to be retired by the end of 2025. In the event that the approval is not obtained, future operations could be impacted. We cannot estimate the financial impact on us if this approval is not obtained. Refer to Item 1A. Risk Factors, "Operational Risks," of this Annual Report on Form 10-K for further detail.
 The current replacement plan primarily includes renewable sources of energy, including wind, solar, battery storage, and flexible natural gas resources to be obtained through a combination of NIPSCO ownership and PPAs. NIPSCO has sold, and may in the future sell, renewable energy credits from its renewable generation to third parties to offset customer costs. NIPSCO has executed several PPAs to purchase 100% of the output from renewable generation facilities at a fixed price per MWh. Each facility supplying the energy will have an associated nameplate capacity, and payments under the PPAs will not begin until the associated generation facility is constructed by the owner/seller. NIPSCO has also executed several BTAs with developers to construct renewable generation facilities.
 Since 2020, two wind PPA projects and six owned projects (two wind, two solar and two solar plus storage) have been placed into service totaling 2,201 MW of nameplate capacity, including Dunns Bridge II which was placed into service in January 2025. NIPSCO has executed commercial agreements for each of the six remaining identified projects. Fairbanks, Gibson, Green River, Appleseed and Carpenter have received IURC approval. The Templeton Wind project previously received approval as a PPA, however, NIPSCO has contracted with a developer to convert the PPA to a BTA and has provided a notice of intent to file a CPCN with the IURC. In January 2024, the IURC approved increases to the project costs as well as the full ownership of Cavalry and Dunns Bridge II. In August 2024, the IURC approved full ownership of Gibson and Fairbanks as well as increases to the cost of the Fairbanks project. In October 2024, the IURC approved the CPCN for NIPSCO's planned gas peaking facility to be located at the R.M. Schahfer Generating Station. See "Executive Summary - Energy Transition" in this Management's

 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
 NIPSCO Operations (continued)

 Discussion for additional information. We expect our remaining contracted BTA and PPA projects to be placed in service between 2025 and 2027.

 Remaining Renewables Projects

 Transaction Type
 Technology
 Nameplate Capacity (MW)
 Storage Capacity (MW)

 Fairbanks

 BTA
 Solar
 —

 Gibson

 BTA
 Solar
 —

 Templeton

 BTA(1)

 Wind
 —

 Green River
 20 year PPA
 Solar
 —

 Appleseed
 20 year PPA
 Solar
 —

 Carpenter
 20 year PPA
 Wind
 —

 (1) Pending regulatory approval.

 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)

 Liquidity and Capital Resources

 We continually evaluate the availability of adequate financing to fund our ongoing business operations, working capital and core safety and infrastructure investment programs. Our financing is sourced through cash flow from operations and the issuance of debt and/or equity. External debt financing is provided primarily through the issuance of long-term debt, accounts receivable securitization programs and our $1.85 billion commercial paper program, which is backstopped by our committed revolving credit facility with a total availability from third-party lenders of $1.85 billion. Sources of financing activities for the current year are as follows:
 • On December 31, 2023, we consummated the NIPSCO Minority Interest Transaction in exchange for a capital contribution of $2.16 billion in cash.
 • On January 3, 2024, we applied the proceeds from the NIPSCO Minority Interest Transaction and repaid in full our $1.0 billion term credit agreement and our $650.0 million term credit agreement.
 • On February 22, 2024, we entered into an ATM equity program that provides an opportunity to issue and sell shares of our common stock up to an aggregate issuance of $900.0 million through December 31, 2025. As of December 31, 2024, the ATM program had approximately $297.7 million of equity available for issuance.
 • On March 14, 2024, we completed the issuance and sale of $650.0 million of 5.350% senior unsecured notes maturing in 2034, which resulted in approximately $642.6 million of net proceeds after discount and debt issuance costs.
 • On March 15, 2024, we redeemed all 20,000 outstanding shares of Series B Preferred Stock for a redemption price of $25,000 per share and all 20,000 outstanding shares of Series B-1 Preferred Stock for a redemption price of $0.01 per share or $500.0 million in total.
 • On May 16, 2024, we completed the issuance and sale of $500.0 million of 6.950% fixed-to-fixed reset rate junior subordinated notes maturing in 2054, which resulted in approximately $493.4 million of net proceeds after debt issuance costs.
 • On June 24, 2024, we completed the issuance and sale of $600.0 million of 5.200% senior unsecured notes maturing in 2029, which resulted in approximately $593.7 million of net proceeds after discount and debt issuance costs.
 • On September 9, 2024, we completed the issuance and sale of $500.0 million of 6.375% fixed-to-fixed reset rate junior subordinated notes maturing in 2055, which resulted in approximately $493.6 million of net proceeds after debt issuance costs.
 See Note 4, "Noncontrolling Interests,", Note 6, "Equity," Note 7, "Short-Term Borrowings," and Note 8, "Long-Term Debt," in the Notes to the Consolidated Financial Statements for more information.
 We believe these sources provide adequate capital to fund our operating activities and capital expenditures in 2025 and beyond.

 Operating Activities
 Net cash from operating activities for the year ended December 31, 2024 was $1,781.5 million, a decrease of $153.6 million from 2023. This decrease in cash from operating activities was primarily driven by year over year change in accounts receivable collections and exchange gas receivables due to the impact of lower gas prices, offset by a year over year increase in revenue, net of cost of energy and higher accounts payables due to increased gas purchases.

 Investing Activities
 Net cash used for investing activities for the year ended December 31, 2024 was $3,213.0 million, a decrease of $358.6 million from 2023. Lower current year investing activities were primarily driven by lower milestone payments to renewable generation asset developers for certain of our BTA projects in 2024 compared to 2023.

 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)

 Capital Expenditures. The table below reflects actual capital expenditures and certain other investing activities by segment for 2024.

 Actual

 2024

 System Growth and Tracker
 $
 923.0

 Maintenance
 286.0

 Total Columbia Operations

 1,209.0

 System Growth and Tracker
 754.0

 Maintenance
 492.0

 Generation Transition Investments
 1,006.4

 Total NIPSCO Operations

 2,252.4

 Corporate and Other Operations - Maintenance(1)

 231.1

 Total Capital Expenditures(2)

 $
 3,692.5

 (1) Certain amounts may subsequently be allocated out of Corporate and Other Maintenance Costs to the Columbia Operations and NIPSCO Operations segments when placed in service.
 (2)Amounts differ from those presented on the Statements of Consolidated Cash Flows primarily due to the capitalized portion of the Corporate Incentive Plan payout, inclusion of capital expenditures included in current liabilities and AFUDC Equity.
 In addition to these capital expenditures, we made $29.0 million of advanced deposits for project costs related to the construction of the R.M. Schahfer gas peaker as part of our generation transition and invested $65.7 million in deferred cloud computing costs in 2024. We also made $454.2 million of capital investments in the form of milestone payments to the renewable generation asset developers in 2023 that were recognized in capital expenditures in 2024.
 We expect to make capital investments totaling approximately $19.4 billion during the 2025-2029 period related to infrastructure modernization, generation transition and customer growth. This forecast incorporates an estimated $1.6 billion of additional investment in renewable generation projects.

 (in billions)
 2024 Actual

 2025 Estimated

 2026 Estimated

 2027 Estimated

 2028 Estimated

 2029 Estimated

 Capital Investments
 $3.3
 $4.0 - 4.3

 $3.4 - 3.7

 $3.6 - 3.9

 $3.7 - 4.0

 $3.8 - 4.1

 Regulatory Capital Programs. We are in the process of upgrading and modernizing our electric system to enhance safety and reliability by addressing aged infrastructure and deploying advanced grid technologies. We are also upgrading and modernizing our gas infrastructure to enhance safety and reliability by reducing leaks. An ancillary benefit of these programs is the reduction of GHG emissions. In 2024, we continued to move forward on core infrastructure and environmental investment programs supported by complementary regulatory and customer initiatives across all six states of our operating area.

 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)

 The following table describes the most recent vintage of our regulatory programs to recover infrastructure replacement and other federally mandated compliance investments:

 Company
 Program
 Capital Investment

 Investment Period
 Filing Date

 Costs Covered(1)

 Approved

 Columbia of Pennsylvania(2)

 DSIC - Q4 2024

 $
 180.1
 2/24-8/24

 9/20/2024
 Eligible project costs including piping, couplings, gas service lines, excess flow valves, risers, meter bars, meters, and other related capitalized investments to improve the distribution system.

 IRP - 2024

 $
 753.5
 4/21-12/23

 2/26/2024
 Replacement of hazardous service lines, cast iron, wrought iron, uncoated steel, and bare steel pipe.

 PHMSA IRP - 2024

 $
 14.6
 1/23-12/23

 2/28/2024
 Investments necessary to comply with the PHMSA Mega Rule.

 CEP - 2024

 $
 763.3
 4/21-12/23

 2/26/2024
 Assets not included in the IRP or PHMSA IRP.

 Columbia of Virginia

 SAVE - 2025

 $
 89.0
 10/24-12/25

 8/15/2024
 Replacement projects that (1) enhance system safety or reliability, or (2) reduce, or potentially reduce, greenhouse gas emissions. Includes costs associated with Advanced Leak Detection and Repair.

 Columbia of Kentucky

 SMRP - 2024

 $
 81.9
 1/23-12/24

 10/13/2023
 Replacement of mains and inclusion of system safety investments.

 NIPSCO - Electric

 TDSIC - 5

 $
 346.9
 7/22-3/24

 5/28/2024
 New or replacement projects undertaken for the purpose of safety, reliability, system modernization or economic development.

 NIPSCO - Gas

 TDSIC - 8

 $
 8.3
 1/23-2/24

 4/30/2024
 New or replacement projects undertaken for the purpose of safety, reliability, system modernization or economic development.

 NIPSCO - Gas

 FMCA - 3

 $
 27.0
 1/23-6/24

 8/27/2024
 Project costs to comply with federal mandates.

 Pending Commission Approval (3)

 Columbia of Kentucky(4)

 SMRP - 2025

 $
 128.5
 1/23-12/25

 10/15/2024

 Replacement of mains and inclusion of system safety investments.

 NIPSCO - Electric

 TDSIC - 6

 $
 555.0
 7/22-9/24

 11/26/2024
 New or replacement projects undertaken for the purpose of safety, reliability, system modernization or economic development.

 NIPSCO - Electric(5)

 GCT - 1

 $
 149.9
 9/23-10/25

 12/16/2024
 New gas peaker generation project costs forecasted through the requested billing period May – Oct. 2025.

 (1)Programs do not include any costs already included in base rates.
 (2)Rate decreased to zero on December 14, 2024 with the implementation of new base rates resulting from Columbia of Pennsylvania's 2024 Rate Case.
 (3)On July 30, 2024, CMD filed an application for approval of a new five-year STRIDE. On December 30, 2024, the filing was withdrawn.
 (4)Rates went into effect January 2, 2025, subject to refund.
 (5)Capital investment is based off of a projected amount. The capital investment has not all been incurred to date and represents a forecasted average for the billing period.
 Refer to Note 12, "Regulatory Matters," in the Notes to Consolidated Financial Statements for a further discussion of regulatory developments during 2024.

 Financing Activities
 Common Stock, Preferred Stock and Equity Unit Sale. Refer to Note 6, "Equity," in the Notes to Consolidated Financial Statements for information on common stock, preferred stock and equity units activity.
 Short-term Debt. Refer to Note 7, "Short-Term Borrowings," in the Notes to Consolidated Financial Statements for information on short-term debt.
 Long-term Debt. Refer to Note 8, "Long-Term Debt," in the Notes to Consolidated Financial Statements for information on long-term debt.
 Non-controlling Interest. Refer to Note 4, "Noncontrolling Interests," in the Notes to Consolidated Financial Statements for more information.

 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)

 Sources of Liquidity
 The following table displays our liquidity position as of December 31, 2024 and 2023:

 2024
 2023

 Current Liquidity

 Revolving Credit Facility
 $
 1,850.0
 $
 1,850.0

 Accounts Receivable Programs(1)

 175.0
 383.9

 Less:

 Commercial Paper
 604.6
 1,061.0

 Accounts Receivable Programs Utilized
 —
 337.6

 Letters of Credit Outstanding Under Credit Facility
 9.4
 9.9

 Add:

 Cash and Cash Equivalents
 156.6
 2,245.4

 Net Available Liquidity
 $
 1,567.6
 $
 3,070.8

 (1)Represents the lesser of the seasonal limit or maximum borrowings supportable by the underlying receivables.
 Debt Covenants. We are subject to a financial covenant under our revolving credit facility which requires us to maintain a debt to capitalization ratio that does not exceed 70%. As of December 31, 2024, the ratio was 52.6%.
 Credit Ratings. The credit rating agencies periodically review our ratings, taking into account factors such as our capital structure and earnings profile. The following table includes our and NIPSCO's credit ratings and ratings outlook as of December 31, 2024. There have been no changes to our credit ratings or outlooks since February 2020.
 A credit rating is not a recommendation to buy, sell or hold securities, and may be subject to revision or withdrawal at any time by the assigning rating organization.

 S&P
 Moody's
 Fitch

 Rating
 Outlook
 Rating
 Outlook
 Rating
 Outlook

 BBB+
 Baa2
 BBB

 NIPSCO
 BBB+
 Baa1
 BBB

 Commercial Paper
 A-2
 P-2
 F2

 Certain of our subsidiaries have agreements that contain "ratings triggers" that require increased collateral if our credit ratings or the credit ratings of certain of our subsidiaries are below investment grade. These agreements are primarily for insurance purposes and for the physical purchase or sale of power. As of December 31, 2024, a collateral requirement of approximately $115.5 million would be required in the event of a downgrade below investment grade. In addition to agreements with ratings triggers, there are other agreements that contain "adequate assurance" or "material adverse change" provisions that could necessitate additional credit support such as letters of credit and cash collateral to transact business.
 Equity. Our authorized capital stock consists of 770,000,000 shares, $0.01 par value, of which 750,000,000 are common stock and 20,000,000 are preferred stock. As of December 31, 2024, 469,822,472 shares of common stock were outstanding. For more information regarding our common and preferred stock, see Note 6, "Equity," in the Notes to Consolidated Financial Statements.

 Contractual Obligations, Cash Requirements and Off-Balance Sheet Arrangements
 We have certain contractual obligations requiring payments at specified periods. Our material cash requirements are detailed below. We intend to use funds from the liquidity sources referenced above to meet these cash requirements.
 At December 31, 2024, we had $13,355.7 million in long-term debt, of which $1,281.2 million is current and $604.6 million in short-term borrowings outstanding.
 During 2025 and 2026, we expect to make cash payments of $685.5 million and $631.2 million, respectively, related to pipeline service obligations including demand for gas transportation, gas storage and gas purchases, and $140.5 million and $24.9 million, respectively, for long lead time items related to plant equipment purchases.

 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)

 Our expected payments include employer contributions to pension and other postretirement benefits plans expected to be made in 2025. Plan contributions beyond 2025 are dependent upon a number of factors, including actual returns on plan assets, which cannot be reliably estimated at this time. In 2025, we expect to make contributions of approximately $2.3 million to our pension plans and approximately $21.3 million to our postretirement medical and life plans. Refer to Note 16, "Pension and Other Postemployment Benefits," in the Notes to Consolidated Financial Statements for more information.
 We cannot reasonably estimate the settlement amounts or timing of cash flows related to certain of our long-term obligations classified as "Total Other Liabilities" on the Consolidated Balance Sheets.
 We have uncertain income tax positions for which we are unable to predict when the matters will be resolved. Refer to Note 15, "Income Taxes," in the Notes to Consolidated Financial Statements for more information.
 NIPSCO has executed several PPAs to purchase 100% of the output from renewable generation facilities at a fixed price per MWh. NIPSCO has also executed several BTAs with developers to construct renewable generation facilities. See Note 19, "Other Commitments and Contingencies - A. Contractual Obligations," and Note 19, "Other Commitments and Contingencies - E. Other Matters," in the Notes to Consolidated Financial Statements for additional information.
 In addition, we, along with certain of our subsidiaries, enter into various agreements providing financial or performance assurance to third parties on behalf of certain subsidiaries. Such agreements include guarantees and stand-by letters of credit.
 Refer to Note 19, "Other Commitments and Contingencies," in the Notes to Consolidated Financial Statements for additional information regarding our contractual obligations over the next 5 years and thereafter and our off-balance sheet arrangements.

 Market Risk Disclosures
 Risk is an inherent part of our businesses. The extent to which we properly and effectively identify, assess, monitor and manage each of the various types of risk involved in our businesses is critical to our profitability. We seek to identify, assess, monitor and manage, in accordance with defined policies and procedures, the following principal market risks that are involved in our businesses: commodity price risk, interest rate risk and credit risk. We manage risk through a multi-faceted process with oversight by the Risk Management Committee that requires constant communication, judgment and knowledge of specialized products and markets. Our senior management takes an active role in the risk management process and has developed policies and procedures that require specific administrative and business functions to assist in the identification, assessment and control of various risks. These may include, but are not limited to market, operational, financial, compliance and strategic risk types. In recognition of the increasingly varied and complex nature of the energy business, our risk management process, policies and procedures continue to evolve and are subject to ongoing review and modification.
 Commodity Price Risk
 Our gas and electric subsidiaries have commodity price risk primarily related to the purchases of natural gas and power. To manage this market risk, our subsidiaries use derivatives, including commodity futures contracts, swaps, forwards and options. We do not participate in speculative energy trading activity.
 Commodity price risk resulting from derivative activities at our rate-regulated subsidiaries is limited and does not bear significant exposure to earnings risk, since our current regulatory mechanisms allow recovery of prudently incurred purchased power, fuel and gas costs through the rate-making process, including gains or losses on these derivative instruments. These changes are included in the GCA and FAC regulatory rate-recovery mechanisms. If these mechanisms were to be adjusted or eliminated, these subsidiaries may begin providing services without the benefit of the traditional rate-making process and may be more exposed to commodity price risk. For additional information, see "Results and Discussion of Operations" in this Management's Discussion.
 Our subsidiaries are required to make cash margin deposits with their brokers to cover actual and potential losses in the value of outstanding exchange traded derivative contracts. The amount of these deposits, some of which are reflected in our restricted cash balance, may fluctuate significantly during periods of high volatility in the energy commodity markets.
 Refer to Note 13, "Risk Management Activities," in the Notes to Consolidated Financial Statements for further information on our commodity price risk assets and liabilities as of December 31, 2024 and 2023.

 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)

 Interest Rate Risk
 We are exposed to interest rate risk as a result of changes in interest rates on borrowings under our revolving credit agreement, commercial paper program, and accounts receivable programs, which have interest rates that are indexed to short-term market interest rates. Based upon average borrowings and debt obligations subject to fluctuations in short-term market interest rates, an increase (or decrease) in short-term interest rates of 100 basis points (1%) would have increased (or decreased) interest expense by $7.9 million and $18.9 million for 2024 and 2023, respectively. We are also exposed to interest rate risk as a result of changes in benchmark rates that can influence the interest rates of future long-term debt issuances. From time to time, we may enter into forward interest rate instruments to lock in long term interest costs and/ or rates.
 Credit Risk
 Due to the nature of the industry, credit risk is embedded in many of our business activities. Our extension of credit is governed by a Corporate Credit Risk Management Policy which establishes guidelines for documenting management approval levels for credit limits, evaluating creditworthiness, and credit risk mitigation efforts. Exposures to credit risks are monitored by the risk management function, which is independent of commercial operations. Credit risk arises due to the possibility that a customer, supplier or counterparty will not be able or willing to fulfill its obligations on a transaction on or before the settlement date. For derivative-related contracts, credit risk arises when counterparties are obligated to deliver or purchase defined commodity units of gas or power to us at a future date per execution of contractual terms and conditions. Exposure to credit risk is measured in terms of both current obligations and the market value of forward positions net of any posted collateral such as cash and letters of credit.

 The financial status of our banking partners is periodically assessed through traditional credit ratings provided by major credit rating agencies.

 Other Information
 Critical Accounting Estimates
 We apply certain accounting policies in accordance with GAAP, which require that we make estimates and judgments that have had, and may continue to have, significant impacts on our operations and Consolidated Financial Statements. We evaluate our estimates on an ongoing basis. We base our estimates on historical experience and on various other assumptions that we believe are reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates. We believe the following represent the more significant items requiring the use of judgment in preparing our Consolidated Financial Statements:
 Basis of Accounting for Rate-Regulated Subsidiaries. ASC Topic 980, Regulated Operations, provides that rate-regulated subsidiaries account for and report assets and liabilities consistent with the economic effect of the way in which regulators establish rates, if the rates established are designed to recover the costs of providing the regulated service and if the competitive environment makes it probable that such rates can be billed and collected. Accordingly, certain expenses and credits subject to utility regulation or rate determination normally reflected in income may be deferred on the Consolidated Balance Sheets and recognized in income as the related amounts are included in service rates and recovered from or refunded to customers. For additional information, refer to Note 12, "Regulatory Matters," in the Notes to Consolidated Financial Statements.
 In the event that regulation significantly changes the opportunity for us to recover our costs in the future, all or a portion of our regulated operations may no longer meet the criteria for the application of ASC Topic 980, Regulated Operations. In such event, a write-down of all or a portion of our existing regulatory assets and liabilities could result. If transition cost recovery is approved by the appropriate regulatory bodies that would meet the requirements under GAAP for continued accounting as regulatory assets and liabilities during such recovery period, the regulatory assets and liabilities would be reported at the recoverable amounts. If we were unable to continue to apply the provisions of ASC Topic 980, Regulated Operations, we would be required to apply the provisions of ASC Topic 980-20, Discontinuation of Rate-Regulated Accounting. In management's opinion, our regulated subsidiaries will be subject to ASC Topic 980, Regulated Operations for the foreseeable future.
 Certain of the regulatory assets reflected on our Consolidated Balance Sheets require specific regulatory action in order to be included in future service rates. Although recovery of these amounts is not guaranteed, we believe that these costs meet the requirements for deferral as regulatory assets. If we determine that the amounts included as regulatory assets are no longer probable of recovery, a charge to income would immediately be required to the extent of the unrecoverable amounts.

 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)

 One of the more significant items recorded through the application of this accounting guidance is the regulatory overlay for JV accounting. The application of HLBV to consolidated VIEs generally results in the recognition of profit from the related JVs over a time frame that is different from when the regulatory return is earned. In accordance with the principles of ASC 980, we have recognized a regulatory deferral of certain amounts representing the timing difference between the profit earned from the JVs and the amount included in regulated rates to recover our approved investments in consolidated JVs. For additional information, refer to Note 1, "Nature of Operations and Summary of Significant Accounting Policies - S. Noncontrolling Interest," in the Notes to Consolidated Financial Statements.
 Pension and Postretirement Benefits. We have defined benefit plans for both pension and other postretirement benefits. The calculation of the net obligations and annual expense related to the plans requires a significant degree of judgment regarding the discount rates to be used in bringing the liabilities to present value, expected long-term rates of return on plan assets, health care trend rates, and mortality rates, among other assumptions. Due to the size of the plans and the long-term nature of the associated liabilities, changes in the assumptions used in the actuarial estimates could have material impacts on the measurement of the net obligations and annual expense recognition. Differences between actuarial assumptions and actual plan results are deferred into AOCI or a regulatory balance sheet account, depending on the jurisdiction of our entity. These deferred gains or losses are then amortized into the income statement when the accumulated differences exceed 10% of the greater of the projected benefit obligation or the fair value of plan assets (known in GAAP as the "corridor" method) or when settlement accounting is triggered.
 The discount rates, expected long-term rates of return on plan assets, health care cost trend rates and mortality rates are critical assumptions. Methods used to develop these assumptions are described below. While a third party actuarial firm assists with the development of many of these assumptions, we are ultimately responsible for selecting the final assumptions.
 The discount rate is utilized principally in calculating the actuarial present value of pension and other postretirement benefit obligations and net periodic pension and other postretirement benefit plan costs. Our discount rates for both pension and other postretirement benefits are determined using spot rates along an AA-rated above median yield curve with cash flows matching the expected duration of benefit payments to be made to plan participants.
 The expected long-term rate of return on plan assets is a component utilized in calculating annual pension and other postretirement benefit plan costs. We estimate the expected return on plan assets by evaluating expected bond returns, equity risk premiums, target asset allocations, the effects of active plan management, the impact of periodic plan asset rebalancing and historical performance. We also consider the guidance from our investment advisors in making a final determination of our expected rate of return on assets. For measurement of 2024 net periodic benefit cost, we selected a weighted-average assumption of the expected pre-tax long-term rate of return of 7.02% and 7.06% for our pension and other postretirement benefit plan assets, respectively. For measurement of 2025 net periodic benefit cost, we selected a weighted-average assumption of the expected pre-tax long-term rate of return of 7.30% and 7.09 % respectively, for our pension and other postretirement benefit plan assets.
 We estimate the assumed health care cost trend rate, which is used in determining our other postretirement benefit net expense, based upon our actual health care cost experience, the effects of recently enacted legislation, third-party actuarial surveys and general economic conditions.
 We utilize a full yield curve approach to estimate the service and interest components of net periodic benefit cost for pension and other postretirement benefits by applying the specific spot rates along the yield curve used in the determination of the benefit obligation to the relevant projected cash flows. For further discussion of our pension and other postretirement benefits, see Note 16, "Pension and Other Postemployment Benefits," in the Notes to Consolidated Financial Statements.
 Typically, we use the Society of Actuaries' most recently published mortality data in developing a best estimate of mortality as part of the calculation of the pension and other postretirement benefit obligations. We adopted Aon's U.S. Endemic Mortality Improvement scale MP-2021, accounting for both the near-term and long-term COVID-19 impacts.

 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)

 The following tables illustrate the effects of changes in these actuarial assumptions while holding all other assumptions constant:

 Impact on December 31, 2024 Projected Benefit Obligation Increase/(Decrease)

 Change in Assumptions (in millions)

 Other Postretirement Benefits

 +50 basis points change in discount rate
 $
 (44.9)
 $
 (18.8)

 -50 basis points change in discount rate
 48.2
 20.4

 Impact on 2024 Expense Increase/(Decrease)(1)

 Change in Assumptions (in millions)

 Other Postretirement Benefits

 +50 basis points change in discount rate
 $
 (1.6)
 $
 0.3

 -50 basis points change in discount rate
 1.6
 0.4

 +50 basis points change in expected long-term rate of return on plan assets
 (6.8)
 (1.2)

 -50 basis points change in expected long-term rate of return on plan assets
 6.8
 1.2

 (1)Before labor capitalization and regulatory deferrals.
 Goodwill and Other Intangible Assets. We have six goodwill reporting units, comprised of the six state operating companies within both the Columbia Operations and NIPSCO Operations reportable segments. Our goodwill assets at December 31, 2024 were $1,485.9 million, most of which resulted from the acquisition of Columbia on November 1, 2000.
 As required by GAAP, we test for impairment of goodwill on an annual basis and on an interim basis when events or circumstances indicate that a potential impairment may exist. Our annual goodwill test takes place in the second quarter of each year and was performed on May 1, 2024. A quantitative ("step 1") test was completed on May 1, 2024 for all reporting units. Consistent with our historical impairment testing of goodwill, fair value of the reporting units was determined based on a weighting of income and market approaches. These approaches require significant judgments including appropriate long-term growth rates and discount rates for the income approach and appropriate multiples of earnings for peer companies and control premiums for the market approach. The discount rates were derived using peer company data compiled with the assistance of a third party valuation services firm. The discount rates used are subject to change based on changes in tax rates at both the state and federal level, debt and equity ratios at each reporting unit, U.S. Treasury interest rates and general economic conditions. The long-term growth rate was derived by evaluating historic growth rates, new business and investment opportunities beyond the near term horizon. The long-term growth rate is subject to change depending on inflationary impacts to the U.S. economy and the individual business environments in which each reporting unit operates. The Step 1 analysis performed indicated that the fair value of each of the reporting units exceeds their carrying value. As a result, no impairment charges were recorded. See Note 10, "Goodwill," in the Notes to Consolidated Financial Statements for information regarding our 2024 analyses and assumptions.
 Unbilled Revenue. We record utility operating revenues when energy is delivered to our customers. However, the determination of energy sales to individual customers is based upon the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of their last meter reading are estimated and corresponding unbilled revenues are calculated. This unbilled revenue is estimated each month based upon historical usage, customer rates and weather. As of December 31, 2024, we recorded $408.1 million of customer accounts receivable for unbilled revenue. Significant fluctuations in energy demand for the unbilled period or changes in the composition of customer classes could impact the accuracy of the unbilled revenue estimate. Refer to Note 3, "Revenue Recognition," in the Notes to Consolidated Financial Statements for additional information regarding our significant judgments and estimates related to unbilled revenue recognition.
 Income Taxes. The consolidated income tax provision and deferred income tax assets and liabilities, as well as any unrecognized tax benefits and valuation allowances, require use of estimates and significant management judgement. Although we believe that current estimates for deferred tax assets and liabilities are reasonable, actual results could differ from these estimates for a variety of reasons, including reasonable projections of taxable income, the ability and intent to implement tax planning strategies if necessary, and interpretations of applicable tax laws and regulations across multiple taxing jurisdictions.

 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)

 Ultimate resolution or clarification of income tax matters may result in favorable or unfavorable impacts to net income and cash flows, and adjustments to tax-related assets and liabilities could be material.
 We account for uncertain income tax positions using a benefit recognition model with a two-step approach including a more-likely-than-not recognition threshold and a measurement approach based on the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement. We evaluate each position based solely on the technical merits and facts and circumstances of the position, assuming the position will be examined by a taxing authority having full knowledge of all relevant information. Significant judgment is required to determine whether the recognition threshold has been met and, if so, the appropriate amount of tax benefits to be recorded in the consolidated financial statements. At December 31, 2024 and 2023, we had $21.7 million of unrecognized tax benefits. Changes in these unrecognized tax benefits may result from remeasurement of amounts expected to be realized, settlements with tax authorities and expiration of statutes of limitations.
 On a quarterly basis, we evaluate our deferred tax assets by considering current and historical financial results, expectations for future taxable income and the availability of tax planning strategies that can be implemented, if necessary, to realize deferred tax assets. Failure to achieve forecasted taxable income or successfully implement tax planning strategies may affect the realization of deferred tax assets. We establish a valuation allowance when we conclude it is more likely than not that all, or a portion, of a deferred tax asset will not be realized in future periods. Significant judgment is required to determine the amount of tax benefits expected to be realized. At December 31, 2024 and 2023, we had established $6.4 million and $6.4 million, respectively, of valuation allowances (net of federal benefit) related to certain state net operating loss carryforwards. Refer to Note 15, "Income Taxes," in the Notes to Consolidated Financial Statements for additional information.
 Recently Issued Accounting Pronouncements
 Refer to Note 2, "Recent Accounting Pronouncements," in the Notes to Consolidated Financial Statements.

 Item 7A. Quantitative and Qualitative Disclosures About Market Risk
 Quantitative and Qualitative Disclosures about Market Risk are reported in Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations – Market Risk Disclosures."

