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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, 2022
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
Depositary Shares, each representing a 1/1,000th ownership interest in a share of 6.50% Series B Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Stock, par value $0.01 per share, liquidation preference $25,000 per share and a 1/1,000th ownership interest in a share of Series B-1 Preferred Stock, par value $0.01 per share, liquidation preference $0.01 per share | NI PR B | NYSE
Series A Corporate Units | NIMC | NYSE

Securities registered pursuant to Section 12(g) of the Act: None
I ndicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes þ 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 þ
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 þ 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 þ 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 þ 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 þ
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 $11,950,785,429 based upon the June 30, 2022, closing price of $29.49 on the New York Stock Exchange.
There were 412,507,944 shares of Common Stock outstanding as of February 15, 2023.
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 23, 2023.

CONTENTS

|  | Page No.
Defined Terms | 3
Part I |  |
Item 1. | Business | 6
Item 1A. | Risk Factors | 16
Item 1B. | Unresolved Staff Comments | 32
Item 2. | Properties | 32
Item 3. | Legal Proceedings | 32
Item 4 | Mine Safety Disclosures | 32
Part II |  |
Item 5. | Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities | 33
Item 6. | Reserved | 34
Item 7. | Management’s Discussion and Analysis of Financial Condition and Results of Operations | 35
Item 7A. | Quantitative and Qualitative Disclosures About Market Risk | 54
Item 8. | Financial Statements and Supplementary Data | 55
Item 9. | Changes in and Disagreements With Accountants on Accounting and Financial Disclosure | 119
Item 9A. | Controls and Procedures | 119
Item 9B. | Other Information | 121
Item 9C. | Disclosure Regarding Foreign Jurisdictions that Prevent Inspections | 121
Part III |  |
Item 10. | Directors, Executive Officers and Corporate Governance | 122
Item 11. | Executive Compensation | 122
Item 12. | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters | 122
Item 13. | Certain Relationships and Related Transactions, and Director Independence | 122
Item 14. | Principal Accounting Fees and Services | 122
Part IV |  |
Item 15. | Exhibits, Financial Statement Schedules | 123
Item 16. | Form 10-K Summary | 130
Signatures | 131

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DEFINED TERMS
The following is a list of frequently used abbreviations or acronyms that are found in this report:
NiSource Subsidiaries and Affiliates |  |
Columbia of Kentucky |  | Columbia Gas of Kentucky, Inc.
Columbia of Maryland |  | Columbia Gas of Maryland, Inc.
Columbia of Massachusetts |  | Bay State Gas Company
Columbia of Ohio |  | 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
NiSource ("we," "us" or "our") |  | NiSource Inc.
Rosewater |  | Rosewater Wind Generation LLC and its wholly owned subsidiary, Rosewater Wind Farm LLC
Indiana Crossroads Wind |  | Indiana Crossroads Wind Generation LLC and its wholly owned subsidiary, Indiana Crossroads Wind Farm 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
BTA |  | Build-transfer agreement
CAP |  | Compliance Assurance Process
CCGT |  | Combined Cycle Gas Turbine
CCRs |  | Coal Combustion Residuals
CEP |  | Capital Expenditure Program
CERCLA |  | Comprehensive Environmental Response Compensation and Liability Act (also known as Superfund)
Corporate Units |  | Series A Corporate Units
COVID-19 ("the COVID-19 pandemic" or "the pandemic") |  | Novel Coronavirus 2019 and its variants, including the Delta and Omicron variants, and any other variant that may emerge
DE&I |  | Diversity Equity and Inclusion
DPU |  | Department of Public Utilities
DSM |  | Demand Side Management
EPA |  | United States Environmental Protection Agency
EPS |  | Earnings per share
Equity Units |  | Series A Equity Units
FAC |  | Fuel adjustment clause
FERC |  | Federal Energy Regulatory Commission
FMCA |  | Federally Mandated Cost Adjustment
GAAP |  | Generally Accepted Accounting Principles
GCA |  | Gas cost adjustment
GHG |  | Greenhouse gases
HLBV |  | Hypothetical Liquidation at Book Value
IRA |  | Inflation Reduction Act
IRP |  | Infrastructure Replacement Program
IRS |  | Internal Revenue Service

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DEFINED TERMS
IURC |  | Indiana Utility Regulatory Commission
JV |  | Joint Venture
LDCs |  | Local distribution companies
LIBOR |  | London InterBank Offered Rate
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
NOL |  | Net Operating Loss
NTSB |  | National Transportation Safety Board
NYMEX |  | The New York Mercantile Exchange
OPEB |  | Other Postretirement and Postemployment Benefits
PCB |  | Polychlorinated biphenyls
PHMSA |  | Pipeline and Hazardous Materials Safety Administration
PPA |  | Power Purchase Agreement
PSC |  | Public Service Commission
PUC |  | Public Utilities Commission
ROE |  | Return on Equity
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
U.S. Attorney's Office |  | U.S. Attorney's Office for the District of Massachusetts
VIE |  | Variable Interest Entity

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,"
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"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; potential incidents and other operating risks associated with our business; our ability to adapt to, and manage costs related to, advances in 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 natural gas costs 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 demands; the attraction and retention of a qualified, diverse workforce and ability to maintain good labor relations; our ability to manage new initiatives and organizational changes; the actions of activist stockholders; the performance of third-party suppliers and service providers; potential cybersecurity attacks; increased requirements and costs related to cybersecurity; any damage to our reputation; any remaining liabilities or impact related to the sale of the Massachusetts Business; 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 ability to manage the financial and operational risks related to achieving our carbon emission reduction goals, including our Net Zero Goal (as defined below); our debt obligations; any changes to our credit rating or the credit rating of certain of our subsidiaries; any adverse effects related to our equity units; adverse economic and capital market conditions or increases in interest rates; inflation; recessions; economic regulation and the impact of regulatory rate reviews; our ability to obtain expected financial or regulatory outcomes; continuing and potential future impacts from the COVID-19 pandemic; 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; potential remaining liabilities related to the Greater Lawrence Incident; compliance with the agreements entered into with the U.S. Attorney’s Office to settle the U.S. Attorney’s Office’s investigation relating to the Greater Lawrence Incident; compliance with applicable laws, regulations and tariffs; compliance with environmental laws and the costs of associated liabilities; changes in taxation; 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.
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ITEM 1. BUSINESS
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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 3.7 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 natural gas distribution holding company, and NIPSCO, a gas and electric company. NiSource derives substantially all of its revenues and earnings from the operating results of these rate-regulated businesses.
Business Strategy
We focus our business strategy on providing safe and reliable service through our core, rate-regulated asset-based utilities, with the goal of adding value to all stakeholders. Our utilities continue to make progress on core safety, infrastructure and environmental investment programs supported by complementary regulatory and customer initiatives across all six states in which we operate. Our goal is to develop strategies that benefit all stakeholders as we (i) embark on long-term infrastructure investment and safety programs to better serve our customers, (ii) align our tariff structures with our cost structure, and (iii) address changing customer conservation patterns. These strategies focus on improving safety and reliability, enhancing customer service, 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.
NiSource remains 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. In 2022, NiSource achieved conformance certification to the American Petroleum Institute Recommended Practice 1173, which serves as the guiding practice for our SMS. This certification marks an important milestone for our SMS and NiSource’s journey towards operational excellence. Moving forward, our focus shifts to maintaining, sustaining and continuously improving the process, procedures, capabilities and talent to enhance safety and reduce operational risk. Additionally, we continue to pursue regulatory and legislative initiatives that will allow customers not currently on our system to obtain gas and electric service in a cost effective manner.
NiSource has two reportable segments: Gas Distribution Operations and Electric Operations. The remainder of our operations, which are not significant enough on a stand-alone basis to warrant treatment as an operating segment, are included as Corporate and Other. The activities occurring within this non-segment consist of our centralized financing and treasury 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.
Gas Distribution Operations
Our natural gas distribution operations serve approximately 3.3 million customers in six states. Through our wholly-owned subsidiary NiSource Gas Distribution Group, Inc., we own five distribution subsidiaries that provide natural gas to approximately 2.4 million residential, commercial and industrial customers in Ohio, Pennsylvania, Virginia, Kentucky, and Maryland. Additionally, we distribute natural gas to approximately 859,000 customers in northern Indiana through our wholly-owned subsidiary NIPSCO. We operate approximately 54,800 miles of distribution main pipeline plus the associated individual customer service lines and 1,000 miles of transmission main pipeline located in our service areas described below. Throughout our service areas we also have gate stations and other operations support facilities.
Competition. Open access to natural gas supplies over interstate pipelines and the deregulation of the natural gas supply has led to tremendous change in the energy markets and natural gas competition. Due to open access to natural gas supplies, LDC customers can purchase gas directly from producers and marketers in an open, competitive market. This separation or “unbundling” of the transportation and other services offered by LDCs allows customers to purchase the commodity independent of services provided by LDCs. LDCs continue to purchase gas and recover the associated costs from their customers. Certain of our Gas Distribution Operations’ 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 Gas Distribution Operations’ subsidiaries for transportation services. As of December 31, 2022, 24.5% of our residential customers and 33.3% of our commercial customers participated in such programs.
Gas Distribution Operations competes with (i) investor-owned, municipal, and cooperative electric utilities throughout its service areas, (ii) other regulated and unregulated natural gas intra and interstate pipelines and (iii) other alternate fuels, such as propane and fuel oil. Gas Distribution Operations continues to be a strong competitor in the energy market as a result of strong
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customer preference for natural gas. Competition with providers of electricity has traditionally been the strongest in the residential and commercial markets of Kentucky, southern Ohio, central Pennsylvania and western Virginia due to comparatively low electric rates.
Additionally, our gas distribution operations are subject to seasonal fluctuations in sales. Revenues from gas distribution operations are more significant during the heating season, which is primarily from November through March. Please refer to Part II, Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations - Results and Discussion of Segment Operations - Gas Distribution Operations," for additional information.
Electric Operations
We generate, transmit and distribute electricity through our subsidiary NIPSCO to approximately 486,000 customers in 20 counties in the northern part of Indiana and also engage in wholesale electric and transmission transactions. We own and operate sources of generation as well as source power through PPAs. We continue to transition our generation portfolio to primarily renewable sources. During 2021, we operated Rosewater for the full year, Indiana Crossroads Wind went into service during December 2021, and in December of 2022 we closed on the Indiana Crossroads Solar project, which is expected to go into service in 2023. In October 2021, NIPSCO completed the retirement of two coal-burning units with installed capacity of approximately 903 MW at Schahfer Generating Station, located in Wheatfield, IN. We also purchased energy generated from renewable sources through PPAs in 2022. As of December 31, 2022 we have multiple PPAs that provide 500 MW of capacity, with contracts expiring between 2024 and 2040. See below for information on our owned operating facilities:

Facility Name |  | Location | Fuel Type | Generating Capacity (MW)(1)
R.M. Schahfer |  | Wheatfield, IN | Steam - Coal | 722 |
Michigan City |  | Michigan City, IN | Steam - Coal | 455 |
Sugar Creek |  | West Terre Haute, IN | CCGT | 563 |
R.M. Schahfer |  | Wheatfield, IN | Natural Gas | 155 |
Oakdale |  | Carroll County, IN | Hydro | 9 |
Norway |  | White County, IN | Hydro | 7 |
Rosewater Wind Generation LLC(2) |  | White County, IN | Wind | 102 |
Indiana Crossroads Wind Generation LLC(2) |  | White County, IN | Wind | 302 |
Total MW Capacity |  |  |  | 2,315 |

(1)Represents current net generating capability of each fossil fuel and hydro generating unit. Nameplate capacity is listed for wind generating units.
(2)NIPSCO is the managing partner of these JVs. Refer to Note 4, "Variable Interest Entities," in the Notes to Consolidated Financial Statements for more information.
In November 2021, NIPSCO submitted its 2021 Integrated Resource Plan ("2021 Plan") with the IURC. The 2021 plan builds upon the 2018 Integrated Resource Plan which outlined NIPSCO’s plan to retire its coal generating assets by 2028. The 2021 plan affirmed the 2018 retirement decisions and calls for the replacement of the retiring units with a diverse portfolio of resources including demand side management resources, modest amounts of incremental solar, stand-alone energy storage, new gas peaking resources and upgrades to existing facilities at the Sugar Creek Generating Station, among other steps. Refer to Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations” for further discussion of these plans.
NIPSCO’s transmission system, with voltages from 69,000 to 765,000 volts, consists of 3,016 circuit miles. NIPSCO is interconnected with eight neighboring electric utilities.
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, 2022, NIPSCO generating units were dispatched to meet 41.65% of its load requirements, and NIPSCO purchased 58.35% from the MISO market.
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Competition. Our electric utilities generally have 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 electric 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 Segment Operations - Electric Operations," for additional information.
Political Action
The NiSource Political Action Committee ("NiPAC") provides our employees a voice in the political process. NiPAC is a voluntary, employee and director 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.
Regulatory
The regulatory landscape applicable to our operations, including environmental regulations, at both the state and federal levels, continue to evolve. These changes have had and will continue to have an impact on our operations, structure and profitability. Management continually seeks new ways to be more competitive and profitable 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 continued compliance to have a material impact on our capital expenditures, earnings, or competitive position. We continue to monitor existing and pending laws and regulations, and 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 net of tracker impacts. See "Cost Recovery and Trackers" below for further detail on trackers.