 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

 Page

 Report of Independent Registered Public Accounting Firm

 Statements of Consolidated Income

 Statements of Consolidated Comprehensive Income

 Consolidated Balance Sheets

 Statements of Consolidated Cash Flows

 Statements of Consolidated Stockholders' Equity

 1. Nature of Operations and Summary of Significant Accounting Policies

 2. Recent Accounting Pronouncements

 3. Revenue Recognition

 4. Noncontrolling Interests

 5. Earnings Per Share

 6. Equity

 7. Short-Term Borrowings

 8. Long-Term Debt

 9. Property, Plant and Equipment

 10. Goodwill

 11. Asset Retirement Obligations

 12. Regulatory Matters

 13. Risk Management Activities

 14. Fair Value

 15. Income Taxes

 16. Pension and Other Postretirement Benefits

 17. Share-Based Compensation

 18. Leases

 19. Other Commitments and Contingencies

 20. Accumulated Other Comprehensive Loss

 21. Business Segment Information

 22. Other, Net

 23. Interest Expense, Net

 24. Supplemental Cash Flow Information

 Schedule II

 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 To the shareholders and the Board of Directors of NiSource Inc.
 Opinion on the Financial Statements
 We have audited the accompanying consolidated balance sheets of NiSource Inc. and subsidiaries (the "Company") as of December 31, 2024 and 2023, the related consolidated statements of income, comprehensive income, stockholders' equity, and cash flows, for each of the three years in the period ended December 31, 2024, and the related notes and the schedule listed in the Index at Item 15 (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2024 and 2023, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2024, in conformity with accounting principles generally accepted in the United States of America.

 We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2024, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 12, 2025, expressed an unqualified opinion on the Company's internal control over financial reporting.

 Basis for Opinion

 These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

 We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

 Critical Audit Matters

 The critical audit matters communicated below are matters arising from the current-period audit of the financial statements that were communicated or required to be communicated to the audit committee and that (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

 Regulatory Matters - Impact of Rate Regulation on the Financial Statements – Refer to Notes 1, 9, and 12 to the financial statements

 Critical Audit Matter Description

 The Company's primary subsidiaries are fully regulated natural gas and electric utility companies serving customers in six states. These rate-regulated subsidiaries account for and report assets and liabilities consistent with the economic effect of the manner in which regulators establish rates, if the rates established are designed to recover the costs of providing the regulated service and it is probable that such rates can be charged to and collected from customers. Certain expenses and credits subject to utility regulation or rate determination normally reflected in income are deferred on the consolidated balance sheets and are later recognized in income as the related amounts are included in customer rates and recovered from or refunded to customers.

 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 The Company's subsidiaries' rates are determined and approved in regulatory proceedings based on an analysis of the subsidiaries' costs to provide utility service and a return on, and recovery of, the subsidiaries' investment in the utility business. Regulatory decisions can have an impact on the recovery of costs, the rate of return earned on investment, and the timing and amount of assets to be recovered by rates. The respective commission's regulation of rates is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital. Decisions to be made by the commission in the future will impact the accounting for regulated operations, including decisions about the amount of allowable costs and return on invested capital included in rates and any refunds that may be required. While the Company has indicated it expects to recover costs from customers through regulated rates, there is a risk that the commission will not approve: (1) full recovery of the costs of providing utility service, or (2) full recovery of all amounts invested in the utility business and a reasonable return on that investment.

 We identified the impact of rate regulation, specifically certain regulatory assets and liabilities at the Company's Northern Indiana Public Service Company LLC and Columbia Gas of Ohio, Inc. subsidiaries, as a critical audit matter due to the significant judgments made by management to support its assertions about certain account balances and the significant degree of subjectivity involved in assessing the likelihood of recovery of incurred costs in current or future rates due in part to uncertainty related to future decisions by the rate regulators. This required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities and a significant degree of auditor judgment when performing audit procedures to evaluate the reasonableness of management's conclusions.

 How the Critical Audit Matter Was Addressed in the Audit

 Our audit procedures related to the application of specialized rules to account for the effects of cost-based rate regulation related to the uncertainty of future decisions by the rate regulators, specifically the Indiana Utility Regulatory Commission (IURC) and the Public Utility Commission of Ohio (PUCO), included the following, among others:

 • We tested the effectiveness of management's controls over (1) the evaluation of the likelihood of (a) the recovery of costs deferred as regulatory assets in future periods, and (b) regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates; and (2) the evaluation of Hypothetical Liquidation Book Value (HLBV) accounting for the company's Renewable Joint Ventures and its impact on the Company's regulatory liability.

 • We evaluated Northern Indiana Public Service Company LLC and Columbia Gas of Ohio, Inc.'s disclosures related to the financial statement impacts of rate regulation.

 • We read relevant regulatory orders issued by the IURC and the PUCO, including regulatory statutes, interpretations, procedural memorandums, filings made by interveners, and other publicly available information to assess the likelihood of recovery in future rates or a future reduction in rates based on precedents of the commissions' treatment of similar costs under similar circumstances. We evaluated this external information and compared to management's recorded regulatory asset and liability balances for completeness, including the implementation of new rate orders at Northern Indiana Public Service Company LLC's gas business.

 • We inspected minutes of the boards of directors for discussions of changes in legal, regulatory, or business factors which could impact management's conclusions with respect to the financial statement impacts of rate regulation.

 • For the Northern Indiana Public Service Company LLC electric base rate case proceeding that is in-process, we inspected the Company's and intervenors' filings with the commission that may impact the Company's future rates, for any evidence that might contradict management's assertions related to recoverability of recorded assets.

 • We inquired of management about property, plant, and equipment that may be abandoned with an emphasis on the generation strategy related to Northern Indiana Public Service Company LLC's R.M. Schahfer and Michigan City Generating Stations. We inspected minutes of the board of directors and regulatory orders and other filings with the IURC to identify evidence that may contradict management's assertion regarding probability of an abandonment.

 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 • We read the relevant regulatory orders issued by the IURC for the Company's renewable energy investments. We evaluated the appropriateness of recognizing a regulatory liability representing timing differences between the profit allocated under the HLBV method related to the consolidated joint ventures and the allowed earnings included in regulatory rates. We also evaluated the appropriateness of the offset to the regulatory liability recorded in depreciation expense.
 /s/ DELOITTE & TOUCHE LLP
 Columbus, Ohio
 February 12, 2025

 We have served as the Company's auditor since 2002.

 STATEMENTS OF CONSOLIDATED INCOME

 Year Ended December 31, (in millions, except per share amounts)

 2024
 2023
 2022

 Customer revenues
 $
 5,282.9
 $
 5,347.8
 $
 5,738.6

 Other revenues
 172.2
 157.6
 112.0

 Total Operating Revenues
 5,455.1
 5,505.4
 5,850.6

 Operating Expenses

 1,132.2
 1,533.3
 2,110.5

 Operation and maintenance
 1,515.2
 1,494.9
 1,489.4

 1,043.2
 908.2
 820.8

 Loss on impairment of assets

 6.1
 —
 —

 Loss (gain) on sale of assets, net
 2.9
 2.9
 ( 104.2)

 Other taxes
 300.0
 270.6
 268.3

 Total Operating Expenses
 3,999.6
 4,209.9
 4,584.8

 1,455.5
 1,295.5
 1,265.8

 Other Income (Deductions)

 Interest expense, net
 ( 517.2)
 ( 489.6)
 ( 361.6)

 Other, net
 64.5
 8.0
 52.2

 Total Other Deductions, Net
 ( 452.7)
 ( 481.6)
 ( 309.4)

 Income before Income Taxes

 1,002.8
 813.9
 956.4

 158.1
 139.5
 164.6

 844.7
 674.4
 791.8

 Net income (loss) attributable to noncontrolling interest

 84.3
 ( 39.9)
 ( 12.3)

 Net Income attributable to NiSource

 760.4
 714.3
 804.1

 Preferred dividends
 ( 6.7)
 ( 42.8)
 ( 55.1)

 Preferred redemption premium

 ( 14.0)
 ( 9.8)
 —

 Net Income Available to Common Shareholders

 $
 739.7
 $
 661.7
 $
 749.0

 Earnings Per Share

 Basic Earnings Per Share

 $
 1.63
 $
 1.59
 $
 1.84

 Diluted Earnings Per Share

 $
 1.62
 $
 1.48
 $
 1.70

 Basic Average Common Shares Outstanding
 454.2
 416.1
 407.1

 Diluted Average Common Shares
 456.0
 447.9
 442.7

 The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

 STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME

 Year Ended December 31, (in millions, net of taxes)

 2024
 2023
 2022

 $
 844.7
 $
 674.4
 $
 791.8

 Other comprehensive income:

 Net unrealized gain (loss) on available-for-sale securities(1)

 3.3
 3.9
 ( 13.3)

 Net unrealized (loss) gain on cash flow hedges(2)

 109.9

 Unrecognized pension and OPEB benefit (costs)(3)

 0.3
 ( 6.9)

 Total other comprehensive income

 3.2
 3.5
 89.7

 Total Comprehensive Income

 $
 847.9
 $
 677.9
 $
 881.5

 (1) Net unrealized gain (loss) on available-for-sale securities, net of $ 0.9 million tax expense, $ 1.0 million tax expense and $ 3.5 million tax benefit in 2024, 2023 and 2022, respectively.
 (2) Net unrealized (loss) gain on derivatives qualifying as cash flow hedges, net of $ 0.1 million tax benefit, $ 0.1 million tax benefit and $ 36.4 million tax expense in 2024, 2023 and 2022, respectively.
 (3) Unrecognized pension and OPEB benefit (costs), net of $ 0.3 million tax expense, $ 0.1 million tax benefit and $ 2.3 million tax benefit in 2024, 2023 and 2022, respectively.
 The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

 CONSOLIDATED BALANCE SHEETS

 ASSETS

 Property, Plant and Equipment

 Plant
 $
 34,152.9
 $
 30,482.1

 Accumulated depreciation and amortization
 ( 8,699.0)
 ( 8,207.2)

 Net Property, Plant and Equipment(1)

 25,453.9
 22,274.9

 Investments and Other Assets

 Unconsolidated affiliates
 6.5
 5.3

 Available-for-sale debt securities (amortized cost of $ 91.9 and $ 169.0, allowance for credit losses of $ 0.1 and $ 0.6, respectively)

 86.7
 159.1

 Other investments
 85.5
 82.7

 Total Investments and Other Assets
 178.7
 247.1

 Current Assets

 Cash and cash equivalents
 156.6
 2,245.4

 Restricted cash
 42.0
 35.7

 Accounts receivable
 987.9
 884.9

 Allowance for credit losses
 ( 23.7)
 ( 22.9)

 Accounts receivable, net
 964.2
 862.0

 Gas storage

 179.6
 265.8

 Materials and supplies, at average cost
 173.3
 172.1

 Electric production fuel, at average cost
 36.2
 65.3

 Exchange gas receivable
 45.7
 66.0

 Regulatory assets
 319.9
 214.3

 Deposits to renewable generation asset developer
 —
 454.2

 Prepayments

 138.5
 105.5

 Other current assets

 24.2
 13.1

 Total Current Assets(1)

 2,080.2
 4,499.4

 Other Assets

 Regulatory assets
 2,157.4
 2,245.9

 Goodwill
 1,485.9
 1,485.9

 Deferred charges and other
 432.0
 324.0

 Total Other Assets
 4,075.3
 4,055.8

 Total Assets
 $
 31,788.1
 $
 31,077.2

 (1)Includes $ 1,323.8 million and $ 1,369.8 million in 2024 and 2023, respectively, of net property, plant and equipment assets, $ 65.0 million and $ 63.6 million in 2024 and 2023, respectively, of current assets of consolidated VIEs that may be used only to settle obligations of the consolidated VIEs. Refer to Note 4, "Noncontrolling Interests," for additional information.

 The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

 CONSOLIDATED BALANCE SHEETS

 (in millions, except share amounts)

 CAPITALIZATION AND LIABILITIES

 Capitalization

 Stockholders' Equity

 Common stock - $ 0.01 par value, 750,000,000 shares authorized; 469,822,472 and 447,381,671 shares outstanding, respectively

 $
 4.7
 $
 4.5

 Preferred stock - $ 0.01 par value, 20,000,000 shares authorized; 0 and 40,000 shares outstanding, respectively

 —
 486.1

 Treasury stock

 Additional paid-in capital
 9,521.5
 8,879.5

 Retained deficit
 ( 711.7)
 ( 967.0)

 Accumulated other comprehensive loss
 ( 30.4)
 ( 33.6)

 Total NiSource Stockholders' Equity
 8,684.2
 8,269.6

 Noncontrolling interest in consolidated subsidiaries
 1,984.1
 1,866.7

 Total Stockholders' Equity
 10,668.3
 10,136.3

 Long-term debt, excluding amounts due within one year
 12,074.5
 11,055.5

 Total Capitalization
 22,742.8
 21,191.8

 Current Liabilities

 Current portion of long-term debt
 1,281.2
 23.8

 Short-term borrowings
 604.6
 3,048.6

 Accounts payable
 863.1
 749.4

 Customer deposits and credits
 268.8
 294.4

 Taxes accrued
 173.4
 166.2

 Interest accrued
 157.0
 136.1

 Asset retirement obligations

 84.6
 72.5

 Exchange gas payable
 91.8
 50.5

 Regulatory liabilities
 150.5
 278.6

 Accrued compensation and employee benefits
 268.2
 227.6

 Other accruals
 170.2
 217.4

 Total Current Liabilities(1)

 4,113.4
 5,265.1

 Other Liabilities

 Deferred income taxes
 2,281.6
 2,080.4

 Accrued liability for postretirement and postemployment benefits
 207.5
 250.1

 Regulatory liabilities
 1,431.2
 1,510.7

 Asset retirement obligations
 698.6
 480.5

 Other noncurrent liabilities and deferred credits
 313.0
 298.6

 Total Other Liabilities(1)

 4,931.9
 4,620.3

 Commitments and Contingencies (Refer to Note 19, "Other Commitments and Contingencies")

 Total Capitalization and Liabilities
 $
 31,788.1
 $
 31,077.2

 (1)Includes $ 53.7 million and $ 68.3 million in 2024 and 2023, respectively, of current liabilities, $ 58.3 million and $ 55.7 million in 2024 and 2023, respectively, of other liabilities, and finance leases of $ 40.4 million in 2024, of consolidated VIEs that creditors do not have recourse to our general credit. Refer to Note 4, "Noncontrolling Interests," for additional information.
 The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

 STATEMENTS OF CONSOLIDATED CASH FLOWS

 2024
 2023
 2022

 Operating Activities

 $
 844.7
 $
 674.4
 $
 791.8

 Adjustments to Reconcile Net Income to Net Cash from Operating Activities:

 1,043.2
 908.2
 820.8

 Deferred income taxes

 168.0
 134.1
 156.9

 Stock compensation expense and 401(k) profit sharing contribution
 43.6
 33.5
 24.9

 Loss (gain) on sale of assets
 2.9
 2.9
 ( 105.3)

 Payments for assets retirement obligations

 ( 72.5)
 ( 41.6)
 ( 22.3)

 Other adjustments
 ( 52.8)
 ( 17.9)
 5.7

 Changes in Assets and Liabilities:

 Accounts receivable
 ( 101.5)
 184.1
 ( 216.3)

 Gas storage and other inventories

 102.0
 233.9
 ( 258.9)

 Accounts payable
 71.5
 ( 171.8)
 165.0

 Exchange gas receivable/payable
 ( 133.5)
 126.5
 57.8

 Other accruals
 9.5
 ( 102.9)
 73.4

 Prepayments and other current assets
 ( 75.9)
 36.7
 ( 9.8)

 Regulatory assets/liabilities
 ( 8.7)
 ( 26.2)
 ( 129.4)

 Postretirement and postemployment benefits
 ( 64.3)
 ( 22.0)
 84.7

 Deferred charges and other noncurrent assets
 ( 20.8)
 ( 10.1)
 ( 4.1)

 Other noncurrent liabilities and deferred credits
 26.1
 ( 6.7)
 ( 25.5)

 Net Cash Flows from Operating Activities
 1,781.5
 1,935.1
 1,409.4

 Investing Activities

 Capital expenditures
 ( 2,614.0)
 ( 2,645.8)
 ( 2,203.1)

 Insurance recoveries

 0.8
 3.0
 105.0

 Cost of removal
 ( 166.8)
 ( 160.8)
 ( 151.7)

 Purchases of available-for-sale securities
 ( 17.8)
 ( 42.8)
 ( 73.5)

 Sales of available-for-sale securities
 93.2
 39.9
 75.7

 Milestone and final payments to renewable generation asset developer

 ( 482.0)
 ( 761.4)
 ( 323.9)

 Advanced deposits for project costs

 ( 29.0)
 —
 —

 Other investing activities
 2.6
 ( 3.7)
 1.3

 Net Cash Flows used for Investing Activities
 ( 3,213.0)
 ( 3,571.6)
 ( 2,570.2)

 Financing Activities

 Proceeds from issuance of long-term debt
 2,229.5
 1,488.7
 345.6

 Repayments of long-term debt and finance lease obligations
 ( 25.6)
 ( 33.1)
 ( 60.3)

 Repayment of short term credit agreements

 ( 1,650.0)
 —
 —

 Issuance of short term credit agreements

 —
 650.0

 Net change in commercial paper and other short-term borrowings

 ( 794.0)
 636.4
 202.2

 Issuance of common stock, net of issuance costs
 612.6
 12.9
 154.3

 Redemption of preferred stock

 ( 486.1)
 ( 393.9)
 —

 Preferred stock redemption premium

 ( 14.0)
 ( 6.2)
 —

 Payment of obligation to renewable generation asset developer
 —
 ( 347.2)
 —

 Equity costs, premiums and other debt related costs
 ( 67.3)
 ( 30.2)
 ( 13.0)

 Contributions from NIPSCO minority interest holders

 99.5
 2,161.9
 —

 Distributions to NIPSCO minority interest holders

 ( 50.3)
 —
 —

 Contributions from tax equity partners

 —
 240.9
 21.2

 Distributions to tax equity partners

 ( 16.1)
 ( 6.0)

 Dividends paid - common stock
 ( 481.0)
 ( 413.5)
 ( 381.5)

 Dividends paid - preferred stock
 ( 8.2)
 ( 43.8)
 ( 55.1)

 Contract liability payment
 —
 ( 66.6)
 ( 66.1)

 Net Cash Flows (used for) from Financing Activities

 ( 651.0)
 3,842.2
 1,141.3

 Change in cash, cash equivalents and restricted cash
 ( 2,082.5)
 2,205.7
 ( 19.5)

 Cash, cash equivalents and restricted cash at beginning of period
 2,281.1
 75.4
 94.9

 Cash, Cash Equivalents and Restricted Cash at End of Period
 $
 198.6
 $
 2,281.1
 $
 75.4

 Reconciliation to Balance Sheet
 2024
 2023
 2022

 Cash and cash equivalents
 156.6
 2,245.4
 40.8

 Restricted Cash
 42.0
 35.7
 34.6

 Total Cash, Cash Equivalents and Restricted Cash
 198.6
 2,281.1
 75.4

 The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

 STATEMENTS OF CONSOLIDATED STOCKHOLDERS' EQUITY

 Common
Stock
 Preferred Stock(1)

 Treasury
Stock
 Additional
Paid-In
Capital
 Retained Deficit
 Accumulated
Other
Comprehensive
Loss
 Noncontrolling Interest in Consolidated Subsidiaries
 Total

 Balance as of January 1, 2022

 $
 4.1
 $
 1,546.5
 $
 $
 7,204.3
 $
 ( 1,580.9)
 $
 ( 126.8)
 $
 325.6
 $
 7,272.9

 Comprehensive Income:

 Net Income (Loss)

 —
 —
 —
 —
 804.1
 —
 ( 12.3)
 791.8

 Other comprehensive income, net of tax
 —
 —
 —
 —
 —
 89.7
 —
 89.7

 Dividends:

 Common stock ($ 0.94 per share)

 —
 —
 —
 —
 ( 381.7)
 —
 —
 ( 381.7)

 Preferred stock (See Note 6)

 —
 —
 —
 —
 ( 55.1)
 —
 —
 ( 55.1)

 Noncontrolling Interests:

 Contributions from noncontrolling interest
 —
 —
 —
 —
 —
 —
 19.1
 19.1

 Distributions to noncontrolling interest
 —
 —
 —
 —
 —
 —
 ( 6.0)
 ( 6.0)

 Stock issuances:

 —
 —
 —
 5.2
 —
 —
 —
 5.2

 —
 —
 —
 14.3
 —
 —
 —
 14.3

 401(k) and profit sharing
 —
 —
 —
 9.7
 —
 —
 —
 9.7

 ATM Program
 0.1
 —
 —
 141.8
 —
 —
 —
 141.9

 Balance as of December 31, 2022
 $
 4.2
 $
 1,546.5
 $
 $
 7,375.3
 $
 ( 1,213.6)
 $
 ( 37.1)
 $
 326.4
 $
 7,901.8

 Comprehensive Income:

 Net Income (Loss)
 —
 —
 —
 —
 714.3
 —
 ( 39.9)
 674.4

 Other comprehensive income, net of tax
 —
 —
 —
 —
 —
 3.5
 —
 3.5

 Dividends:

 Common stock ($ 1.00 per share)

 —
 —
 —
 —
 ( 414.1)
 —
 —
 ( 414.1)

 Preferred stock (See Note 6)

 —
 —
 —
 —
 ( 43.8)
 —
 —
 ( 43.8)

 Noncontrolling Interests:

 Issuance of noncontrolling interests(2)

 —
 —
 —
 809.6
 —
 —
 1,361.1
 2,170.7

 Contributions from noncontrolling interest(3)

 —
 —
 —
 —
 —
 —
 233.2
 233.2

 Distributions to noncontrolling interest
 —
 —
 —
 —
 —
 —

 Stock issuances:

 Equity Units
 0.3
 ( 666.5)
 —
 666.2
 —
 —
 —
 —

 Series A Preferred stock redemption

 —
 ( 393.9)
 —
 —
 —
 —
 —
 ( 393.9)

 Series A Preferred stock redemption premium

 —
 —
 —
 —
 ( 9.8)
 —
 —
 ( 9.8)

 —
 —
 —
 5.9
 —
 —
 —
 5.9

 —
 —
 —
 12.6
 —
 —
 —
 12.6

 401(k) and profit sharing
 —
 —
 —
 9.9
 —
 —
 —
 9.9

 $
 4.5
 $
 486.1
 $
 $
 8,879.5
 $
 ( 967.0)
 $
 ( 33.6)
 $
 1,866.7
 $
 10,136.3

 Comprehensive Income:

 —
 —
 —
 —
 760.4
 —
 84.3
 844.7

 Other comprehensive income, net of tax
 —
 —
 —
 —
 —
 3.2
 —
 3.2

 Dividends:

 Common stock ($ 1.06 per share)

 —
 —
 —
 —
 ( 483.0)
 —
 —
 ( 483.0)

 Preferred stock (See Note 6)

 —
 —
 —
 —
 ( 8.1)
 —
 —
 ( 8.1)

 Noncontrolling Interests:

 Contributions from noncontrolling interest

 —
 —
 —
 —
 —
 —
 99.5
 99.5

 Distributions to noncontrolling interests

 —
 —
 —
 —
 —
 —
 ( 66.4)
 ( 66.4)

 Stock issuances (redemptions):

 Series B and B-1 Preferred stock redemption

 —
 ( 486.1)
 —
 —
 —
 —
 —
 ( 486.1)

 Series B and B-1 Preferred stock redemption premium

 —
 —
 —
 —
 ( 14.0)
 —
 —
 ( 14.0)

 —
 —
 —
 6.4
 —
 —
 —
 6.4

 —
 —
 —
 26.6
 —
 —
 —
 26.6

 401(k) and profit sharing
 —
 —
 —
 9.2
 —
 —
 —
 9.2

 ATM Program
 0.2
 —
 —
 599.8
 —
 —
 —
 600.0

 $
 4.7
 $
 —
 $
 $
 9,521.5
 $
 ( 711.7)
 $
 ( 30.4)
 $
 1,984.1
 $
 10,668.3

 (1) Series A, Series B and Series C shares had an aggregate liquidation preference of $ 400 M, $ 500 M and $ 863 M, respectively.
 (2) Relates to the NIPSCO Minority Interest Transaction. See Note 4, "Noncontrolling Interests," for additional discussion.
 (3) Contributions from noncontrolling interest is net of transaction costs.

 The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

 STATEMENTS OF CONSOLIDATED STOCKHOLDERS' EQUITY (continued)

 Preferred
 Common

 (in thousands)
 Shares
 Shares
 Treasury
 Outstanding

 Balance as of January 1, 2022

 1,303
 409,266
 ( 3,963)
 405,303

 Issued:

 —
 —

 —
 —

 401(k) and profit sharing plan
 —
 —

 ATM Program
 —
 5,942
 —
 5,942

 Balance as of December 31, 2022
 1,303
 416,106
 ( 3,963)
 412,143

 Issued:

 —
 —

 —
 —

 401(k) and profit sharing plan
 —
 —

 Equity Units(1)

 —
 33,899
 —
 33,899

 Redeemed:

 Equity Units(1)

 ( 863)
 —
 —
 —

 Series A Preferred Stock

 ( 400)
 —
 —
 —

 451,345
 ( 3,963)
 447,382

 Issued:

 —
 —

 —
 —

 401(k) and profit sharing plan
 —
 —

 ATM Program
 —
 21,144
 —
 21,144

 Redeemed:

 Series B and B-1 Preferred Stock

 ( 40)
 —
 —
 —

 —
 473,785
 ( 3,963)
 469,822

 (1)See Note 6, "Equity," for additional information.

 The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

 1. Nature of Operations and Summary of Significant Accounting Policies
 A. Company Structure and Principles of Consolidation. We are an energy holding company incorporated in Delaware and headquartered in Merrillville, Indiana. Our subsidiaries are fully regulated natural gas and electric utility companies serving approximately 3.8 million customers in six states. We generate substantially all of our operating income through these rate-regulated businesses. The consolidated financial statements include the accounts of us, our majority-owned subsidiaries, and VIEs of which we are the primary beneficiary after the elimination of all intercompany accounts and transactions.
 B. Use of Estimates. The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
 C. Cash, Cash Equivalents and Restricted Cash. We consider all highly liquid investments with original maturities of three months or less to be cash equivalents. We report amounts deposited in brokerage accounts for margin requirements as restricted cash. In addition, we have amounts deposited in trusts to satisfy requirements for the provision of various property, liability, workers compensation, and long-term disability insurance, and holdbacks related to certain joint venture development agreements which is classified as restricted cash on the Consolidated Balance Sheets and disclosed with cash and cash equivalents on the Statements of Consolidated Cash Flows.
 D. Accounts Receivable and Unbilled Revenue. Accounts receivable on the Consolidated Balance Sheets includes both billed and unbilled amounts. Unbilled amounts of accounts receivable relate to a portion of a customer's consumption of gas or electricity from their last cycle billing date through the last day of the month (balance sheet date). Factors taken into consideration when estimating unbilled revenue include historical usage, customer rates, weather and reasonable and supportable forecasts. Accounts receivable fluctuates from year to year depending in large part on weather impacts and price volatility. Our accounts receivable on the Consolidated Balance Sheets include unbilled revenue, less reserves. The reserve for uncollectible receivables is our best estimate of the amount of probable credit losses in the existing accounts receivable. We determined the reserve based on historical collection experience, current market conditions and reasonable and supportable forecasts. Account balances are charged against the allowance when it is anticipated the receivable will not be recovered. Refer to Note 3, "Revenue Recognition," for additional information on customer-related accounts receivable, including amounts related to unbilled revenues.
 E. Investments in Debt Securities. Our investments in debt securities are carried at fair value and are designated as available-for-sale. These investments are included within "Available-for-sale debt securities" on the Consolidated Balance Sheets. Unrealized gains and losses, net of deferred income taxes, are recorded to accumulated other comprehensive income or loss. At each reporting period these investments are qualitatively and quantitatively assessed to determine whether a decline in fair value below the amortized cost basis has resulted from a credit loss or other factors. Impairments related to credit loss are recorded through an allowance for credit losses. Impairments that are not related to credit losses are included in other comprehensive income and are reflected in the Statements of Consolidated Income. No material impairment charges were recorded for the years ended December 31, 2024, 2023 or 2022. Refer to Note 14, "Fair Value," for additional information.
 F. Basis of Accounting for Rate-Regulated Subsidiaries. Rate-regulated subsidiaries account for and report assets and liabilities consistent with the economic effect of the way in which regulators establish rates, if the rates established are designed to recover the costs of providing the regulated service and it is probable that such rates can be billed and collected. Certain expenses and credits subject to utility regulation or rate determination that would normally be reflected in income for non-regulated entities are deferred on the Consolidated Balance Sheets and are later recognized in income as the related amounts are included in customer rates and recovered from or refunded to customers.
 We continually evaluate whether or not our operations are within the scope of ASC 980 and rate regulations. As part of that analysis, we evaluate probability of recovery for our regulatory assets. In management's opinion, our regulated subsidiaries will be subject to regulatory accounting for the foreseeable future. Refer to Note 12, "Regulatory Matters," for additional information.
 G. Plant and Other Property and Related Depreciation and Maintenance. Property, plant and equipment (principally utility plant) is stated at cost. Our rate-regulated subsidiaries record depreciation using composite rates on a straight-line basis over the remaining service lives of the electric, gas and common properties, as approved by the appropriate regulators.