(in millions) |  |  |  |  |  |
Company | Proposed ROE | Approved ROE | Requested Incremental Revenue | Approved Incremental Revenue | Filed | Status | Rates Effective
Currently Approved in Current or Future Rates |  |  |  |  |
Columbia of Pennsylvania(1) | 10.95 | % | None specified | $ | 82.2 |  | $ | 44.5 |  | March 18, 2022 | Approved December 8, 2022 | December 2022
Columbia of Maryland | 10.85 | % | 9.65 | % | $ | 5.8 |  | $ | 3.5 |  | May 13, 2022 | Approved November 17, 2022 | December 2022
Columbia of Kentucky(2) | 10.30 | % | 9.35 | % | $ | 26.7 |  | $ | 18.3 |  | May 28, 2021 | Approved December 28, 2021 | January 2022
Columbia of Virginia(3) | 10.95 | % | None specified | $ | 14.2 |  | $ | 1.3 |  | August 28, 2018 | Approved June 12, 2019 | February 2019
Columbia of Ohio | 10.95 | % | 9.60 | % | $ | 221.4 |  | $ | 68.2 |  | June 30, 2021 | Approved January 26, 2023 | March 2023
NIPSCO - Gas(4) | 10.50 | % | 9.85 | % | $ | 109.7 |  | $ | 71.8 |  | September 29, 2021 | Approved July 27, 2022 | September 2022
NIPSCO - Electric | 10.80 | % | 9.75 | % | $ | 21.4 |  | $ | (53.5) |  | October 31, 2018 | Approved December 4, 2019 | January 2020
Active Rate Cases |  |  |  |  |  |  |
Columbia of Virginia(5) | 10.75 | % | In process | $ | 40.6 |  | In process | April 29, 2022 | Order Expected Q1 2023 | Interim Rates October 2022
NIPSCO - Electric(6) | 10.40 | % | In process | $ | 291.8 |  | In process | September 19, 2022 | Order Expected Q3 2023 | September 2023

(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 ROE for natural gas capital riders (e.g.,SMRP) is 9.275%.
(3)Columbia of Virginia's 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.
(4)New rates are implemented in 2 steps, with implementation of Step 1 rates in September 2022. The Step 2 rates were filed on February 21, 2023, with rates effective March 2023.
(5) Beginning October 2022, interim rates are being billed subject to refund, pending a final commission order. On December 9, 2022, a Stipulation and Proposed Recommendation was filed with the Virginia State Corporation Commission recommending approval of $25.8 million of incremental revenue.
(6)New rates will be implemented in 2 steps, with implementation of Step 1 rates to be effective in September 2023 and Step 2 rates to be effective in March 2024. On February 16, 2023, NIPSCO filed rebuttal updating the requested revenue requirement to $279.2 million.
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FERC. NiSource’s service companies 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 and Columbia of Ohio have limited jurisdictional certificates to transport gas in the respective service territories into interstate commerce. NIPSCO and Columbia of Pennsylvania currently have applications pending at FERC for limited jurisdictional certificates.
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 Operations utilities have pursued non-traditional revenue sources within the evolving natural gas marketplace. These efforts include (i) the sale of products and services in the companies’ service territories, and (ii) gas supply cost incentive mechanisms for service to their core markets. 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 purchase prices paid below an agreed upon benchmark and their ability to reduce pipeline capacity charges with their customers.
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 contributes 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 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 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. In a prior gas base rate proceeding, NIPSCO implemented a higher fixed customer charge for residential and small customer classes moving toward recovering more of its fixed costs through a fixed recovery charge, but has no weather or usage protection mechanism.
While increased efficiency of electric appliances and improvements in home building codes and standards has 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. Further growth is anticipated as electric vehicles become more prevalent. 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 line item operating results is impacted by regulatory trackers that allow for the recovery in rates of certain costs such as those described below. Increases in the expenses that are subject to approved regulatory tracker mechanisms generally lead to increased regulatory assets, which ultimately result in a corresponding increase in operating revenues and, therefore, have essentially no impact on total operating income results. 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 Gas Distribution Operations revenue is related to the recovery of gas costs, the review and recovery of which occurs through standard regulatory proceedings. All states in our operating area require periodic review of actual gas
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procurement activity to determine prudence and confirm the recovery of prudently incurred energy commodity costs supplied to customers.
A portion of the Electric 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.
Environmental and Safety Matters
PHMSA Regulations
On December 27, 2020, the Protecting Our Infrastructure of Pipelines and Enhancing Safety (PIPES) Act of 2020 was signed into law, reauthorizing funding for federal pipeline safety programs through September 30, 2023. Among other things, the PIPES Act requires that PHMSA revise the pipeline safety regulations to require operators to update, as needed, their existing distribution integrity management plans, emergency response plans, and operation and maintenance plans. The PIPES Act also requires PHMSA to adopt new requirements for managing records and updating, as necessary, existing district regulator stations to eliminate common modes of failure that can lead to overpressurization. PHMSA must also require that operators implement and utilize advanced leak detection and repair technologies that enable the location and categorization of all leaks that are hazardous, or potentially hazardous, to human safety or the environment. Natural gas companies, including NiSource and our subsidiaries, may see increased costs depending on how PHMSA implements the new mandates resulting from the PIPES Act.
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 ongoing 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 on an ongoing basis.
Transition Climate Risks. Future legislative and regulatory programs, at both the federal and state levels, could significantly limit allowed GHG emissions or impose a cost or tax on GHG emissions. Revised or additional 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.
Regarding federal policies, we continue to monitor the implementation of any final and proposed climate change-related legislation and regulations, including the Infrastructure Investment and Jobs Act, signed into law in November 2021; the development of the Enhancement and Standardization of Climate-Related Disclosures, proposed by the SEC in March 2022; the IRA, signed into law in August 2022; and the EPA's proposed methane regulations for the oil and natural gas industry, but we cannot predict their impact on our business at this time. We have identified potential opportunities associated with the Infrastructure Investment and Jobs Act and the IRA and are evaluating how they may align with our strategy going forward. The energy-related provisions of the Infrastructure Investment and Jobs Act include new federal funding for power grid infrastructure and resiliency investments, new and existing energy efficiency and weatherization programs, electric vehicle infrastructure for public chargers and additional LIHEAP funding over the next five years. The IRA contains climate and energy provisions, including funding to decarbonize the electric sector.
In February 2021, the United States rejoined the Paris Agreement, an international treaty through which parties set nationally determined contributions to reduce GHG emissions, build resilience, and adapt to the impacts of climate change. Subsequently, the Biden Administration released a target for the United States to achieve a 50%-52% GHG reduction from 2005 levels by 2030, which supports the President's goals to create a carbon-free power sector by 2035 and net zero emissions economy no later than 2050. There are many pathways to reach these goals.
On June 30, 2022, the Supreme Court of the United States ruled for the petitioners in West Virginia v. EPA, which examined the authority of the EPA to regulate GHG emissions from the power sector. We will continue to evaluate this matter, but we remain committed to our previously stated carbon reduction goals.
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We also continue to monitor the implementation of any final and proposed state policy. The Virginia Clean Economy Act was signed into law in 2020. While the Act does not establish any new mandates on Columbia of Virginia, certain natural gas customers may, over the long-term, reduce their use of natural gas to meet the 100% renewable electricity requirement. Columbia of Virginia will continue to monitor this matter, but we cannot predict its final impact on our business at this time. Separately, the Virginia Energy Innovation Act, enacted into law in April 2022, and effective July 1, 2022, allows natural gas utilities to supply alternative forms of gas that meet certain standards and reduce emissions intensity. The Act also provides that the costs of enhanced leak detection and repair may be added to a utility’s plan to identify proposed eligible infrastructure replacement projects and related cost recovery mechanisms, known as the SAVE Plan. Furthermore, under the Act, utilities can recover eligible biogas supply infrastructure costs on an ongoing basis. The provisions of these laws may provide opportunities for Columbia of Virginia as it participates in the transition to a lower carbon future.
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 is required to adopt a plan to achieve the 2031 goal by December 2023, and it is required to adopt a plan for the net zero goal by 2030. The Act also enacts a state policy to move to broader electrification of both existing buildings and new construction, and requires the Public Service Commission to complete a study assessing the capacity of gas and electric distribution systems to successfully serve customers under a transition to a highly electrified building sector. Columbia of Maryland will continue to monitor this matter, but we cannot predict its final impact on our business at this time.
NIPSCO, Columbia of Maryland, Columbia of Pennsylvania, Columbia of Virginia and Columbia of Kentucky each filed petitions to implement the Green Path Rider, which will be a voluntary rider that allows customers to opt in and offset either 50% or 100% of their natural gas related emissions. To reduce the emissions, the utilities will purchase RNG attributes and carbon offsets to match the usage for customers opting into the program. The program was approved by the IURC at NIPSCO in November 2022 with a January 2023 start date. After reaching settlement with other parties in September 2022, NIPSCO agreed to add a third tier to offset 25% of customer usage. Columbia of Maryland’s filing was denied by the PUC in January 2023. The filings for Columbia of Pennsylvania, Columbia of Virginia and Columbia of Kentucky are still being evaluated. Additionally, NIPSCO has a voluntary Green Power Rider program in place that allows customers to designate a portion or all their monthly electric usage to come from power generated by renewable energy sources.
Net Zero Goal. In response to these transition risks and opportunities, on November 7, 2022, we announced a goal of net zero greenhouse gas emissions by 2040 covering both Scope 1 and Scope 2 emissions ("Net Zero Goal"). Our Net Zero Goal builds on greenhouse gas emission reductions achieved to-date and demonstrates that continued execution of our long-term business plan will drive further greenhouse gas emission reductions. We remain on track to achieve previously announced interim greenhouse gas emission reduction targets by reducing fugitive methane emissions from main and service lines by 50 percent from 2005 levels by 2025 and reducing Scope 1 greenhouse gas emissions from company-wide operations by 90 percent from 2005 levels by 2030. We plan to achieve our Net Zero Goal primarily through 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, such as hydrogen, renewable natural gas, 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 2021, we had reduced Scope 1 GHG emissions by approximately 58% from 2005 levels.
Our greenhouse gas emissions projections, including achieving a Net Zero Goal, are subject to various assumptions that involve risks and uncertainties. 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 economical to deploy. Should such regulatory and legislative policies, stakeholder environments or technologies fail to materialize, 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 Segment Operations - Electric Operations," NIPSCO continues to execute on an electric generation transition consistent with the preferred pathways identified in its 2018 and 2021 Integrated Resource Plans. Additionally, as discussed in Management's Discussion within "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 of our Board of Directors (the "Board") is primarily responsible for assisting the Board in overseeing our human capital
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management practices. The Compensation and Human Capital Committee charter includes reviewing our human capital management function and programs, including related procedures, programs, policies and practices, and making recommendations to management with respect to equal employment opportunity and DE&I initiatives, employee engagement and corporate culture, and talent management.
In addition to overseeing our human capital management practices, in 2022 our Board was refreshed and is committed to ensuring that the Board is comprised of directors with diverse skills, expertise, experience and demographics, including racial and gender diversity. Women and people of color ("POC") each comprise 33% of our Board.
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 resources function. We aspire to be an employer of choice in the utility industry through accelerating and embedding DE&I throughout the enterprise and creating an enviable employee experience.
Workforce Composition. As of December 31, 2022, we had 7,117 full-time and 45 part-time active employees. Thirty-five percent of our employees were subject to collective bargaining agreements with various labor unions which expire between 2026 and 2027.
Diversity, Equity and Inclusion. We are committed to accelerating and embedding DE&I throughout the enterprise to reflect the communities and customers we serve. We have worked to develop diverse sourcing strategies to attract and increase our diverse representation. Our talent acquisition team hired 523 external candidates in 2022 across all business segments. Twenty-eight percent of external hires in 2022 were racially or ethnically diverse and 44% were female.
In addition, we have focused on our implementation and development of programs to drive higher retention and engagement of our employees. Through our efforts, we have been able to increase participation in our Targeted Development for Diverse Talent program in 2022. Participants in this program are either female or POC. POC make up 49% of the participant population for 2022. In addition, we have implemented over 50 DE&I programs with a strong emphasis on professional development and retention efforts within our seven Employee Resource Groups.
We plan to post our 2022 consolidated EEO-1 report data on our website by the end of the first quarter of 2023.
The following graph shows the percentage of total employees represented by gender overall and for our officers as of December 31, 2022:
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The following graph shows the percentage of total employees and officers represented by race/ethnicity as of December 31, 2022:
Talent Attraction. To recruit and hire individuals with a variety of skills, talents, backgrounds and experiences, we value and cultivate relationships with the community and diverse outreach partners. We also target job fairs, including those focused on people of color, veterans and women candidates, and partner with local colleges and universities to identify and recruit qualified applicants in the communities we serve.
We are focused on our future of work and creating a more flexible, agile model for roles that can be performed in a more remote setting to attract talent across our footprint. In 2022, we introduced a hybrid-working model, which recognizes differing ways of working: onsite, hybrid and remote. As of December 31, 2022, 58% of our workforce is onsite, 35% are hybrid and 7% are remote. This new working model supports colleague connection, development and mentoring as well as 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 2022, we had participation from employees at all levels in our extensive technical and non-technical employee leadership development training programs.
We strive to provide promotion and advancement opportunities for employees. In 2022, for all leadership positions at the supervisor and above level posted externally, we filled 69% with internal employees. We 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 2022 was over 91%. We calculate retention as the total number of separations divided by the average headcount for the annual period. These separations include involuntary separation (2%), resignation (5%), and retirement (2%).
Executive Succession Planning. We perform succession planning quarterly 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 and are well-prepared for future roles. We maintain formal succession plans for our Chief Executive Officer ("CEO") and key executive officers. The succession plan for our CEO is reviewed by the Environmental, Social, Nominating and Governance Committee of the Board and the succession plans for executive officers (other than the CEO) and other critical roles are reviewed by the Compensation and Human Capital Committee annually or more frequently as needed.
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Employee and Workplace Health and Safety. We have several programs to support employees, and their families’ physical, mental, and financial well-being. These programs include a paid wellness day, telemedicine services, an Employee Assistance Program, Integrated Health Management navigation services, employee paid sick/disability leave, parental leave, and paid illness in family days. We also offer competitive medical, dental, vision, life and long-term disability programs, including employee health savings account company contributions.
We have a robust program to support employee, contractor and public safety, which is led by our Chief Safety Officer and is overseen by the Safety, Operations, Regulatory and Policy Committee of our Board. As we will outline in our annual safety report on our corporate website, we continue to invest in risk reduction activities and assets.
Culture and Engagement. Our culture is another important aspect of our ability to advance our strategic and operational objectives. In addition to our DE&I, 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 with employees. We measure and monitor culture and employee engagement through a variety of channels including employee lifecycle, pulse, and census surveys.
To instill and reinforce our values and culture, we require our employees to participate in regular trainings 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 biannually or more frequently if there is a material change in content. Our business ethics program, including the employee training program, is reviewed annually by our executive leadership team and the Audit Committee of our Board.
Our Compensation and Human Capital Committee reviews reports from our Chief Human Resources Officer and Chief Diversity, Equity and Inclusion 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 Chief Executive Officer, 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.
Other Relevant Business Information
Our customer base is broadly diversified, with no single customer accounting for a significant portion of revenues.
For a listing of material subsidiaries of NiSource, refer to Exhibit 21.
We electronically file various reports with the SEC, including annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to such reports, as well as our proxy statements for the Company's annual meetings of stockholders at http://www.sec.gov. Additionally, we make all SEC filings available without charge to the public on our web site at http://www.nisource.com. The information contained on our website is not included in, nor incorporated by reference into, this Annual Report on Form 10-K.
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INFORMATION ABOUT OUR EXECUTIVE OFFICERS
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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 |  | 62 |  |  | President and Chief Executive Officer
|  |  |  | Executive Vice President, Customer and Delivery Operations, and President, Carolinas Region, of Duke Energy Corporation from 2014 to 2019.
Donald E. Brown |  | 51 |  |  | Executive Vice President and Chief Financial Officer
|  |  |  | Executive Vice President of NiSource since May 2015.
|  |  |  | Chief Financial Officer of NiSource since July 2015.
|  |  |  | President, NiSource Corporate Services since June 2020.
Melody Birmingham |  | 51 |  |  | Executive Vice President, Chief Innovation Officer
|  |  |  | 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 Corporation from November 2018 to April 2021.
|  |  |  | President of Duke Energy Corporation from June 2015 to November 2018
William Jefferson, Jr |  | 61 |  |  | Executive Vice President, Operations and Chief Safety Officer
|  |  |  | Station Director and Vice President at STPNOC, Wadsworth, Texas, from 2016 to May 2022.
Shawn Anderson |  | 41 |  |  | Senior Vice President,Strategy and Chief Risk Officer
|  |  |  | Vice President, Strategy of NiSource from January 2019 to May 2020.
|  |  |  | Vice President of NiSource from May 2018 to December 2018.
|  |  |  | Treasurer and Chief Risk Officer of NiSource from June 2016 to December 2018.
Kimberly S. Cuccia |  | 39 |  |  | Senior Vice President, General Counsel and Corporate Secretary
|  |  |  | Vice President General Counsel, Interim Corporate Secretary of NiSource from January 2022 to March 2022.
|  |  |  | Vice President and Deputy General Counsel, Regulatory, of NiSource Corporate Services Company, from January 2021 to December 2021.
|  |  |  | Vice President and General Counsel, Columbia Gas of Massachusetts, NiSource Corporate Services Company, from October 2019 to December 2020.
|  |  |  | Vice President and General Counsel, Massachusetts Restoration, NiSource Corporate Services Company, from October 2018 to October 2019.
|  |  |  | Chief Counsel, Columbia Gas Companies from June 2015 to September 2018.
Melanie B. Berman |  | 52 |  |  | Senior Vice President and Chief Human Resources Officer
|  |  |  | Executive Vice President and Chief Human Resources Officer of The Michaels Companies, Inc. from 2020 to 2021.
|  |  |  | Vice President, Human Resources of Anthem, Inc. from January 2018 to 2019.