 Non-utility property, consisting of renewable generation assets owned by JVs of which we are the primary beneficiary and certain retired regulatory assets described below, is generally depreciated over the life of the associated assets. Refer to Note 9, "Property, Plant and Equipment," for additional information related to depreciation expense.
 For rate-regulated companies where provided for in rates, AFUDC is capitalized on all classes of property except organization costs, land, autos, office equipment, tools and other general property purchases. The allowance is applied to construction costs for that period of time between the date of the expenditure and the date on which such project is placed in service. Our consolidated pre-tax rate for AFUDC was 4.8 % in 2024, 3.9 % in 2023 and 3.4 % in 2022.
 Generally, our subsidiaries follow the practice of charging maintenance and repairs, including the cost of removal of minor items of property, to expense as incurred. When our subsidiaries retire regulated property, plant and equipment, original cost plus the cost of retirement, less salvage value, is charged to accumulated depreciation. However, when it becomes probable a regulated asset will be retired substantially in advance of its original expected useful life or is abandoned, the cost of the asset and the corresponding accumulated depreciation is recognized as a separate asset. If the asset is still in operation, the gross amounts are classified as "Non-Utility and Other " as described in Note 9, "Property, Plant and Equipment." If the asset is no longer operating but still subject to recovery, the net amount is classified in "Regulatory assets" on the Consolidated Balance Sheets. If we are able to recover a full return of and on investment, the carrying value of the asset is based on historical cost. If we are not able to recover a full return on investment, a loss on impairment is recognized to the extent the net book value of the asset exceeds the present value of future revenues discounted at the incremental borrowing rate.
 External and internal costs associated with on-premise computer software developed for internal use are capitalized. Capitalization of such costs commences upon the completion of the preliminary stage of each project. Once the installed software is ready for its intended use, such capitalized costs are amortized on a straight-line basis generally over a period of five years. External and internal up-front implementation costs associated with cloud computing arrangements that are service contracts are deferred on the Consolidated Balance Sheets, with the associated internal-use software capitalized to plant if the we have a contractual right to take possession of the software at any time during the hosting period without significant penalty and it is feasible for us to either run the software on our own hardware or contract with another party unrelated to the vendor to host the software. Once the installed software is ready for its intended use, such deferred costs are amortized on a straight-line basis to "Operation and maintenance," over the minimum term of the contract plus contractually-provided renewal periods that are reasonably expected to be exercised.
 H. Goodwill and Other Intangible Assets. Substantially all of our goodwill relates to the excess of cost over the fair value of the net assets acquired in the Columbia acquisition on November 1, 2000. We test our goodwill for impairment annually as of May 1, or more frequently if events and circumstances indicate that goodwill might be impaired. Fair value of our reporting units is determined using a combination of income and market approaches. See Note 10, "Goodwill," for additional information.
 I. Accounts Receivable Transfer Programs. Certain of our subsidiaries have agreements with third parties to transfer certain accounts receivable without recourse. These transfers of accounts receivable are accounted for as secured borrowings. The entire gross receivables balance remains on the December 31, 2024 and 2023 Consolidated Balance Sheets. When amounts are securitized, the short-term debt is recorded in the amount of proceeds received from the transferees involved in the transactions. Refer to Note 7, "Short-Term Borrowings," for further information.
 J. Gas Cost and Fuel Adjustment Clause. Our regulated subsidiaries defer most differences between gas and fuel purchase costs and the recovery of such costs in revenues and adjust future billings for such deferrals on a basis consistent with applicable state-approved tariff provisions. These deferred balances are recorded as "Regulatory assets" or "Regulatory liabilities," as appropriate, on the Consolidated Balance Sheets. Refer to Note 12, "Regulatory Matters," for additional information.
 K. Gas Storage and Other Inventories. Both the LIFO inventory methodology and the weighted average cost methodology are used to value natural gas in storage, as approved by regulators for all of our regulated subsidiaries. Inventory valued using LIFO was $ 43.8 million and $ 43.9 million at December 31, 2024 and 2023, respectively. Based on the average cost of gas using the LIFO method, the estimated replacement cost of gas in storage was less than the stated LIFO cost by $ 12.8 million at December 31, 2024 and was less than the stated LIFO cost by $ 22.5 million at December 31, 2023. As all LIFO inventory costs are collected from customers through our rate-regulated subsidiaries, no inventory impairment has been recorded. Gas inventory valued using the weighted average cost methodology was $ 135.8 million at December 31, 2024 and $ 222.0 million at December 31, 2023.

 Electric production fuel is valued using the weighted average cost inventory methodology, as approved by NIPSCO's regulator.
 Materials and supplies are valued using the weighted average cost inventory methodology. Materials and supplies are charged to expense or capitalized to property, plant and equipment when issued.
 L. Accounting for Exchange and Balancing Arrangements of Natural Gas. Our Columbia Operations and NIPSCO Operations segment enters into balancing and exchange arrangements of natural gas as part of its operations and off-system sales programs. We record a receivable or payable for any of our respective cumulative gas imbalances, as well as for any gas inventory borrowed or lent under an exchange agreement. Exchange gas is valued based on individual regulatory jurisdiction requirements (for example, historical spot rate, spot at the beginning of the month). These receivables and payables are recorded as "Exchange gas receivable" or "Exchange gas payable" on our Consolidated Balance Sheets, as appropriate.
 M. Accounting for Risk Management Activities. We account for our derivatives and hedging activities in accordance with ASC 815. We recognize all derivatives as either assets or liabilities on the Consolidated Balance Sheets at fair value, unless such contracts are exempted as a normal purchase normal sale under the provisions of the standard. The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and resulting designation.
 We do not offset the fair value amounts recognized for any of our derivative instruments against the fair value amounts recognized for the right to reclaim cash collateral or obligation to return cash collateral for derivative instruments executed with the same counterparty under a master netting arrangement. See Note 13, "Risk Management Activities," for additional information.
 N. Income Taxes and Investment Tax Credits. Under the asset and liability method, deferred income taxes are provided for the tax consequences of temporary differences by applying enacted statutory tax rates applicable to future years to differences between the financial statement carrying amount and the tax basis of existing assets and liabilities. Investment tax credits associated with regulated operations are deferred and amortized as a reduction to income tax expense over the estimated useful lives of the related properties. Furthermore, the tax basis of the asset is reduced by 50% of the ITCs received, resulting in a net deferred tax asset.
 To the extent certain deferred income taxes of the regulated companies are recoverable or payable through future rates, regulatory assets and liabilities have been established. Regulatory assets for income taxes are primarily attributable to property-related tax timing differences for which deferred taxes had not been provided in the past when regulators did not recognize such taxes as costs in the rate-making process. Regulatory liabilities for income taxes are primarily attributable to the regulated companies' obligation to refund to ratepayers deferred income taxes provided at rates higher than the current Federal income tax rate. Such property-related amounts are credited to ratepayers using either the average rate assumption method or the reverse South Georgia method. Non property-related amounts are credited to ratepayers consistent with state utility commission direction.
 Pursuant to the Internal Revenue Code and relevant state taxing authorities, we and our subsidiaries file consolidated income tax returns for federal and certain state jurisdictions. We and our subsidiaries are parties to a tax sharing agreement. Income taxes recorded by each party represent amounts that would be owed had the party been separately subject to tax.
 O. Pension Remeasurement. We utilize a third-party actuary for the purpose of performing actuarial valuations of our defined benefit plans. Annually, as of December 31, we perform a remeasurement for our defined benefit plans. Quarterly, we monitor for significant events, and if a significant event is identified, we perform a qualitative and quantitative assessment to determine if the resulting remeasurement would materially impact the NiSource financial statements. If material, an interim remeasurement is performed. See Note 16, "Pension and Other Postemployment Benefits," for additional information.
 P. Environmental Expenditures. We accrue for costs associated with environmental remediation obligations, including expenditures related to asset retirement obligations and cost of removal, when the incurrence of such costs is probable and the amounts can be reasonably estimated, regardless of when the expenditures are actually made. The estimated future expenditures are based on currently enacted laws and regulations, existing technology and estimated site-specific costs where assumptions may be made about the nature and extent of site contamination, the extent of cleanup efforts, costs of alternative cleanup methods and other variables. The liability is adjusted as further information is discovered or circumstances change. The accruals for estimated environmental expenditures are recorded on the Consolidated Balance Sheets in "Other accruals" for short-term portions of these liabilities and "Other noncurrent liabilities and deferred credits" for the respective long-term portions of these liabilities. Rate-regulated subsidiaries applying regulatory accounting establish regulatory assets on the Consolidated Balance

 Sheets to the extent that future recovery of environmental remediation costs is probable through the regulatory process. Refer to Note 11, "Asset Retirement Obligations," and Note 19, "Other Commitments and Contingencies," for further information.
 Q. Excise Taxes. As an agent for some state and local governments, we invoice and collect certain excise taxes levied by state and local governments on customers and record these amounts as liabilities payable to the applicable taxing jurisdiction. Such balances are presented within "Other accruals" on the Consolidated Balance Sheets. These types of taxes collected from customers, comprised largely of sales taxes, are presented on a net basis affecting neither revenues nor cost of sales. We account for excise taxes for which we are liable by recording a liability for the expected tax with a corresponding charge to "Other taxes" expense on the Statements of Consolidated Income.
 R. Accrued Insurance Liabilities. We accrue for insurance costs related to workers compensation, automobile, property, general and employment practices liabilities based on the most probable value of each claim. In general, claim values are determined by professional, licensed loss adjusters who consider the facts of the claim, anticipated indemnification and legal expenses, and respective state rules. Claims are reviewed by us at least quarterly and an adjustment is made to the accrual based on the most current information.

 S. Noncontrolling Interest. We maintain a controlling financial interest in certain of our less than wholly owned subsidiaries. We consolidate these subsidiaries as either voting interest entities or VIEs and present the third-party investors' portion of our net income (loss), net assets and comprehensive income (loss) as noncontrolling interest. Noncontrolling interest is included as a component of equity on the Consolidated Balance Sheet.
 On December 31, 2023, the NIPSCO Minority Interest Transaction closed and a 19.9 % equity interest in NIPSCO Holdings II, the sole owner of NIPSCO, was issued to an affiliate of Blackstone. NIPSCO Holdings II does not meet the criteria of a VIE and instead is consolidated under the voting interest model in accordance with ASC 810 as we maintain control through a majority interest in NIPSCO Holdings II. Refer to Note 4, "Noncontrolling Interests," for further discussion on the NIPSCO Minority Interest Transaction.
 We fund a portion of our renewable generation assets through JVs with tax equity partners. We consolidate these JVs in accordance with ASC 810 as they are VIEs in which we hold a variable interest, and we control decisions that are significant to the JVs' ongoing operations and economic results (i.e., we are the primary beneficiary).
 These JVs are subject to profit sharing arrangements in which the allocation of the JVs' cash distributions and tax benefits to members is based on factors other than members' relative ownership percentages. As such, we utilize the HLBV method to allocate proceeds to each partner at the balance sheet date based on the liquidation provisions of the related JV's operating agreement and adjust the amount of the VIE's net income attributable to us and the noncontrolling tax equity member during the period.
 In each reporting period, the application of HLBV to our consolidated VIEs results in a difference between the amount of profit from the consolidated JVs and the amount included in regulated rates. As discussed above in "F. Basis of Accounting for Rate-Regulated Subsidiaries," we are subject to the accounting and reporting requirements of ASC 980. In accordance with these principles, we recognize a regulatory liability or asset for amounts representing the timing difference between the profit earned from the JVs and the amount included in regulated rates to recover our approved investments in consolidated JVs. The amounts recorded in income will ultimately reflect the amount allowed in regulated rates to recover our investments over the useful life of the projects. The offset to the regulatory liability or asset associated with our renewable investments included in regulated rates is recorded in "Depreciation expense" on the Statements of Consolidated Income.

 2. Recent Accounting Pronouncements
 Recently Issued Accounting Pronouncements
 In November 2024, the FASB issued ASU 2024-03, Income Statement—Reporting Comprehensive Income—Expense Disaggregation Disclosures (Subtopic 220-40). This pronouncement requires disaggregated disclosure of income statement expenses for public business entities. The ASU requires disclosure in tabular format of disaggregation of relevant expense captions presented on the income statement by certain natural expense categories with certain related qualitative disclosures within the notes to the financial statements. The ASU does not change the expense captions an entity presents on the income

 statement. The ASU is effective for fiscal years beginning after December 15, 2026 and interim reporting periods beginning after December 15, 2027. We are currently evaluating the impacts this amendment will have on our required disclosures.

 In December 2023, the FASB issued ASU 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures. This pronouncement enhances required income tax disclosures. The pronouncement will require disclosure of specific categories and reconciling items included in the rate reconciliation, disaggregation between federal, state and local income taxes paid, and disclosure of income taxes paid by jurisdictions over a certain threshold. Additionally, the pronouncement eliminates certain required disclosures related to unrecognized tax benefits. This ASU is effective for annual periods beginning after December 15, 2024, with early adoption permitted, and is to be applied on a prospective basis with retrospective application permitted. We will implement and provide the required disclosures beginning in 2025.
 Recently Adopted Accounting Pronouncements
 In November 2023, the FASB issued ASU 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures. This pronouncement enhances annual and interim disclosure requirements over reportable segments, primarily through enhanced disclosures about significant segment expenses. Specifically, the pronouncement requires disclosure of significant segment expenses that are regularly provided to the Chief Operating Decision Maker ("CODM") and included within each reported measure of segment profit or loss, disclosure of an amount for other segment items representing the difference between segment revenue and segment expenses already disclosed, disclosure of all required annual disclosures for interim periods and disclosure of title and position of the CODM and how the CODM uses reported measures. The pronouncement also allows for more than one measure of segment profit if the CODM uses more than one measure in assessing segment performance. This pronouncement is effective for annual periods beginning after December 15, 2023 and interim periods within fiscal years beginning after December 15, 2024. The Company adopted this pronouncement as of December 31, 2024 with retrospective application and updated its disclosures to include significant expenses regularly provided to the CODM, the CODM's title and how the CODM utilizes reported measures. See Note 21, "Business Segment Information" for further discussion.

 3. Revenue Recognition
 Customer Revenues. Substantially all of our revenues are tariff-based. Under ASC 606, the recipients of our utility service meet the definition of a customer, while the operating company tariffs represent an agreement that meets the definition of a contract, which creates enforceable rights and obligations. Customers in certain of our jurisdictions participate in programs that allow for a fixed payment each month regardless of usage. Payments received that exceed the value of gas or electricity actually delivered are recorded as a liability and presented in "Customer deposits and credits" on the Consolidated Balance Sheets. Amounts in this account are reduced and revenue is recorded when customer usage exceeds payments received.
 We have identified our performance obligations created under tariff-based sales as 1) the commodity (natural gas or electricity, which includes generation and capacity) and 2) delivery. These commodities are sold and / or delivered to and generally consumed by customers simultaneously, leading to satisfaction of our performance obligations over time as gas or electricity is delivered to customers. Due to the at-will nature of utility customers, performance obligations are limited to the services requested and received to date. Once complete, we generally maintain no additional performance obligations.
 Transaction prices for each performance obligation are generally prescribed by each operating company's respective tariff. Rates include provisions to adjust billings for fluctuations in fuel and purchased power costs and cost of natural gas. Revenues are adjusted for differences between actual costs, subject to reconciliation, and the amounts billed in current rates. Under or over recovered revenues related to these cost recovery mechanisms are included in "Regulatory assets" or "Regulatory liabilities" on the Consolidated Balance Sheets and are recovered from or returned to customers through adjustments to tariff rates. As we provide and deliver service to customers, revenue is recognized based on the transaction price allocated to each performance obligation. Distribution revenues are generally considered daily or "at-will" contracts as customers may cancel their service at any time (subject to notification requirements), and revenue generally represents the amount we are entitled to bill customers.
 In addition to tariff-based sales, our gas distribution in both our Columbia Operations and NIPSCO Operations segments enters into balancing and exchange arrangements of natural gas as part of our operations and off-system sales programs. Performance obligations for these types of sales include transportation and storage of natural gas and can be satisfied at a point in time or over a period of time, depending on the specific transaction. For those transactions that span a period of time, we record a

 receivable or payable for any cumulative gas imbalances, as well as for any gas inventory borrowed or lent under a gas distribution operations exchange agreement.
 Revenue Disaggregation and Reconciliation. We disaggregate revenue from contracts with customers based upon reportable segment, as well as by customer class. As of January 1, 2024, we have changed our reportable segments from Gas Distribution Operations and Electric Operations to Columbia Operations and NIPSCO Operations. Our historical segment disclosures have been recast to be consistent with the current presentation. For additional information see Note 21, "Business Segment Information".
 The Columbia Operations segment provides regulated natural gas service and transportation for residential, commercial and industrial customers in Ohio, Pennsylvania, Virginia, Kentucky, and Maryland. The NIPSCO Operations segment provides regulated gas and electric service in northern Indiana for residential, commercial and industrial customers.
 Other Revenues. As permitted by accounting principles generally accepted in the United States, regulated utilities have the ability to earn certain types of revenue that are outside the scope of ASC 606. These revenues primarily represent revenue earned under alternative revenue programs. Alternative revenue programs represent regulator-approved mechanisms that allow for the adjustment of billings and revenue for certain approved programs. We maintain a variety of these programs, including demand side management initiatives that recover costs associated with the implementation of energy efficiency programs, as well as normalization programs that adjust revenues for the effects of weather or other external factors. Additionally, we maintain certain programs with future test periods that operate similarly to FERC formula rate programs and allow for recovery of costs incurred to replace aging infrastructure. When the criteria to recognize alternative revenue have been met, we establish a regulatory asset and present revenue from alternative revenue programs on the Statements of Consolidated Income as "Other revenues". When amounts previously recognized under alternative revenue accounting guidance are billed, we reduce the regulatory asset and record a customer account receivable.
 The tables below reconcile revenue disaggregation by customer class to segment revenue, as well as to revenues reflected on the Statements of Consolidated Income:

 Year Ended December 31, 2024 (in millions)

 Total

 Gas Distribution

 $
 1,833.8
 $
 531.4
 $
 —
 $
 2,365.2

 580.3
 199.2
 —
 779.5

 144.2
 79.0
 —
 223.2

 Off-system
 42.6
 —
 —
 42.6

 1.2
 —
 —
 1.2

 26.3
 15.4
 —
 41.7

 $
 2,628.4
 $
 825.0
 $
 —
 $
 3,453.4

 Electric Generation and Power Delivery

 $
 —
 $
 649.9
 $
 —
 $
 649.9

 —
 620.4
 —
 620.4

 —
 499.1
 —
 499.1

 —
 38.3
 —
 38.3

 Public Authority

 —
 8.1
 —
 8.1

 —
 13.7
 —
 13.7

 $
 —
 $
 1,829.5
 $
 —
 $
 1,829.5

 Total Customer Revenues(2)

 2,628.4
 2,654.5
 —
 5,282.9

 Other Revenues(3)

 74.8
 96.5
 0.9
 172.2

 Total Operating Revenues
 $
 2,703.2
 $
 2,751.0
 $
 0.9
 $
 5,455.1

 (1)Amounts included in Columbia Operations are primarily related to earnings sharing mechanisms and late fees. Amounts included in NIPSCO Operations are primarily related to revenue refunds, public repairs and property rentals.
 (2)Customer revenue amounts exclude intersegment revenues. See Note 21, "Business Segment Information," for discussion of intersegment revenues.

 (3)Amounts included in Columbia Operations primarily relate to weather normalization adjustment mechanisms. Amounts included in NIPSCO Operations primarily relate to weather normalization adjustment mechanisms, MISO multi-value projects and revenue from non-jurisdictional transmission assets.

 Year Ended December 31, 2023 (in millions)

 Total

 Gas Distribution

 $
 1,827.5
 $
 635.0
 $
 —
 $
 2,462.5

 598.9
 249.0
 —
 847.9

 139.0
 87.0
 —
 226.0

 Off-system
 60.6
 —
 —
 60.6

 1.6
 —
 —
 1.6

 33.4
 14.8
 —
 48.2

 2,661.0
 985.8
 —
 3,646.8

 Electric Generation and Power Delivery

 —
 583.9
 —
 583.9

 —
 578.1
 —
 578.1

 —
 474.1
 —
 474.1

 —
 32.0
 —
 32.0

 Public Authority

 —
 11.5
 —
 11.5

 —
 21.4
 —
 21.4

 —
 1,701.0
 —
 1,701.0

 Total Customer Revenues(2)

 $
 2,661.0
 $
 2,686.8
 $
 —
 $
 5,347.8

 Other Revenues(3)

 72.9
 83.9
 0.8
 157.6

 Total Operating Revenues
 $
 2,733.9
 $
 2,770.7
 $
 0.8
 $
 5,505.4

 (1)Amounts included in Columbia Operations are primarily related to earnings sharing mechanisms and late fees. Amounts included in NIPSCO Operations are primarily related to late fees, property rentals, revenue refunds, and adjustments.
 (2)Customer revenue amounts exclude intersegment revenues. See Note 21, "Business Segment Information," for discussion of intersegment revenues.
 (3)Amounts included in Columbia Operations primarily related to weather normalization adjustment mechanisms. Amounts included in NIPSCO Operations primarily related to MISO multi-value projects and revenue from non-jurisdictional transmission assets.

 Year Ended December 31, 2022 (in millions)

 Total

 Gas Distribution

 $
 1,918.2
 $
 691.5
 $
 —
 $
 2,609.7

 672.2
 267.4
 —
 939.6

 135.5
 85.1
 —
 220.6

 Off-system
 192.9
 —
 —
 192.9

 2.1
 —
 —
 2.1

 27.3
 10.9
 —
 38.2

 $
 2,948.2
 $
 1,054.9
 $
 —
 $
 4,003.1

 Electric Generation and Power Delivery

 $
 —
 $
 592.4
 $
 —
 $
 592.4

 —
 571.0
 —
 571.0

 —
 560.6
 —
 560.6

 —
 13.5
 —
 13.5

 Public Authority
 —
 12.1
 —
 12.1

 —
 —

 $
 —
 $
 1,735.5
 $
 —
 $
 1,735.5

 Total Customer Revenues(2)

 $
 2,948.2
 $
 2,790.4
 $
 —
 $
 5,738.6

 Other Revenues(3)

 3.7
 95.8
 12.5
 112.0

 Total Operating Revenues
 $
 2,951.9
 $
 2,886.2
 $
 12.5
 $
 5,850.6

 (1)Amounts included in Columbia Operations are primarily related to earnings share mechanisms and late fees. Amounts included in NIPSCO Operations are primarily related to revenue trackers, late fees and property rentals.2.1
 (2)Customer revenue amounts exclude intersegment revenues. See Note 21, "Business Segment Information," for discussion of intersegment revenues.
 (3)Amounts included in Columbia Operations primarily related to weather normalization adjustment mechanisms. Amounts included in NIPSCO Operations primarily related to MISO multi-value projects and revenue from non-jurisdictional transmission assets. Amounts included in Corporate and Other primarily related to the Transition Services Agreement entered into in connection with the sale of the Massachusetts Business.

 Customer Accounts Receivable. Accounts receivable on our Consolidated Balance Sheets includes both billed and unbilled amounts, as well as certain amounts that are not related to customer revenues. Unbilled amounts of accounts receivable relate to a portion of a customer's consumption of gas or electricity from the date of their last cycle billing through the last day of the month (balance sheet date). Factors taken into consideration when estimating unbilled revenue include historical usage, customer rates, and weather. A significant portion of our operations are subject to seasonal fluctuations in sales. During the heating season, primarily from November through March, revenues and receivables from gas sales are more significant than in other months. The opening and closing balances of customer receivables for the year ended December 31, 2024, are presented in the table below. We had no significant contract assets or liabilities during the period. Additionally, we have not incurred any significant costs to obtain or fulfill contracts.

 Customer Accounts Receivable, Billed (less reserve)
 Customer Accounts Receivable, Unbilled (less reserve)

 $
 479.4
 $
 337.6

 525.1
 408.1

 Utility revenues are billed to customers monthly on a cycle basis. We expect that substantially all customer accounts receivable will be collected following customer billing, as this revenue consists primarily of periodic, tariff-based billings for service and usage. We maintain common utility credit risk mitigation practices, including requiring deposits and actively pursuing collection of past due amounts. Our regulated operations also utilize certain regulatory mechanisms that facilitate recovery of bad debt costs within tariff-based rates, which provides further evidence of collectibility. It is probable that substantially all of the consideration to which we are entitled from customers will be collected upon satisfaction of performance obligations.

 Allowance for Credit Losses. To evaluate for expected credit losses, customer account receivables are pooled based on similar risk characteristics, such as customer type, geography, payment terms, and related macro-economic risks. Expected credit losses are established using a model that considers historical collections experience, current information, and reasonable and supportable forecasts. Internal and external inputs are used in our credit model including, but not limited to, energy consumption trends, revenue projections, actual charge-offs data, recoveries data, shut-offs, customer delinquencies, final bill data, and inflation. We continuously evaluate available information relevant to assessing collectability of current and future receivables. We evaluate creditworthiness of specific customers periodically or following changes in facts and circumstances. When we become aware of a specific commercial or industrial customer's inability to pay, an allowance for expected credit losses is recorded for the relevant amount. We also monitor other circumstances that could affect our overall expected credit losses including, but not limited to, creditworthiness of overall population in service territories, adverse conditions impacting an industry sector, and current economic conditions.
 At each reporting period, we record expected credit losses to an allowance for credit losses account. When deemed to be uncollectible, customer accounts are written-off. A rollforward of our allowance for credit losses as of December 31, 2024 and December 31, 2023, are presented in the tables below:

 Total

 Balance as of January 1, 2024

 $
 10.2
 $
 11.9
 $
 0.8
 $
 22.9

 Current period provisions
 26.7
 12.1
 —
 38.8

 Write-offs charged against allowance
 ( 43.9)
 ( 11.0)
 ( 0.8)
 ( 55.7)

 Recoveries of amounts previously written off
 16.8
 0.9
 —
 17.7

 $
 9.8
 $
 13.9
 $
 —
 $
 23.7

 Total

 Balance as of January 1, 2023

 $
 11.1
 $
 12.0
 $
 0.8
 $
 23.9

 Current period provisions
 28.3
 11.5
 —
 39.8

 Write-offs charged against allowance
 ( 49.2)
 ( 12.4)
 —
 ( 61.6)

 Recoveries of amounts previously written off
 20.0
 0.8
 —
 20.8

 $
 10.2
 $
 11.9
 $
 0.8
 $
 22.9

 4. Noncontrolling Interests
 Variable Interest Entities. A VIE is an entity in which the controlling interest is determined through means other than a majority voting interest. Refer to Note 1, "Nature of Operations and Summary of Significant Accounting Policies - S. Noncontrolling Interest," for information on our accounting policy for the VIEs.
 NIPSCO is the managing member and operator of two wind JVs, Rosewater and Indiana Crossroads Wind, which have 102 MW and 302 MW of nameplate capacity, respectively. NIPSCO is also a managing member and operator of two solar JVs, Indiana Crossroads Solar and Dunns Bridge I, which have a nameplate capacity of 200 MW and 265 MW, respectively. We have determined that these JVs are VIEs. NIPSCO controls decisions that are significant to these entities' ongoing operations and economic results. Therefore, we have concluded that NIPSCO is the primary beneficiary and have consolidated all four entities.
 Members of each respective JV include NIPSCO (who is the managing member) and a tax equity partner. Earnings, tax attributes and cash flows are allocated to both NIPSCO and the tax equity partner in varying percentages by category and over the life of the partnership. NIPSCO and each tax equity partner contributed cash to the respective JV. Once the tax equity partner has earned their negotiated rate of return and the JV has reached a stated contractual date, NIPSCO has the option to purchase the remaining interest in the respective JV from the tax equity partner. NIPSCO has an obligation to purchase 100 % of the electricity generated by each commercially operational JV.

 We did not provide any financial or other support during the year that was not contractually required.

 Our Consolidated Balance Sheets included the following assets and liabilities associated with VIEs.

2024
2023

 Net Property, Plant and Equipment
 $
 1,323.8
 $
 1,369.8

 Current assets
 65.0
 63.6

 Total assets(1)(2)

 1,388.8
 1,433.4

 Current liabilities
 53.7
 68.3

 Asset retirement obligations
 58.3
 55.7

 Finance lease obligations

 40.4
 —

 Total liabilities(1)(2)

 $
 152.4
 $
 124.0

 (1)The assets of each VIE represent assets of a consolidated VIE that can be used only to settle obligations of the respective consolidated VIE. The creditors of the liabilities of the VIEs do not have recourse to the general credit of the primary beneficiary.
 (2) In addition to the amounts disclosed above there is a de minimis amount of other noncurrent assets and liabilities at Rosewater as of December 31, 2024.

 Voting Interest Entities. On December 31, 2023, we consummated the NIPSCO Minority Interest Transaction for a capital contribution of $ 2.16 billion in cash. The difference between the $ 2.16 billion consideration received and the $ 1.36 billion carrying value of the noncontrolling interest claim on net assets was recorded to additional paid-in capital, net of $ 54.7 million in transaction costs and a $ 63.5 million income tax benefit. We retain a controlling financial interest in NIPSCO Holdings II and its subsidiaries and consolidate their financial results. For the twelve months ending December 31, 2024 we received $ 99.5 million of contributions, and we made $ 50.3 million of distributions, to our NIPSCO minority interest holders. See Note 19, "Other Commitments and Contingencies - E. Other Matters," for a detailed discussion of the NIPSCO Holdings II LLC Agreement and governance structure.

 5. Earnings Per Share
 The calculations of basic and diluted EPS are based on the weighted average number of shares of common stock and potential common stock outstanding during the period. Diluted EPS includes the incremental effects of the various long-term incentive compensation plans and ATM forward sale agreements under the treasury stock method when the impact would be dilutive. For the purposes of determining diluted EPS, for the twelve months ended December 31, 2023 and 2022, the shares underlying the purchase contracts included within the Equity Units were included in the calculation of potential common stock outstanding using the if-converted method under US GAAP and we assumed share settlement of the remaining purchase contract payment balance from our Equity Units based on the average share price during the period. This method assumes conversion at the beginning of the reporting period, or at time of issuance, if later. The purchase contracts were settled on December 1, 2023. For the purchase contracts, the number of shares of our common stock that would have been issuable at the end of each reporting period prior to the settlement date were reflected in the denominator of our diluted EPS calculation. A numerator adjustment was reflected in the calculation of diluted EPS for interest expense incurred in 2023 and 2022, net of tax, related to the purchase contracts.

 We adopted ASU 2020-06 on January 1, 2022, which required us to assume share settlement of the remaining purchase contract payment balance from our Equity Units based on the average share price during the period.
 The shares underlying the Series C Mandatory Convertible Preferred Stock included within the Equity Units were contingently convertible as the conversion was contingent on a successful remarketing. Contingently convertible shares where conversion was not tied to a market price trigger were excluded from the calculation of diluted EPS until such time as the contingency had been resolved under the if-converted method. The unsuccessful remarketing resolved the contingency and no shares were reflected in the denominator for the years ended December 31, 2023 and 2022, for the calculation of diluted EPS.
 We began using the two-class method of computing earnings per share in 2023 because we have participating securities in the form of non-vested restricted stock units with a non-forfeitable right to dividend equivalents, for which vesting is predicated solely on the passage of time. The calculation of earnings per share using the two-class method excludes income attributable to these participating securities from the numerator and excludes the dilutive impact of those shares from the denominator.

 During 2022, we had no outstanding securities other than common and preferred stock, which required holders' participation in dividends and earnings; therefore, we were not required to calculate EPS under the two-class method. Basic net income per share is computed by dividing net income available to common shareholders by the weighted-average number of shares of common stock outstanding during the period. Diluted net income per share is computed by giving effect to all potential shares of common stock, to the extent they are dilutive. Refer to Note 6, "Equity," for additional information.
 The following table presents the calculation of our basic and diluted EPS:

 Year Ended December 31, (in millions, except per share amounts)

 2024
 2023
 2022

 Numerator:

 Net Income Available to Common Shareholders
 $
 739.7
 $
 661.7
 $
 749.0

 Less: Income allocated to participating securities
 1.6
 0.6
 —

 Net Income Available to Common Shareholders - Basic
 $
 738.1
 $
 661.1
 $
 749.0

 Add: Dilutive effect of Equity Units
 —
 1.4
 2.0

 Net Income Available to Common Shareholders - Diluted
 $
 738.1
 $
 662.5
 $
 751.0

 Denominator:

 Average common shares outstanding - Basic
 454.2
 416.1
 407.1

 Dilutive potential common shares:

 Equity Units purchase contracts
 —
 29.8
 30.2

 Equity Units purchase contract payment balance
 —
 0.9
 3.2

 Shares contingently issuable under employee stock plans
 0.9
 0.7
 0.9

 Shares restricted under employee stock plans
 0.3
 0.4
 0.5

 ATM Forward agreements
 0.6
 —
 0.8

 Average Common Shares - Diluted
 456.0
 447.9
 442.7

 Earnings per common share:

 Basic
 $
 1.63
 $
 1.59
 $
 1.84

 Diluted
 $
 1.62
 $
 1.48
 $
 1.70

 6. Equity
 Holders of shares of our common stock are entitled to receive dividends when, as, and if declared by the Board out of funds legally available. The policy of the Board has been to declare cash dividends on a quarterly basis payable on or about the 20th day of February, May, August and November. We have certain debt covenants that could potentially limit the amount of dividends we could pay in order to maintain compliance with these covenants. Refer to Note 8, "Long-Term Debt," for more information. As of December 31, 2024, these covenants did not restrict the amount of dividends that were available to be paid.
 There is no preferred stock outstanding as of December 31, 2024.
 Common and preferred stock activity for 2024, 2023 and 2022 is described further below.
 ATM Program. In February 2024, we entered into eight separate equity distribution agreements pursuant to which we were able to sell up to an aggregate of $ 900.0 million of our common stock.
 In February 2024, under the ATM program, we executed a forward sale agreement, which allowed us to issue a fixed number of shares at a price to be settled in the future. The forward purchaser under our forward sale agreement borrowed 7,757,951 shares from third parties, which the forward purchaser sold, through its affiliated agent, at a weighted average price of $ 25.78 per share. On September 17, 2024 we settled all the shares under the forward sale agreement for $ 199.9 million, based on a net price of $ 25.77 per share.
 In May 2024, under the ATM program, we executed a forward sale agreement, which allowed us to issue a fixed number of shares at a price to be settled in the future. The forward purchaser under our forward sale agreement borrowed 10,390,000 shares from third parties, which the forward purchaser sold, through its affiliated agent, at a weighted average price of $ 28.87 per share. On September 11, 2024 we settled all the shares under the forward sale agreement for $ 299.1 million, based on a net price of $ 28.79 per share.

 In September 2024, under the ATM program, we executed a forward sale agreement, which allowed us to issue a fixed number of shares at a price to be settled in the future. The forward purchaser under our forward sale agreement borrowed 1,495,949 shares from third parties, which the forward purchaser sold, through its affiliated agent, at a weighted average price of $ 34.01 per share. On November 19, 2024 we settled all the shares under the forward sale agreement for $ 50.3 million, based on a net price of $ 33.64 per share.

 In September 2024, under the ATM program, we executed a second forward sale agreement, which allowed us to issue a fixed number of shares at a price to be settled in the future. The forward purchasers under our forward sale agreement borrowed 1,500,000 shares from third parties, which the forward purchaser sold, through its affiliated agent, at a weighted average price of $ 34.32 per share. On November 20, 2024 we settled all the shares under the forward sale agreement for$ 51.0 million, based on a net price of $ 33.99 per share.
 As of December 31, 2024, the ATM program had approximately $ 297.7 million of equity available for issuance. The program expires on December 31, 2025.

 Series A Preferred Stock. During 2023, there were $ 28.25 dividends declared per share for the Series A Preferred Stock.
 On June 15, 2023, we redeemed all 400,000 outstanding shares of Series A Preferred Stock for a redemption price of $ 1,000 per share or $ 400.0 million in total.

 Series B and B-1 Preferred Stock. During 2024 and 2023, dividends declared per share for the Series B Preferred Stock were $ 406.25 and $ 1,625.0, respectively.
 On March 15, 2024, we redeemed all 20,000 outstanding shares of Series B Preferred Stock for a redemption price of $ 25,000 per share and all 20,000 outstanding shares of Series B-1 Preferred Stock for a redemption price of $ 0.01 per share or $ 500.0 million in total. Following the redemption, dividends ceased to accrue on the shares of Series B Preferred Stock, shares of the Series B Preferred Stock and Series B-1 Preferred Stock were no longer deemed outstanding and all rights of the holders of such shares of Series B Preferred Stock and Series B-1 Preferred Stock terminated. In conjunction with the redemption, we recorded a $ 14.0 million preferred stock redemption premium, calculated as the difference between the carrying value on the redemption date of the Series B Preferred Stock and Series B-1 Preferred Stock and the total amount of consideration paid to redeem, which was recorded as a reduction to retained earnings during the first quarter of 2024. We did not recognize an excise tax liability under the IRA in connection with this redemption as we issued common stock in 2024 in excess of the fair value of the Series B Preferred Stock and Series B-1 Preferred Stock redeemed.
 In March 2024, we filed a Certificate of Elimination to our Amended and Restated Certificate of Incorporation with the Secretary of State of Delaware to eliminate from the Amended and Restated Certificate of Incorporation all matters set forth in the Certificate of Designations with respect to the Series B Preferred Stock and the Certificate of Designations with respect to the Series B-1 Preferred Stock. As a result, the 20,000 shares that were previously designated as Series B Preferred Stock and the 20,000 shares that were previously designated as Series B-1 Preferred Stock were returned to the status of authorized but unissued shares of preferred stock, par value $ 0.01 per share, without designation as to series. The Certificate of Elimination does not change the total number of authorized shares of capital stock of NiSource or the total number of authorized shares of preferred stock. We voluntarily delisted the preferred stock from the New York Stock Exchange on March 15, 2024.

 Equity Units. On December 1, 2023, we issued 33,898,837 shares of our common stock under the purchase contract component of the Corporate Units. As of December 1, 2023, each holder of Corporate Units was deemed to have automatically delivered to us the related Series C Mandatory Convertible Preferred Stock that were components of the Corporate Units in full satisfaction of such holder's obligations under the related purchase contract, and all 862,500 shares of Series C Mandatory Convertible Preferred Stock were returned to the status of authorized but unissued preferred stock, par value of $ 0.01 per share, without designation as to series. We voluntarily delisted the Corporate Units from the New York Stock Exchange on December 1, 2023.
 Refer to Note 5, "Earnings Per Share," for additional information regarding our treatment of the Equity Units for diluted EPS.
 On October 21, 2024, we filed a Certificate of Elimination to our Amended and Restated Certificate of Incorporation with the Secretary of State of the State of Delaware to eliminate from the Amended and Restated Certificate of Incorporation all matters set forth in the Certificate of Designations with respect to the Series C Mandatory Convertible Preferred Stock.

 Noncontrolling Interest in Consolidated Subsidiaries. As of December 31, 2024 and 2023, NIPSCO and tax equity partners have completed their cash contributions into the Indiana Crossroads Wind, Rosewater, Indiana Crossroads Solar and Dunns Bridge I JVs. Earnings, tax attributes and cash flows are allocated to both NIPSCO and the respective tax equity partners in varying percentages by category and over the life of the partnership. The tax equity partner's contributions, net of these allocations, is represented as a noncontrolling interest within total equity on the Consolidated Balance Sheets. Refer to Note 4, "Noncontrolling Interests," for more information.
 On December 31, 2023, we consummated the closing of the NIPSCO Minority Interest Transaction and issued a 19.9 % equity interest in NIPSCO Holdings II LLC to BIP in exchange for a capital contribution of $ 2.16 billion in cash. Transaction costs and deferred tax impacts of $ 54.7 million and $ 63.5 million were recorded during the period ending December 31, 2023. Refer to Note 15, "Income Taxes," and Note 19, "Other Commitments and Contingencies - E. Other Matters," in the Notes to the Consolidated Financial Statements for more information on this transaction.

 7. Short-Term Borrowings
 We generate short-term borrowings from our revolving credit facility, commercial paper program, accounts receivable transfer programs, and term credit agreements. Each of these borrowing sources is described further below.
 Revolving Credit Facility. We maintain a revolving credit facility to fund ongoing working capital requirements, including the provision of liquidity support for our commercial paper program, provide for issuance of letters of credit, and also for general corporate purposes. Our revolving credit facility has a program limit of $ 1.85 billion and is comprised of a syndicate of banks. At December 31, 2024 and 2023, we had no outstanding borrowings under this facility.
 Commercial Paper Program. At December 31, 2024 and December 31, 2023, our commercial paper program had a program limit of up to $ 1.85 billion and $ 1.50 billion, respectively. On February 9, 2024, we increased the program limit from $ 1.50 billion to $ 1.85 billion. We had $ 604.6 million and $ 1,061.0 million of commercial paper outstanding with weighted-average interest rates of 4.73 % and 5.65 % as of December 31, 2024 and 2023, respectively.
 Accounts Receivable Transfer Programs. Columbia of Ohio, NIPSCO, and Columbia of Pennsylvania each maintain a receivables agreement whereby they transfer their customer accounts receivables to third party financial institutions through consolidated special purpose entities. The three agreements expire between May 2025 and October 2025 and may be further extended if mutually agreed to by the parties thereto.
 All receivables transferred to third parties are valued at face value, which approximates fair value due to their short-term nature. The amount of the undivided percentage ownership interest in the accounts receivables transferred is determined in part by required loss reserves under the agreements.
 Transfers of accounts receivable are accounted for as secured borrowings resulting in the recognition of short-term borrowings on the Consolidated Balance Sheets. As of December 31, 2024, the maximum amount we could borrow related to our accounts receivable programs is $ 175.0 million.
 We had zero and $ 337.6 million short-term borrowings related to the securitization transactions as of December 31, 2024 and 2023, respectively.
 For the year ended December 31, 2024 and 2023, $ 337.6 million and $ 9.6 million, respectively, was recorded as cash flows used for financing activities related to the change in short-term borrowings due to securitization transactions. For the accounts receivable transfer programs, we pay used facility fees for amounts borrowed, unused commitment fees for amounts not borrowed, and upfront renewal fees. Fees associated with the securitization transactions were $ 1.5 million, $ 2.7 million, and $ 2.5 million for the years ended December 31, 2024, 2023 and 2022, respectively. Columbia of Ohio, NIPSCO and Columbia of Pennsylvania remain responsible for collecting the receivables securitized, and the receivables cannot be transferred to another party. Refer to Note 23, "Interest Expense, Net," for additional information on securitization transaction fees.
 Term Credit Agreements. At December 31, 2023, we had $ 1.0 billion, and $ 650.0 million outstanding under term credit agreements with interest rates of 6.41 % and 6.50 %, respectively. On January 3, 2024, we terminated and repaid in full our $ 1.0 billion and $ 650.0 million term credit agreements with proceeds from the NIPSCO Minority Interest Transaction.

 Items listed above, excluding the term credit agreements, are presented net in the Statements of Consolidated Cash Flows as their maturities are less than 90 days.

 8. Long-Term Debt
 Our long-term debt as of December 31, 2024 and 2023 is as follows:

 Long-term debt type
 Maturity as of December 31, 2024

 Weighted average interest rate (%)
 Outstanding balance as of December 31, (in millions)

 2024
 2023

 Senior notes:

 August 2025
 0.950
 %
 $
 1,250.0
 $
 1,250.0

 May 2027
 3.490
 %

 December 2027
 6.780
 %
 3.0
 3.0

 March 2028
 5.250
 %
 1,050.0
 1,050.0

 July 2029
 5.200
 %
 600.0
 —

 September 2029
 2.950
 %
 750.0
 750.0

 May 2030
 3.600
 %

 February 2031
 1.700
 %
 750.0
 750.0

 June 2033
 5.400
 %
 450.0
 450.0

 April 2034
 5.350
 %
 650.0
 —

 December 2040
 6.250
 %
 152.6
 152.6

 June 2041
 5.950
 %
 347.4
 347.4

 February 2042
 5.800
 %
 250.0
 250.0

 February 2043
 5.250
 %
 500.0
 500.0

 February 2044
 4.800
 %
 750.0
 750.0

 February 2045
 5.650
 %
 500.0
 500.0

 May 2047
 4.375
 %

 March 2048
 3.950
 %
 750.0
 750.0

 June 2052
 5.000
 %
 350.0
 350.0

 Total senior notes
 $
 12,103.0
 $
 10,853.0

 Junior subordinated notes:

 November 2054
 6.950
 %
 500.0
 —

 March 2055
 6.375
 %
 500.0
 —

 Total junior subordinated notes

 $
 $
 —

 Medium term notes:

 May 2027

 7.990
 %
 $
 29.0
 $
 29.0

 NIPSCO
 June 2027 to August 2027

 7.644
 %
 58.0
 58.0

 Columbia of Massachusetts
 December 2025 to February 2028

 6.373
 %
 15.0
 15.0

 Total medium term notes
 $
 102.0
 $
 102.0

 Finance leases:

 NiSource Corporate Services
 January 2025 to September 2027

 3.470
 %
 $
 14.6
 $
 30.5

 NIPSCO
 December 2027 to November 2035

 5.250
 %
 124.3
 61.2

 December 2025 to March 2044

 6.150
 %
 85.6
 90.3

 Columbia of Virginia
 July 2029 to November 2039

 6.190
 %
 15.2
 16.1

 Columbia of Kentucky
 May 2027

 5.360
 %
 0.1
 0.2

 Columbia of Pennsylvania
 July 2027 to May 2035

 4.470
 %
 6.4
 7.1

 Total finance leases
 $
 246.2
 $
 205.4

 Less: Unamortized issuance costs and discounts

 ( 95.5)
 ( 81.1)

 Less: Current portion of long term debt

 ( 1,281.2)
 ( 23.8)

 Total Long-Term Debt
 $
 12,074.5
 $
 11,055.5

 Details of our 2024 long-term debt related activity are summarized below:
 • On March 14, 2024, we completed the issuance and sale of $ 650.0 million of 5.350 % senior unsecured notes maturing in 2034, which resulted in approximately $ 642.6 million of net proceeds after discount and debt issuance costs.

 • On May 16, 2024, we completed the issuance and sale of $ 500.0 million of 6.950 % fixed-to-fixed reset rate junior subordinated notes maturing in 2054, which resulted in approximately $ 493.4 million of net proceeds after debt issuance costs. The subordinated notes bear interest (i) from and including May 16, 2024 to, but excluding, November 30, 2029 at a rate of 6.950 % per annum and (ii) from and including November 30, 2029, during each five-year reset period at a rate per annum equal to the five-year U.S. treasury rate (determined as described in the prospectus supplement dated May 13, 2024, which was filed with the SEC on May 14, 2024) as of the then most recent reset interest determination date plus a spread of 2.451 %, to be reset on each reset date. At our option, we may redeem some or all of the subordinated notes during specified periods, and upon the occurrence of certain ratings or tax events, all as described in the prospectus supplement. In accordance with terms of the subordinated notes, we have the right, from time to time, to defer the payment of interest on the outstanding subordinated notes on one or more occasions for up to ten consecutive years. In the event that we were to exercise such right to defer interest on the subordinated notes, we would not be able to pay cash dividends on the common stock during the periods in which such payments were deferred. The subordinated notes were issued pursuant to a Subordinated Indenture, dated as of May 16, 2024, between us and The Bank of New York Mellon, as trustee, as supplemented by the First Supplemental Indenture thereto, dated as of May 16, 2024.
 • On June 24, 2024, we completed the issuance and sale of $ 600.0 million of 5.200 % senior unsecured notes maturing in 2029, which resulted in approximately $ 593.7 million of net proceeds after discount and debt issuance costs.
 • On September 9, 2024, we completed the issuance and sale of $ 500.0 million of 6.375 % fixed-to-fixed reset rate junior subordinated notes maturing in 2055, which resulted in approximately $ 493.6 million of net proceeds after debt issuance costs. The subordinated notes bear interest (i) from and including September 9, 2024 to, but excluding, March 31, 2035 at a rate of 6.375 % per annum and (ii) from and including March 31, 2035, during each five-year reset period at a rate per annum equal to the five-year U.S. treasury rate (determined as described in the prospectus supplement dated September 3, 2024, which was filed with the SEC on September 4, 2024) as of the then most recent reset interest determination date plus a spread of 2.527 %, to be reset on each reset date. At our option, we may redeem some or all of the subordinated notes during specified periods, and upon the occurrence of certain ratings or tax events, all as described in the prospectus supplement. In accordance with terms of the subordinated notes, we have the right, from time to time, to defer the payment of interest on the outstanding subordinated notes on one or more occasions for up to ten consecutive years. In the event that we were to exercise such right to defer interest on the subordinated notes, we would not be able to pay cash dividends on the common stock during the periods in which such payments were deferred. The subordinated notes were issued pursuant to a Subordinated Indenture, dated as of May 16, 2024, between us and The Bank of New York Mellon, as trustee, as supplemented by the Second Supplemental Indenture thereto, dated as of September 9, 2024.
 Details of our 2023 long-term debt related activity are summarized below:
 • On March 24, 2023, we completed the issuance sale of $ 750.0 million of 5.250 % senior unsecured notes maturing in 2028, which resulted in approximately $ 742.2 million of net proceeds after discount and debt issuance costs.
 • On June 8, 2023, we completed the issuance and sale of $ 300.0 million of 5.250 % senior unsecured notes maturing in 2028 (the "2028 Notes"). The terms of the 2028 Notes, other than the issue date and the price to the public, are identical to the terms of, and constitute as a reopening of, our 5.250 % senior unsecured notes due 2028 issued on March 24, 2023. With the incremental issuance, we now have $ 1.05 billion of 5.250 % senior unsecured notes maturing in 2028. On June 8, 2023, we also completed the issuance and sale of $ 450.0 million of 5.400 % senior unsecured notes maturing in 2033. These issuances resulted in approximately $ 742.5 million of total net proceeds after discount and debt issuance costs.

 See Note 19, "Other Commitments and Contingencies - A. Contractual Obligations," for the outstanding long-term debt maturities at December 31, 2024.
 Unamortized debt expense, premium and discount on long-term debt applicable to outstanding bonds are being amortized over the life of such bonds.

 We are subject to a financial covenant under our revolving credit facility which requires us to maintain a debt to capitalization ratio that does not exceed 70 %. As of December 31, 2024, the ratio was 52.6 %.
 We are also subject to certain other non-financial covenants under the revolving credit facility. Such covenants include a limitation on the creation or existence of new liens on our assets, generally exempting liens on utility assets, purchase money security interests, preexisting security interests and an additional subset of assets equal to $ 200 million. An asset sale covenant generally restricts the sale, conveyance, lease, transfer or other disposition of our assets to those dispositions that are for a price not materially less than fair market of such assets, that would not materially impair our ability to perform obligations under the revolving credit facility, and that together with all other such dispositions, would not have a material adverse effect. The covenant also restricts dispositions to no more than 15 % of our consolidated total assets on December 31, 2022. Additionally, the revolving credit facility requires us to own directly or indirectly at least 70 % of NIPSCO. The revolving credit facility also includes a cross-default provision, which triggers an event of default under the credit facility in the event of an uncured payment default relating to any indebtedness of us or any of our subsidiaries in a principal amount of $ 75.0 million or more.
 Our indentures generally do not contain any financial maintenance covenants. However, our indentures are generally subject to cross-default provisions ranging from uncured payment defaults of $ 5.0 million to $ 50.0 million, and limitations on the incurrence of liens on our assets, generally exempting liens on utility assets, purchase money security interests, preexisting security interests and an additional subset of assets capped at 10 % of our consolidated net tangible assets.

 9. Property, Plant and Equipment
 Our property, plant and equipment on the Consolidated Balance Sheets are classified as follows:

 2024
 2023

 Property, Plant and Equipment

 Gas Distribution Utility

 $
 20,007.2
 $
 18,154.5

 Electric Utility

 8,666.8
 7,907.9

 Corporate
 248.1
 274.2

 Construction Work in Process
 2,084.7
 1,261.1

 JV Renewable Generation Assets(1)

 1,434.2
 1,434.4

 Non-Utility and Other
 1,711.9
 1,450.0

 Total Property, Plant and Equipment
 $
 34,152.9
 $
 30,482.1

 Accumulated Depreciation and Amortization

 Gas Distribution Utility

 $
 ( 4,166.8)
 $
 ( 3,924.4)

 Electric Utility

 ( 2,707.8)
 ( 2,709.5)

 Corporate
 ( 163.4)
 ( 174.2)

 JV Renewable Generation Assets(1)

 ( 110.4)
 ( 64.5)

 Non-Utility and Other
 ( 1,550.6)
 ( 1,334.6)

 Total Accumulated Depreciation and Amortization
 $
 ( 8,699.0)
 $
 ( 8,207.2)

 Net Property, Plant and Equipment
 $
 25,453.9
 $
 22,274.9

 (1)These JV renewable generation assets owned and operated by JVs between NIPSCO and unrelated tax equity partners represent Non-Utility Property, are depreciated straight-line over 30 years and are part of our NIPSCO Operations segment. Refer to Note 4, "Noncontrolling Interests," for additional information.

 The weighted average depreciation provisions for utility plant, as a percentage of the original cost, for the periods ended December 31, 2024, 2023 and 2022 were as follows:

 2024
 2023
 2022

 3.0
 %
 3.0
 %
 2.7
 %

 2.6
 %
 2.5
 %
 2.4
 %

 We recognized depreciation expense of $ 820.4 million, $ 756.9 million and $ 685.0 million for the years ended 2024, 2023 and 2022, respectively. The 2024, 2023 and 2022, depreciation expense includes $ 58.9 million, $ 12.5 million, and $ 11.0 million

 related to the regulatory deferral of income associated with our JVs. See Note 1, "Nature of Operations and Summary of Significant Accounting Policies - S. Noncontrolling Interest," for additional details.
 Amortization of on-premise Software Costs. We amortized $ 85.2 million, $ 77.5 million and $ 53.1 million in 2024, 2023 and 2022, respectively, related to software recorded as intangible assets. Our unamortized software balance was $ 236.1 million and $ 205.6 million at December 31, 2024 and 2023, respectively.
 Amortization of Cloud Computing Costs. We amortized $ 17.7 million, $ 12.6 million and $ 11.1 million in 2024, 2023 and 2022, respectively, related to cloud computing costs to "Operation and maintenance" expense. Our unamortized cloud computing balance was $ 77.5 million and $ 32.2 million at December 31, 2024 and 2023, respectively.

 10. Goodwill
 Substantially all of our goodwill relates to the excess of cost over the fair value of the net assets acquired in the Columbia acquisition on November 1, 2000. Our goodwill balance was $ 1,485.9 million as of December 31, 2024 and 2023. The majority of our goodwill has been allocated to the Columbia Operations segment.
 For our annual goodwill impairment analysis performed as of May 1, 2024, we completed a quantitative ("step 1") fair value measurement of our reporting units. Fair value of our reporting units was determined based on a weighting of income and market approaches. The income approach calculated discounted cash flows using updated cash flow projections, discount rates and return on equity assumptions. The market approach applied a combination of comparable company multiples and comparable transactions and used the most recent cash flow projections. The test indicated that the fair value of each of the reporting units that are allocated goodwill exceeded their carrying values, indicating that no impairment was necessary.

 11. Asset Retirement Obligations
 We have recognized asset retirement obligations associated with various legal obligations including costs to remove and dispose of certain construction materials located within many of our facilities (including our JV facilities), certain costs to retire pipeline, removal costs for certain underground storage tanks, removal of certain pipelines known to contain PCB contamination, closure costs for certain sites including ash ponds, solid waste management units and a landfill, as well as some other nominal asset retirement obligations. We also have an obligation associated with the decommissioning of our two hydro facilities located in Indiana. These hydro facilities have an indeterminate life, and as such, no asset retirement obligation has been recorded.
 During the fourth quarter of 2024, we continued to evaluate the applicability of revisions to the EPA rule for disposal of CCRs, which was announced in May 2024. As a result, we recorded an increase of $ 149.7 million based on initial assessments of estimated costs to comply with the EPA rule for certain sites. Additional costs will be recorded if they become probable and estimable. These costs are expected to be recoverable through existing and future depreciation rates. See Note 19, "Other Commitments and Contingencies - D. Environmental Matters," for additional information on the legacy CCR rule.
 Changes in our liability for asset retirement obligations for the years 2024 and 2023 are presented in the table below:

 2024
 2023

 Beginning Balance
 $
 553.0
 $
 513.5

 Accretion recorded as a regulatory asset/liability
 25.3
 20.0

 Additions
 189.9
 23.5

 Settlements
 ( 72.5)
 ( 41.6)

 Change in estimated cash flows
 87.5
 37.6

 Ending Balance
 $
 783.2
 $
 553.0

 Certain non-legal costs of removal not yet incurred but have been, and continue to be, included in depreciation rates and collected in the customer rates of the rate-regulated subsidiaries are classified as "Regulatory liabilities" on the Consolidated Balance Sheets.

 12. Regulatory Matters
 Regulatory Assets and Liabilities
 We follow the accounting and reporting requirements of ASC Topic 980, which provides that regulated entities account for and report assets and liabilities consistent with the economic effect of regulatory rate-making procedures when the rates established are designed to recover the costs of providing the regulated service and it is probable that such rates will be charged and collected from customers. Certain expenses and credits subject to utility regulation or rate determination normally reflected in income or expense are deferred on the balance sheet and are recognized in the income statement as the related amounts are included in customer rates and recovered from or refunded to customers. We assess the probability of collection for all of our regulatory assets each period.

 Regulatory assets were comprised of the following items:

 2024
 2023

 Regulatory Assets

 Unrecognized pension and other postretirement benefit costs (see Note 16)

 $
 485.3
 $
 561.6

 Deferred pension and other postretirement benefit costs (see Note 16)

 45.3
 59.7

 Environmental costs (see Note 19-D.)

 42.8
 40.6

 Regulatory effects of accounting for income taxes (see Note 1-N. and Note 15)

 172.0
 163.5

 Under-recovered gas and fuel costs (see Note 1-J.)

 82.3
 12.7

 Depreciation
 214.9
 201.9

 Post-in-service carrying charges
 280.8
 269.9

 Safety activity costs
 203.7
 206.6

 DSM programs
 17.8
 25.0

 Retired coal generating stations
 617.0
 682.0

 Losses on commodity price risk programs (See Note 13)

 6.5
 24.4

 Deferred property taxes
 75.9
 72.3

 Renewable energy investments

 81.3
 60.8

 WAM system filing

 21.5
 —

 Customer assistance programs

 24.4
 —

 Other
 105.8
 79.2

 Total Regulatory Assets
 $
 2,477.3
 $
 2,460.2

 Less: Current Portion
 319.9
 214.3

 Total Noncurrent Regulatory Assets
 $
 2,157.4
 $
 2,245.9

 Regulatory liabilities were comprised of the following items:

 2024
 2023

 Regulatory Liabilities

 Over-recovered gas and fuel costs (see Note 1-J.)

 $
 21.4
 $
 144.5

 Cost of removal (see Note 11)

 482.8
 597.2

 Regulatory effects of accounting for income taxes (see Note 1-N. and Note 15)

 827.0
 849.9

 Deferred pension and other postretirement benefit costs (see Note 16)

 40.4
 54.0

 Gains on commodity price risk programs (See Note 13)

 28.7
 23.3

 Customer assistance programs

 9.4
 19.8

 Off-system sales sharing

 21.4
 19.0

 Renewable energy investments (See Note 1-S. and Note 4)

 77.0
 18.1

 Rate refunds

 16.6
 16.1

 Other
 57.0
 47.4

 Total Regulatory Liabilities
 $
 1,581.7
 $
 1,789.3

 Less: Current Portion
 150.5
 278.6

 Total Noncurrent Regulatory Liabilities
 $
 1,431.2
 $
 1,510.7

 Regulatory assets, including under-recovered gas and fuel costs and depreciation, of approximately $ 671.3 million and $ 716.4 million as of December 31, 2024 and 2023, respectively, are not earning a return on investment. These costs are recovered over a remaining life of between 15 and 75 years.

 Assets:
 Unrecognized pension and other postretirement benefit costs. Represents the deferred other comprehensive income or loss of the actuarial gains or losses and the prior service costs or credits that arise during the period but that are not immediately recognized as components of net periodic benefit costs by certain subsidiaries that will ultimately be recovered through base rates.
 Deferred pension and other postretirement benefit costs. Primarily relates to the difference between defined benefit plan expense recorded by certain subsidiaries due to regulatory orders and the corresponding expense that would otherwise be recorded in accordance with GAAP. This balance is driven by Columbia of Ohio deferrals.
 Environmental costs. Includes certain recoverable costs related to gas plant sites, disposal sites or other sites onto which material may have migrated, the recovery of which is to be addressed in future base rates, billing riders or tracking mechanisms of certain of our subsidiaries.
 Regulatory effects of accounting for income taxes. Represents the deferral and under collection of deferred taxes in the rate making process.
 Under-recovered gas and fuel costs. Represents the difference between the costs of gas and fuel, as well as energy acquired through power purchase agreements, including NIPSCO's own renewable projects, and the recovery of such costs in revenue and is used to adjust future billings for such deferrals on a basis consistent with applicable state-approved tariff provisions. Recovery of these costs is achieved through tracking mechanisms.
 Depreciation. Represents differences between depreciation expense incurred on a GAAP basis and that prescribed through regulatory order. The majority of this balance is driven by Columbia of Ohio's IRP and CEP deferrals.
 Post-in-service carrying charges. Represents deferred debt-based carrying charges incurred on certain assets placed into service but not yet included in customer rates. The majority of this balance is driven by Columbia of Ohio's IRP and CEP deferrals.
 Safety activity costs. Represents the difference between costs incurred by certain of our subsidiaries in eligible safety programs in compliance with PHMSA regulations in excess of those being recovered in rates. The majority of this balance is driven by Columbia of Ohio, which began recovery in March 2023 through base rates.
 DSM programs. Represents costs associated with Columbia Operations and NIPSCO Operations energy efficiency and conservation programs. Costs are recovered through tracking mechanisms.
 Retired coal generating stations. Represents the net book value of Units 7 and 8 of Bailly Generating Station that was retired during 2018 and the net book value of Units 14 and 15 of R.M. Schahfer Generating Station retired in 2021. These amounts are currently being amortized at a rate consistent with their inclusion in customer rates. The August 2023 NIPSCO electric rate case order extends the recovery of, and on, the net book value of the stations by the end of 2034 and implements a revenue credit for the retired units. The credit is based on the difference between the year-end value of Units 14 and 15 and the most recent value established in the last base rate case proceeding or credit compliance filing.
 Losses on commodity price risk programs. Represents the unrealized losses related to certain of our subsidiary's commodity price risk programs. These programs help to protect against the volatility of commodity prices and these amounts are collected from customers through their inclusion in customer rates.
 Deferred property taxes. Represents the deferral and under collection of property taxes in the rate making process for Columbia of Ohio and is driven by the IRP and CEP deferrals.
 Renewable energy investments. Represents the regulatory deferral of renewable energy formation and developer costs.
 WAM system filing. Represents the deferral of certain costs, including depreciation and amortization incurred in connection with improvements to its information technology systems through the design, development, and implementation of a new WAM program for the scheduling, dispatch, and execution of work and the management of underlying assets.
 Customer Assistance Programs. Represents the difference between the eligible customer assistance program costs and collections, which will be collected from customers.