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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 complete the sale of a minority interest in NIPSCO on the expected timeline or at all.
On November 7, 2022, we announced our intention to sell a minority interest in NIPSCO (the “NIPSCO Minority Interest Sale”). We intend to evaluate various alternatives to determine the optimal transaction structure to maximize stakeholder value as a result of the NIPSCO Minority Interest Sale. A successful sale will be dependent on factors such as regulatory approval(s) and negotiations with one or more counterparties. There can be no assurances that we will be able to successfully complete the NIPSCO Minority Interest Sale on the anticipated timeline or at all. Furthermore, there can be no assurances that the NIPSCO Minority Interest Sale will lead to the anticipated benefits to stockholders.
We may not be able to execute our business plan or growth strategy, including the NIPSCO Minority Interest Sale and utility infrastructure investments.
Business or regulatory conditions may result in our inability to execute our business plan or growth strategy, including the NIPSCO Minority Interest Sale and identified, planned and other utility infrastructure investments, which includes investments related to natural gas pipeline modernization and our renewable energy projects, and the build-transfer execution goals within our business plan.
Our Enterprise Transformation Roadmap initiatives are designed to identify long-term sustainable capability enhancements, cost optimization improvements, technology investments and work process optimization, has 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. 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, including in connection with the NIPSCO Minority Interest Sale, and mergers from time to time as we execute on our business plan and growth strategy. Any of these circumstances could adversely affect our results of operations and growth prospects. Even if our business plan and growth strategy 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. Risks to our capital projects, including risks related to supply chain challenges and labor availability, are described in a separate risk factor below.
Our gas distribution and transmission activities, as well as generation, transmission and distribution of electricity, involve a variety of inherent hazards and operating risks, including potential public safety risks.
Our gas distribution and transmission activities, as well as generation, transmission and distribution of electricity, 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 and other incidents, which could cause substantial financial losses, as demonstrated in part by the Greater Lawrence Incident. We also have distribution propane assets that involve similar risks. In addition, these hazards and risks have resulted and may result in the future 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 losses for NiSource and its stockholders. 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. As with the Greater Lawrence Incident, certain incidents have subjected and may in the future 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
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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 may conduct certain operations, including in connection with the NIPSCO Minority Interest Sale, through a JV arrangement involving third-party investors that may result in delays, litigation or operational impasses.
We may enter into JV arrangements involving third-party investors, including in connection with the NIPSCO Minority Interest Sale. As part of a JV arrangement, third-party investors may hold certain protective rights that may impact our ability to make certain decisions. Any such third-party investors may have interests and objectives which may differ from ours and, accordingly, disputes may arise that may result in delays, litigation or operational impasses.
Failure to adapt to advances in technology and manage the related costs could make us less competitive and negatively impact our results of operations and financial condition.
A key element of our electric business model includes generating power at central station power plants 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 energy efficiency designed to reduce regulated emissions. 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 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, 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 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 results of operations and financial condition.
Aging infrastructure may lead to disruptions in operations and increased capital expenditures and maintenance costs, all of which could negatively impact our financial results.
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, and (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. 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 and transportation logistics may lead to delays in the maintenance and replacement of aging 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
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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, are affected by developments affecting our business; international, national, state, or local events; and the financial condition and underwriting considerations of insurers. For example, some insurers are moving away from underwriting certain carbon-intensive energy-related businesses such as those in the coal industry or those exposed to specific perils such as wildfires as well as gas explosion events or other infrastructure-related or natural catastrophe risks. The utility insurance market continues to be impacted by a prevalence of severe losses, and despite significant annual increases in rates over the past few years, markets are experiencing unacceptable loss ratios. Certain perils, such as cyber, are now being excluded from some master policies for property and casualty insurance, requiring procurement of additional policies to be obtained to maintain consistent coverage at an additional cost. Capacity limits insurers are willing to issue have decreased, requiring participation from more insurers to provide adequate coverage. 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 retirement of our coal generation units, may be delayed and may not achieve intended results.
As discussed in “Results and Discussion of Segment Operations - Electric Operations,” in Management’s Discussion and Analysis of Financial Condition and Results of Operations, our 2018 Integrated Resource Plan (“2018 Plan”) 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 by the end of 2028, to be replaced by lower-cost, reliable and cleaner options. Our 2021 Integrated Resource Plan (“2021 Plan”) validated the activities underway pursuant to our 2018 Plan and calls for the retirement of the Michigan City Generating Station, replacement of existing vintage gas peaking units at the R.M. Schahfer Generating Station and upgrades to the transmission system to enhance our electric generation transition. Recent developments, including macro supply chain issues and U.S. federal policy actions, have created significant uncertainty around the availability of key input material necessary to develop and place our renewable energy projects in service. In the U.S., solar industry supply chain issues include the pending U.S. Department of Commerce investigation on Antidumping and Countervailing Duties Anti Circumvention Petition filed by a domestic solar manufacturer (the “DOC Investigation”), the Uyghur Forced Labor Protection Act, Section 201 Tariffs and persistent general global supply chain and labor availability issues. The most prominent effect of these issues is the significant curtailment of imported solar panels and other key components required to complete utility scale solar projects in the U.S. Any available solar panels may not meet the cost and efficiency standards of our currently approved projects and the incremental cost may not be recoverable through customer rates. As a result of the challenges in obtaining solar panels, many solar projects in the U.S. have been delayed or canceled. As we are in the midst of a transition to an electric generation portfolio with more renewable resources, including solar, our projects are subject to the effects of these issues.
Our expectation has been that solar energy sources would be one of 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. The high level of uncertainty surrounding the completion of our solar renewable energy projects creates significant risks for us to reliably meet our capacity and energy obligations to MISO and to provide reliable and affordable energy to our customers. Any additional delays to the completion dates of our ten planned and approved solar projects are expected to impact our capacity position and our ability to meet our resource adequacy obligations to MISO. 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.
As noted above, we expect our electric generation strategy to 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 renewable projects is negatively
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impacting our generation transition timeline and may negatively impact our achievement of decarbonization goals and reputation.
Our capital projects and programs subject us to construction risks and natural gas costs 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 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 due in part to shortages in materials as described more fully below. 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.
Our existing and planned capital projects require numerous permits, approvals and certificates from federal, state, and local governmental agencies. 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. Other construction risks include changes in the availability and costs of materials, equipment, commodities or labor (including changes to tariffs on materials), delays caused by construction incidents or injuries, work stoppages, shortages in qualified labor, poor initial cost estimates, unforeseen engineering issues, the ability to obtain necessary rights-of-way, easements and transmissions connections and general contractors and subcontractors not performing as required under their contracts.
We are monitoring risks related to increasing order and delivery lead times for 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 are also seeing 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 or costs increase, customer affordability as well as our business operations, results of operations, cash flows and financial condition could be materially adversely affected. In addition, to the extent that delays occur on projects that target system integrity, the risk of an operational incident could increase. For more information on global availability of materials for our renewable projects, see “ - Results and Discussion of Segment Operations - Electric Operations - Electric Supply and Generation Transition.” To the extent that delays occur, costs become unrecoverable or recovery is delayed, or we otherwise become unable to effectively manage and complete our capital projects, our results of operations, cash flows, and financial condition may be adversely affected.
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, inflation and economic conditions impact demand of our customers and our operating results.
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, whereby usage declines with increased costs, thus affecting our financial results. Commodity prices have been and may continue to be volatile. 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, consumption 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 to meet customer demands may have a negative impact on our financial results.
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Our current electric generating fleet is dependent 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. However, 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 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 and retain an appropriately qualified workforce, and maintain good labor relations, could harm our results of operations.
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 and other conditions, including those related to organizational changes as described in the risk factor below.
We face increased competition for talent in the current environment of sustained labor shortage and increased turnover rates. Incidents of any pandemic in our workforce could increase the risk of worker illness and availability. These or other employee workforce factors could negatively impact our business, financial condition or results of operations.
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.
Our strategic plan includes enhanced technology and transmission and distribution investments and a reduction in reliance on coal-fired generation. As part of our strategic plan, we will need to attract and retain personnel that are qualified to implement our strategy and may need to retrain or re-skill certain employees to support our long-term objectives.
Failure to hire and retain qualified employees, including the ability to transfer significant internal historical knowledge and expertise to the new employees, may adversely affect our ability to manage and operate our business. If we are unable to successfully attract and retain an appropriately qualified workforce and maintain satisfactory collective bargaining agreements, safety, service reliability, customer satisfaction and 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, loss of personnel. Front-line workers are being impacted by the variety of process and technology changes that are currently in progress.
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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. We have had communications with an activist stockholder. 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 substandard performance by those third parties could harm our business, reputation and results of operations.
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 are seeing slowing deliveries from suppliers and in some cases materials and labor shortages for capital projects. We outsource certain services to third parties in areas including construction services, information technology, materials, fleet, environmental, operational services, corporate and other areas. 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 or accidents or reputational harm, which could negatively impact our results of operations. We do not have full visibility into our supply chain, which may 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 on any of our or certain third-party technology systems upon which we rely may adversely affect our ability to operate and 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 financial and operational 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 cyber 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 sensitive and confidential customer and employee information, electric grid infrastructure, and natural gas infrastructure. 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 energy grid and the natural gas infrastructure. Additionally, the conflict between Russia and Ukraine, as well as increased surveillance activity from China, has increased the likelihood of a cyber-attack on critical infrastructure systems.
Increasing large-scale corporate attacks in conjunction with more sophisticated threats continue to challenge power and utility companies. Any failure of our technology systems, or those of our customers, suppliers or others with whom we do business,
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could materially disrupt our ability to operate our business and could result in a financial loss and possibly do harm to our reputation.
Additionally, our information systems experience ongoing, often sophisticated, cyber-attacks 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 attacks, our cybersecurity program does not prevent all breaches or cyberattack 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, cyber intrusions and attacks to our information systems and our operational technology. 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 attacks have advanced in sophistication and number around the world. Technological complexities combined with advanced cyber-attack techniques, lack of cyber hygiene and human error can result in a cybersecurity incident, such as a ransomware attack. Supplier non-compliance with cyber controls can also result in a cybersecurity incident. Attacks can occur at any point in the supply chain or with any suppliers. In addition, unmanned aircraft systems (UAS) or drones are used for various commercial and recreational purposes across the country. The Cybersecurity & Infrastructure Security Agency (CISA) released alerts pertaining to UASs being used for malicious activities and the cybersecurity risk is continuing to increase.
In addition, we collect and retain personally identifiable information of our customers, stockholders and employees. Customers, stockholders and employees expect that we will adequately protect their personal information. The regulatory environment surrounding information security and privacy is increasingly demanding.
Although we attempt to maintain adequate defenses to these attacks and work through industry groups and trade associations to identify common threats and assess our countermeasures, a security breach of our information systems and/or operational technology, or a security breach of the information systems of our customers, suppliers or others with whom we do business, could (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, results of operations and/or prospects. Although we do maintain cyber 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.
As cyber-attacks are becoming more sophisticated, U.S. government warnings have indicated that critical infrastructure assets, including pipelines and electric infrastructure, may be specifically targeted by certain groups. In 2021, the Transportation Security Administration (“TSA”) announced two new security directives in response to a ransomware attack on the Colonial Pipeline that occurred earlier in the year. These 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. Such directives or other requirements may require expenditure of significant additional resources to respond to cyberattacks, to continue to modify or enhance protective measures, or to assess, investigate and remediate any critical infrastructure security vulnerabilities. Additionally, on November 30, 2022, the TSA issued an advance notice of proposed rulemaking (ANPRM) seeking public comment on more comprehensive, formal cybersecurity regulations for the pipeline industry. Any failure to comply with such government regulations or failure in our cybersecurity protective measures may result in enforcement actions that 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, cyber-attacks, accidents, public health emergencies or other catastrophic events may disrupt operations and reduce the ability to service customers.
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A disruption or failure of natural gas distribution systems, or within electric generation, transmission or distribution systems, in the event of a major hurricane, tornado, or other major weather event, or terrorist attack, acts of war, including the political and economic disruption and uncertainty related to Russia’s military invasion of Ukraine, civil unrest, cyber-attack (as further detailed above), accident, public health emergency, 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 hurricanes and tornadoes 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 timely restoration of services. The occurrence of such events could adversely affect our 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.
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 reliability 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 cyber security 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 impacts. 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 adverse publicity and investigations we experienced as a result of the Greater Lawrence Incident may have an ongoing negative impact on the public’s perception of us. It is difficult to predict the ultimate impact of this adverse publicity. The foregoing may have continuing 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 heat stresses to power lines, cold temperature stress to our electric and gas systems, 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. 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 adverse economic conditions, availability of alternative energy sources, including private solar, microturbines, fuel cells, energy-efficient buildings and energy storage devices, and new regulations restricting emissions, including potential regulations of methane 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 over time, 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 generating 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.
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Some of our baseload 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. We are unable to forecast the future of commodity markets, but 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 harm our reputation and 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, in February 2023, the Maryland Office of People's Counsel filed a petition with the Maryland Public Service Commission seeking an investigation regarding planning, practices, and future operations of natural gas suppliers in the state.
We are subject to operational and financial risks and liabilities associated with the implementation and efforts to achieve our carbon emission reduction goals.
On November 7, 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 economical to deploy, the impacts and costs of which are not fully understood at this time. NIPSCO’s electric generation transition is a key element of the Net Zero Goal. Our analysis and plan for execution, which is outlined in the NIPSCO 2021 Integrated Resource Plan, 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, service territory size and capacity needs remaining in line with expectations; regulatory approval; impacts of future environmental regulations or legislation; impact of future GHG pricing regulations or legislation, including a future carbon tax or methane fee; price, availability and regulation of carbon offsets; price of fuel, such as natural gas; cost of energy generation technologies, such as wind and solar, natural gas and storage solutions; adoption of alternative energy by the public, including adoption of electric vehicles; rate of technology innovation with regards to alternative energy resources; our ability to implement our modernization plans for our pipelines and facilities; the ability to complete and implement generation alternatives to NIPSCO’s coal generation and retirement dates of NIPSCO’s coal facilities by 2028; the ability to construct and/or permit new natural gas pipelines; the ability to procure resources needed to build at a reasonable cost, the lack of scarcity of resources and labor, project cancellations, construction delays or overruns and the ability to appropriately estimate costs of new generation; impact of any supply chain disruptions; and advancement of energy efficiencies. Any negative opinions with respect to these goals or our environmental practices, including any inability to achieve, 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 $11,315.5 million outstanding as of December 31, 2022. 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;
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•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.
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, 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, 2022, the collateral requirement that would be required in the event of a downgrade below the ratings trigger levels would amount to approximately $85.7 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 increased inflation, increases in 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. Actions to reduce inflation, including raising interest rates, increase our cost of borrowing, which in turn 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
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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, large institutional investors may choose to sell or choose not to purchase our stock due to environmental, social and governance (“ESG”) concerns or concerns regarding renewable energy supply chain challenges. 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.
If, in the future, we face limits to the credit and capital markets or experience significant increases in the cost of capital or are unable to access the capital markets, it 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.
The COVID-19 pandemic has adversely impacted and may continue to adversely impact our business, results of operations, financial condition, liquidity and cash flows.
The COVID-19 pandemic has resulted in widespread impacts on the global economy and financial markets. The duration and ultimate impact of the COVID-19 pandemic on our business, results of operations and financial condition, including liquidity, capital and financing resources, will depend on numerous evolving factors and future developments, which are highly uncertain and cannot be predicted at this time. Such factors and developments may include the severity and duration of the COVID-19 pandemic, including whether there are periods of increased COVID-19 cases; the emergence of other new or more contagious variants that may render vaccines ineffective or less effective; disruption to our operations resulting from employee illnesses or any inability to attract, retain or motivate employees; the development, availability and administration of effective treatment or vaccines and the willingness of individuals to receive a vaccine; the extent and duration of the impact on the U.S. or global economy, including the pace and extent of recovery from the COVID-19 pandemic; and the actions that have been or may be taken by various governmental authorities in response to the COVID-19 pandemic.
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, the quality of service, regulatory interpretations, customer intervention, economic conditions and the political environment. 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 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 concerns. Any change in rates, including changes in allowed rate of return, are subject
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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 costs incurred by our electric and natural gas companies, including costs for construction, operation and maintenance, and compliance with current and future changes in environmental, federal pipeline safety, critical infrastructure and cyber security laws and regulations. Challenges arise with state regulators on inflationary pricing for electric and gas materials and potential price increases, ensuring that updated pricing for electric and gas materials is included in plans and regulatory assumptions, and ensuring there is a regulatory recovery model for emergency inventory stock. 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 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 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 such as potential increases in taxes and incremental costs related to COVID-19. 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 could subject our gas utilities to higher operating costs. 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, and fluctuating demand for its products. In addition, our results of operations are negatively impacted by lower revenues resulting from higher bankruptcies, predominately focused on commercial and industrial customers not able to sustain operations through the economic disruptions related to the pandemic.
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 Policy, involves considerable judgment by our employees and is based on an evaluation of a customer 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 result in an increase in defaults by customers, suppliers and counterparties.
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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.
The trading prices for our Equity Units, initially consisting of Corporate Units, and related treasury units and Series C Mandatory Convertible Preferred Stock, are expected to be affected by, among other things, the trading prices of our common stock, the general level of interest rates and our credit quality.
The trading prices of the Equity Units, initially consisting of Corporate Units, which are listed on the New York Stock Exchange, and the related treasury units and Series C Mandatory Convertible Preferred Stock in the secondary market, are expected to be affected by, among other things, the trading prices of our common stock, the general level of interest rates and our credit quality. It is impossible to predict whether the price of our common stock or interest rates will rise or fall. The price of our common stock could be subject to wide fluctuations in the future in response to many events or factors, including those discussed in the risk factors herein, many of which events and factors are beyond our control. Fluctuations in interest rates may give rise to arbitrage opportunities based upon changes in the relative value of the common stock underlying the purchase contracts and of the other components of the Equity Units. Any such arbitrage could, in turn, affect the trading prices of the Corporate Units, treasury units, mandatory convertible preferred stock and our common stock.
The early settlement right triggered under certain circumstances and the supermajority rights of the Series C Mandatory Convertible Preferred Stock following a fundamental change, could discourage a potential acquirer.
The fundamental change early settlement right with respect to the purchase contracts triggered under certain circumstances by a fundamental change and the supermajority voting rights of the Series C Mandatory Convertible Preferred Stock in connection with certain fundamental change transactions jointly could discourage a potential acquirer, including potential acquirers that would otherwise seek a transaction with us that would be attractive to our investors.
Our Equity Units, initially consisting of Corporate Units, and related Series C Mandatory Convertible Preferred Stock, and the issuance and sale of common stock in settlement of the purchase contracts and conversion of mandatory convertible preferred stock, may all adversely affect the market price of our common stock and will cause dilution to our stockholders.
The market price of our common stock is likely to be influenced by our Equity Units, initially consisting of Corporate Units, and related mandatory convertible preferred stock. For example, the market price of our common stock could become more volatile and could be depressed by:
•investors’ anticipation of the sale into the market of a substantial number of additional shares of our common stock issued upon settlement of the purchase contracts or conversion of our mandatory convertible preferred stock;
•possible sales of our common stock by investors who view our Equity Units, initially consisting of Corporate Units, or related mandatory convertible preferred stock as a more attractive means of equity participation in us than owning shares of our common stock; and
•hedging or arbitrage trading activity that may develop involving our Equity Units, initially consisting of Corporate Units, or related mandatory convertible preferred stock and our common stock.
In addition, we cannot predict the effect that future issuances or sales of our common stock, if any, including those made upon the settlement of the purchase contracts or conversion of the mandatory convertible preferred stock, may have on the market price for our common stock.
Our Equity Units, initially consisting of Corporate Units, and the issuance and sale of substantial amounts of common stock, including issuances and sales upon the settlement of the purchase contracts or conversion of the mandatory convertible preferred stock, could adversely affect the market price of our common stock and will cause dilution to our stockholders.
Capital market performance and other factors may decrease the value of benefit plan assets, which then could require significant additional funding and impact earnings.
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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 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 expense 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.
A significant 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 and term credit agreement, which requires us to maintain a debt to capitalization ratio that does not exceed 70%. As of December 31, 2022, the ratio was 58.9%.
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 involved in legal and regulatory proceedings, investigations, inquiries, claims and litigation in connection with our business operations, including those related to the Greater Lawrence Incident, the most significant of which are summarized in Note 19, "Other Commitments and Contingencies," in the Notes to Consolidated Financial Statements. Our insurance does not cover all costs and expenses that we have incurred relating to the Greater Lawrence Incident, and does not fully cover incidents that could occur in the future. 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.
The Greater Lawrence Incident has materially adversely affected and may continue to materially adversely affect our financial condition, results of operations and cash flows and we may have continued financial liabilities related to the sale of the Massachusetts Business.
In connection with the Greater Lawrence Incident, we have incurred and will incur various costs and expenses. While we have recovered the full amount of our liability insurance coverage available under our policies, total expenses related to the incident exceeded such amount. Expenses in excess of our liability insurance coverage have materially adversely affected and may continue to materially adversely affect our results of operations, cash flows and financial position. We may also incur additional costs associated with the Greater Lawrence Incident, beyond the amount currently anticipated, including in connection with civil litigation. Additionally, it may be difficult to determine whether a claim for damages from a third party related to the Massachusetts Business or the Greater Lawrence Incident is our responsibility or Eversource’s, and we may expend substantial resources trying to determine whether we or Eversource has responsibility for the claim. Further, state or federal legislation may be enacted that would require us to incur additional costs by mandating various changes, including changes to our operating practice standards for natural gas distribution operations and safety. In addition, if it is determined in other matters that we did not comply with applicable statutes, regulations or rules in connection with the operations or maintenance of our natural gas system, and we are ordered to pay additional amounts in penalties, or other amounts, our financial condition, results of operations, and cash flows could be materially and adversely affected.
Our settlement with the U.S. Attorney’s Office in respect of federal charges in connection with the Greater Lawrence Incident may expose us to further penalties, liabilities and private litigation, and may impact our operations.
On February 26, 2020, the Company entered into a DPA and Columbia of Massachusetts entered into a plea agreement with the U.S. Attorney’s Office to resolve the U.S. Attorney’s Office’s investigation relating to the Greater Lawrence Incident, which
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was subsequently approved by the United States District Court for the District of Massachusetts. The agreements impose various compliance and remedial obligations on the Company and Columbia of Massachusetts. Failure to comply with the terms of these agreements could result in further enforcement action by the U.S. Attorney’s Office, expose the Company and Columbia of Massachusetts to penalties, financial or otherwise, and subject the Company to further private litigation, each of which could impact our operations and have a material adverse effect on our business.
Our businesses are subject to various federal, state and local laws, regulations, tariffs and policies. We could be materially adversely affected if we fail to comply with such laws, regulations, tariffs and policies or with any changes in or new interpretations of such laws, regulations, tariffs and policies.
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 laws, regulations, tariffs and policies increases our costs or risks of liability. Supply chain constraints may challenge our ability to remain in compliance if we cannot obtain the materials that we need to 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, 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.
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 continue to execute our plan to reduce our Scope 1 GHG emissions through the retirement of coal-fired electric generation, increased sourcing of renewable energy, priority pipeline replacement, leak detection and repair, and other methods, and while we have set a Net Zero Goal, 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 plans to promulgate additional regulations concerning the management, transformation, transportation and storage of CCRs. NIPSCO is also incurring or will incur costs associated with closing, corrective action, and ongoing monitoring of certain CCR impoundments. We have two pending petitions at the Indiana Utility Regulatory Commission (IURC) seeking recovery of ash pond closure costs related to federal regulations governing CCRs at the Michigan City and R.M. Schahfer Generating Stations and believe there is supportive Indiana law authorizing such recovery. 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
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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 in costs and the ability to recover under regulatory mechanisms could affect our financial position, financial results and cash flows.
Changes in taxation and the ability to quantify such changes as well as 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 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. We are currently assessing the potential impact of these legislative changes. The outcome of regulatory proceedings regarding the extent to which the effect of a change in corporate tax rate will impact customers and the time period over which the impact will occur could significantly impact future earnings and cash flows. Separately, 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.
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ITEM 1B. UNRESOLVED STAFF COMMENTS
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None.
ITEM 2. PROPERTIES
Discussed below are the principal properties held by us and our subsidiaries as of December 31, 2022.
Gas Distribution Operations
Refer to Item 1, "Business - Gas Distribution Operations," of this report for further information on Gas Distribution Operations properties.
Electric Operations
Refer to Item 1, "Business - Electric Operations," of this report for further information on Electric 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.
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PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
N I S OURCE I NC.
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, subject to the prior dividend rights of holders of our preferred stock or the depositary shares representing such preferred stock outstanding, and if full dividends have not been declared and paid on all outstanding shares of preferred stock in any dividend period, no dividend may be declared or paid or set aside for payment on our common stock. 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 26, 2023 meeting, the Board declared a quarterly common dividend of $0.250 per share, payable on February 17, 2023 to holders of record on February 7, 2023.
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 15, 2023, NiSource had 16,572 common stockholders of record and 412,507,944 shares outstanding.
The graph below compares the cumulative total shareholder return of NiSource’s common stock for the period commencing December 31, 2017 and ending December 31, 2022 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 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, 2022, 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.
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ITEM 6. RESERVED
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Not applicable.
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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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Index | Page
Executive Summary | 35
Summary of Consolidated Financial Results | 37
Results and Discussion of Segment Operations | 38
Gas Distribution Operations | 39
Electric Operations | 42
Liquidity and Capital Resources | 46
Market Risk Disclosures | 50
Other Information | 51

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.
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.
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: Gas Distribution Operations and Electric Operations.
Refer to the "Business" section under Item 1 of this annual report and Note 21, "Business Segment Information," in the Notes to Consolidated Financial Statements for further discussion of our regulated utility business segments.
Our goal is to develop strategies that benefit all stakeholders as we (i) embark on long-term infrastructure investment and safety programs to better serve our customers, (ii) align our tariff structures with our cost structure, and (iii) address changing customer conservation patterns. These strategies focus on improving safety and reliability, enhancing customer service, ensuring customer affordability and reducing emissions while generating sustainable returns. The safety of our customers, communities and employees remains our top priority. In 2022, NiSource achieved conformance certification to the American Petroleum Institute Recommended Practice 1173, which serves as the guiding practice for our SMS. This certification marks an important milestone for our SMS and NiSource’s journey towards operational excellence. Additionally, we continue to pursue regulatory and legislative initiatives that will allow residential customers not currently on our system to obtain gas service in a cost effective manner.
2022 Overview: In 2022, we continued to make significant progress towards our strategic and financial goals and objectives. We completed the first full year of operating Indiana Crossroads Wind, and construction is near completion for two of our solar projects. In 2022, we filed four rate cases and resolved three, in Pennsylvania, Maryland, and the gas rate case in Indiana filed in 2021. In addition, the Ohio rate case was resolved in January 2023 and the Virginia rate case is anticipated to be resolved in the first quarter of 2023. These cases represent balanced outcomes supporting all stakeholders. Between our Gas Distribution and Electric Operating Segments, we added 25,000 customers. We also invested $1.6 billion in infrastructure modernization to enhance safe, reliable service, including replacement of 410 miles of distribution main and service lines, 48 miles of underground cable and 1,352 electric poles.
We also made advancements in key strategic initiatives, described in further detail below.
Your Energy, Your Future: Our plan to replace our coal generation capacity by the end of 2028 with primarily renewable resources, initiated through our 2018 Integrated Resource Plan ("2018 Plan") is well underway, and we are continually adjusting to the dynamic renewable energy landscape. As of December 31, 2022, we have executed and received IURC approval for BTAs and PPAs with a combined nameplate capacity of 1,950 MW and 1,380 MW, respectively, under the 2018 Plan. During 2022, we made significant progress on our first two solar BTAs and anticipate completion of these projects and tax equity financing in 2023. We have also taken contractual actions on a number of our other renewable projects to address the
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timing of these projects as well as consider the broad market issues facing the industry. We remain on track to retire R.M Schahfer's remaining two coal units by the end of 2025. In August 2022, the IRA was signed into law. We are evaluating the impact of this legislation to our renewable projects with potential to drive increased value to customers as part of our expansion of renewable projects and generation transition strategy. However, the leveraging of the IRA will be considered on a project-by-project basis and evaluate several factors, both quantitative and qualitative, that results in the best position for project success as well as customer and company considerations. For additional information, see "Results and Discussion of Segment Operations - Electric Operations," in this Management's Discussion.
In 2021, we announced and filed with the IURC the Preferred Energy Resource Plan associated with our 2021 Integrated Resource Plan ("2021 Plan"). The 2021 Plan lays out a timeline to retire the Michigan City Generating Station by the end of 2028. The 2021 Plan calls for the replacement of the retiring units with a diverse portfolio of resources including demand side management resources, incremental solar, stand-alone energy storage and upgrades to existing facilities at the Sugar Creek Generating Station, among other steps. Additionally, the 2021 Plan calls for a natural gas peaking unit to replace existing vintage gas peaking units at the R.M. Schahfer Generating Station to support system reliability and resiliency, as well as upgrades to the transmission system to enhance our electric generation transition. The planned retirement of the two vintage gas peaking units 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. We are continuing to evaluate potential projects under the 2021 Plan given the responses to our Request for Proposal issued in August 2022.
Transformation: The NiNext initiative, which commenced in 2020, focused on optimizing our workforce and advancing our operations. NiNext has been foundational in preparing for incremental, enterprise-wide investments to address inefficiencies in our current technology footprint, which stem primarily from a complex array of legacy systems. We plan to address these inefficiencies through our Enterprise Transformation Roadmap with investments in technology systems and infrastructure. As a result of these investments, we will deliver more modern, dependable, and secure IT systems backed with standardized processes to reduce the operating risks of our business, increase workforce efficiencies, and increase visibility to data which will be leveraged to drive risk-informed decisions. Our Enterprise Transformation Roadmap will position us to accomplish future strategic investments and aspirational goals.
Economic Environment: We are monitoring risks related to increasing order and delivery lead times for construction and other materials, increasing risk of unavailability of materials due to global shortages in raw materials, and risk of decreased construction labor productivity in the event of disruptions in the availability of materials. We are also seeing increasing prices associated with certain materials and supplies. To the extent that delays occur or our costs increase, our business operations, results of operations, cash flows, and financial condition could be materially adversely affected. For more information on supply chain impacts to our electric generation strategy, see "Results and Discussion of Segment Operations - Electric Operations," in this Management's Discussion.
Early in 2022, NIPSCO experienced a rail service shortage in deliveries of coal, particularly to its Michigan City Generating Station, and the primary rail carrier for that generating station was unable to provide assurance of adequate future service to maintain coal inventory. A lack of adequate coal deliveries to any of our coal-fired generating facilities for an extended period could deplete our inventories to a level that prevents the generating station from running, and NIPSCO would need to rely on market purchases of replacement power, which could increase the cost of electricity for NIPSCO's customers. NIPSCO believes these shortages have been resolved but continues to monitor deliveries of coal from its rail carriers. This did not have a material impact on our operations in 2022.
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 anticipating to evaluate our talent footprint for the future by creating flexible work arrangements where we can, to ensure we have the right people, in the right role, and at the right time. To the extent we are unable to execute on our workforce planning initiatives and experience increased employee and contractor costs, our business operations, results of operations, cash flows, and financial condition could be materially adversely affected.
We experienced an increase in natural gas costs as the spot market for natural gas substantially increased throughout much of 2022, followed by a decrease in the price of natural gas since November 2022. Nationally, levels of gas in storage were lower in 2022 compared to 2021, liquified natural gas exports to Europe continued at a steady pace, and domestic production saw a recent decline in demand. These factors drove increased volatility in the marketplace, which influenced customer bills
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throughout 2022. While production was increasing towards the end of 2022, weather changes have limited demand and decreased withdrawals, causing inventory balances to be higher compared to 2021. With this decline in price, we expect to see lower volatility and declining customer bills. For the year ended December 31, 2022, we did not see this volatility have a material impact on our results of operations. For more information on our commodity price impacts, see "Results and Discussion of Segment Operations - Gas Distribution Operations," and "Market Risk Disclosures."
Due to rising interest rates, we experienced higher interest expense in 2022 compared to 2021 associated with short-term borrowings. 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".
For more information on global availability of materials for our renewable projects, see "Results and Discussion of Segment Operations - Electric Operations - Electric Supply and Generation Transition."
Summary of Consolidated Financial Results
A summary of our consolidated financial results for the years ended December 31, 2022, 2021 and 2020, are presented below:

|  |  |  |  |  |  | Favorable (Unfavorable)
Year Ended December 31, (in millions, except per share amounts) | 2022 |  | 2021 |  | 2020 |  | 2022 vs. 2021 |  | 2021 vs. 2020
Operating Revenues | $ | 5,850.6 |  |  | $ | 4,899.6 |  |  | $ | 4,681.7 |  |  | $ | 951.0 |  |  | $ | 217.9 |
Operating Expenses |  |  |  |  |  |  |  |  |
Cost of energy | 2,110.5 |  |  | 1,392.3 |  |  | 1,109.3 |  |  | (718.2) |  |  | (283.0) |
Other Operating Expenses | 2,474.3 |  |  | 2,500.4 |  |  | 3,021.6 |  |  | 26.1 |  |  | 521.2 |
Total Operating Expenses | 4,584.8 |  |  | 3,892.7 |  |  | 4,130.9 |  |  | (692.1) |  |  | 238.2 |
Operating Income | 1,265.8 |  |  | 1,006.9 |  |  | 550.8 |  |  | 258.9 |  |  | 456.1 |
Total Other Deductions, Net | (309.4) |  |  | (300.3) |  |  | (582.1) |  |  | (9.1) |  |  | 281.8 |
Income Taxes | 164.6 |  |  | 117.8 |  |  | (17.1) |  |  | (46.8) |  |  | (134.9) |
Net Income (Loss) | 791.8 |  |  | 588.8 |  |  | (14.2) |  |  | 203.0 |  |  | 603.0 |
Net income (loss) attributable to noncontrolling interest | (12.3) |  |  | 3.9 |  |  | 3.4 |  |  | 16.2 |  |  | (0.5) |
Net Income (Loss) attributable to NiSource | 804.1 |  |  | 584.9 |  |  | (17.6) |  |  | 219.2 |  |  | 602.5 |
Preferred dividends | (55.1) |  |  | (55.1) |  |  | (55.1) |  |  | — |  |  | — |
Net Income (Loss) Available to Common Shareholders | 749.0 |  |  | 529.8 |  |  | (72.7) |  |  | 219.2 |  |  | 602.5 |
Basic Earnings (Loss) Per Share | $ | 1.84 |  |  | $ | 1.35 |  |  | $ | (0.19) |  |  | $ | 0.49 |  |  | $ | 1.54 |
Diluted Earnings (Loss) Per Share | $ | 1.70 |  |  | $ | 1.27 |  |  | $ | (0.19) |  |  | $ | 0.43 |  |  | $ | 1.46 |

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 2022 was primarily due to higher revenues from outcomes of gas base rate proceedings and regulatory capital programs, as well as an insurance settlement related to the Greater Lawrence Incident, offset by higher income taxes in 2022 compared to 2021.
For additional information on operating income variance drivers see "Results and Discussion of Segment Operations" for Gas and Electric Operations in this Management's Discussion.
Other Deductions, Net
The change in Other deductions, net in 2022 compared to 2021 is primarily driven by higher long-term and short-term debt interest in 2022 and lower non-service pension benefits partially offset by the interest rate swap settlement gain in 2022 and charitable contributions in 2021. See Note 15, "Long-Term Debt," Note 16, "Short-Term Borrowings," and Note 12, "Pension and Other Postemployment Benefits," in the Notes to Consolidated Financial Statements for additional information.
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Income Taxes
The increase in income tax expense in 2022 compared to the same period in 2021 is primarily attributable to higher pre-tax income, offset by higher state flow through and the reduction of the Pennsylvania corporate income tax rate.
Refer to Note 11, "Income Taxes," in the Notes to Consolidated Financial Statements for additional information on income taxes and the change in the effective tax rate.
RESULTS AND DISCUSSION OF OPERATIONS
Presentation of Segment Information
Our operations are divided into two primary reportable segments: Gas Distribution Operations and Electric Operations. 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" 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.
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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
N I S OURCE I NC.
Gas Distribution Operations
Financial and operational data for the Gas Distribution Operations segment for the years ended December 31, 2022, 2021 and 2020, are presented below:

|  |  |  |  |  |  | Favorable (Unfavorable)
Year Ended December 31, (in millions) | 2022 |  | 2021 |  | 2020 |  | 2022 vs. 2021 |  | 2021 vs. 2020
Operating Revenues | $ | 4,019.8 |  |  | $ | 3,183.5 |  |  | $ | 3,140.1 |  |  | $ | 836.3 |  |  | $ | 43.4 |
Operating Expenses |  |  |  |  |  |  |  |  |
Cost of energy | 1,534.8 |  |  | 962.7 |  |  | 794.2 |  |  | (572.1) |  |  | (168.5) |
Operation and maintenance | 1,045.3 |  |  | 993.8 |  |  | 1,138.0 |  |  | (51.5) |  |  | 144.2 |
Depreciation and amortization | 415.9 |  |  | 383.0 |  |  | 363.1 |  |  | (32.9) |  |  | (19.9) |
Loss (gain) on sale of fixed assets and impairments, net | (103.9) |  |  | 8.7 |  |  | 412.4 |  |  | 112.6 |  |  | 403.7 |
Other taxes | 211.9 |  |  | 217.8 |  |  | 233.3 |  |  | 5.9 |  |  | 15.5 |
Total Operating Expenses | 3,104.0 |  |  | 2,566.0 |  |  | 2,941.0 |  |  | (538.0) |  |  | 375.0 |
Operating Income | $ | 915.8 |  |  | $ | 617.5 |  |  | $ | 199.1 |  |  | $ | 298.3 |  |  | $ | 418.4 |
Revenues |  |  |  |  |  |  |  |  |
Residential | $ | 2,609.6 |  |  | $ | 2,143.4 |  |  | $ | 2,110.6 |  |  | $ | 466.2 |  |  | $ | 32.8 |
Commercial | 942.4 |  |  | 731.0 |  |  | 679.7 |  |  | 211.4 |  |  | 51.3 |
Industrial | 221.5 |  |  | 197.2 |  |  | 213.8 |  |  | 24.3 |  |  | (16.6) |
Off-System | 192.9 |  |  | 71.3 |  |  | 41.0 |  |  | 121.6 |  |  | 30.3 |
Other | 53.4 |  |  | 40.6 |  |  | 95.0 |  |  | 12.8 |  |  | (54.4) |
Total | $ | 4,019.8 |  |  | $ | 3,183.5 |  |  | $ | 3,140.1 |  |  | $ | 836.3 |  |  | $ | 43.4 |
Sales and Transportation (MMDth) |  |  |  |  |  |  |  |  |
Residential | 249.0 |  |  | 231.2 |  |  | 249.5 |  |  | 17.8 |  |  | (18.3) |
Commercial | 181.3 |  |  | 167.0 |  |  | 170.5 |  |  | 14.3 |  |  | (3.5) |
Industrial | 490.7 |  |  | 507.1 |  |  | 538.1 |  |  | (16.4) |  |  | (31.0) |
Off-System | 32.3 |  |  | 21.6 |  |  | 23.3 |  |  | 10.7 |  |  | (1.7) |
Other | 0.3 |  |  | 0.3 |  |  | 0.3 |  |  | — |  |  | — |
Total | 953.6 |  |  | 927.2 |  |  | 981.7 |  |  | 26.4 |  |  | (54.5) |
Heating Degree Days | 5,436 |  |  | 5,002 |  |  | 5,097 |  |  | 434 |  |  | (95) |
Normal Heating Degree Days | 5,347 |  |  | 5,427 |  |  | 5,485 |  |  | (80) |  |  | (58) |
% Colder (Warmer) than Normal | 2 | % |  | (8) | % |  | (7) | % |  |  |  |
% Colder (Warmer) than Prior Year | 9 | % |  | (2) | % |  | (5) | % |  |  |  |
Gas Distribution Customers |  |  |  |  |  |  |  |  |
Residential | 2,991,913 |  | 2,970,157 |  | 2,954,478 |  | 21,756 |  |  | 15,679 |
Commercial | 254,436 |  | 253,987 |  | 253,184 |  | 449 |  |  | 803 |
Industrial | 4,870 |  | 4,921 |  | 4,968 |  | (51) |  |  | (47) |
Other | 3 |  | 4 |  | 3 |  | (1) |  |  | 1 |
Total | 3,251,222 |  | 3,229,069 |  | 3,212,633 |  | 22,153 |  |  | 16,436 |