 Liabilities:
 Over-recovered gas and fuel costs. Represents the difference between the cost of gas and fuel, as well as energy acquired through power purchase agreements, including NIPSCO's own renewable projects and, the recovery of such costs in revenues and is the basis to adjust future billings for such refunds on a basis consistent with applicable state-approved tariff provisions. Refunding of these revenues is achieved through tracking mechanisms.
 Cost of removal. Represents anticipated costs of removal for utility assets that have been collected through depreciation rates for future costs to be incurred.
 Regulatory effects of accounting for income taxes. Represents amounts owed to customers for deferred taxes collected at a higher rate than the current statutory rates and liabilities associated with accelerated tax deductions owed to customers. Balance includes excess deferred taxes recorded upon implementation of the TCJA in December 2017, net of amounts amortized through 2024 and federal tax credits generated by Cavalry solar facility that are passed back to customers. For discussion of the regulatory impact of the NIPSCO Minority Interest Transaction on deferred taxes, see Note 15, "Income Taxes," for additional details.
 Deferred pension and other postretirement benefit costs. Primarily represents cash contributions in excess of postretirement benefit expense that is deferred by certain subsidiaries.
 Gains on commodity price risk programs. Represents the unrealized gains related to certain of our subsidiary's commodity price risk programs. These programs help to protect against the volatility of commodity prices, and these amounts are passed back to customers through their inclusion in customer rates.
 Customer Assistance Programs. Represents the difference between the eligible customer assistance program costs and collections, which will be refunded to customers.
 Renewable energy investments. Represents the regulatory deferral of certain amounts representing the timing difference between the profit earned from the JVs and the amount included in regulated rates to recover our approved investments in consolidated JVs. The offset to the regulatory liability associated with our renewable investments is recorded in "Depreciation expense" on the Statements of Consolidated Comprehensive Income. Refer to Note 1, "Nature of Operations and Summary of Significant Accounting Policies - S. Noncontrolling Interest," Note 4, "Noncontrolling Interests," and Note 9, "Property, Plant and Equipment," for additional information.
 Rate Refunds. Represents supplier refunds received by the company that are owed to customers and will be remitted and amounts that are being collected in rates subject to refund.
 Off System Sales Sharing. Represents amounts to be passed back to the customers as a result of Off System sales that is shared between the company and the customer.
 Regulatory Filings

 Renewable generation filings
 In March 2024, NIPSCO filed a petition with the IURC to issue an order modifying its November 22, 2023 order to approve direct ownership of the Gibson project. Also, in March 2024, NIPSCO filed a petition with the IURC to issue an order modifying its June 29, 2021 order to approve direct ownership of the Fairbanks project. Hearings for both the Gibson project and Fairbanks project were held in June 2024 and July 2024, respectively, with orders approving direct ownership of both projects received in August 2024.

 NIPSCO Gas peaker filing
 In September 2023, NIPSCO filed a request for issuance of a CPCN for an approximately 400 MW natural gas peaking generation facility with the IURC, which was supplemented in January 2024 based on updates on availability of certain key equipment. A final order was received in October 2024 approving the request.

 NIPSCO Electric rate case filing
 On February 7, 2025, NIPSCO and certain intervening parties filed a Joint Stipulation and Settlement Agreement with the IURC. New rates proposed to be implemented in 2 steps, with implementation of Step 1 rates effective no later than September 2025 and Step 2 rates to be effective no later than March 2026.

 Columbia of Virginia rate case filing
 Columbia of Virginia and the intervening parties, with the exception of the Office of the Attorney General, filed a Joint Stipulation and Proposed Recommendation for settlement on December 5, 2024 for an annual revenue increase of $ 28.2 million, net of SAVE. Rates became effective on an as filed basis in October 2024 and we have recorded a regulatory liability to reflect the pending settlement.

 13. Risk Management Activities
 We are exposed to certain risks related to our ongoing business operations; namely commodity price risk and interest rate risk. We recognize that the prudent and selective use of derivatives may help to limit volatility in the price of natural gas, and manage interest rate exposure.
 Risk management assets and liabilities on our derivatives are presented on the Consolidated Balance Sheets as shown below:

 Current(1)

 Derivatives not designated as hedging instruments
 $
 9.1
 $
 2.3
 $
 1.1
 $
 7.5

 Total
 $
 9.1
 $
 2.3
 $
 1.1
 $
 7.5

 Noncurrent(2)

 Derivatives not designated as hedging instruments
 $
 17.9
 $
 1.2
 $
 22.2
 $
 1.9

 Total
 $
 17.9
 $
 1.2
 $
 22.2
 $
 1.9

 (1) Current assets and liabilities are presented in "Prepayments and other" and "Other accruals", respectively, on the Consolidated Balance Sheets.
 (2) Noncurrent assets and liabilities are presented in "Deferred charges and other" and "Other noncurrent liabilities and deferred credits", respectively, on the Consolidated Balance Sheets.

 Our derivative instruments are subject to enforceable master netting arrangements or similar agreements. No collateral was either received or posted related to our outstanding derivative positions at December 31, 2024 and 2023. If the above gross asset and liability positions were presented net of amounts owed or receivable from counterparties, we would report a net asset position of $ 23.5 million and $ 13.9 million at December 31, 2024 and 2023, respectively.

 Derivatives Not Designated as Hedging Instruments
 Commodity price risk management. We, along with our utility customers, are exposed to variability in cash flows associated with natural gas purchases and volatility in natural gas prices. We purchase natural gas for sale and delivery to our retail, commercial and industrial customers, and for most customers the variability in the market price of gas is passed through in their rates. Some of our utility subsidiaries offer programs whereby variability in the market price of gas is assumed by the respective utility. The objective of our commodity price risk programs is to mitigate the gas cost variability, for us or on behalf of our customers, associated with natural gas purchases or sales by economically hedging the various gas cost components using a combination of futures, options, forwards or other derivative contracts. As of December 31, 2024 and 2023, we had 77.8 MMDth and 76.1 MMDth, respectively, of net energy derivative volumes outstanding related to our natural gas hedges.
 NIPSCO has received IURC approval to lock in a fixed price for its natural gas customers using long-term forward purchase instruments and is limited to 20 % of NIPSCO's average annual GCA purchase volume. As of December 31, 2024, the remaining terms of these instruments range from one to three years. Likewise, Columbia of Pennsylvania has received approval for a 24-month rolling hedge program. The hedging program was executed in December 2023, with an effective date of April 1, 2024 and will continue in perpetuity. The program is designed to financially hedge approximately 20 % of the customer's annual demand. All gains and losses on these derivative contracts are deferred as regulatory liabilities or assets and are remitted to or collected from customers through the relevant cost recovery mechanism.

 Derivatives Designated as Hedging Instruments
 Interest rate risk management. As of December 31, 2024 and 2023, we had no forward-starting interest rate swaps outstanding.
 The overall net loss related to our multiple settled interest rate swaps is recorded to AOCI. We amortize the net loss over the life of the debt associated with these swaps as we recognize interest expense. These amounts are immaterial in 2024, 2023 and 2022 and are recorded in "Interest expense, net" on the Statements of Consolidated Income.
 Cash flows for derivative financial instruments are generally classified as operating activities.

 14. Fair Value
 A.Fair Value Measurements
 Recurring Fair Value Measurements
 The following tables present financial assets and liabilities measured and recorded at fair value on our Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of December 31, 2024 and December 31, 2023:

 Recurring Fair Value Measurements
 December 31, 2024 (in millions)

 Quoted Prices
in Active Markets
for Identical Assets
(Level 1)
 Significant Other
Observable Inputs
(Level 2)
 Significant
Unobservable
Inputs
(Level 3)
 Balance as of

 U.S. Treasury debt securities(1)

 $
 80.1
 $
 —
 $
 —
 $
 80.1

 Risk management assets
 —
 27.0
 —
 27.0

 Available-for-sale debt securities
 —
 86.7
 —
 86.7

 Total
 $
 80.1
 $
 113.7
 $
 —
 $
 193.8

 Risk management liabilities
 $
 —
 $
 3.5
 $
 —
 $
 3.5

 Total
 $
 —
 $
 3.5
 $
 —
 $
 3.5

 (1) Treasury bills are presented in "Cash and cash equivalents" and "Restricted cash" on the Consolidated Balance Sheets.

 Recurring Fair Value Measurements
 December 31, 2023 (in millions)

 Quoted Prices
in Active Markets
for Identical Assets
(Level 1)
 Significant Other
Observable Inputs
(Level 2)
 Significant
Unobservable
Inputs
(Level 3)
 Balance as of

 Risk management assets
 $
 —
 $
 23.3
 $
 —
 $
 23.3

 Available-for-sale debt securities
 —
 159.1
 —
 159.1

 Total
 $
 —
 $
 182.4
 $
 —
 $
 182.4

 Risk management liabilities
 $
 —
 $
 9.4
 $
 —
 $
 9.4

 Total
 $
 —
 $
 9.4
 $
 —
 $
 9.4

 Risk Management Assets and Liabilities. Risk management assets and liabilities include interest rate swaps, exchange-traded NYMEX futures and NYMEX options and non-exchange-based forward purchase contracts.

 Level 1- When utilized, exchange-traded derivative contracts are based on unadjusted quoted prices in active markets and are classified within Level 1. These financial assets and liabilities are secured with cash on deposit with the exchange; therefore, nonperformance risk has not been incorporated into these valuations. These financial assets and liabilities are deemed to be cleared and settled daily by NYMEX as the related cash collateral is posted with the exchange. As a result of this exchange rule, NYMEX derivatives are considered to have no fair value at the balance sheet date for financial reporting purposes, and are presented in Level 1 net of posted cash; however, the derivatives remain outstanding and are subject to future commodity price fluctuations until they are settled in accordance with their contractual terms.
 Level 2- Certain non-exchange-traded derivatives are valued using broker or over-the-counter, on-line exchanges. In such cases, these non-exchange-traded derivatives are classified within Level 2. Non-exchange-based derivative instruments include swaps, forwards, and options. In certain instances, these instruments may utilize models to measure fair value. We use a similar model to value similar instruments. Valuation models utilize various inputs that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, other observable inputs for the asset or liability and market-corroborated inputs, (i.e., inputs derived principally from or corroborated by observable market data by correlation or other means). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized within Level 2.
 Level 3- Certain derivatives trade in less active markets with a lower availability of pricing information and models may be utilized in the valuation. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized within Level 3.
 Credit risk is considered in the fair value calculation of derivative instruments that are not exchange-traded. Credit exposures are adjusted to reflect collateral agreements that reduce exposures. As of December 31, 2024 and 2023, there were no material transfers between fair value hierarchies. Additionally, there were no changes in the method or significant assumptions used to estimate the fair value of our financial instruments.
 NIPSCO and Columbia of Pennsylvania have entered into long-term forward natural gas purchase instruments to lock in a fixed price for their natural gas customers. We value these contracts using a pricing model that incorporates market-based information when available, as these instruments trade less frequently and are classified within Level 2 of the fair value hierarchy. For additional information, see Note 13, "Risk Management Activities."
 Available-for-Sale Debt Securities. Available-for-sale debt securities are investments pledged as collateral for trust accounts related to our wholly-owned insurance company. We value U.S. Treasury, corporate debt and mortgage-backed securities using a matrix pricing model that incorporates market-based information. These securities trade less frequently and are classified within Level 2.
 Our available-for-sale debt securities impairments are recognized periodically using an allowance approach. At each reporting date, we utilize a quantitative and qualitative review process to assess the impairment of available-for-sale debt securities at the individual security level. For securities in a loss position, we evaluate our intent to sell or whether it is more-likely-than-not that we will be required to sell the security prior to the recovery of its amortized cost. If either criteria is met, the loss is recognized in earnings immediately, with the offsetting entry to the carrying value of the security. If both criteria are not met, we perform an analysis to determine whether the unrealized loss is related to credit factors. The analysis focuses on a variety of factors that include, but are not limited to, downgrade on ratings of the security, defaults in the current reporting period or projected defaults in the future, the security's yield spread over treasuries, and other relevant market data. If the unrealized loss is not related to credit factors, it is included in other comprehensive income. If the unrealized loss is related to credit factors, the loss is recognized as credit loss expense in earnings during the period, with an offsetting entry to the allowance for credit losses. The amount of the credit loss recorded to the allowance account is limited by the amount at which the security's fair value is less than its amortized cost basis. If certain amounts recorded in the allowance for credit losses are deemed uncollectible, the allowance on the uncollectible portion will be charged off, with an offsetting entry to the carrying value of the security. Subsequent improvements to the estimated credit losses of available-for-sale debt securities will be recognized immediately in earnings. As of December 31, 2024 and December 31, 2023, we recorded $ 0.1 million and $ 0.6 million, respectively, as an allowance for credit losses on available-for-sale debt securities as a result of the analysis described above. Continuous credit monitoring and portfolio credit balancing mitigates our risk of credit losses on our available-for-sale debt securities.

 The amortized cost, gross unrealized gains and losses, allowance for credit losses, and fair value of available-for-sale securities at December 31, 2024 and 2023 were:

 December 31, 2024 (in millions)

 Amortized
Cost
 Gross
Unrealized
Gains
 Gross
 Unrealized
 Losses(1)

 Allowance for Credit Losses

 Available-for-sale debt securities

 Corporate/Other debt securities
 $
 91.9
 $
 0.5
 $
 ( 5.6)
 $
 $
 86.7

 Total
 $
 91.9
 $
 0.5
 $
 ( 5.6)
 $
 $
 86.7

 December 31, 2023 (in millions)

 Amortized
Cost
 Gross
Unrealized
Gains
 Gross
 Unrealized
 Losses(2)

 Allowance for Credit Losses

 Available-for-sale debt securities

 U.S. Treasury debt securities
 $
 63.8
 $
 —
 $
 ( 3.2)
 $
 —
 $
 60.6

 Corporate/Other debt securities
 105.2
 0.8
 ( 6.9)
 ( 0.6)
 98.5

 Total
 $
 169.0
 $
 0.8
 $
 ( 10.1)
 $
 ( 0.6)
 $
 159.1

 (1) Fair value of Corporate/Other debt securities in an unrealized loss position without an allowance for credit losses is $ 70.1 million at December 31, 2024.
 (2) Fair value of U.S. Treasury debt securities and Corporate/Other debt securities in an unrealized loss position without an allowance for credit losses is $ 58.7 million and $ 74.8 million, respectively, at December 31, 2023.
 Realized gains and losses on available-for-sale securities was $ 2.3 million for the year ended December 31, 2024 and $ 1.0 million for 2023.
 The cost of maturities sold is based upon specific identification. At December 31, 2024, approximately $ 10.9 million of Corporate/Other debt securities have maturities of less than a year.
 There are no material items in the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis for the years ended December 31, 2024 and 2023.
 Additional plan investments in corporate-owned life insurance are recorded at their cash surrender value, not fair value, and therefore are not included above. These plan investments are classified as "Other investments" on the Consolidated Balance Sheets.
 Non-recurring Fair Value Measurements
 We measure the fair value of certain assets, including goodwill, on a non-recurring basis, typically when events or changes in circumstances indicate that the carrying amount of the assets may not be recoverable.
 B. Other Fair Value Disclosures for Financial Instruments. The carrying amount of cash and cash equivalents, restricted cash, notes receivable, customer deposits and short-term borrowings is a reasonable estimate of fair value due to their liquid or short-term nature. Our long-term borrowings are recorded at historical amounts.
 The following method and assumptions were used to estimate the fair value of each class of financial instruments.
 Long-term debt. The fair value of outstanding long-term debt is estimated based on the quoted market prices for the same or similar securities. Certain premium costs associated with the early settlement of long-term debt are not taken into consideration in determining fair value. These fair value measurements are classified within Level 2 of the fair value hierarchy. For the years ended December 31, 2024 and 2023, there was no change in the method or significant assumptions used to estimate the fair value of long-term debt.

 The carrying amount and estimated fair values of these financial instruments were as follows:

 Carrying
 Amount
 2024

 Estimated
 2024

 Carrying
 Amount
 2023

 Estimated
 2023

 Long-term debt (including current portion)
 $
 13,355.7
 $
 12,505.2
 $
 11,079.3
 $
 10,370.9

 15. Income Taxes
 Judgment and the use of estimates are required in developing the provision for income taxes and reporting of tax-related assets and liabilities. The interpretation of tax laws and associated regulations involves uncertainty as taxing authorities may interpret the laws differently.

 NIPSCO's historical business activities through the closing of the NIPSCO Minority Interest Transaction in 2023 were included in the consolidated U.S. federal and certain state income tax returns of NiSource Inc. Historically, NIPSCO has been treated as a taxable division of its corporate parent, NiSource Inc., and then as a division of NIPSCO Holdings I effective April 13, 2023. In connection with the NIPSCO Minority Interest Transaction, NIPSCO Holdings I retained NIPSCO's income tax balances and 80.1 % of the excess deferred income tax regulatory balances as described below. NIPSCO Holdings I's income tax balances are based on the difference between the financial statement amount and the tax basis of its investment in NIPSCO Holdings II.

 Income Tax Expense. The components of income tax expense (benefit) were as follows:

 2024
 2023
 2022

 Current

 Federal
 $
 ( 19.3)
 $
 —
 $
 0.4

 State
 9.4
 5.3
 7.3

 Total Current (Benefit) Expense

 ( 9.9)
 5.3
 7.7

 Deferred

 Federal

 Taxes before operating loss carryforwards and investment credits
 105.9
 49.7
 87.9

 Tax utilization expense of operating loss carryforwards
 60.4
 65.1
 93.1

 Investment tax credits
 ( 2.1)
 —

 State
 2.6
 22.5
 ( 23.0)

 Total Deferred Expense

 168.8
 135.2
 158.0

 Deferred Investment Tax Credits

 ( 0.8)
 ( 1.0)
 ( 1.1)

 Income Taxes from Continuing Operations

 $
 158.1
 $
 139.5
 $
 164.6

 In connection with the NIPSCO Minority Interest Transaction during 2023, NiSource recognized a $ 63.5 million income tax benefit in additional paid in capital related to 19.9 % of NIPSCO's excess deferred income taxes attributable to Blackstone's noncontrolling interest. This benefit does not impact NIPSCO's regulatory books or the excess deferred taxes that will benefit customers through lower future rates in accordance with applicable regulatory orders. See Note 4, "Noncontrolling Interests," for further discussion of the NIPSCO Minority Interest Transaction.

 Statutory Rate Reconciliation. The following table represents a reconciliation of income tax expense at the statutory federal income tax rate to the actual income tax expense from continuing operations:

 2024
 2023
 2022

 Book income before income taxes

 $
 1,002.8
 $
 813.9
 $
 956.4

 Tax expense at statutory federal income tax rate

 210.6
 21.0
 %
 170.8
 21.0
 %
 200.8
 21.0
 %

 Increases (reductions) in taxes resulting from:

 State income taxes, net of federal income tax benefit
 11.7
 1.2
 13.7
 1.7
 4.5
 0.5

 Amortization of regulatory liabilities
 ( 11.1)
 ( 1.1)
 ( 38.2)
 ( 4.7)
 ( 38.5)
 ( 4.0)

 Employee stock ownership plan dividends and other compensation
 ( 1.3)
 ( 1.3)
 ( 1.2)

 Federal tax credits
 ( 23.3)
 ( 2.3)
 ( 4.9)
 ( 0.6)
 ( 2.3)

 Tax effect of non-controlling Interest

 ( 27.3)
 ( 2.7)
 —
 —
 —
 —

 Other adjustments
 ( 1.2)
 ( 0.6)
 1.3
 —

 $
 158.1
 15.8
 %
 $
 139.5
 17.1
 %
 $
 164.6
 17.2
 %

 The increase in tax expense of $ 18.6 million in 2024 versus 2023 was primarily due to higher pre-tax income, partially offset by the tax effect of non-controlling interest, and higher federal tax credits generated by the Cavalry solar and storage facility that are offset in a regulatory liability to pass back to customers in future periods.

 The decrease in the Amortization of Regulatory Liabilities in 2024 versus 2023 was primarily due to the regulatory liability established for the Cavalry tax credits generated in 2024, net of TCJA excess deferred amortization which decreased approximately $ 7.9 million from the prior year.

 The difference in tax expense of $ 25.1 million in 2023 versus 2022 was primarily due to lower pre-tax income.

 Net Deferred Income Tax Liability Components. Deferred income taxes result from temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities. The principal components of our net deferred tax liabilities were as follows:

 2024
 2023

 Deferred tax liabilities

 Accelerated depreciation and other property differences
 $
 1,419.4
 $
 1,384.8

 Partnership basis differences

 1,328.6
 1,241.9

 Other regulatory assets
 210.1
 212.1

 Total Deferred Tax Liabilities
 2,958.1
 2,838.8

 Deferred tax assets

 Other regulatory liabilities and deferred investment tax credits (including TCJA)
 170.4
 182.2

 Pension and other postretirement/postemployment benefits
 58.8
 58.6

 Loss and credit carryforwards

 369.4
 422.9

 Environmental liabilities
 12.2
 10.1

 Other accrued liabilities
 43.4
 40.3

 Other, net
 28.7
 50.7

 Total Deferred Tax Assets
 682.9
 764.8

 Valuation Allowance

 Net Deferred Tax Assets
 676.5
 758.4

 Net Deferred Tax Liabilities
 $
 2,281.6
 $
 2,080.4

 In connection with the NIPSCO Minority Interest Transaction, NIPSCO's deferred taxes were removed from its GAAP books and were reconstituted as deferred taxes on the outside basis difference of NiSource's investment in NIPSCO Holdings II. These deferred taxes are reflected as partnership basis differences above.

 NiSource has the following deductible loss and credit carryforwards:

 At December 31, 2024 (in millions)

 Deductible Amount

 Deferred Tax Asset

 Valuation Allowance

 Expiration Period

 Federal losses

 $
 1,369.1
 $
 287.5
 $
 —
 2037

 Federal investment tax credits

 —
 2.2
 —
 2043

 Federal production tax credits

 —
 1.0
 —
 2040-2043

 Federal other credit

 —
 17.3
 —
 2029-2043

 State losses

 2,024.4
 81.9
 2031-2037

 Total
 $
 389.9
 $

 We believe it is not more likely than not that a portion of the benefit from certain state net operating loss carryforwards will be realized. We have recorded a valuation allowance of $ 6.4 million on the deferred tax assets related to sale of Massachusetts Business assets reflected in the state net operating loss carryforward presented above.

 Unrecognized Tax Benefits. A reconciliation of the beginning and ending amounts of unrecognized tax benefits is as follows:

 At December 31, 2024(in millions)

 2024
 2023
 2022

 Opening Balance
 $
 21.7
 $
 21.7
 $
 21.7

 Gross decreases - tax positions in prior period
 —
 —
 —

 Gross increases - current period tax positions
 —
 —
 —

 Ending Balance
 $
 21.7
 $
 21.7
 $
 21.7

 Offset for net operating loss carryforwards
 ( 21.7)
 ( 21.7)
 ( 21.7)

 Balance, Less Net Operating Loss Carryforwards
 $
 —
 $
 —
 $
 —

 We are subject to income taxation in the United States and various state jurisdictions, primarily Indiana, Pennsylvania, Kentucky, Massachusetts, Maryland and Virginia.

 We participate in the IRS CAP, which provides the opportunity to resolve tax matters with the IRS before filing each year's consolidated federal income tax return. As of December 31, 2024, tax years through 2021 have been audited and are closed to further assessment. The Company has transitioned to the Bridge Phase of the IRS CAP for the year ended December 31, 2022 and participated in the Bridge Plus pilot program in 2022 and 2023. NiSource received a full acceptance letter from the IRS for its 2022 return, but has not yet received a final acceptance letter from the IRS for its 2023 return. However, no adjustments are expected, and the year is effectively closed to further assessment.

 The statute of limitations in each of the state jurisdictions in which we operate remains open between 3-4 years from the date the state income tax returns are filed. As of December 31, 2024, there were no state income tax audits in progress that would have a material impact on the consolidated financial statements.

 NiSource is obligated to report adjustments resulting from IRS audits or settlements to state taxing authorities. In addition, if NiSource utilizes net operating losses or tax credits generated in years for which the statute of limitations has expired, such amounts are generally subject to examination.

 On April 14, 2023, the IRS issued Revenue Procedure 2023-15 which provides a safe harbor method of accounting that taxpayers may use to determine whether expenses to repair, maintain, replace, or improve linear property and non-linear natural gas transmission and distribution property must be capitalized as improvements or are allowable as deductions. On June 3, 2024, the IRS extended the favorable rules to a Year 2 adoption period. The Company is planning to elect this change in tax accounting method with its 2024 consolidated tax return filing in the upcoming year and continues to analyze and quantify the provisions of the safe harbor method of accounting.

 16. Pension and Other Postemployment Benefits
 We provide defined contribution plans and noncontributory defined benefit retirement plans that cover certain of our employees. Benefits under the defined benefit retirement plans reflect the employees' compensation, years of service and age at retirement. Additionally, we provide health care and life insurance benefits for certain retired employees. The majority of employees may become eligible for these benefits if they reach retirement age while working for us. The expected cost of such benefits is accrued during the employees' years of service. Current rates of rate-regulated companies include postretirement benefit costs, including amortization of the regulatory assets that arose prior to inclusion of these costs in rates. For most plans, cash contributions are remitted to grantor trusts.
 Our Pension and Other Postretirement Benefit Plans' Asset Management. The Board has delegated oversight of the pension and other postretirement benefit plans' assets to the NiSource Benefits Committee (the "Committee"). The Committee has adopted investment policy statements for the pension and other postretirement benefit plans' assets. For the pension plans, we employ a liability-driven investing strategy. A total return approach is utilized for the other postretirement benefit plans' assets. A mix of diversified investments are used to maximize the long-term return of plan assets and hedge the liabilities at a prudent level of risk. The investment portfolio includes U.S. and non-U.S. equities, real estate, long-term and intermediate-term fixed income and alternative investments. Risk tolerance is established through careful consideration of plan liabilities, funded status, and asset class volatility. Investment risk is measured and monitored on an ongoing basis through quarterly investment portfolio reviews, annual liability measurements, and periodic asset/liability studies.

 In determining the expected long-term rate of return on plan assets, historical markets are studied, relationships between equities and fixed income are analyzed and current market factors, such as inflation and interest rates are evaluated with consideration of diversification and rebalancing. Our expected long-term rate of return on assets is based on assumptions regarding target asset allocations and corresponding long-term capital market assumptions for each asset class. The pension plans' investment policy calls for a gradual reduction in the allocation of return-seeking assets (equities, real estate and private equity) and a corresponding increase in the allocation of liability-hedging assets (fixed income) as the funded status of the plans' increase.
 As of December 31, 2024 and December 31, 2023, the acceptable minimum and maximum ranges established by the policy for the pension and other postretirement benefit plans are as follows:

 Defined Benefit Pension Plan
 Postretirement Benefit Plan

 Asset Category
 Minimum
 Maximum
 Minimum
 Maximum

 Domestic Equities
 10 %
 30 %
 0 %
 55 %

 International Equities
 5 %
 15 %
 0 %
 25 %

 Fixed Income
 65 %
 75 %
 20 %
 100 %

 Real Estate
 0 %
 0 %
 0 %
 0 %

 Private Equity
 0 %
 3 %
 0 %
 0 %

 Short-Term Investments
 0 %
 10 %
 0 %
 10 %

 Defined Benefit Pension Plan
 Postretirement Benefit Plan

 Asset Category
 Minimum
 Maximum
 Minimum
 Maximum

 Domestic Equities
 10 %
 30 %
 0 %
 55 %

 International Equities
 5 %
 15 %
 0 %
 25 %

 Fixed Income
 65 %
 75 %
 20 %
 100 %

 Real Estate
 0 %
 0 %
 0 %
 0 %

 Private Equity
 0 %
 3 %
 0 %
 0 %

 Short-Term Investments
 0 %
 10 %
 0 %
 10 %

 The actual Pension Plan and Postretirement Plan Asset Mix at December 31, 2024 and December 31, 2023 are as follows:

 Defined Benefit
 Pension Assets(1)

2024
 Postretirement
Benefit Plan Assets
2024

 Asset Class (in millions)

 Asset Value
 % of Total Assets
 Asset Value
 % of Total Assets

 Domestic Equities
 $
 258.9
 19.4
 %
 $
 99.6
 40.9
 %

 International Equities
 122.5
 9.2
 %
 40.7
 16.7
 %

 Fixed Income
 891.2
 66.7
 %
 96.5
 39.6
 %

 Real Estate
 4.0
 0.3
 %
 —
 —

 Cash/Other
 59.8
 4.4
 %
 6.7
 2.8
 %

 Total
 $
 1,336.4
 100.0
 %
 $
 243.5
 100.0
 %

 (1)Total includes accrued dividends and pending trades with brokers.

 Defined Benefit Pension Assets(1)

2023
 Postretirement Benefit Plan Assets(1)

2023

 Asset Class (in millions)

 Asset Value
 % of Total Assets
 Asset Value
 % of Total Assets

 Domestic Equities
 $
 261.7
 18.3
 %
 $
 93.7
 39.6
 %

 International Equities
 141.9
 9.9
 %
 40.7
 17.2
 %

 Fixed Income
 939.9
 65.9
 %
 97.0
 41.0
 %

 Real Estate
 4.0
 0.3
 %
 —
 —

 Cash/Other
 79.3
 5.6
 %
 5.1
 2.2
 %

 Total
 $
 1,426.8
 100.0
 %
 $
 236.5
 100.0
 %

 (1)Total includes accrued dividends and pending trades with brokers.
 The categorization of investments into the asset classes in the tables above are based on definitions established by the Committee.
 Fair Value Measurements. The following table sets forth, by level within the fair value hierarchy, the pension and other postretirement benefits investment assets at fair value as of December 31, 2024 and 2023. Assets are classified in their entirety based on the observability of inputs used in determining the fair value measurement. There were no material investment assets in the pension and other postretirement benefits trusts classified within Level 3 for the years ended December 31, 2024 and 2023.
 We use the following valuation techniques to determine fair value. For the year ended December 31, 2024, there were no significant changes to valuation techniques to determine the fair value of our pension and other postretirement benefits' assets.
 Level 1 Measurements
 Most common and preferred stocks are traded in active markets on national and international securities exchanges and are valued at closing prices on the last business day of each period presented. Cash is stated at cost, which approximates fair value, with the exception of cash held in foreign currencies which fluctuates with changes in the exchange rates. Short-term bills and notes are priced based on quoted market values.
 Level 2 Measurements
 Most U.S. Government Agency obligations, mortgage/asset-backed securities, and corporate fixed income securities are generally valued by benchmarking model-derived prices to quoted market prices and trade data for identical or comparable securities. To the extent that quoted prices are not available, fair value is determined based on a valuation model that includes inputs such as interest rate yield curves and credit spreads. Securities traded in markets that are not considered active are valued based on quoted market prices, broker or dealer quotations, or alternative pricing sources with reasonable levels of price transparency. Other fixed income includes futures and options which are priced on bid valuation or settlement pricing.