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
N I S OURCE I NC.
Gas Distribution 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 2022 to 2021 are presented in the respective tables below. Please refer to Part II, Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations - Results and Discussion of Segment Operations - Gas Distribution Operations," of the Company's 2021 Annual Report on Form 10-K for discussion of underlying reasons for changes in our operating revenues and expenses for 2021 versus 2020.

| Favorable (Unfavorable)
Changes in Operating Revenues (in millions) | 2022 vs 2021
New rates from base rate proceedings and regulatory capital programs | $ | 169.7 |
The effects of weather in 2022 compared to 2021 | 31.1 |
Higher revenue related to off system sales | 8.8 |
The effects of customer growth | 4.9 |
Higher revenue due to the effects of resuming common credit mitigation practices | 3.5 |
Increased customer usage | 2.3 |
Other | 4.7 |
Change in operating revenues (before cost of energy and other tracked items) | $ | 225.0 |
Operating revenues offset in operating expense |
Higher cost of energy billed to customers | 572.1 |
Higher tracker deferrals within operation and maintenance, depreciation, and tax | 39.2 |
Total change in operating revenues | $ | 836.3 |

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 Gas Distribution 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 2022 compared to 2021 of 26.4 MMDth is primarily attributable to the effects of colder weather.
Commodity Price Impact
Cost of energy for the Gas Distribution Operations segment is principally comprised of the cost of natural gas used while providing transportation and distribution services to customers. All of our Gas Distribution 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. The difference 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 Gas Distribution 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.
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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
N I S OURCE I NC.
Gas Distribution Operations (continued)

| Favorable (Unfavorable)
Changes in Operating Expenses (in millions) | 2022 vs 2021
Property insurance settlement related to the Greater Lawrence Incident | $ | 105.0 |
Lower NiSource Next program expenses | 20.0 |
Lower other than income taxes primarily related to property tax expense | 17.8 |
Loss on sale and expenses related to the Massachusetts Business in 2021 | 16.6 |
Higher depreciation and amortization expense | (35.1) |
Higher outside services expenses | (12.2) |
Higher employee and administrative related expenses | (10.0) |
Higher fleet expenses | (5.5) |
Rate case settlement impacts | (3.7) |
Higher unrecoverable environmental remediation costs | (2.7) |
Higher materials and supplies expense | (2.7) |
Earnings test reserve adjustment in 2021 | (2.5) |
Other | (11.7) |
Change in operating expenses (before cost of energy and other tracked items) | $ | 73.3 |
Operating expenses offset in operating revenue |
Higher cost of energy billed to customers | (572.1) |
Higher tracker deferrals within operation and maintenance, depreciation, and tax | (39.2) |
Total change in operating expense | $ | (538.0) |

Columbia of Massachusetts Asset Sale
On October 9, 2020, we completed the sale of our Massachusetts Business. In March 2021, we reached an agreement with Eversource regarding the final purchase price, including net working capital adjustments. This resulted in a pre-tax loss for the years ended December 31, 2022 and 2021 of zero and $6.8 million, respectively, based on asset and liability balances as of the close of the transaction on October 9, 2020, transaction costs and the final purchase price. The pre-tax loss is presented as "Loss (gain) on sale of assets, net" on the Statements of Consolidated Income (Loss).
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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
N I S OURCE I NC.
Electric Operations
Financial and operational data for the Electric Operations segment for the years ended December 31, 2022, 2021 and 2020, are presented below:

|  |  |  |  |  |  | Favorable (Unfavorable)
Year Ended December 31, (in millions) | 2022 |  | 2021 |  | 2020 |  | 2022 vs. 2021 |  | 2021 vs. 2020
Operating Revenues | $ | 1,831.7 |  |  | $ | 1,697.1 |  |  | $ | 1,536.6 |  |  | $ | 134.6 |  |  | $ | 160.5 |
Operating Expenses |  |  |  |  |  |  |  |  |
Cost of energy | 575.8 |  |  | 429.7 |  |  | 315.2 |  |  | (146.1) |  |  | (114.5) |
Operation and maintenance | 486.2 |  |  | 493.6 |  |  | 497.6 |  |  | 7.4 |  |  | 4.0 |
Depreciation and amortization | 362.9 |  |  | 329.4 |  |  | 321.3 |  |  | (33.5) |  |  | (8.1) |
Gain on sale of fixed assets and impairments, net | — |  |  | (0.9) |  |  | — |  |  | (0.9) |  |  | 0.9 |
Other taxes | 44.4 |  |  | 57.5 |  |  | 53.7 |  |  | 13.1 |  |  | (3.8) |
Total Operating Expenses | 1,469.3 |  |  | 1,309.3 |  |  | 1,187.8 |  |  | (160.0) |  |  | (121.5) |
Operating Income | $ | 362.4 |  |  | $ | 387.8 |  |  | $ | 348.8 |  |  | $ | (25.4) |  |  | $ | 39.0 |
Revenues |  |  |  |  |  |  |  |  |
Residential | $ | 592.4 |  |  | $ | 568.0 |  |  | $ | 527.8 |  |  | $ | 24.4 |  |  | $ | 40.2 |
Commercial | 571.0 |  |  | 534.9 |  |  | 480.3 |  |  | 36.1 |  |  | 54.6 |
Industrial | 561.4 |  |  | 494.1 |  |  | 412.9 |  |  | 67.3 |  |  | 81.2 |
Wholesale | 13.5 |  |  | 15.7 |  |  | 12.3 |  |  | (2.2) |  |  | 3.4 |
Other | 93.4 |  |  | 84.4 |  |  | 103.3 |  |  | 9.0 |  |  | (18.9) |
Total | $ | 1,831.7 |  |  | $ | 1,697.1 |  |  | $ | 1,536.6 |  |  | $ | 134.6 |  |  | $ | 160.5 |
Sales (Gigawatt Hours) |  |  |  |  |  |  |  |  |
Residential | 3,482.9 |  |  | 3,546.8 |  |  | 3,484.0 |  |  | (63.9) |  |  | 62.8 |
Commercial | 3,682.4 |  |  | 3,698.0 |  |  | 3,550.0 |  |  | (15.6) |  |  | 148.0 |
Industrial | 7,915.3 |  |  | 8,253.7 |  |  | 7,480.3 |  |  | (338.4) |  |  | 773.4 |
Wholesale | 50.0 |  |  | 124.7 |  |  | 83.6 |  |  | (74.7) |  |  | 41.1 |
Other | 89.5 |  |  | 108.5 |  |  | 106.0 |  |  | (19.0) |  |  | 2.5 |
Total | 15,220.1 |  |  | 15,731.7 |  |  | 14,703.9 |  |  | (511.6) |  |  | 1,027.8 |
Cooling Degree Days | 942 |  |  | 1,020 |  |  | 900 |  |  | (78) |  |  | 120 |
Normal Cooling Degree Days | 831 |  |  | 803 |  |  | 803 |  |  | 28 |  |  | — |
% Warmer than Normal | 13 | % |  | 27 | % |  | 12 | % |  |  |  |
% Warmer (Colder) than prior year | (8) | % |  | 13 | % |  |  |  |  |  |
Electric Customers |  |  |  |  |  |  |  |  |
Residential | 424,735 |  |  | 422,436 |  |  | 418,871 |  |  | 2,299 |  |  | 3,565 |
Commercial | 58,374 |  |  | 58,010 |  |  | 57,435 |  |  | 364 |  |  | 575 |
Industrial | 2,130 |  |  | 2,137 |  |  | 2,154 |  |  | (7) |  |  | (17) |
Wholesale | 710 |  |  | 714 |  |  | 722 |  |  | (4) |  |  | (8) |
Other | 3 |  |  | 2 |  |  | 2 |  |  | 1 |  |  | — |
Total | 485,952 |  |  | 483,299 |  |  | 479,184 |  |  | 2,653 |  |  | 4,115 |

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
N I S OURCE I NC.
Electric 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 2022 to 2021 are presented in the respective tables below. Please refer to Part II, Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations - Results and Discussion of Segment Operations - Electric Operations," of the Company's 2021 Annual Report on Form 10-K for discussion of underlying reasons for changes in our operating revenues and expenses for 2021 versus 2020.

| Favorable (Unfavorable)
Changes in Operating Revenues (in millions) | 2022 vs 2021
PPA revenue from renewable JV projects, fully offset by JV operating expenses and noncontrolling interest net income (loss) | $ | 27.5 |
The effects of customer growth | 4.6 |
Decreased fuel handling costs | 4.0 |
New rates from regulatory capital and DSM programs | 2.8 |
Decreased customer usage | (18.5) |
Reduction in gross receipts tax, offset in operating expenses | (10.3) |
FAC adjustment(1) | (8.0) |
FAC over earnings reserve | (5.8) |
The effects of weather in 2022 compared to 2021 | (5.0) |
Other | (2.4) |
Change in operating revenues (before cost of energy and other tracked items) | $ | (11.1) |
Operating revenues offset in operating expense |
Higher cost of energy billed to customers | 146.1 |
Lower tracker deferrals within operation and maintenance, depreciation and tax | (0.4) |
Total change in operating revenues | $ | 134.6 |

(1)See Note 9, "Regulatory Matters," in the Notes to Consolidated Financial Statements for additional information.
Weather
In general, we calculate the weather-related revenue variance based on changing customer demand driven by weather variance from normal heating or cooling degree days. Our composite heating or cooling degree days reported do not directly correlate to the weather-related dollar impact on the results of Electric Operations. Heating or cooling degree days experienced during different times of the year 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 heating or cooling degree day comparison.
Sales
NIPSCO's Electric Segment results remains closely linked to the performance of the steel industry. MWh sales to steel-related industries accounted for approximately 47.4% and 48.1% of the total industrial MWh sales for the years ended December 31, 2022 and 2021, respectively.
Commodity Price Impact
Cost of energy for the Electric Operations segment is principally comprised of the cost of coal, natural gas purchased for internal generation of electricity at NIPSCO, and the cost of power purchased from generators of electricity. NIPSCO 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. The difference is recorded on the Consolidated Balance Sheets as under-recovered or over-recovered fuel 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.
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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
N I S OURCE I NC.
Electric Operations (continued)

| Favorable (Unfavorable)
Changes in Operating Expenses (in millions) | 2022 vs 2021
Renewable JV project expenses, offset by JV operating revenues | $ | (25.5) |
Higher depreciation and amortization expense driven by the JV depreciation adjustment(1) | (15.7) |
Effects of environmental recoveries in 2021 | (6.5) |
Higher outside services expenses | (5.7) |
Expenses related to the accelerated retirement of the R.M. Schahfer Generating Station's coal Units 14 and 15 in 2021 | 13.2 |
Reduction in gross receipts tax, offset in operating revenues | 10.3 |
Lower NiSource Next program expenses | 8.1 |
Lower employee and administrative expenses | 5.6 |
Other | 1.9 |
Change in operating expenses (before cost of energy and other tracked items) | $ | (14.3) |
Operating expenses offset in operating revenue |
Higher cost of energy billed to customers | (146.1) |
Lower tracker deferrals within operation and maintenance, depreciation and tax | 0.4 |
Total change in operating expense | $ | (160.0) |

(1)See Note 9, "Regulatory Matters," in the Notes to Consolidated Financial Statements for additional information.
Electric Supply and Generation Transition
NIPSCO continues to execute on an electric generation transition consistent with the 2018 Plan, which outlines the path to retire the remaining two coal units at Schahfer by the end of 2025 and the remaining coal-fired generation by the end of 2028, to be replaced by lower-cost, reliable and cleaner options. See "Project Status" discussion, below, and "Liquidity and Capital Resources" in this Management's Discussion for anticipated barriers to the success of our electric generation transition and additional information on our capital investment spend.
NIPSCO continues to work with the EPA and the Indiana Department of Environmental Management to obtain administrative approvals associated with the operation of R.M. Schahfer’s remaining two coal units beyond 2023. In the event that the approvals are not obtained, future operations could be impacted. We cannot estimate the financial impact on us if these approvals are not obtained.
The current replacement plan primarily includes renewable sources of energy, including wind, solar, and battery storage to be obtained through a combination of NIPSCO ownership and PPAs. NIPSCO has sold, and may in the future sell, renewable energy credits from this 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.
Three wind projects have been placed into service, totaling approximately 804 MW of nameplate capacity. All announced projects below have received IURC approval. During 2022, NIPSCO amended certain of its BTAs and PPAs. NIPSCO is discussing potentially amending other BTAs and PPAs. Any amendments that result in increased project costs may require additional approval by the IURC in order to obtain recovery for increased costs. Our current replacement program will be augmented by the Preferred Energy Resource Plan outlined in our 2021 Integrated Resource Plan. See "Executive Summary - Your Energy, Your Future" in this Management's Discussion for additional information.
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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
N I S OURCE I NC.
Electric Operations (continued)

Project Name | Transaction Type | Technology | Nameplate Capacity (MW) | Storage Capacity (MW) |  |  |
Dunn's Bridge I(1) | BTA | Solar | 265 | — |  |  |
Indiana Crossroads Solar(1) | BTA | Solar | 200 | — |  |  |
Dunn's Bridge II(1) | BTA | Solar & Storage | 435 | 75 |  |  |
Cavalry(1) | BTA | Solar & Storage | 200 | 60 |  |  |
Fairbanks(1) | BTA | Solar | 250 | — |  |  |
Elliott(1) | BTA | Solar | 200 | — |  |  |
Indiana Crossroads II | 15 year PPA | Wind | 204 | — |  |  |
Brickyard | 20 year PPA | Solar | 200 | — |  |  |
Greensboro | 20 year PPA | Solar & Storage | 100 | 30 |  |  |
Gibson | 22 year PPA | Solar | 280 | — |  |  |
Green River | 20 year PPA | Solar | 200 | — |  |  |

(1) Ownership of the facilities will be transferred to JVs whose members are expected to include NIPSCO and an unrelated tax equity partner.
Project Status. Our contract amendments with certain solar agreements will result in the majority of our remaining projects, and investments, being placed in service between 2023 and 2025. These amendments also formally address inflationary cost pressures communicated from the developers of our solar and storage projects that are primarily due to (i) unavailability of solar panels and other uncertainties related to the pending U.S. Department of Commerce investigation on Antidumping and Countervailing Duties petition filed by a domestic solar manufacturer (the "DOC Investigation"), (ii) the U.S. Department of Homeland Security's June 2021 Withhold Release Order on silica-based products made by Hoshine Silicon Industry Co., Ltd./Uyghur Forced Labor Prevention Act, (iii) Section 201 Tariffs and (iv) persistent general global supply chain and labor availability issues. We are also monitoring the developers of our renewable energy projects related to local permitting processes and obtaining interconnection rights. Preliminary findings from the DOC Investigation were released in December 2022, with a final decision expected in May 2023. The resolution of these issues, including the final conclusion of the DOC Investigation will determine which, if any, of our solar projects will be subject to any tariffs imposed.
In June 2022, the Biden Administration announced a 24-month tariff relief on solar panels subject to the ongoing U.S. Department of Commerce investigation and authorized the use of the Defense Production Act, to accelerate domestic production of clean energy technologies, including solar panel parts.
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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
N I S OURCE I NC.
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 $1.5 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. On December 20, 2022, we entered into a $1.0 billion term credit agreement that matures on December 19, 2023. On February 18, 2022, we amended our revolving credit agreement to, among other things, extend its term to February 18, 2027. The commercial paper program and credit facility provide cost-effective, short-term financing until it can be replaced with a balance of long-term debt and equity financing that achieves our desired capital structure. On June 10, 2022, we completed the issuance and sale of $350.0 million of 5.00% senior unsecured notes maturing in 2052, which resulted in approximately $344.6 million of net proceeds after discount and debt issuance costs. We intend to disburse an amount equal to the net proceeds of the notes to finance, in whole or in part, the acquisition of our 302 MW Indiana Crossroads Wind project and 102 MW Rosewater Wind project from the project developer. On November 7, 2022, we announced that we intend to pursue the sale of a minority interest in our NIPSCO business unit. We utilize an ATM equity program that allows us to issue and sell shares of our common stock up to an aggregate issuance of $750.0 million through December 31, 2023. As of December 31, 2022, the ATM program had approximately $300.0 million of equity available for issuance. We also expect to remarket the Series C Mandatory Convertible Preferred Stock prior to December 1, 2023, which could result in additional cash proceeds. See Note 13, "Equity," in the Notes to Consolidated Financial Statements for more information on our ATM program and Equity Units.
We believe these sources provide adequate capital to fund our operating activities and capital expenditures in 2023 and beyond.
Greater Lawrence Incident. As discussed in Part I, Item 1A, "Risk Factors," and in Note 19, "Other Commitments and Contingencies," in the Notes to Consolidated Financial Statements, due to the inherent uncertainty of litigation, there can be no assurance that the outcome or resolution of any particular claim related to the Greater Lawrence Incident will not continue to have an adverse impact on our cash flows. Through income generated from operating activities, amounts available under the short-term revolving credit facility, and our ability to access capital markets, we believe we have adequate capital available to settle remaining anticipated claims associated with the Greater Lawrence Incident.
Operating Activities
Net cash from operating activities for the year ended December 31, 2022 was $1,409.4 million, an increase of $191.5 million from 2021. This increase was primarily driven by a year over year increase in revenue and collection of under-recovered gas and fuel cost from the prior year. This was offset by increased cash outflows related to inventory purchases year over year due to higher gas costs.
Investing Activities
Net cash used for investing activities for the year ended December 31, 2022 was $2,570.2 million, an increase of $365.3 million from 2021. Our current year investing activities were comprised of increased capital expenditures related to system growth and reliability as well as payments to renewable generation asset developers related to Dunn's Bridge I and Indiana Crossroads Solar milestone payments. This was offset by the property insurance settlement related to the Greater Lawrence Incident.
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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
N I S OURCE I NC.
Capital Expenditures. The table below reflects actual capital expenditures and certain other investing activities by segment for 2022.

| Actual |  |
(in millions) | 2022 |  |  |  |  |  |
Gas Distribution Operations |  |  |  |  |  |  |
System Growth and Tracker | $ | 1,266.1 |  |  |  |  |  |  |
Maintenance | 329.7 |  |  |  |  |  |  |
Total Gas Distribution Operations(1) | 1,595.8 |  |  |  |  |  |  |
Electric Operations |  |  |  |  |  |  |
System Growth and Tracker | 345.0 |  |  |  |  |  |  |
Maintenance | 164.2 |  |  |  |  |  |  |
Generation Transition Investments | 31.4 |  |  |  |  |  |  |
Total Electric Operations(1) | 540.6 |  |  |  |  |  |  |
Corporate and Other Operations - Maintenance(1) | 161.6 |  |  |  |  |  |  |
Total Capital Expenditures(2) | $ | 2,298.0 |  |  |  |  |  |  |

(1)Amounts differ from those presented in Note 21, "Business Segment Information," in the Notes to Consolidated Financial Statements due to the allocation of Corporate and Other Maintenance Costs to the Gas Distribution and Electric Operations segments.
(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 $323.9 million of capital investments in the form of milestone payments to the renewable generation asset developer.
We expect to make capital investments totaling approximately $15 billion during the 2023-2027 period related to infrastructure modernization, generation transition and renewables and customer growth for the next five years:

(in billions) | 2022 Actual | 2023 Estimated | 2024 Estimated | 2025 Estimated | 2026 Estimated | 2027 Estimated
Capital Investments | $2.6 | $3.3 - 3.6 | $2.6 - 2.9 | $3.1 - 3.4 | $2.7 - 3.0 | $ 2.7 - 3.0

Regulatory Capital Programs. We replace pipe and modernize our gas infrastructure to enhance safety and reliability and reduce leaks. An ancillary benefit of these programs is the reduction of GHG emissions. In 2022, 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.
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The following table describes the most recent vintage of our regulatory programs to recover infrastructure replacement and other federally mandated compliance investments currently in rates or pending commission approval:

(in millions) |  |  |  |
Company | Program | Incremental Revenue | Incremental Capital Investment | Investment Period | Costs Covered(1) | Rates Effective
Columbia of Ohio(2) | IRP - 2022 | $ | 25.0 |  | $ | 232.9 |  | 1/21-12/21 | Replacement of (1) hazardous service lines, (2) cast iron, wrought iron, uncoated steel, and bare steel pipe, (3) natural gas risers prone to failure and (4) installation of AMR devices. | May 2022
Columbia of Ohio(2) | CEP - 2022 | $ | 32.2 |  | $ | 253.5 |  | 1/21-12/21 | Assets not included in the IRP. | September 2022
NIPSCO - Gas(3) | TDSIC 4 | $ | 0.5 |  | $ | 77.5 |  | 7/21-12/21 | New or replacement projects undertaken for the purpose of safety, reliability, system modernization or economic development. | July 2022
NIPSCO - Gas(4) | FMCA 1 | $ | 1.5 |  | $ | 14.1 |  | 10/21-3/22 | Project costs to comply with federal mandates. | October 2022
NIPSCO - Gas(4) | FMCA 2 | $ | 5.3 |  | $ | 38.2 |  | 4/22-9/22 | Project costs to comply with federal mandates. | April 2023
Columbia of Virginia(5) | SAVE - 2023 | $ | 4.5 |  | $ | 45.9 |  | 1/23-12/23 | Replacement projects that (1) enhance system safety or reliability, or (2) reduce, or potentially reduce, greenhouse gas emissions. | January 2023
Columbia of Kentucky(6) | SMRP - 2023 | $ | 1.6 |  | $ | 41.6 |  | 1/23-12/23 | Replacement of mains and inclusion of system safety investments. | January 2023
Columbia of Maryland | STRIDE - 2023 | $ | 1.3 |  | $ | 18.0 |  | 1/23-12/23 | Pipeline upgrades designed to improve public safety or infrastructure reliability. | January 2023
NIPSCO - Electric(7) | TDSIC - 1 | $ | 10.4 |  | $ | 148.5 |  | 6/21-1/22 | New or replacement projects undertaken for the purpose of safety, reliability, system modernization or economic development. | August 2022
NIPSCO - Electric | TDSIC - 2 | $ | 6.6 |  | $ | 143.5 |  | 2/22-7/22 | New or replacement projects undertaken for the purpose of safety, reliability, system modernization or economic development. | February 2023

(1)Programs do not include any costs already included in base rates.
(2)The January through March 2021 investments included in these filings are also included in the pending Columbia of Ohio rate case. The infrastructure filings will be adjusted to reflect the final rate case outcome.
(3)NIPSCO Gas program incremental revenue decreased because of revisions for the rate case compliance filings amounts included in base rates.
(4)NIPSCO received approval for a new certificate of public convenience and necessity on December 28, 2022 for an additional Pipeline Safety III Compliance Plan, including $235.3M in capital and $34.1M in operation and maintenance expense project investments.
(5) Columbia of Virginia received a final order on November 1, 2022 modifying the SAVE filing incremental revenue and investments.
(6)Columbia of Kentucky received an Order on December 28, 2022, modifying its 2023 SMRP filing by removing recovery of the 2022 investment not recovered as part of the most recently approved rate case. This modification lowered incremental revenue recovered through SMRP to $1.6M, a reduction of $3.2M from the original filing.
(7)NIPSCO filed for a new electric TDSIC plan on June 1, 2021. An order approving NIPSCO's new electric TDSIC plan was received on December 28, 2021.
On March 30, 2022, NIPSCO Electric filed a petition with the IURC seeking approval of NIPSCO's federally mandated costs for closure of Michigan City Generating Station's CCR ash ponds. The project includes a total estimated $40.0 million of federally mandated retirement costs. A final order is expected in the first quarter of 2023. On November 2, 2022, NIPSCO Electric filed a petition with the IURC seeking approval of NIPSCO's federally mandated costs for closure of R.M. Schahfer Generation Station's multi-cell unit. The project includes a total estimated $53.0 million of federally mandated retirement costs. NIPSCO is requesting all associated accounting and ratemaking relief, including establishment of a periodic rate adjustment through the FMCA mechanism. On February 21, 2023, the Indiana Court of Appeals issued a decision in a case filed by an Indiana utility company interpreting a statute authorizing recovery of federally mandated costs, finding that such costs incurred prior to issuance of an order by the IURC are not recoverable as federally mandated costs. If any of NIPSCO’s CCR costs were determined to be not eligible for recovery under the federal mandate mechanism, NIPSCO would seek recovery through depreciation within base rates. Refer to Note 19, "Other Commitments and Contingencies - E. Environmental Matters," in the Notes to Consolidated Financial Statements for further discussion of the CCRs.
Refer to Note 9, "Regulatory Matters," in the Notes to Consolidated Financial Statements for a further discussion of regulatory developments during 2022.
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Financing Activities
Common Stock, Preferred Stock and Equity Unit Sale. Refer to Note 13, "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 16, "Short-Term Borrowings," in the Notes to Consolidated Financial Statements for information on short-term debt.
Long-term Debt. Refer to Note 15, "Long-Term Debt," in the Notes to Consolidated Financial Statements for information on long-term debt.
Non-controlling Interest. Refer to Note 4, "Variable Interest Entities," in the Notes to Consolidated Financial Statements for information on contributions from noncontrolling interest activity.
Sources of Liquidity
The following table displays our liquidity position as of December 31, 2022 and 2021:

Year Ended December 31, (in millions) | 2022 | 2021
Current Liquidity |  |
Revolving Credit Facility | $ | 1,850.0 |  | $ | 1,850.0 |
Accounts Receivable Programs(1) | 447.2 |  | 251.2 |
Less: |  |
Commercial Paper | 415.0 |  | 560.0 |
Accounts Receivable Programs Utilized | 347.2 |  | — |
Letters of Credit Outstanding Under Credit Facility | 10.2 |  | 18.9 |
Add: |  |
Cash and Cash Equivalents | 40.8 |  | 84.2 |
Net Available Liquidity | $ | 1,565.6 |  | $ | 1,606.5 |

(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 and term credit agreement, which requires us to maintain a debt to capitalization ratio that does not exceed 70%. As of December 31, 2022, the ratio was 58.9%.
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, 2022. 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
NiSource | BBB+ | Stable | Baa2 | Stable | BBB | Stable
NIPSCO | BBB+ | Stable | Baa1 | Stable | BBB | Stable
Commercial Paper | A-2 | Stable | P-2 | Stable | F2 | Stable