 Level 3 Measurements
 Investments with unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets and liabilities are classified as level 3 investments.
 Not Classified
 Commingled funds, private equity limited partnerships and real estate partnerships are not classified within the fair value hierarchy. Instead, these assets are measured at estimated fair value using the net asset value per share of the investments. Commingled funds' underlying assets are principally marketable equity and fixed income securities. Units held in commingled funds are valued at the unit value as reported by the investment managers. Private equity funds invest capital in non-public companies and real estate funds invest in commercial and distressed real estate directly or through related debt instruments. The fair value of these investments is determined by reference to the funds' underlying assets.

 Fair Value Measurements at December 31, 2024:

2024
 Quoted Prices in Active Markets for
 Identical Assets
(Level 1)
 Significant Other
Observable Inputs (Level 2)
 Significant
Unobservable Inputs
 (Level 3)

 Pension plan assets:

 Cash
 $
 1.2
 $
 1.1
 $
 0.1
 $
 —

 Fixed income securities

 Government
 186.8
 —
 186.8
 —

 Corporate
 486.6
 —
 486.6
 —

 Mortgages/ Asset Backed Securities
 3.6
 —
 3.6
 —

 Mutual Funds

 U.S. multi-strategy
 56.1
 56.1
 —
 —

 57.2
 57.2
 —
 —

 Private equity limited partnerships(1)

 U.S. multi-strategy(2)

 3.1
 —
 —
 —

 International multi-strategy(3)

 0.8
 —
 —
 —

 Distressed opportunities
 0.1
 —
 —
 —

 Real estate(1)

 4.0
 —
 —
 —

 Commingled funds(1)

 45.9
 —
 —
 —

 202.8
 —
 —
 —

 65.3
 —
 —
 —

 214.1
 —
 —
 —

 Pension plan assets subtotal
 $
 1,327.6
 $
 114.4
 $
 677.1
 $
 —

 Other postretirement benefit plan assets:

 Mutual funds

 U.S. multi-strategy
 87.4
 87.4
 —
 —

 16.5
 16.5
 —
 —

 96.5
 96.5
 —
 —

 Commingled funds(1)

 6.7
 —
 —
 —

 12.2
 —
 —
 —

 24.2
 —
 —
 —

 Other postretirement benefit plan assets subtotal
 $
 243.5
 $
 200.4
 $
 —
 $
 —

 Due to brokers, net(4)

 —
 —

 Accrued income/dividends
 8.9
 8.9

 —

 Total pension and other postretirement benefit plan assets
 $
 1,579.9
 $
 323.7
 $
 677.0
 $
 —

 (1))This class of investments is measured at fair value using the net asset value per share and has not been classified in the fair value hierarchy.
 (2)This class includes limited partnerships that invest in a diverse portfolio of private equity strategies, including buy-outs, growth capital, special situations and secondary markets, primarily inside the United States.
 (3)This class includes limited partnerships that invest a in diverse portfolio of private equity strategies, including buy-outs, growth capital, special situations and secondary markets, primarily outside the United States.
 (4)This class represents pending trades with brokers.

 The table below sets forth a summary of unfunded commitments, redemption frequency and redemption notice periods for certain investments that are measured at fair value using the net asset value per share for the year ended December 31, 2024:

 Redemption Frequency
 Redemption Notice Period

 Commingled Funds

 $
 52.6
 Daily
 1 day

 215.0
 Daily
 1 day - 5 days

 89.5
 Monthly
 10 days- 30 days

 214.1
 Daily
 3 days

 Private Equity and Real Estate Limited Partnerships(1)

 8.0
 N/A
 N/A

 Total
 $
 579.2

 (1)Private equity and real estate limited partnerships typically call capital over a 3-5 year period and pay out distributions as the underlying investments are liquidated. The typical expected life of these limited partnerships is 0-15 years, and these investments typically cannot be redeemed prior to liquidation.

 Fair Value Measurements at December 31, 2023:
2023
 Quoted Prices in Active Markets for Identical Assets (Level 1)
 Significant Other
Observable Inputs (Level 2)
 Significant
Unobservable Inputs
(Level 3)

 Pension plan assets:

 Cash
 $
 2.2
 $
 2.0
 $
 0.2
 $
 —

 Equity securities

 1.1
 1.1
 —
 —

 Fixed income securities

 Government
 213.1
 —
 213.1
 —

 Corporate
 482.2
 —
 482.2
 —

 Mortgages/Asset backed securities
 2.4
 —
 2.4
 —

 Mutual Funds

 U.S. multi-strategy
 113.1
 113.1
 —
 —

 38.5
 38.5
 —
 —

 Private equity limited partnerships(1)

 U.S. multi-strategy(2)

 4.8
 —
 —
 —

 International multi-strategy(3)

 1.2
 —
 —
 —

 Distressed opportunities
 0.1
 —
 —
 —

 Real estate(1)

 4.0
 —
 —
 —

 Commingled funds(1)

 65.3
 —
 —
 —

 148.5
 —
 —
 —

 102.3
 —
 —
 —

 242.2
 —
 —
 —

 Pension plan assets subtotal
 $
 1,421.0
 $
 154.7
 $
 697.9
 $
 —

 Other postretirement benefit plan assets:

 Mutual funds

 U.S. multi-strategy
 82.4
 82.4
 —
 —

 18.0
 18.0
 —
 —

 97.0
 97.0
 —
 —

 Commingled funds(1)

 5.2
 —
 —
 —

 11.4
 —
 —
 —

 22.8
 —
 —
 —

 Other postretirement benefit plan assets subtotal
 $
 236.8
 $
 197.4
 $
 —
 $
 —

 Due to brokers, net(4)

 ( 2.7)
 —
 ( 2.7)
 —

 Accrued income/dividends
 8.5
 8.5
 —
 —

 Total pension and other postretirement benefit plan assets
 $
 1,663.6
 $
 360.6
 $
 695.2
 $
 —

 (1)This class of investments is measured at fair value using the net asset value per share and has not been classified in the fair value hierarchy.
 (2)This class includes limited partnerships/fund of funds that invest in a diverse portfolio of private equity strategies, including buy-outs, growth capital, special situations and secondary markets, primarily inside the United States.
 (3)This class includes limited partnerships/fund of funds that invest in diverse portfolio of private equity strategies, including buy-outs, growth capital, special situations and secondary markets, primarily outside the United States.
 (4)This class represents pending trades with brokers.

 The table below sets forth a summary of unfunded commitments, redemption frequency and redemption notice periods for certain investments that are measured at fair value using the net asset value per share for the year ended December 31, 2023:

 Redemption Frequency
 Redemption Notice Period

 Commingled Funds

 $
 70.5
 Daily
 1 day

 159.9
 Daily
 1 day - 5 days

 125.1
 Monthly
 10 days - 30 days

 242.2
 Daily
 3 days

 Private Equity and Real Estate Limited Partnerships(1)

 10.1
 N/A
 N/A

 Total
 $
 607.8

 (1)Private equity and real estate limited partnerships typically call capital over a 3-5 year period and pay out distributions as the underlying investments are liquidated. The typical expected life of these limited partnerships is 0-15 years, and these investments typically cannot be redeemed prior to liquidation.

 Our Pension and Other Postretirement Benefit Plans' Funded Status and Related Disclosure. The following table provides a reconciliation of the plans' funded status and amounts reflected in our Consolidated Balance Sheets at December 31 based on a December 31 measurement date:

 Other Postretirement Benefits

 2024
 2023
 2024
 2023

 Change in projected benefit obligation(1)

 Benefit obligation at beginning of year
 $
 1,401.8
 $
 1,427.4
 $
 468.8
 $
 449.0

 Service cost
 21.9
 20.5
 5.0
 5.1

 Interest cost
 64.9
 68.4
 22.0
 21.8

 Plan participants' contributions
 —
 —
 3.6
 4.2

 Plan amendments
 —
 —
 —
 3.4

 Actuarial loss (gain)(2)

 ( 64.8)
 27.4
 ( 22.5)
 29.1

 Benefits paid
 ( 136.4)
 ( 141.9)
 ( 40.7)
 ( 44.3)

 Estimated benefits paid by incurred subsidy
 —
 —
 0.1
 0.5

 Projected benefit obligation at end of year
 $
 1,287.4
 $
 1,401.8
 $
 436.3
 $
 468.8

 Change in plan assets

 Fair value of plan assets at beginning of year
 $
 1,426.8
 $
 1,422.8
 $
 236.5
 $
 224.9

 Actual return on plan assets
 43.7
 142.8
 20.0
 28.2

 Employer contributions
 2.4
 3.1
 23.6
 23.4

 Plan participants' contributions
 —
 —
 3.8
 4.3

 Benefits paid
 ( 136.4)
 ( 141.9)
 ( 40.7)
 ( 44.3)

 Fair value of plan assets at end of year
 $
 1,336.5
 $
 1,426.8
 $
 243.2
 $
 236.5

 Funded Status at end of year
 $
 49.1
 $
 25.0
 $
 ( 193.1)
 $
 ( 232.3)

 Amounts recognized in the statement of financial position consist of:

 Noncurrent assets
 66.5
 44.1
 —
 —

 Current liabilities
 ( 2.3)
 ( 2.2)
 ( 1.0)
 ( 1.0)

 Noncurrent liabilities
 ( 15.1)
 ( 16.9)
 ( 192.1)
 ( 231.3)

 Net amount recognized at end of year(3)

 $
 49.1
 $
 25.0
 $
 ( 193.1)
 $
 ( 232.3)

 Amounts recognized in accumulated other comprehensive income or regulatory asset/liability(4)

 Unrecognized prior service credit
 $
 0.3
 $
 0.3
 $
 3.8
 $
 2.1

 Unrecognized actuarial loss
 451.4
 500.4
 47.0
 76.6

 Net amount recognized at end of year
 $
 451.7
 $
 500.7
 $
 50.8
 $
 78.7

 (1)The change in benefit obligation for Pension Benefits represents the change in Projected Benefit Obligation while the change in benefit obligation for Other Postretirement Benefits represents the change in accumulated postretirement benefit obligation.
 (2)The pension actuarial gain was primarily driven by the increase in discount rates interest rate movements. The postretirement benefit actuarial loss (gain) was also primarily driven by a increase in discount rates and claims experience changes in trend rates.
 (3)We recognize our Consolidated Balance Sheets underfunded and overfunded status of our various defined benefit postretirement plans, measured as the difference between the fair value of the plan assets and the benefit obligation.
 (4)We determined that for certain rate-regulated subsidiaries the future recovery of pension and other postretirement benefits costs is probable. These rate-regulated subsidiaries recorded regulatory assets and liabilities of $ 485.3 million and zero, respectively, as of December 31, 2024, and $ 561.6 million and zero, respectively, as of December 31, 2023 that would otherwise have been recorded to accumulated other comprehensive loss.
 Our accumulated benefit obligation for our pension plans was $ 1,278.4 million and $ 1,390.9 million as of December 31, 2024 and 2023, respectively. The accumulated benefit obligation at each date is the actuarial present value of benefits attributed by the pension benefit formula to employee service rendered prior to that date and based on current and past compensation levels. The accumulated benefit obligation differs from the projected benefit obligation disclosed in the table above in that it includes no assumptions about future compensation levels.
 We are required to reflect the funded status of our pension and postretirement benefit plans on the Consolidated Balance Sheet. The funded status of the plans is measured as the difference between the plan assets' fair value and the projected benefit obligation. We present the noncurrent aggregate of all underfunded plans within "Accrued liability for postretirement and postemployment benefits." The portion of the amount by which the actuarial present value of benefits included in the projected

 benefit obligation exceeds the fair value of plan assets, payable in the next 12 months, is reflected in "Accrued compensation and other benefits." We present the aggregate of all overfunded plans within "Deferred charges and other."
 For our pension plans as of December 31, 2024 and 2023, only our nonqualified plans were underfunded. These plans have no assets as they are not funded until benefits are paid. The following table sets forth the year end accumulated benefit obligation and projected benefit obligation for pension plans with a projected benefit obligation in excess of plan assets:

 2024
 2023

 Accumulated Benefit Obligation
 $
 17.4
 $
 19.1

 Funded Status

 Projected Benefit Obligation
 $
 17.4
 $
 19.1

 Funded Status of Underfunded Pension Plans at End of Year

 $
 ( 17.4)
 $
 ( 19.1)

 The following table sets forth the year end accumulated benefit obligation, projected benefit obligation and fair value of plan assets for pension plans with plan assets in excess of the projected benefit obligation:

 2024
 2023

 Accumulated Benefit Obligation
 $
 1,261.0
 $
 1,371.8

 Funded Status

 Fair Value of Plan Assets
 $
 1,336.4
 $
 1,426.8

 Projected Benefit Obligation
 1,269.9
 1,382.7

 Funded Status of Overfunded Pension Plans at End of Year
 $
 66.5
 $
 44.1

 Our pension plans were overfunded, in aggregate, by $ 49.1 million at December 31, 2024 compared to being overfunded by $ 25.0 million at December 31, 2023. The improvement in the funded status was primarily due to an increase in discount rates partially offset by actual return on assets being less than expected return on assets. We contributed $ 2.4 million and $ 3.1 million to our pension plans in 2024 and 2023, respectively.
 Our other postretirement benefit plans were underfunded, in aggregate by $ 193.1 million and $ 232.3 million at December 31, 2024 and 2023, respectively. The change in funded status was primarily due to increased discount rates and actual return on plan assets exceeding expected return. We contributed $ 23.6 million and $ 23.4 million to our other postretirement benefit plans in 2024 and 2023, respectively.
 In 2024 and 2023, our NiSource Pension Restoration and Columbia Energy Group pension plans paid lump sum payouts in excess of the respective plan's service cost plus interest cost, thereby meeting the requirement for settlement accounting. We recorded settlement charges of $ 7.2 million and $ 9.2 million in 2024 and 2023, respectively. In 2024 and 2023, no remeasurement occurred related to lump sum payouts.

 The following table provides the key assumptions that were used to calculate the pension and other postretirement benefits obligations for our various plans as of December 31:

 Other Postretirement Benefits

 2024
 2023
 2024
 2023

 Weighted-average assumptions to Determine Benefit Obligation

 Discount Rate
 5.58
 %
 4.95
 %
 5.66
 %
 4.98
 %

 Rate of Compensation Increases
 4.00
 %
 4.00
 %
 N/A
 N/A

 Interest Crediting Rates
 4.00
 %
 4.00
 %
 N/A
 N/A

 Health Care Trend Rates

 Trend for Next Year
 N/A
 N/A
 9.77
 %
 8.84
 %

 Ultimate Trend
 N/A
 N/A
 4.75
 %
 4.75
 %

 Year Ultimate Trend Reached
 N/A
 N/A
 2033
 2032

 We expect to make contributions of approximately $ 2.3 million to our pension plans and approximately $ 21.3 million to our postretirement medical and life plans in 2025.
 The following table provides benefits expected to be paid in each of the next five fiscal years, and in the aggregate for the five fiscal years thereafter. The expected benefits are estimated based on the same assumptions used to measure our benefit obligation at the end of the year and include benefits attributable to the estimated future service of employees:

 Other
Postretirement Benefits

 Year(s)

 2025
 $
 142.6
 $
 36.6

 2026
 136.6
 36.1

 2027
 130.9
 36.1

 2028
 125.8
 35.8

 2029
 119.4
 35.6

 2030-2034
 528.6
 171.7

 The following table provides the components of the plans' actuarially determined net periodic benefits cost for each of the three years ended December 31, 2024, 2023 and 2022:

 Other Postretirement
Benefits

 2024
 2023
 2022
 2024
 2023
 2022

 Components of Net Periodic Benefit (Income) Cost(1)

 Service cost
 $
 21.9
 $
 20.5
 $
 27.8
 $
 5.0
 $
 5.1
 $
 6.5

 Interest cost
 64.9
 68.4
 40.5
 22.0
 21.8
 12.0

 Expected return on assets
 ( 95.3)
 ( 94.5)
 ( 90.8)
 ( 16.1)
 ( 15.1)
 ( 16.2)

 Amortization of prior service cost (credit)
 0.1
 0.1
 0.1
 ( 1.8)
 ( 2.1)
 ( 2.2)

 Recognized actuarial loss
 28.6
 33.7
 20.3
 3.2
 3.3
 2.6

 Settlement loss

 7.2
 9.2
 12.4
 —
 —
 —

 Total Net Periodic Benefits Cost

 $
 27.4
 $
 37.4
 $
 10.3
 $
 12.3
 $
 13.0
 $
 2.7

 (1)Service cost is presented in "Operation and maintenance" on the Statements of Consolidated Income. Non-service cost components are presented within "Other, net."

 The following table provides the key assumptions that were used to calculate the net periodic benefits cost for our various plans:

 Other Postretirement
Benefits

 2024
 2023
 2022
 2024
 2023
 2022

 Weighted-average Assumptions to Determine Net Periodic Benefit Cost

 Discount rate - service cost
 5.06
 %
 5.25
 %
 3.08
 %
 5.14
 %
 5.30
 %
 3.21
 %

 Discount rate - interest cost
 4.88
 %
 5.06
 %
 2.11
 %
 4.89
 %
 5.07
 %
 2.24
 %

 Expected Long-Term Rate of Return on Plan Assets
 7.02
 %
 7.00
 %
 4.80
 %
 7.06
 %
 6.96
 %
 5.72
 %

 Rate of Compensation Increases
 4.00
 %
 4.00
 %
 4.00
 %
 N/A
 N/A
 N/A

 Interest Crediting Rates
 4.00
 %
 4.00
 %
 4.00
 %
 N/A
 N/A
 N/A

 We assumed a 7.02 % and 7.06 % rate of return on pension and other postretirement plan assets, respectively, for our calculation of 2024 pension benefits and other postretirement benefits costs. These rates were primarily based on asset mix and historical rates of return and were adjusted in 2024 due to changes in asset allocation and projected market returns.
 The following table provides other changes in plan assets and projected benefit obligations recognized in other comprehensive income or regulatory asset or liability:

 Other Postretirement
Benefits

 2024
 2023
 2024
 2023

 Other Changes in Plan Assets and Projected Benefit Obligations
Recognized in Other Comprehensive Income or Regulatory Asset
or Liability

 Net prior service cost
 $
 —
 $
 —
 $
 —
 $
 3.3

 Net actuarial (gain) loss

 ( 13.1)
 ( 20.9)
 ( 26.4)
 16.0

 Settlements/curtailments
 ( 7.2)
 ( 9.2)
 —
 —

 Less: amortization of prior service cost
 1.8
 2.1

 Less: amortization of net actuarial loss
 ( 28.6)
 ( 33.7)
 ( 3.2)
 ( 3.3)

 Total Recognized in Other Comprehensive Income or Regulatory
Asset or Liability
 $
 ( 49.0)
 $
 ( 63.9)
 $
 ( 27.8)
 $
 18.1

 Amount Recognized in Net Periodic Benefits Cost and Other
Comprehensive Income or Regulatory Asset or Liability
 $
 ( 21.6)
 $
 ( 26.5)
 $
 ( 15.5)
 $
 31.1

 17. Share-Based Compensation
 Prior to May 19, 2020, we issued share-based compensation to employees and non-employee directors under the NiSource Inc. 2010 Omnibus Plan ("2010 Omnibus Plan"), which was most recently approved by stockholders at the Annual Meeting of Stockholders held on May 12, 2015. The 2010 Omnibus Plan provided for awards to employees and non-employee directors of incentive and nonqualified stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance units, cash-based awards and other stock-based awards and superseded the Director Stock Incentive Plan ("Director Plan") with respect to grants made after the effective date of the 2010 Omnibus Plan.
 The stockholders approved and adopted the NiSource Inc. 2020 Omnibus Incentive Plan ("2020 Omnibus Plan") at the Annual Meeting of Stockholders held on May 19, 2020. The 2020 Omnibus Plan provides for awards to employees and non-employee directors of incentive and nonqualified stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance units, cash-based awards and other stock-based awards and supersedes the 2010 Omnibus Plan with respect to grants made after the effective date of the 2020 Omnibus Plan.
 The 2020 Omnibus Plan provides that the number of shares of common stock of NiSource available for awards is 10,000,000 plus the number of shares subject to outstanding awards that expire or terminate for any reason that were granted under the

 2020 Omnibus Plan, the 2010 Omnibus Plan or any other equity plan under which awards were outstanding as of May 19, 2020. At December 31, 2024, there were 7,216,823 shares available for future awards under the 2020 Omnibus Plan.
 We recognized stock-based employee compensation expense of $ 32.1 million, $ 23.9 million and $ 19.0 million, during 2024, 2023 and 2022, respectively, as well as related tax benefits of $ 7.0 million, $ 7.7 million and $ 3.6 million, respectively. We recognized related excess tax benefits from the distribution of vested share-based employee compensation of $ 2.0 million, $ 2.9 million, and $ 0.4 million in 2024, 2023 and 2022, respectively.
 As of December 31, 2024, the total remaining unrecognized compensation cost related to non-vested awards amounted to $ 46.7 million, which will be amortized over the weighted-average remaining requisite service period of 1.8 years.
 Restricted Stock Units and Restricted Stock. We granted 655,713, 500,968, and 477,292 restricted stock units and shares of restricted stock to employees, subject to service conditions in 2024, 2023, and 2022, respectively. The total grant date fair value of the restricted stock units and shares of restricted stock during 2024, 2023, and 2022, respectively, was $ 17.1 million, $ 13.7 million, and $ 12.5 million. The grant date fair value for the 2024 and 2023 awards is based on the average market price of our common stock at the date of each grant. For the year ended 2022, the grant date fair value is based on the average market price of our common stock at the date of each grant less the present value of any dividends not received during the vesting period. The awards are expensed over the vesting period which is generally three years. As of December 31, 2024, 592,490, 393,509, and 270,325 non-vested restricted stock units and shares of restricted stock granted in 2024, 2023, and 2022, respectively, were outstanding. Our non-vested restricted stock units have a non-forfeitable right to dividend equivalents, with immaterial amounts paid in the periods ending December 31, 2024 and 2023. See Note 5, "Earnings Per Share," for further discussion.
 In general, if an employee terminates employment before the service conditions lapse under the 2022, 2023 or 2024 awards due to (1) retirement or disability (as defined in the 2020 Omnibus Plan), or (2) death, the service conditions will lapse on the date of such termination with respect to a pro rata portion of the restricted stock units and shares of restricted stock based upon the percentage of the service period satisfied between the grant date and the date of the termination of employment. In the event of a change in control (as defined in the 2020 Omnibus Plan), all unvested shares of restricted stock and restricted stock units awarded will immediately vest upon termination of employment occurring in connection with a change in control. Termination due to any other reason, in general, will result in all unvested shares of restricted stock and restricted stock units awarded being forfeited effective on the employee's date of termination.
 A summary of our restricted stock unit award transactions for the year ended December 31, 2024 is as follows:

 (shares)
 Restricted Stock
Units
 Weighted Average
Award Date Fair
Value Per Unit ($)

 Non-vested at December 31, 2023

 1,066,916
 25.71

 Granted
 655,713
 26.10

 Forfeited
 ( 167,057)
 26.19

 Vested
 ( 227,452)
 22.90

 Non-vested at December 31, 2024

 1,328,120
 26.49

 Employee Performance Shares. We granted 896,363 performance shares subject to service, performance and/or market-based vesting conditions in 2024. The performance conditions for these shares are based on the achievement of one non-GAAP financial measure, achievement of relative total shareholder return, and other operational metrics, which make up 55%, 25%, and 20% of the issued awards respectively.
 The non-GAAP financial measure is cumulative adjusted earnings per share, which we define as diluted earnings per share adjusted for certain items. Relative total shareholder return, a market-based vesting condition, which we define as the annualized growth in dividends and share price of a share of our common stock (calculated using a 20 trading day average of our closing price over the performance period, approximately) compared to the total shareholder return of a predetermined peer group of companies. A Monte Carlo analysis was used to value the portion of these awards dependent on the market-based vesting condition. The grant date fair value of the non-GAAP financial measure shares is based on the closing stock price of our common stock at the date of each grant, which will be expensed over the requisite service period of three years. The conditions

 for the remaining performance-based awards are based on operational goals of Annual Operational Index Scorecard (10%), Employee Engagement Index Score (5%), and Environmental Greenhouse Gas Reduction (5%).
 In 2023, we granted 649,088 performance shares subject to service, performance and/or market-based vesting conditions. The performance conditions for these shares are based on the achievement of one non-GAAP financial measure, achievement of relative total shareholder return, and other operational metrics, which make up 50%, 25%, and 25% of the issued awards respectively. The operational metrics consist of goals of economic inclusion (5%), OPEX ("Operating Expenses") Index (10%), Employee Engagement Index Score (5%), and Environmental GHG Reduction (5%). The OPEX Index is further defined by goals related to risk mitigation and modernization of our infrastructure.
 In 2022, we granted 566,086 performance shares subject to service, performance and/or market-based vesting conditions. The performance conditions for these shares are based on the achievement of one non-GAAP financial measure, and/or achievement of relative total shareholder return, outlined above. The number of shares that are eligible to vest based on these performance conditions are adjusted based on performance of the magnifier framework for 2022 awards. The operational magnifier framework for 2022 performance shares consists of three areas of focus, including safety, environment, and workforce, representing 20%, 10% and 10%, respectively.
 The following table presents details of the performance awards described above.

 Award Year
 Service Conditions Lapse date
 Performance Period
 Award Conditions
 Shares outstanding at 12/31/2024
 (shares)

 Grant Date Fair Value

 2024
 2/26/2027
 01/01/2024-
 12/31/2026

 Non-GAAP Financial and Operational Measures

 619,673
 $
 17.4

 Relative Total Shareholder Return
 206,524
 $
 6.9

 2023
 2/28/2026
 01/01/2023-
 12/31/2025

 Non-GAAP Financial and Operational Measures

 430,670
 $
 13.3

 Relative Total Shareholder Return
 143,540
 $
 5.4

 2022
 2/28/2025
 01/01/2022-
 12/31/2024

 Non-GAAP Financial Measure
 195,460
 $
 7.4

 Relative Total Shareholder Return
 195,460
 $
 10.6

 A summary of our performance award transactions for the year ended December 31, 2024 is as follows:

 (shares)
 Performance
Awards
 Weighted Average
Grant Date Fair
Value Per Unit ($)

 Non-vested at December 31, 2023

 1,558,509
 28.01

 Granted
 896,363
 27.05

 Forfeited
 ( 189,080)
 31.75

 Vested
 ( 546,569)
 21.95

 Non-vested at December 31, 2024

 1,719,223
 24.96

 Non-employee Director Awards. As of May 19, 2020, awards to non-employee directors may be made only under the 2020 Omnibus Plan. Currently, restricted stock units are granted annually to non-employee directors, subject to a non-employee director's election to defer receipt of such restricted stock unit award. The non-employee director's annual award of restricted stock units vest on the first anniversary of the grant date subject to special pro-rata vesting rules in the event of retirement or

 disability (as defined in the award agreement), or death. The vested restricted stock units are payable as soon as practicable following vesting except as otherwise provided pursuant to the non-employee director's deferral election. Certain restricted stock units remain outstanding from the 2010 Omnibus Plan and the Director Plan. All such awards are fully vested and shall be distributed to the directors upon their separation from the Board.
 As of December 31, 2024, 292,566 restricted stock units are outstanding to non-employee directors under either the 2020 Omnibus Plan, the 2010 Omnibus Plan or the Director Plan. Of this amount, 68,436 restricted stock units are unvested and expected to vest.
 401(k) Match, Profit Sharing and Company Contribution. Eligible salaried employees hired after January 1, 2010 and hourly and union employees hired after January 1, 2013 receive a non-elective company contribution of 4.5 % of eligible pay payable in cash or shares of NiSource common stock. We also have a voluntary 401(k) savings plan covering eligible union and nonunion employees that allows for periodic discretionary matches as a percentage of each participant's contributions payable in cash or shares. Further, we have a retirement savings plan that provides for discretionary profit sharing contributions to eligible employees. For the years ended December 31, 2024, 2023 and 2022, we recognized 401(k) match, profit sharing and non-elective contribution expense of $ 56.9 million, $ 50.7 million and $ 39.1 million, respectively.

 18. Leases
 Lease Descriptions. We are the lessee for substantially all of our leasing activity, which includes operating and finance leases for corporate and field offices, railcars, land, and fleet vehicles. Our corporate and field office leases and certain land leases have remaining terms between 1 and 39 years with options to renew the leases for up to 35 years. We lease railcars to transport coal to and from our electric generation facilities in Indiana. Our railcars are specifically identified in the lease agreements which have remaining lease terms between 1 and 3 years with options to renew for 1 year. Our fleet vehicles include trucks, trailers and equipment that have been customized specifically for use in the utility industry. We lease fleet vehicles for 1 year terms, after which we have the option to extend on a month-to-month basis or terminate with written notice. We elected the short-term lease practical expedient, allowing us to not recognize ROU assets or lease liabilities for all leases with a term of 12 months or less. ROU assets and liabilities on our Consolidated Balance Sheets do not include obligations for possible fleet vehicle lease renewals beyond the initial lease term. While we have the ability to renew these leases beyond the initial term, we are not reasonably certain to do so.
 We have not provided material residual value guarantees for our leases, nor do our leases contain material restrictions or covenants. Lease contracts containing renewal and termination options are mostly exercisable at our sole discretion. Certain of our real estate and railcar leases include renewal periods in the measurement of the lease obligation if we have deemed the renewals reasonably certain to be exercised.
 With respect to service contracts involving the use of assets, if we have the right to direct the use of the asset and obtain substantially all economic benefits from the use of an asset, we account for the service contract as a lease. Unless specifically provided to us by the lessor, we utilize NiSource's collateralized incremental borrowing rate commensurate to the lease term as the discount rate for all of our leases. ASC 842 permits a lessee, by class of underlying asset, not to separate nonlease components from lease components. Our policy is to apply this expedient for our leases of fleet vehicles, IT assets and railcars when calculating their respective lease liabilities.
 Lease costs for the years ended December 31, 2024 and December 31, 2023 are presented in the table below. These costs include both amounts recognized in expense and amounts capitalized as part of the cost of another asset. Income statement presentation for these costs (when ultimately recognized on the income statement) is also included:

 Income Statement Classification
 2024
 2023

 Finance lease cost

 Amortization of right-of-use assets
 $
 27.1
 $
 32.0

 Interest on lease liabilities
 Interest expense, net
 13.5
 8.6

 Total finance lease cost
 40.6
 40.6

 Operating lease cost
 Operation and maintenance
 14.7
 11.3

 Total lease cost
 $
 55.3
 $
 51.9

 Our right-of-use assets and liabilities are presented in the following lines on the Consolidated Balance Sheets:

 Balance Sheet Classification
 2024
 2023

 Net Property, Plant and Equipment
 $
 222.9
 $
 184.3

 Deferred charges and other
 26.4
 32.9

 Total leased assets
 $
 249.3
 217.2

 Current

 Current portion of long-term debt
 $
 22.9
 23.8

 Other accruals
 9.1
 8.3

 Noncurrent

 Long-term debt, excluding amounts due within one year
 223.3
 181.6

 Other noncurrent liabilities and deferred credits

 18.2
 25.8

 Total lease liabilities
 $
 273.5
 $
 239.5

 Other pertinent information related to leases was as follows:

 2024
 2023

 Cash paid for amounts included in the measurement of lease liabilities

 Operating cash flows used for finance leases
 $
 11.2
 $
 9.3

 Operating cash flows used for operating leases
 14.5
 11.1

 Financing cash flows used for finance leases
 26.9
 33.1

 Right-of-use assets obtained in exchange for lease obligations

 65.9
 64.5

 $
 12.2
 $
 5.6

 Weighted-average remaining lease term (years)

 20.5
 16.4

 5.6
 6.7

 Weighted-average discount rate

 5.6
 %
 5.5
 %

 4.5
 %
 4.3
 %

 Maturities of our lease liabilities as of December 31, 2024 were as follows:

 As of December 31, 2024, (in millions)

 Total
 Finance Leases
 Operating Leases

 2025
 $
 44.6
 $
 34.6
 $
 10.0

 2026
 34.7
 29.4
 5.3

 2027
 28.5
 24.2
 4.3

 2028
 26.1
 23.0
 3.1

 2029
 21.5
 19.0
 2.5

 Thereafter
 304.9
 299.2
 5.7

 Total lease payments
 460.3
 429.4
 30.9

 Less: Imputed interest
 ( 186.8)
 ( 183.2)
 ( 3.6)

 Total

 $
 273.5
 $
 246.2
 $
 27.3

 Reported as of December 31, 2024

 Short-term lease liabilities
 32.0
 22.9
 9.1

 Long-term lease liabilities
 241.5
 223.3
 18.2

 Total lease liabilities
 $
 273.5
 $
 246.2
 $
 27.3

 19. Other Commitments and Contingencies

 A. Contractual Obligations. We have certain contractual obligations requiring payments at specified periods. The obligations include long-term debt, lease obligations, energy commodity contracts and obligations for various services including pipeline capacity and outsourcing of IT services. The total contractual obligations in existence at December 31, 2024 and their maturities were:

 Total
 2025
 2026
 2027
 2028
 2029
 After

 Long-term debt (1)

 $
 13,205.0
 $
 1,260.0
 $
 —
 $
 1,090.0
 $
 1,055.0
 $
 1,350.0
 $
 8,450.0

 Interest payments on long-term debt
 8,090.3
 566.2
 551.1
 531.7
 481.6
 453.9
 5,505.8

 Finance leases(2)

 429.4
 34.6
 29.4
 24.2
 23.0
 19.0
 299.2

 Operating leases(3)

 30.9
 10.0
 5.3
 4.3
 3.1
 2.5
 5.7

 Energy commodity contracts
 119.7
 118.5
 0.3
 0.3
 0.4
 0.2
 —

 Service obligations:

 Pipeline service obligations
 2,694.6
 685.5
 631.2
 609.2
 373.2
 245.2
 150.3

 IT service obligations
 120.7
 73.9
 30.3
 11.4
 5.1
 —
 —

 Plant equipment purchase obligations

 173.5
 140.5
 24.9
 4.3
 3.8
 —
 —

 Other liabilities(4)

 336.0
 287.0
 7.9
 7.7
 7.6
 7.7
 18.1

 Total contractual obligations
 $
 25,200.1
 $
 3,176.2
 $
 1,280.4
 $
 2,283.1
 $
 1,952.8
 $
 2,078.5
 $
 14,429.1

 (1) Long-term debt balance excludes unamortized issuance costs and discounts of $ 95.5 million.
 (2) Finance lease payments shown above are inclusive of interest totaling $ 183.2 million.
 (3) Operating lease payments shown above are inclusive of interest totaling $ 3.6 million. Operating lease balances do not include obligations for possible fleet vehicle lease renewals beyond the initial lease term. While we have the ability to renew these leases beyond the initial term, we are not reasonably certain to do so as they are renewed month-to-month after the first year.
 (4)Other liabilities shown above are primarily related to the Dunns Bridge II and Indiana Crossroads Solar Developer payments due in 2025 and ongoing maintenance service agreements for our renewable joint ventures.
 Purchase and Service Obligations. We have entered into various purchase and service agreements whereby we are contractually obligated to make certain minimum payments in future periods. Our energy commodity contracts are for the purchase of physical quantities of natural gas, electricity and coal. Our service obligations, consisting of pipeline service obligations and IT service obligations, encompass a broad range of business support and maintenance functions which are generally described below. Our plant equipment purchase obligations are for plant equipment, typically for generation assets, with long lead times that require payments made over time
 Our subsidiaries have entered into various energy commodity contracts to purchase physical quantities of natural gas, electricity and coal. These amounts represent the minimum quantity of these commodities we are obligated to purchase at both fixed and variable prices. To the extent contractual purchase prices are variable, obligations disclosed in the table above are valued at market prices as of December 31, 2024.
 NIPSCO has PPAs representing a total of 600 MW of wind power, with contracts expiring between 2038 and 2040. No minimum quantities are specified within these agreements due to the variability of electricity generation from wind, so no amounts related to these contracts are included in the table above. Upon early termination of one of these agreements by NIPSCO for any reason (other than material breach by the counterparties), NIPSCO may be required to pay a termination charge that could be material depending on the events giving rise to termination and the timing of the termination.
 We have pipeline service agreements that provide for pipeline capacity, transportation and storage services. These agreements, which have expiration dates ranging from 2028 to 2038, require us to pay fixed monthly charges.
 NIPSCO has contracts with three major rail operators providing coal transportation services for which there are certain minimum payments. These service contracts extend for various periods through 2025.
 We have executed agreements with multiple IT service providers. The agreements extend for various periods through 2029.

 B. Guarantees and Indemnities. We and certain of our subsidiaries enter into various agreements providing financial or performance assurance to third parties on behalf of certain subsidiaries as part of normal business. Such agreements include guarantees and stand-by letters of credit. These agreements are entered into primarily to support or enhance the creditworthiness otherwise attributed to a subsidiary on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish the subsidiaries' intended commercial purposes. At December 31, 2024 and 2023, we issued stand-by letters of credit of $ 9.4 million and $ 9.9 million, respectively, for the benefit of third parties.
 We provide guarantees related to our future performance under BTAs for our renewable generation projects. At December 31, 2024 and 2023, our guarantees for multiple BTAs totaled $ 1,127.5 million and $ 646.1 million, respectively. The amount of each guaranty will decrease upon completion of certain milestones for the construction of the facilities, including mechanical and substantial completion. See "- E. Other Matters - Generation Transition," below for more information.
 We provide guarantees related to some of our rail and pipeline service agreements. If we do not meet our contractual obligations under the terms of these agreements we would be required to pay up to a maximum of $ 61.7 million.

 C. Legal Proceedings. From time to time, various legal and regulatory claims and proceedings are pending or threatened against the Company and its subsidiaries. While the amounts claimed may be substantial, the Company is unable to predict with certainty the ultimate outcome of such claims and proceedings. The Company establishes reserves whenever it believes it to be appropriate for pending litigation matters. However, the actual results of resolving the pending litigation matters may be substantially higher than the amounts reserved. If one or more other matters were decided against us, the effects could be material to our results of operations in the period in which we would be required to record or adjust the related liability and could also be material to our cash flows in the periods that we would be required to pay such liability. Due to the inherent uncertainty of litigation, there can be no assurance that the resolution of any particular claim, proceeding or investigation would not have a material adverse effect on our results of operations, financial position or liquidity.

 Other Claims and Proceedings. We are also party to certain other claims, regulatory and legal proceedings arising in the ordinary course of business in each state in which we have operations, and based upon an investigation of these matters and discussion with legal counsel, we believe the ultimate outcome of such other legal proceedings to be individually, or in aggregate, not material at this time.

 D. Environmental Matters. Our operations are subject to environmental statutes and regulations related to air quality, water quality, hazardous waste and solid waste. We believe that we are in substantial compliance with the environmental regulations currently applicable to our operations.
 It is management's continued intent to address environmental issues in cooperation with regulatory authorities in such a manner as to achieve mutually acceptable compliance plans. However, there can be no assurance that fines and penalties will not be incurred. Management expects the majority of environmental assessment and remediation costs and asset retirement costs, further described below, to be recoverable through rates. See Note 11, "Asset Retirement Obligations" and Note 12, "Regulatory Matters," for additional detail.
 As of December 31, 2024 and 2023, we had recorded a liability of $ 91.8 million and $ 80 million, respectively, to cover environmental remediation at various sites. This liability is included in "Other accruals" and "Other noncurrent liabilities and deferred credits" in the Consolidated Balance Sheets. We recognize costs associated with environmental remediation obligations when the incurrence of such costs is probable and the amounts can be reasonably estimated. The original estimates for remediation activities may differ materially from the amount ultimately expended. The actual future expenditures depend on many factors, including laws and regulations, the nature and extent of impact and the method of remediation. These expenditures are not currently estimable at some sites. We periodically adjust our liability as information is collected and estimates become more refined.
 CERCLA. Our subsidiaries are potentially responsible parties at waste disposal sites under the CERCLA and similar state laws. Under CERCLA, each potentially responsible party can be held jointly, severally and strictly liable for the remediation costs as the EPA, or state, can allow the parties to pay for remedial action or perform remedial action themselves and request reimbursement from the potentially responsible parties. Our affiliates have retained CERCLA environmental liabilities, including remediation liabilities, associated with certain current and former operations. At this time, we cannot estimate the full cost of remediating properties that have not yet been investigated, but it is possible that the future costs could be material to the Consolidated Financial Statements.

 MGP. We maintain a program to identify and investigate former MGP sites where gas distribution subsidiaries or predecessors may have liability. The program has identified 51 such sites where liability is probable. Remedial actions at many of these sites are being overseen by state or federal environmental agencies through consent agreements or voluntary remediation agreements.
 We utilize a probabilistic model to estimate our future remediation costs related to MGP sites. The model was prepared with the assistance of a third party and incorporates our experience and general industry experience with remediating MGP sites. We complete an annual refresh of the model in the second quarter of each fiscal year. We recorded an $ 11.2 million increase to the estimated future remediation costs as a result of the refresh completed in the second quarter of 2024. No material changes to the estimated future remediation costs were noted as a result of an internal quarterly review of environmental reserves completed as of December 31, 2024. Our total estimated liability related to the facilities subject to remediation was $ 86.4 million and $ 73.7 million at December 31, 2024 and 2023, respectively. The liability represents our best estimate of the probable cost to remediate the MGP sites. Our model indicates that it is reasonably possible that remediation costs could vary by as much as $ 16.3 million in addition to the costs noted above. Remediation costs are estimated based on the best available information, applicable remediation standards at the balance sheet date, and experience with similar facilities.
 CCRs. NIPSCO continues to meet the compliance requirements established by the EPA for the regulation of CCRs. The CCR rule requirements currently in effect required revisions to previously recorded legal obligations associated with the retirement of certain NIPSCO facilities. The actual asset retirement costs related to the CCR rule may vary substantially from the estimates used to record the increased asset retirement obligation due to the uncertainty about the requirements that will be established by environmental authorities, compliance strategies that will be used and the preliminary nature of available data used to estimate costs. As allowed by the rule, NIPSCO will continue to collect data over time to determine the specific compliance solutions and associated costs and, as a result, the actual costs may vary.
 On May 8, 2024, the EPA finalized changes to the current CCR regulations ("Legacy CCR Rule") which address inactive surface impoundments at inactive facilities, referred to as legacy impoundments, and CCR management units ("CCRMUs") at inactive and active facilities. The rule largely requires these newly regulated units to conform to existing requirements, such as groundwater monitoring, closure requirements, and post-closure care. During 2024, we recorded additional asset retirement obligations of $ 149.7 million to cover probable and estimable compliance activities associated with the Legacy CCR Rule with an offsetting regulatory asset. Facility evaluations for CCRMUs are required by February 2026 and 2027. NIPSCO continues to assess whether existing legal obligations associated with the retirement of certain facilities must be revised and to estimate probable additional required asset retirement costs. NIPSCO expects to receive recovery of any such costs through existing and future depreciation rates.

 E. Other Matters
 Generation Transition. NIPSCO has executed several BTAs with developers to construct renewable generation facilities. NIPSCO has received IURC approval for all of its BTAs and PPAs. In October 2024, NIPSCO contracted with a developer to convert the previously approved Templeton Wind PPA to a BTA and has provided a notice of intent to file a CPCN with the IURC. In addition to IURC approval, NIPSCO's purchase obligation under certain BTAs is dependent on timely completion of construction. Certain agreements require NIPSCO to make partial payments upon the developer's completion of significant construction milestones. With respect to BTAs for which tax equity partnerships are utilized, once the tax equity partner has earned its negotiated rate of return and we have reached the agreed upon contractual date, NIPSCO has the option to purchase at fair market value the remaining interest in the JV from the tax equity partner. In January 2024, the IURC approved the full ownership of Cavalry and Dunns Bridge II which will allow those BTAs to be executed through direct ownership. In March 2024, Cavalry achieved mechanical completion, resulting in NIPSCO making a $ 110.6 million payment to the developer. In May 2024, Cavalry achieved substantial completion and commenced commercial operations, resulting in NIPSCO making a $ 114.9 million payment to the developer. In August 2024, the IURC approved full ownership of the Gibson and Fairbanks projects as well as an increase to the cost of the Fairbanks project. In January 2025, Fairbanks achieved mechanical completion resulting in NIPSCO making a $ 336.6 million payment to the developer. In September 2024, Dunns Bridge II achieved mechanical completion, resulting in NIPSCO making a $ 153.3 million payment to the developer. In January 2025, substantial completion was achieved requiring a final payment of $ 217.6 million to be paid in February 2025. NIPSCO has filed a request to modify the ownership structure for the Templeton wind project to become a wholly owned project.
 NIPSCO Minority Interest Transaction. On December 31, 2023, pursuant to the terms of the BIP Purchase Agreement and simultaneously with the closing of the NIPSCO Minority Interest Transaction, Blackstone, NIPSCO Holdings I, NIPSCO

 Holdings II and NiSource entered into an Amended and Restated Limited Liability Company Agreement (the "LLC Agreement") of NIPSCO Holdings II. Specifically, under the terms of the LLC Agreement, Blackstone will provide up to $ 250 million in additional capital contributions over a three-year period after the closing, which the obligation is backed by an Equity Commitment Letter from an affiliate of Blackstone. Under the LLC Agreement, Blackstone is entitled to appoint two directors to the board of directors of NIPSCO Holdings II (the "Board") so long as Blackstone (together with any approved affiliate) holds at least a 17.5 % percentage interest (as defined in the LLC Agreement). In connection with the closing, Blackstone appointed two directors to the Board, such that the Board is now comprised of seven directors, two appointed by Blackstone and five appointed by NiSource. The LLC Agreement also contains certain investor protections, including, among other things, requiring Blackstone approval for Holdings II to take certain major actions. In addition, the LLC Agreement contains certain terms regarding transfer rights and other obligations applicable to both Blackstone and NiSource. The LLC Agreement establishes, among other things, governance rights, exit rights, requirements for additional capital contributions, mechanics for distributions, and other arrangements for Holdings II following the closing. On January 31, 2024, BIP transferred a 4.5 % equity interest in NIPSCO Holdings II to BIP Blue Buyer VCOC L.L.C., a Delaware limited liability company and also an affiliate of Blackstone. Effective upon the closing of this transfer, the members of NIPSCO Holdings II entered into a Second Amended and Restated Limited Liability Company Operating Agreement of NIPSCO Holdings II (the "Amended LLC Agreement"). The two affiliates of Blackstone must vote their equity holdings under the Amended LLC Agreement as one investor.

 Refer to Note 4, "Noncontrolling Interests," for detailed discussion of accounting for the NIPSCO Minority Interest Transaction.

 20. Accumulated Other Comprehensive Loss
 The following table displays the activity of Accumulated Other Comprehensive Loss, net of tax:

 Gains and Losses on Securities(1)

 Gains and Losses on Cash Flow Hedges(1)

 Pension and OPEB Items(1)

 Accumulated
 Other
 Comprehensive
 Loss(1)

 Balance as of January 1, 2022

 $
 2.1
 $
 ( 122.5)
 $
 $
 ( 126.8)

 Other comprehensive (loss) income before reclassifications

 ( 13.7)
 109.7
 ( 8.9)
 87.1

 Amounts reclassified from accumulated other comprehensive loss
 0.4
 0.2
 2.0
 2.6

 Net current-period other comprehensive (loss) income

 ( 13.3)
 109.9
 ( 6.9)
 89.7

 Balance as of December 31, 2022
 $
 ( 11.2)
 $
 ( 12.6)
 $
 ( 13.3)
 $
 ( 37.1)

 Other comprehensive (loss) income before reclassifications

 3.1
 ( 0.5)
 ( 1.4)
 1.2

 Amounts reclassified from accumulated other comprehensive loss
 0.8
 0.3
 1.2
 2.3

 Net current-period other comprehensive (loss) income

 3.9
 3.5

 $
 ( 7.3)
 $
 ( 12.8)
 $
 ( 13.5)
 $
 ( 33.6)

 Other comprehensive income (loss) before reclassifications
 1.5
 —
 ( 1.2)
 0.3

 Amounts reclassified from accumulated other comprehensive loss
 1.8
 1.5
 2.9

 Net current-period other comprehensive income (loss)
 3.3
 0.3
 3.2

 $
 ( 4.0)
 $
 ( 13.2)
 $
 ( 13.2)
 $
 ( 30.4)

 (1)All amounts are net of tax. Amounts in parentheses indicate debits.

 21. Business Segment Information
 Our reportable segments reflect the manner in which our business is managed and our resources are allocated. Following the consummation of the NIPSCO Minority Interest Transaction, we revised how we evaluate results and allocate resources across our business with an increased focus on operating performance at the state level. Refer to Note 4, "Noncontrolling Interests," for additional information on the NIPSCO Minority Interest Transaction. At December 31, 2024, our operations are divided into two primary reportable segments, the Columbia Operations and the NIPSCO Operations segments. Columbia Operations aggregates the results of the fully regulated and wholly owned subsidiaries of NiSource Gas Distribution Group, Inc. (a holding company that owns Columbia of Kentucky, Columbia of Maryland, Columbia of Ohio, Columbia of Pennsylvania, and Columbia of Virginia). Each Columbia distribution company is an operating segment which we aggregate to form the Columbia Operations reportable segment. NIPSCO Operations includes the results of NIPSCO Holdings I and its majority-owned subsidiaries, including NIPSCO, which has fully regulated gas and electric operations in northern Indiana. Our historical segment disclosures have been recast to be consistent with the current presentation.
 The remainder of our operations, which are not significant enough on a stand-alone basis to warrant treatment as an operating segment, are presented as "Corporate and Other" in the subsequent reconciliation table and primarily are comprised of interest expense on holding company debt and unallocated corporate costs and activities. Refer to Note 3, "Revenue Recognition," for additional information on our segments and their sources of revenues. The following table provides information about our reportable segments. We use operating income as our primary measurement for each of the reported segments and make decisions on financing, dividends and taxes at the corporate level on a consolidated basis. We provide this measure to our Chief Operating Decision Maker, the CEO, who utilizes this measure to make operating segment level strategy decisions based on budget-to-actual variances and against prior periods to allocate resources accordingly. Segment revenues include intersegment sales to affiliated subsidiaries, which are eliminated in consolidation. Affiliated sales are recognized on the basis of prevailing market, regulated prices or at levels provided for under contractual agreements. Operating income is derived from revenues and expenses directly associated with each segment.

 Year Ended December 31, 2024 (in millions)

 Total of Reportable Segments

 External Revenue

 $
 2,703.2
 $
 2,751.0
 $
 5,454.2

 Intersegment Revenue

 12.8
 1.0
 13.8

 $
 2,716.0
 $
 2,752.0
 $
 5,468.0

 514.7
 617.5
 1,132.2

 O&M

 837.5
 761.4
 1,598.9

 Depreciation
 409.1
 590.3
 999.4

 Total other taxes

 218.6
 64.3
 282.9

 Other segment items(1)

 7.4
 ( 1.3)
 6.1

 $
 728.7
 $
 719.8
 $
 1,448.5

 Capital Expenditures(2)

 $
 1,209.0
 $
 2,252.4
 $
 3,461.4

 $
 14,769.5
 $
 15,823.5
 $
 30,593.0

 (1)Other segment items consists of Loss (gain) on Sale or Impairment of Assets and other segment income or expenses deemed insignificant which are used to reach our measurement of segment profit or loss, Operating Income.
 (2)Amounts differ from those presented on the Statements of Consolidated Cash Flows primarily due to the inclusion of capital expenditures in current liabilities, the capitalized portion of the Corporate Incentive Plan payout, and AFUDC Equity.

 Year Ended December 31, 2023 (in millions)

 Total of Reportable Segments

 External Revenue

 $
 2,733.9
 $
 2,770.7
 $
 5,504.6

 Intersegment Revenue

 12.2
 0.9
 13.1

 $
 2,746.1
 $
 2,771.6
 $
 5,517.7

 645.0
 888.3
 1,533.3

 O&M

 792.3
 787.7
 1,580.0

 Depreciation
 371.7
 493.8
 865.5

 Total other taxes

 198.8
 57.9
 256.7

 Other segment items(1)

 —
 2.2
 2.2

 $
 738.3
 $
 541.7
 $
 1,280.0

 Capital Expenditures(2)

 $
 1,159.6
 $
 1,294.8
 $
 2,454.4

 $
 13,664.5
 $
 13,962.6
 $
 27,627.1

 (1)Other segment items consists of Loss(gain) on Sale or Impairment of Assets and other segment income or expenses deemed insignificant which are used to reach our measurement of segment profit or loss, Operating Income.
 (2)Amounts differ from those presented on the Statements of Consolidated Cash Flows primarily due to the inclusion of capital expenditures in current liabilities, the capitalized portion of the Corporate Incentive Plan payout, and AFUDC Equity.

 Year Ended December 31, 2022 (in millions)

 Total of Reportable Segments

 External Revenue

 $
 2,951.9
 $
 2,886.2
 $
 5,838.1

 Intersegment Revenue

 12.5
 0.9
 13.4

 $
 2,964.4
 $
 2,887.1
 $
 5,851.5

 978.4
 1,132.1
 2,110.5

 O&M

 791.3
 740.4
 1,531.7

 Depreciation
 329.4
 449.4
 778.8

 Total other taxes

 184.2
 72.1
 256.3

 Other segment items(1)

 ( 103.9)
 —
 ( 103.9)

 $
 785.0
 $
 493.1
 $
 1,278.1

 Capital Expenditures(2)

 $
 1,237.9
 $
 1,018.9
 $
 2,256.8

 $
 13,059.4
 $
 11,759.9
 $
 24,819.3

 (1)Other segment items consists of proceeds from a property insurance settlement related to the Greater Lawrence Incident and other segment income or expenses deemed insignificant which are used to reach our measurement of segment profit or loss, Operating Income.
 (2)Amounts differ from those presented on the Statements of Consolidated Cash Flows primarily due to the inclusion of capital expenditures in current liabilities, the capitalized portion of the Corporate Incentive Plan payout, and AFUDC Equity.

 To reconcile the segment tables above to consolidated NiSource:

 Year Ended December 31, 2024 (in millions)

 Total Reportable Segments

 Eliminations

 Consolidated NiSource

 $
 5,468.0
 $
 581.9
 $
 ( 594.8)
 $
 5,455.1

 1,448.5
 7.0
 —
 1,455.5

 Capital Expenditures

 3,461.4
 231.1
 —
 3,692.5

 30,593.0
 1,195.1
 —
 31,788.1

 Year Ended December 31, 2023 (in millions)

 Total Reportable Segments

 Eliminations

 Consolidated NiSource

 $
 5,517.7
 $
 504.6
 $
 ( 516.9)
 $
 5,505.4

 1,280.0
 15.5
 —
 1,295.5

 Capital Expenditures

 2,454.4
 236.3
 —
 2,690.7

 27,627.1
 3,450.1
 —
 31,077.2

 Year Ended December 31, 2022 (in millions)

 Total Reportable Segments

 Eliminations

 Consolidated NiSource

 $
 5,851.5
 $
 477.5
 $
 ( 478.4)
 $
 5,850.6

 Operating Income (Loss)

 1,278.1
 ( 12.3)
 —
 1,265.8

 Capital Expenditures

 2,256.8
 41.2
 —
 2,298.0

 24,819.3
 1,917.3
 —
 26,736.6

 22. Other, Net
 The following table displays the components of Other, Net included on the Statements of Consolidated Income:

 2024
 2023
 2022

 Interest income
 $
 10.4
 $
 9.0
 $
 4.3

 AFUDC equity
 75.1
 25.2
 15.1

 Charitable contributions
 ( 5.4)
 ( 1.8)
 ( 4.4)

 Pension and other postretirement non-service cost(1)

 ( 13.5)
 ( 24.0)
 27.6

 Interest rate swap settlement gain

 —
 —
 10.0

 Miscellaneous
 ( 2.1)

 Total Other, net
 $
 64.5
 $
 8.0
 $
 52.2

 (1) See Note 16, "Pension and Other Postemployment Benefits," for additional information.

 23. Interest Expense, Net
 The following table displays the components of Interest Expense, Net included on the Statements of Consolidated Income:

 2024
 2023
 2022

 Interest on long-term debt
 $
 506.2
 $
 404.1
 $
 344.5

 Interest on short-term borrowings
 43.2
 108.9
 22.7

 Debt discount/cost amortization
 13.8
 13.5
 11.7

 Accounts receivable securitization fees
 1.5
 2.7
 2.5

 Allowance for borrowed funds used and interest capitalized during construction
 ( 40.1)
 ( 25.3)
 ( 6.7)

 Debt-based post-in-service carrying charges
 ( 26.4)
 ( 30.7)
 ( 21.1)

 Other
 19.0
 16.4
 8.0

 Total Interest Expense, net
 $
 517.2
 $
 489.6
 $
 361.6

 24. Supplemental Cash Flow Information
 The following table provides additional information regarding our Consolidated Statements of Cash Flows for the years ended December 31, 2024, 2023 and 2022:

 2024
 2023
 2022

 Supplemental Disclosures of Cash Flow Information

 Non-cash transactions:

 Capital expenditures included in current liabilities
 $
 367.0
 $
 315.0
 $
 275.1

 Assets acquired under a finance lease
 65.9
 64.5
 19.3

 Assets acquired under an operating lease
 12.2
 5.6
 8.8

 Assets recorded for asset retirement obligations(1)

 277.4
 61.1
 6.3

 Purchase contract liability, net of fees and payments(2)

 —
 —
 65.0

 Schedule of interest and income taxes paid:

 Cash paid for interest on debt, net of interest capitalized amounts

 $
 468.2
 $
 433.9
 $
 343.8

 Cash paid for interest on finance leases
 11.2
 8.6
 8.5

 Cash paid for income taxes, net of refunds

 4.3
 9.4
 7.2

 (1)See Note 11, "Asset Retirement Obligations," for additional information.
 (2)Refer to Note 6, "Equity," for additional information.

 SCHEDULE II – VALUATION AND QUALIFYING ACCOUNTS

 Twelve months ended December 31, 2024

 Additions

 ($ in millions)
 Balance Jan. 1, 2024
 Charged to Costs and Expenses
 Charged to Other Account (1)

 Deductions for Purposes for which Reserves were Created
 Balance Dec. 31, 2024

 Reserves Deducted in Consolidated Balance Sheet from Assets to Which They Apply:

 Reserve for accounts receivable
 $
 22.9
 $
 23.2
 $
 32.3
 $
 54.7
 $
 23.7

 Reserve for deferred charges and other
 1.3
 —
 —
 1.1

 Twelve months ended December 31, 2023

 Additions

 ($ in millions)
 Balance Jan. 1, 2023
 Charged to Costs and Expenses
 Charged to Other Account (1)

 Deductions for Purposes for which Reserves were Created
 Balance Dec. 31, 2023

 Reserves Deducted in Consolidated Balance Sheet from Assets to Which They Apply:

 Reserve for accounts receivable
 $
 23.9
 $
 23.4
 $
 36.6
 $
 61.0
 $
 22.9

 Reserve for deferred charges and other
 1.0
 —
 0.3
 —
 1.3

 Twelve months ended December 31, 2022

 Additions

 ($ in millions)
 Balance
Jan. 1, 2022
 Charged to Costs and Expenses
 Charged to Other Account (1)

 Deductions for Purposes for which Reserves were Created
 Balance
Dec. 31, 2022

 Reserves Deducted in Consolidated Balance Sheet from Assets to Which They Apply:

 Reserve for accounts receivable
 $
 23.5
 $
 20.6
 $
 36.4
 $
 56.6
 $
 23.9

 Reserve for deferred charges and other
 2.3
 —
 ( 1.3)
 —
 1.0

 (1) Charged to Other Accounts reflects the deferral of bad debt expense to a regulatory asset or the movement of the reserve between short term and long term.

 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

 None.

 ITEM 9A. CONTROLS AND PROCEDURES
 Evaluation of Disclosure Controls and Procedures
 Our CEO and CFO are responsible for evaluating the effectiveness of disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)). Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by the Company in reports that are filed or submitted under the Exchange Act are accumulated and communicated to management, including our CEO and CFO, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon that evaluation, our CEO and CFO concluded that, as of the end of the period covered by this report, disclosure controls and procedures were effective to provide reasonable assurance that financial information was processed, recorded and reported accurately.
 Management's Annual Report on Internal Control over Financial Reporting
 Our management, including our CEO and CFO, are responsible for establishing and maintaining internal control over financial reporting, as such term is defined under Rule 13a-15(f) or Rule 15d-15(f) promulgated under the Exchange Act. However, management would note that a control system can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Our management has adopted the 2013 framework set forth in the Committee of Sponsoring Organizations of the Treadway Commission report, Internal Control - Integrated Framework, the most commonly used and understood framework for evaluating internal control over financial reporting, as its framework for evaluating the reliability and effectiveness of internal control over financial reporting. During 2024, we conducted an evaluation of our internal control over financial reporting. Based on this evaluation, management concluded that our internal control over financial reporting was effective as of the end of the period covered by this Annual Report on Form 10-K.
 Deloitte & Touche LLP, our independent registered public accounting firm, issued an attestation report on our internal controls over financial reporting which is included herein.
 Changes in Internal Controls
 There have been no changes in our internal control over financial reporting during the most recently completed quarter covered by this report that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

 ITEM 9A. CONTROLS AND PROCEDURES

 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 To the shareholders and the Board of Directors of NiSource Inc.
 Opinion on Internal Control over Financial Reporting
 We have audited the internal control over financial reporting of NiSource Inc. and subsidiaries (the "Company") as of December 31, 2024, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2024, based on criteria established in Internal Control — Integrated Framework (2013) issued by COSO.

 We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as of and for the year ended December 31, 2024, of the Company and our report dated February 12, 2025, expressed an unqualified opinion on those financial statements.

 Basis for Opinion
 The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

 We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

 Definition and Limitations of Internal Control over Financial Reporting
 A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

 Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
 /s/ DELOITTE & TOUCHE LLP
 Columbus, Ohio
 February 12, 2025

 ITEM 9B. OTHER INFORMATION

 Director and Officer Trading Arrangements
 The following table describes any contracts, instructions or written plans for the sale or purchase of NiSource securities and intended to satisfy the affirmative defense conditions of Rule 10b5-1(c) of the Exchange Act that were adopted by our directors and executive officers during the year ended December 31, 2024:

 Name and Title

 Date of Adoption of Rule 10b-5-1 Trading Plan

 Scheduled Expiration Date of Rule 10b5-1 Trading Plan(1)

 Aggregate Number of Securities to Be Purchased or Sold

 Shawn Anderson Executive Vice President, Chief Financial Officer

 11/1/2024
 5/30/2025
 Sale of up to 12,900 shares of common stock in multiple transactions

 Michael Jesanis Director

 11/11/2024
 5/16/2025
 Sale of up to 10,092 shares of common stock in multiple transactions

 (1)A trading plan may also expire on such earlier date that all transactions under the trading plan are completed.

 During the year ended December 31, 2024, none of our directors or executive officers terminated a Rule 10b5-1 trading plan or adopted or terminated a non-Rule 10b5-1 trading arrangement (as defined in Item 408(c) of Regulation S-K).

 ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS
 Not applicable.

 ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

 Except for the information required by this item with respect to our executive officers included at the end of Part I of this report on Form 10-K and the information with respect to our insider trading policy set forth below, the information required by this Item 10 is incorporated herein by reference to the discussion in "Proposal 1 Election of Directors," "Corporate Governance - Board Committee Composition," "Corporate Governance - Code of Business Conduct," and "Delinquent Section 16(a) Reports" of the Proxy Statement for the Annual Meeting of Stockholders to be held on May 12, 2025.
 Insider Trading Policy
 The Company has adopted an Insider Trading Policy, our "Securities Transaction Compliance Policy", governing the purchase, sale, and/or other dispositions of the Company's securities by our directors and all employees, including officers as defined under Rule 16a-1(f) of the Securities Exchange Act of 1934 and certain designated employees as well as their immediate family and members of their households, that we believe is reasonably designed to promote compliance with insider trading laws, rules and regulations and the exchange listing standards applicable to us. A copy of our policy is filed as Exhibit 19.1 to this Annual Report on Form 10-K.

 ITEM 11. EXECUTIVE COMPENSATION
 The information required by this Item 11 is incorporated herein by reference to the discussion in "Compensation and Human Capital Committee Interlocks and Insider Participation," "2024 Director Compensation," "2024 Executive Compensation," "Compensation Discussion and Analysis (CD&A)," "Assessment of Risk," "2024 Pay Versus Performance," and "Compensation and Human Capital Committee Report" of the Proxy Statement for the Annual Meeting of Stockholders to be held on May 12, 2025.

 ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
 The information required by this Item 12 is incorporated herein by reference to the discussion in "Security Ownership of Certain Beneficial Owners and Management," and "Equity Compensation Plan Information" of the Proxy Statement for the Annual Meeting of Stockholders to be held on May 12, 2025.

 ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
 The information required by this Item 13 is incorporated herein by reference to the discussion in "Corporate Governance - Policies and Procedures with Respect to Transactions with Related Persons" and "Corporate Governance - Director Independence" of the Proxy Statement for the Annual Meeting of Stockholders to be held on May 12, 2025.

 ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
 The information required by this Item 14 is incorporated herein by reference to the discussion in "Independent Registered Public Accounting Firm Fees" of the Proxy Statement for the Annual Meeting of Stockholders to be held on May 12, 2025.

 ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

 Financial Statements and Financial Statement Schedules
 The following financial statements and financial statement schedules filed as a part of the Annual Report on Form 10-K are included in Item 8, "Financial Statements and Supplementary Data."

 Page

 Report of Independent Registered Public Accounting Firm (PCAOB ID: 34)

 Statements of Consolidated Income

 Statements of Consolidated Comprehensive Income

 Consolidated Balance Sheets

 Statements of Consolidated Cash Flows

 Statements of Consolidated Stockholders' Equity

 Schedule II

 Exhibits
 The exhibits filed herewith as a part of this report on Form 10-K are listed on the Exhibit Index below. Each management contract or compensatory plan or arrangement of ours, listed on the Exhibit Index, is separately identified by an asterisk.
 Pursuant to Item 601(b), paragraph (4)(iii)(A) of Regulation S-K, certain instruments representing long-term debt of our subsidiaries have not been included as Exhibits because such debt does not exceed 10% of the total assets of ours and our subsidiaries on a consolidated basis. We agree to furnish a copy of any such instrument to the SEC upon request.

 EXHIBIT
NUMBER
 DESCRIPTION OF ITEM

 (1.1)
 Form of Equity Distribution Agreement (incorporated by reference to Exhibit 1.1 of the NiSource Inc. Form 8-K filed on February 22, 2024).

 (1.2)
 Form of Master Forward Sale Confirmation (incorporated by reference to Exhibit 1.2 of the NiSource Inc. Form 8-K filed on February 22, 2024).

 (2.1)
 Separation and Distribution Agreement, dated as of June 30, 2015, by and between NiSource Inc. and Columbia Pipeline Group, Inc. (incorporated by reference to Exhibit 2.1 to the NiSource Inc. Form 8-K filed on July 2, 2015).

 (3.1)
 Articles of Incorporation of NiSource Inc., as amended and restated through October 21, 2024 (incorporated by
 reference to Exhibit 3.3 to the NiSource Inc. Form 8-K filed on October 22, 2024).

 (3.2)
 Bylaws of NiSource Inc., as amended and restated through October 21, 2024 (incorporated by reference to Exhibit 3.4 to the NiSource Inc. Form 8-K filed on October 22, 2024).

 (3.3)
 Certificate of Designations of 6.50% Series B Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Stock (incorporated by reference to Exhibit 3.1 of the NiSource Inc. Form 8-K filed on December 6, 2018).

 (3.4)
 Certificate of Designations of Series B-1 Preferred Stock (incorporated by reference to Exhibit 3.1 to the NiSource Inc. Form 8-K filed on December 27, 2018).

 (3.5)
 Certificate of Elimination of the Company with respect to the Series B Preferred Stock and Series B-1 Preferred Stock (incorporated by reference to Exhibit 3.1 of the NiSource Inc. Form 8-K filed on March 18, 2024).

 (3.6)
 Certificate of Elimination of the Company with respect to the Series C Preferred Stock, dated October 21, 2024, issued by NiSource Inc. (incorporated by reference to Exhibit 3.1 of the NiSource Inc. Form 8-K filed on October 22, 2024).

 (3.7)
 Certificate of Elimination of the Company with respect to the Series A Junior Participating Preferred Stock, dated October 21, 2024, issued by NiSource Inc. (incorporated by reference to Exhibit 3.2 of the NiSource Inc. Form 8-K filed on October 22, 2024).

 (4.1)
 Indenture, dated as of March 1, 1988, by and between Northern Indiana Public Service Company ("NIPSCO") and Manufacturers Hanover Trust Company, as Trustee (incorporated by reference to Exhibit 4 to the NIPSCO Registration Statement (Registration No. 33-44193)).

 (4.2)
 First Supplemental Indenture, dated as of December 1, 1991, by and between Northern Indiana Public Service Company and Manufacturers Hanover Trust Company, as Trustee (incorporated by reference to Exhibit 4.1 to the NIPSCO Registration Statement (Registration No. 33-63870)).

 (4.3)
 Indenture Agreement, dated as of February 14, 1997, by and between NIPSCO Industries, Inc., NIPSCO Capital Markets, Inc. and Chase Manhattan Bank as trustee (incorporated by reference to Exhibit 4.1 to the NIPSCO Industries, Inc. Registration Statement (Registration No. 333-22347)).

 (4.4)
 Second Supplemental Indenture, dated as of November 1, 2000, by and among NiSource Capital Markets, Inc., NiSource Inc., New NiSource Inc., and The Chase Manhattan Bank, as trustee (incorporated by reference to Exhibit 4.45 to the NiSource Inc. Form 10-K for the period ended December 31, 2000).

 (4.5)
 Indenture, dated November 14, 2000, among NiSource Finance Corp., NiSource Inc., as guarantor, and The Chase Manhattan Bank, as Trustee (incorporated by reference to Exhibit 4.1 to the NiSource Inc. Form S-3, dated November 17, 2000 (Registration No. 333-49330)).

 (4.6)
 Form of 3.490% Notes due 2027 (incorporated by reference to Exhibit 4.1 to the NiSource Inc. Form 8-K filed on May 17, 2017).

 (4.7)
 Form of 4.375% Notes due 2047 (incorporated by reference to Exhibit 4.2 to the NiSource Inc. Form 8-K filed on May 17, 2017).

 (4.8)
 Form of 3.950% Notes due 2048 (incorporated by reference to Exhibit 4.1 to the NiSource Inc. Form 8-K filed on September 8, 2017).

 (4.9)
 Second Supplemental Indenture, dated as of November 30, 2017, between NiSource Inc. and The Bank of New York Mellon, as trustee (incorporated by reference to Exhibit 4.4 to Post-Effective Amendment No. 1 to Form S-3 filed November 30, 2017 (Registration No. 333-214360)).

 (4.10)
 Third Supplemental Indenture, dated as of November 30, 2017, between NiSource Inc. and The Bank of New York Mellon, as trustee (incorporated by reference to Exhibit 4.2 to the NiSource Inc. Form 8-K filed on December 1, 2017).

 (4.11)
 Second Supplemental Indenture, dated as of February 12, 2018, between Northern Indiana Public Service Company and The Bank of New York Mellon, solely as successor trustee under the Indenture dated as of March 1, 1988 between the Company and Manufacturers Hanover Trust Company, as original trustee. (incorporated by reference to Exhibit 4.1 to the NiSource Inc. Form 10-Q filed on May 2, 2018).

 (4.12)
 Fourth Supplemental Indenture, dated as of December 18, 2023, between NiSource, Inc. and The Bank of New York Mellon, as trustee, relating to the 7.99% Medium-Term Notes due 2027 and the 6.78% Senior Notes due 2027 (incorporated by reference to Exhibit 10.1 to the NiSource Inc. Form 8-K filed on December 18, 2023).

 (4.13)
 Subordinated Indenture, dated as of May 16, 2024, between NiSource Inc. and The Bank of New York Mellon, as trustee (incorporated by reference to Exhibit 4.2 to the NiSource Form 8-K filed on May 16, 2024).

 (4.14)
 First Supplemental Indenture, dated as of May 16, 2024, between NiSource Inc. and The Bank of New York Mellon, as trustee (incorporated by reference to Exhibit 4.3 to the NiSource Form 8-K filed on May 16, 2024).

 (4.15)
 Second Supplemental Indenture, dated as of September 09, 2024, between NiSource Inc. and The Bank of New York Mellon, as trustee (incorporated by reference to Exhibit 4.2 to the NiSource Form 8-K filed on September 09, 2024).

 (4.16)
 Deposit Agreement, dated as of December 5, 2018, among NiSource, Inc., Computershare Inc. and Computershare Trust Company, N.A., acting jointly as depositary, and the holders from time to time of the depositary receipts described therein (incorporated by reference to Exhibit 4.1 of the NiSource Inc. Form 8-K filed on December 6, 2018).

 (4.17)
 Form of Depositary Receipt (incorporated by reference to Exhibit 4.1 of the NiSource Inc. Form 8-K filed on December 6, 2018).

 (4.18)
 Amended and Restated Deposit Agreement, dated as of December 27, 2018, among NiSource, Inc., Computershare Inc. and Computershare Trust Company, N.A., acting jointly as depositary, and the holders from time to time of the depositary receipts described therein (incorporated by reference to Exhibit 4.1 to the NiSource Inc. Form 8-K filed on December 27, 2018).

 (4.19)
 Form of Depositary Receipt (incorporated by reference to Exhibit 4.1 to the NiSource Inc. Form 8-K filed on December 27, 2018).

 (4.20)
 Form of 2.950% Notes due 2029 (incorporated by reference to Exhibit 4.1 to NiSource Inc. Form 8-K filed on August 12, 2019).

 (4.21)
 Amended and Restated NiSource Inc. Employee Stock Purchase Plan (incorporated by reference to Exhibit C to the Registrant's Definitive Proxy Statement on Schedule 14A, filed with the Commission on April 1, 2019).

 (4.22)
 Form of 3.600% Notes due 2030 (incorporated by reference to Exhibit 4.1 to the NiSource Inc. Form 8-K filed on April 8, 2020).

 (4.23)
 Form of 0.950% Notes due 2025 (incorporated by reference to Exhibit 4.1 to the NiSource Inc. Form 8-K filed on August 18, 2020).

 (4.24)
 Form of 1.700% Notes due 2031(incorporated by reference to Exhibit 4.2 to the NiSource Inc. Form 8-K filed on August 18, 2020).

 (4.25)
 Form of 5.000% Notes due 2052 (incorporated by reference to Exhibit 4.1 of the NiSource Inc. Form 8-K filed on June 10, 2022).

 (4.26)
 Form of 5.250% Notes due 2028 (incorporated by reference to Exhibit 4.1 to the NiSource Inc. Form 8-K filed on March 24, 2023).

 (4.27)
 Form of 5.400% Notes due 2033 (incorporated by reference to Exhibit 4.2 to the NiSource Inc. Form 8-K filed on June 9, 2023).

 (4.28)
 Form of 5.350% Notes due 2034 (incorporated by reference to Exhibit 4.1 to the NiSource Inc. Form 8-K filed on March 14, 2024).

 (4.29)
 Form of 6.950% Fixed-to-Fixed Reset Rate Junior Subordinated Notes due 2054 (incorporated by reference to Exhibit 4.1 to the NiSource Inc. Form 8-K filed on May 16, 2024).

 (4.30)
 Form of 5.200% Notes due 2029 (incorporated by reference to Exhibit 4.1 to the NiSource Inc. Form 8-K filed on June 24, 2024).

 (4.31)
 Form of 6.375% Fixed-to-Fixed Reset Rate Junior Subordinated Notes due 2055 (incorporated by reference to Exhibit 4.1 to the NiSource Inc. Form 8-K filed on September 09, 2024).

 (4.32)
 Description of NiSource Inc.'s Securities Registered Under Section 12 of the Exchange Act. **

 (4.33)
 Form of 6.25% Notes due 2040 (incorporated by reference to Exhibit 4.1 to the NiSource Inc. Form 8-K filed on December 6, 2010).

 (4.34)
 Form of 5.95% Notes due 2041 (incorporated by reference to Exhibit 4.1 to the NiSource Inc. Form 8-K filed on June 10, 2011).

 (4.35)
 Form of 5.80% Notes due 2042 (incorporated by reference to Exhibit 4.2 to the NiSource Inc. Form 8-K filed on November 17, 2011).

 (4.36)
 Form of 5.25% Notes due 2043 (incorporated by reference to Exhibit 4.2 to the NiSource Inc. Form 8-K filed on June 14, 2012).

 (4.37)
 Form of 4.80% Notes due 2044 (incorporated by reference to Exhibit 4.1 to the NiSource Inc. Form 8-K filed on April 12, 2013).

 (4.38)
 Form of 5.65% Notes due 2045 (incorporated by reference to Exhibit 4.1 to the NiSource Inc. Form 8-K filed on October 7, 2013).

 (10.1)
 2010 Omnibus Incentive Plan (incorporated by reference to Exhibit B to the NiSource Inc. Definitive Proxy Statement to Stockholders for the Annual Meeting held on May 11, 2010, filed on April 2, 2010).*

 (10.2)
 First Amendment to the 2010 Omnibus Incentive Plan (incorporated by reference to Exhibit 10.2 to the NiSource Inc. Form 10-K filed on February 18, 2014.)*

 (10.3)
 2010 Omnibus Incentive Plan (incorporated by reference to Exhibit C to the NiSource Inc. Definitive Proxy Statement to Stockholders for the Annual Meeting held on May 12, 2015, filed on April 7, 2015).*

 (10.4)
 Second Amendment to the NiSource Inc. 2010 Omnibus Incentive Plan (incorporated by reference to Exhibit 10.1 to the NiSource Inc. Form 8-K filed October 23, 2015.)*

 (10.5)
 Form of Amendment to Restricted Stock Unit Award Agreement related to Vested but Unpaid NiSource Restricted Stock Unit Awards for Nonemployee Directors of NiSource entered into as of July 13, 2015 (incorporated by reference to Exhibit 10.3 to the NiSource Inc. Form 10-Q filed on November 3, 2015).*

 (10.6)
 Supplemental Life Insurance Plan effective January 1, 1991, as amended, (incorporated by reference to Exhibit 2 to the NIPSCO Industries, Inc. Form 8-K filed on March 25, 1992).*

 (10.7)
 Form of Restricted Stock Unit Award Agreement for Nonemployee Directors under the 2010 Omnibus Incentive Plan (incorporated by reference to Exhibit 10.1 to NiSource Inc. Form 10-Q filed on August 2, 2011).*

 (10.8)
 Form of Restricted Stock Unit Award Agreement for Nonemployee Directors under the 2010 Omnibus Incentive Plan (incorporated by reference to Exhibit 10.18 to the NiSource Inc. Form 10-K filed on February 22, 2017). *

 (10.9)
 Amended and Restated NiSource Inc. Executive Deferred Compensation Plan effective November 1, 2012 (incorporated by reference to Exhibit 10.21 to the NiSource Inc. Form 10-K filed on February 19, 2013).*

 (10.10)
 Amended and Restated Executive Deferred Compensation Plan, dated August 12, 2024 (incorporated by reference to Exhibit 10.1 of the NiSource Inc. Form 10-Q filed on October 30, 2024).*

 (10.11)
 Note Purchase Agreement, dated as of August 23, 2005, by and among NiSource Finance Corp., as issuer, NiSource Inc., as guarantor, and the purchasers named therein (incorporated by reference to Exhibit 10.1 to the NiSource Inc. Current Report on Form 8-K filed on August 26, 2005).

 (10.12)
 Amendment No. 1, dated as of November 10, 2008, to the Note Purchase Agreement by and among NiSource Finance Corp., as issuer, NiSource Inc., as guarantor, and the purchasers whose names appear on the signature page thereto (incorporated by reference to Exhibit 10.30 to the NiSource Inc. Form 10-K filed on February 27, 2009).

 (10.13)
 Form of Change in Control and Termination Agreement (incorporated by reference to Exhibit 10.1 to the NiSource Inc. Form 10-Q filed on August 2, 2017).*

 (10.14)
 Registration Rights Agreement, dated as of May 2, 2018, by and among NiSource Inc. and the purchasers named therein (incorporated by reference to Exhibit 10.2 of the NiSource Inc. Form 8-K filed on May 2, 2018).

 (10.15)
 Amended and Restated NiSource Inc. Employee Stock Purchase Plan adopted as of February 1, 2019 (incorporated by reference to Exhibit C to the NiSource Inc. Definitive Proxy Statement to Stockholders for the Annual Meeting to be held on May 7, 2019, filed on April 1, 2019).

 (10.16)
 Amended and Restated NiSource Inc. Employee Stock Purchase Plan adopted as of January 25, 2024 (incorporated by reference to Appendix B to the NiSource Inc. Definitive Proxy Statement to Stockholders for the Annual Meeting to be held on May 13, 2024, filed on April 1, 2024).

 (10.17)
 Form of Cash-Based Award Agreement (incorporated by reference to Exhibit 10.41 of the NiSource Form 10-K filed on February 28, 2020). *

 (10.18)
 2020 Omnibus Incentive Plan (incorporated by reference to Exhibit A to the NiSource Inc. Definitive Proxy Statement to Stockholders for the Annual Meeting held on May 19, 2020, filed on April 13, 2020).*

 (10.19)
 Form of Restricted Stock Unit Award Agreement for Nonemployee Directors under the 2020 Omnibus Incentive Plan (incorporated by reference to Exhibit 10.2 of the NiSource Inc. Form 10-Q filed on August 5, 2020).*

 (10.2)
 NiSource Inc. Supplemental Executive Retirement Plan, as amended and restated effective November 1, 2020 (incorporated by reference to Exhibit 10.4 to the NiSource Inc. Form 10-Q filed on November 2, 2020).*

 (10.21)
 Pension Restoration Plan for NiSource Inc. and Affiliates, as amended and restated effective November 1, 2020 (incorporated by reference to Exhibit 10.5 to the NiSource Inc. Form 10-Q filed on November 2, 2020).

 (10.22)
 Savings Restoration Plan for NiSource Inc. and Affiliates, as amended and restated effective November 1, 2020 (incorporated by reference to Exhibit 10.6 to the NiSource Inc. Form 10-Q filed on November 2, 2020).*

 (10.23)
 First Amendment to the Savings Restoration Plan for NiSource Inc. and Affiliates dated October 12, 2023 and effective November 1, 2020 (incorporated by reference to Exhibit 10.24 to the NiSource Inc. Form 10-K filed on February 21, 2024).*

 (10.24)
 NiSource Inc. Executive Severance Policy, as amended and restated effective October 19, 2020 (incorporated by reference to Exhibit 10.7 to the NiSource Inc. Form 10-Q filed on November 2, 2020).*

 (10.25)
 NiSource Next Voluntary Separation Program, effective as of August 5, 2020 (incorporated by reference to Exhibit 10.8 to the NiSource Inc. Form 10-Q filed on November 2, 2020).*

 (10.26)
 Form of Restricted Stock Unit Award Agreement. (incorporated by reference to Exhibit 10.53 to the NiSource Inc. Form 10-K filed on February 17, 2021).*

 (10.27)
 Form of Performance Share Unit Award Agreement. (incorporated by reference to Exhibit 10.54 to the NiSource Inc. Form 10-K filed on February 17, 2021).*

 (10.28)
 Form of Special Performance Share Unit Award Agreement. (incorporated by reference to Exhibit 10.55 to the NiSource Inc. Form 10-K filed on February 17, 2021).*

 (10.29)
 Sixth Amended and Restated Revolving Credit Agreement, dated as of February 18, 2022, among NiSource Inc., as Borrower, the Lenders party thereto, Barclays Bank PLC, as Administrative Agent, JPMorgan Chase Bank, N.A. and MUFG Bank, Ltd., as Co-Syndication Agents, Credit Suisse AG, New York Branch, Wells Fargo Bank, National Association, and Bank of America, National Association, as Co-Documentation Agents, Barclays Bank PLC and MUFG Bank, Ltd., as Co-Sustainability Structuring Agents, and Barclays Bank PLC, JPMorgan Chase Bank, N.A. MUFG Bank, Ltd., Credit Suisse Loan Funding LLC, Wells Fargo Securities, LLC, and BofA Securities, Inc., as Joint Lead Arrangers and Joint Bookrunners (incorporated by reference to Exhibit 10.1 of the NiSource Inc. Form 8-K filed on February 18, 2022).

 (10.3)
 Amendment No. 1 to the Sixth Amended and Restated Revolving Credit Agreement dated February 18, 2022, made as of August 23, 2023 by and among NiSource Inc., the financial institutions listed on the signature pages and Barclays Bank PLC, as administrative agent (incorporated by reference to Exhibit 10.1 to the NiSource Inc. Form 8-K filed on August 23, 2023).

 (10.31)
 First Amendment to the NiSource Inc. 2020 Omnibus Incentive Plan (incorporated by reference to Exhibit 10.1 of the NiSource Inc. Form 10-Q filed on May 4, 2022).

 (10.32)
 Credit Agreement, dated as of December 20, 2022, among NiSource Inc., as Borrower, the lenders party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent, PNC Capital Markets LLC, as Syndication Agent, Bank of America, N.A. and Wells Fargo Bank, N.A., as Co-Documentation Agents and JPMorgan Chase Bank, N.A., PNC Capital Markets LLC, Bank of America, N.A. and Wells Fargo Securities, LLC, as Joint Lead Arrangers and Joint Bookrunners (incorporated by reference to Exhibit 10.1 of the NiSource Inc. Form 8-K filed on December 20, 2022).

 (10.33)
 Amendment No. 1 to the Credit Agreement dated December 20, 2022, made as of October 5, 2023 by and among NiSource Inc., the financial institutions listed on the signature pages and JPMorgan Chase Bank, N.A., as administrative agent (incorporated by reference to Exhibit 10.1 to the NiSource Inc. Form 8-K filed on October 5, 2023).

 (10.34)
 Credit Agreement, dated as of November 9, 2023, among NiSource Inc., as Borrower, the lenders party there to, and U.S. Bank National Association, as Administrative Agent, as Sole Lead Arranger and Bookrunner (incorporated by reference to Exhibit 10.1 to the NiSource Inc. Form 8-K filed on November 9, 2023).

 (10.35)
 Augmenting Lender Supplement, dated December 6, 2023, by and among NiSource Inc., Mizuho Bank, LTD, Bank of Montreal. and U.S. Bank National Association (incorporated by reference to Exhibit 10.1 to the NiSource Inc. Form 8-K filed on December 6, 2023).

 (10.36)
 Form of Restricted Stock Unit Award Agreement.(incorporated by reference to Exhibit 10.57 to the NiSource Inc. Form 10-K filed on February 22, 2023).*

 (10.37)
 Form of Performance Share Unit Award Agreement (incorporated by reference to Exhibit 10.58 to the NiSource Inc. Form 10-K filed on February 22, 2023).*

 (10.38)
 Form of Restricted Stock Unit Award Agreement. (incorporated by reference to Exhibit 10.59 to the NiSource Inc. Form 10-K filed on February 22, 2023).*

 (10.39)
 Form of Performance Share Unit Award Agreement. (incorporated by reference to Exhibit 10.60 to the NiSource Inc. Form 10-K filed on February 22, 2023).*

 (10.40)
 Purchase and Sale Agreement, dated as of June 17, 2023, among NiSource Inc., as the Parent, NIPSCO Holdings II LLC, as the Company, and BIP BLUE BUYER L.L.C., as the Investor (incorporated by reference to Exhibit 10.1 to the NiSource Inc. Form 8-K filed on June 20, 2023).

 (10.41)
 Amendment No. 1 to the Purchase and Sale Agreement, dated as of July 6, 2023, among NiSource Inc., as the Parent, NIPSCO Holdings II LLC, as the Company, and BIP BLUE BUYER L.L.C., as the Investor (incorporated by reference to Exhibit 10.2 of the NiSource Inc. Form 10-Q filed on August 2, 2023).****

 (10.42)
 Amended and Restated Limited Liability Company Agreement of NIPSCO Holdings II LLC, dated December 31, 2023 (incorporated by reference to Exhibit 10.1 of the NiSource Inc. Form 8-K filed on January 2, 2024).****

 (10.43)
 Second Amended and Restated Limited Liability Company Agreement of NIPSCO Holdings II LLC, dated January 30, 2024 (incorporated by reference to Exhibit 10.44 to the NiSource Inc. Form 10-K filed on February 21, 2024).*

 (10.44)
 Form of 2024 CEO RSU Award Agreement (incorporated by reference to Exhibit 10.1 of the NiSource Inc. Form 8-K filed on January 26, 2024).*

 (10.45)
 Form of 2024 CEO PSU Award Agreement (incorporated by reference to Exhibit 10.2 of the NiSource Inc. Form 8-K filed on January 26, 2024).*

 (10.46)
 Form of RSU Award Agreement (for awards on or after 2024) (incorporated by reference to Exhibit 10.3 of the NiSource Inc. Form 8-K filed on January 26, 2024).*

 (10.47)
 Form of PSU Award Agreement (for awards on or after 2024) (incorporated by reference to Exhibit 10.48 to the NiSource Inc. Form 10-K filed on February 22, 2023).****

 (10.48)
 Separation Agreement dated March 15, 2024, between NiSource Inc. and Donald Brown (incorporated by reference to Exhibit 10.1 to the NiSource Inc. Form 8-K filed on March 15, 2024).

 (19.1)
 Securities Transaction Compliance Policy **

 (21)
 List of Subsidiaries. **

 (23)
 Consent of Deloitte & Touche LLP. **

 (31.1)
 Certification of Chief Executive Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. **

 (31.2)
 Certification of Chief Financial Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. **

 (32.1)
 Certification of Chief Executive Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith). **

 (32.2)
 Certification of Chief Financial Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith). **

 (97.1)
 NiSource Inc. Compensation Recoupment Policy. **

 (101.INS)

 (101.SCH)

 (101.CAL)

 (101.LAB)

 (101.PRE)

 (101.DEF)

 (104)

 *
 Management contract or compensatory plan or arrangement of NiSource Inc.

 **
 Exhibit filed herewith.

 ***
 Schedules and exhibits have been omitted pursuant to Item 601(b)(2) of Regulation S-K. NiSource agrees to furnish supplementally a copy of any omitted schedules or exhibits to the SEC upon request.

 ****

 Schedules and similar attachments to this Exhibit have been omitted pursuant to Item 601(a)(5) of Regulation S-K. The Company agrees to furnish supplementally a copy of any omitted schedule or exhibit to the U.S. Securities and Exchange Commission (the "SEC") upon request.

 References made to NIPSCO filings can be found at Commission File Number 001-04125. References made to NiSource Inc. filings made prior to November 1, 2000 can be found at Commission File Number 001-09779.

 ITEM 16. FORM 10-K SUMMARY
 None.

 SIGNATURES
 Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, hereunto duly authorized.

 NiSource Inc.

 (Registrant)

 By:
 /s/ LLOYD M. YATES

 Lloyd M. Yates

 President, Chief Executive Officer and Director

 (Principal Executive Officer)

 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

 /s/
 LLOYD M. YATES
 President, Chief Executive Officer,

 Lloyd M. Yates
 and Director
 (Principal Executive Officer)

 /s/
 SHAWN ANDERSON
 Executive Vice President and

 Shawn Anderson
 Chief Financial Officer
(Principal Financial Officer)

 /s/
 GUNNAR J. GODE
 Vice President and

 Gunnar J. Gode

 Chief Accounting Officer
(Principal Accounting Officer)

 /s/
 KEVIN T. KABAT
 Chairman of the Board

 Kevin T. Kabat

 /s/
 PETER A. ALTABEF

 Peter A. Altabef

 /s/
 SONDRA L. BARBOUR

 Sondra L. Barbour

 /s/
 THEODORE H. BUNTING, JR.

 Theodore H. Bunting, Jr.

 /s/
 ERIC L. BUTLER

 Eric L. Butler

 /s/
 DEBORAH A. HENRETTA

 Deborah A. Henretta

 /s/
 DEBORAH A.P. HERSMAN

 Deborah A. P. Hersman

 /s/
 WILLIAM D. JOHNSON

 William D. Johnson

 /s/
 MICHAEL E. JESANIS

 Michael E. Jesanis

 /s/
 CASSANDRA S. LEE

 Cassandra S. Lee

 /s/
 JOHN MCAVOY

 John McAvoy