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, 2022, a collateral requirement of approximately $85.7 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 620,000,000 shares, $0.01 par value, of which 600,000,000 are common stock and 20,000,000 are preferred stock. As of December 31, 2022, 412,142,602 shares of common stock and 1,302,500 shares of preferred stock were outstanding. For more information regarding our common and preferred stock, see Note 13, "Equity," in the Notes to Consolidated Financial Statements.
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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, 2022, we had $1,761.9 million in short-term borrowings outstanding. Refer to Note 15, "Long-Term Debt," and Note 16, "Short-Term Borrowings," in the Notes to Consolidated Financial Statements for further information on long-term debt and short-term borrowings, respectively.
During 2023 and 2024, we expect to make cash payments of $642.2 million and $556.9 million, respectively, related to pipeline service obligations including demand for gas transportation, gas storage and gas purchases.
Our expected payments include employer contributions to pension and other postretirement benefits plans expected to be made in 2023. Plan contributions beyond 2023 are dependent upon a number of factors, including actual returns on plan assets, which cannot be reliably estimated at this time. In 2023, we expect to make contributions of approximately $2.6 million to our pension plans and approximately $23.7 million to our postretirement medical and life plans. Refer to Note 12, "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 11, "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," - F. "Other Matters - Generation Transition," 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 Operations 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 signification 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 Segment Operations" in this Management's Discussion.
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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 is reflected in our restricted cash balance, may fluctuate significantly during periods of high volatility in the energy commodity markets.
Refer to Note 10, "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, 2022 and 2021.
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, term credit agreement 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 $8.7 million and $3.1 million for 2022 and 2021, 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 debt issuances. From time to time we may enter into forward interest rate instruments to lock in long term interest costs and/ or rates.
Refer to Note 10, "Risk Management Activities," in the Notes to Consolidated Financial Statements for further information on our interest rate risk assets and liabilities as of December 31, 2022 and 2021.
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 Policy. In addition, our Risk Management Committee has put guidelines in place which document management approval levels for credit limits, evaluation of 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.
We evaluate the financial status of our banking partners through the use of market-based metrics such as credit default swap pricing levels, and also 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 charged and collected. Certain expenses and credits subject to utility regulation or rate determination normally reflected in income are deferred on the Consolidated Balance Sheets and are recognized in income as the related amounts are included in service rates and recovered from or refunded to customers. The total amounts of regulatory assets and liabilities reflected on the Consolidated Balance Sheets were $2,580.8 million and $2,012.6 million at December 31, 2022, and $2,492.2 million and $1,980.0 million at December 31, 2021, respectively. For additional information, refer to Note 9, "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
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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.
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. VIEs and Allocation of Earnings," in the Notes to Consolidated Financial Statements.
Equity Unit Transaction. We record the Series C Mandatory Convertible Preferred Stock and forward purchase contracts that comprise the Corporate Units as a single unit of account and classify the Corporate Units as equity under the provisions of ASC 480 and ASC 815. Significant judgments regarding the economic linkage between the Series C Mandatory Convertible Preferred Stock and the forward purchase contracts, as well as the substance of the terms and conditions of the Corporate Units, were required by management in making these determinations.
The initial classification of the Corporate Units, whether viewed as a single unit of account or as two freestanding financial instruments, would affect our financial results. If determined to be two units of account, the forward purchase contracts underlying the Corporate Units would be classified as a derivative and result in impacts to net income through the recognition of interest expense and mark-to-market adjustments. If determined to be one unit of account, the equity classification of the Corporate Units would have no material impact on net income. Each classification has differing impacts to the numerator in the computation of EPS.
We consider that there are a small number of similar equity hosted unit structures and that our unit structure is unique. We also consider that the provisions of ASC 480 and ASC 815 that govern the determination of unit of account are highly complex and that alternate conclusions reached under this guidance would result in materially different financial results. See Note 13, "Equity," in the Notes to Consolidated Financial Statements for additional details of the equity unit transaction.
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
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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 2022 net periodic benefit cost, we selected a weighted-average assumption of the expected pre-tax long-term rate of return of 4.80% and 5.72% for our pension and other postretirement benefit plan assets, respectively. For measurement of 2023 net periodic benefit cost, we selected a weighted-average assumption of the expected pre-tax long-term rate of return of 7.00% and 6.69% for our pension and other postretirement benefit plan assets, respectively.
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 12, "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.
The following tables illustrate the effects of changes in these actuarial assumptions while holding all other assumptions constant:

| Impact on December 31, 2022 Projected Benefit Obligation Increase/(Decrease)
Change in Assumptions (in millions) | Pension Benefits |  | Other Postretirement Benefits
+50 basis points change in discount rate | $ | (52.6) |  |  | $ | (19.2) |
-50 basis points change in discount rate | 56.7 |  |  | 20.8 |
| Impact on 2022 Expense Increase/(Decrease)(1)
Change in Assumptions (in millions) | Pension Benefits |  | Other Postretirement Benefits
+50 basis points change in discount rate | $ | (1.7) |  |  | $ | 0.5 |
-50 basis points change in discount rate | 1.9 |  |  | 0.8 |
+50 basis points change in expected long-term rate of return on plan assets | (9.2) |  |  | (1.5) |
-50 basis points change in expected long-term rate of return on plan assets | 9.2 |  |  | 1.5 |

(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 the Gas Distribution Operations reportable segment. Our goodwill assets at December 31, 2022 were $1,486 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, 2022. A qualitative ("step 0") test was completed on May 1, 2022 for all reporting units. In the Step 0 analysis, we assessed various assumptions, events and circumstances that would have affected the estimated fair value of the applicable reporting units as compared to the baseline "step 1" fair value measurement performed May 1, 2020. The results of this assessment indicated that it was more likely than not that the estimated fair value of the reporting units substantially exceeded the related carrying values of our reporting units; therefore, no "step 1" analysis was required and no impairment charges were indicated. Since the annual evaluation, there have been no indications that the fair values of the goodwill reporting units have decreased below the carrying values.
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As noted above, application of the qualitative goodwill impairment test requires evaluating various events and circumstances to determine whether it is not more likely than not that the fair value of a reporting unit is less than its carrying amount. Although we believe all relevant factors were considered in the qualitative impairment analysis to reach the conclusion that goodwill is not impaired, significant changes in any one of the assumptions could potentially result in the recording of an impairment that could have significant impacts on the Consolidated Financial Statements.
See Note 7, "Goodwill," in the Notes to Consolidated Financial Statements for further information.
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, 2022 we recorded $453.0 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. 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, 2022 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.
Valuation allowances against deferred tax assets are recorded when we conclude it is more likely than not such asset will not be realized in future periods. Accounting for income taxes also requires that only tax benefits for positions taken or expected to be taken on tax returns that meet the more-likely-than-not recognition threshold can be recognized or continue to be recognized. We evaluate each position solely on the technical merits and facts and circumstances of the position, assuming that the position will be examined by a taxing authority that has full knowledge of all relevant information. Significant judgment is required to determine recognition thresholds and the related amount of tax benefits to be recognized. At December 31, 2022, we had established $7.8 million of valuation allowances related to certain state NOL carryforwards. Refer to Note 11, "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.”
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
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Index | Page
Report of Independent Registered Public Accounting Firm | 56
Statements of Consolidated Income (Loss) | 58
Statements of Consolidated Comprehensive Income (Loss) | 59
Consolidated Balance Sheets | 60
Statements of Consolidated Cash Flows | 62
Statements of Consolidated Stockholders' Equity | 63
Notes to Consolidated Financial Statements | 65
1. Nature of Operations and Summary of Significant Accounting Policies | 65
2. Recent Accounting Pronouncements | 68
3. Revenue Recognition | 69
4. Variable Interest Entities | 72
5. Earnings Per Share | 73
6. Property, Plant and Equipment | 75
7. Goodwill and Other Intangible Assets | 76
8. Asset Retirement Obligations | 76
9. Regulatory Matters | 76
10. Risk Management Activities | 81
11. Income Taxes | 82
12. Pension and Other Postretirement Benefits | 85
13. Equity | 95
14. Share-Based Compensation | 99
15. Long-Term Debt | 102
16. Short-Term Borrowings | 103
17. Leases | 104
18. Fair Value | 106
19. Other Commitments and Contingencies | 110
20. Accumulated Other Comprehensive Loss | 114
21. Segments of Business | 114
22. Other, Net | 116
23. Interest Expense, Net | 116
24. Supplemental Cash Flow Information | 117
Schedule II | 118

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
N I S OURCE I NC.
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, 2022 and 2021, the related statements of consolidated income (loss), comprehensive income (loss), stockholders' equity, and cash flows for each of the three years in the period ended December 31, 2022, 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, 2022 and 2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2022, 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, 2022, 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 22, 2023, 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 matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates 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 matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Impact of Rate Regulation on the Financial Statements - Refer to Notes 1 and 9 to the consolidated financial statements
Critical Audit Matter Description
The Company’s 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.
The Company’s subsidiaries’ rates are subject to regulatory rate-setting processes. 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
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
N I S OURCE I NC.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
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 accounting for rate-regulated subsidiaries as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of (1) recovery in future rates of incurred costs and (2) refunds of amounts previously collected from customers. Given that management’s accounting judgments are based on assumptions about the outcome of future decisions by regulatory commissions, auditing these judgments required specialized knowledge of accounting for rate regulation and the rate making process due to its inherent complexities.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the commissions focused on the ongoing Columbia Gas of Ohio base rate case and the Northern Indiana Public Service Company electric base rate case proceedings and included the following, among others:
•We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of costs incurred as property, plant, and equipment and deferred as regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We also tested the effectiveness of management’s controls over the initial recognition of amounts as property, plant, and equipment; regulatory assets or liabilities; and the monitoring and evaluation of regulatory developments, that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.
•We evaluated the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
• We read relevant regulatory orders issued by the commissions for the Company, regulatory statutes, interpretations, procedural memorandums, filings made by interveners, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the commissions’ treatment of similar costs under similar circumstances. We evaluated the external information and compared to management’s recorded regulatory asset and liability balances for completeness.
• For regulatory matters in process, we inspected the Company’s and intervenors’ filings with the commissions that may impact the Company’s future rates, for any evidence that might contradict management’s assertions related to recoverability of recorded assets. Additionally, we evaluated the joint stipulation filed by Columbia Gas of Ohio with the Public Utilities Commission of Ohio.
• 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’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 commissions to identify evidence that may contradict management’s assertion regarding probability of an abandonment.
• We read the relevant regulatory orders issued by the Commission for the Company’s renewable energy investments. We evaluated the appropriateness of recognizing a regulatory liability or asset representing timing differences between the profit allocated under the Hypothetical Liquidation at Book Value (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 or asset recorded in depreciation expense.
• We evaluated the Company’s disclosures related to the application of ASC Topic 980 to consolidated joint venture accounting.
/s/ DELOITTE & TOUCHE LLP
Columbus, Ohio
February 22, 2023
We have served as the Company's auditor since 2002.
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
N I S OURCE I NC.
STATEMENTS OF CONSOLIDATED INCOME (LOSS)

Year Ended December 31, (in millions, except per share amounts) | 2022 |  | 2021 |  | 2020
Operating Revenues |  |  |  |  |
Customer revenues | $ | 5,738.6 |  |  | $ | 4,731.3 |  |  | $ | 4,473.2 |
Other revenues | 112.0 |  |  | 168.3 |  |  | 208.5 |
Total Operating Revenues | 5,850.6 |  |  | 4,899.6 |  |  | 4,681.7 |
Operating Expenses |  |  |  |  |
Cost of energy | 2,110.5 |  |  | 1,392.3 |  |  | 1,109.3 |
Operation and maintenance | 1,489.4 |  |  | 1,456.0 |  |  | 1,585.9 |
Depreciation and amortization | 820.8 |  |  | 748.4 |  |  | 725.9 |
Loss (gain) on sale of assets, net | (104.2) |  |  | 7.7 |  |  | 410.6 |
Other taxes | 268.3 |  |  | 288.3 |  |  | 299.2 |
Total Operating Expenses | 4,584.8 |  |  | 3,892.7 |  |  | 4,130.9 |
Operating Income | 1,265.8 |  |  | 1,006.9 |  |  | 550.8 |
Other Income (Deductions) |  |  |  |  |
Interest expense, net | (361.6) |  |  | (341.1) |  |  | (370.7) |
Other, net | 52.2 |  |  | 40.8 |  |  | 32.1 |
Loss on early extinguishment of long-term debt | — |  |  | — |  |  | (243.5) |
Total Other Deductions, Net | (309.4) |  |  | (300.3) |  |  | (582.1) |
Income (Loss) before Income Taxes | 956.4 |  |  | 706.6 |  |  | (31.3) |
Income Taxes | 164.6 |  |  | 117.8 |  |  | (17.1) |
Net Income (Loss) | 791.8 |  |  | 588.8 |  |  | (14.2) |
Net income (loss) attributable to noncontrolling interest | (12.3) |  |  | 3.9 |  |  | 3.4 |
Net Income (Loss) attributable to NiSource | 804.1 |  |  | 584.9 |  |  | (17.6) |
Preferred dividends | (55.1) |  |  | (55.1) |  |  | (55.1) |
Net Income (Loss) Available to Common Shareholders | 749.0 |  |  | 529.8 |  |  | (72.7) |
Earnings (Loss) Per Share |  |  |  |  |
Basic Earnings (Loss) Per Share | $ | 1.84 |  |  | $ | 1.35 |  |  | $ | (0.19) |
Diluted Earnings (Loss) Per Share | $ | 1.70 |  |  | $ | 1.27 |  |  | $ | (0.19) |
Basic Average Common Shares Outstanding | 407.1 |  |  | 393.6 |  |  | 384.3 |
Diluted Average Common Shares | 442.7 |  |  | 417.3 |  |  | 384.3 |

The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
N I S OURCE I NC.
STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME (LOSS)

Year Ended December 31, (in millions, net of taxes) | 2022 |  | 2021 |  | 2020
Net Income (Loss) | $ | 791.8 |  |  | $ | 588.8 |  |  | $ | (14.2) |
Other comprehensive income (loss): |  |  |  |  |
Net unrealized gain (loss) on available-for-sale securities(1) | (13.3) |  |  | (3.9) |  |  | 2.7 |
Net unrealized gain (loss) on cash flow hedges(2) | 109.9 |  |  | 25.4 |  |  | (70.7) |
Unrecognized pension and OPEB benefit (costs)(3) | (6.9) |  |  | 8.4 |  |  | 3.9 |
Total other comprehensive income (loss) | 89.7 |  |  | 29.9 |  |  | (64.1) |
Total Comprehensive Income (Loss) | $ | 881.5 |  |  | $ | 618.7 |  |  | $ | (78.3) |

(1) Net unrealized gain (loss) on available-for-sale securities, net of $3.5 million tax benefit, $1.0 million tax benefit and $0.7 million tax expense in 2022, 2021 and 2020, respectively.
(2) Net unrealized gain (loss) on derivatives qualifying as cash flow hedges, net of $36.4 million tax expense, $8.4 million tax expense and $23.4 million tax benefit in 2022, 2021 and 2020, respectively.
(3) Unrecognized pension and OPEB benefit (costs), net of $2.3 million tax benefit, $3.8 million tax expense and $0.1 million tax benefit in 2022, 2021 and 2020, respectively.
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
N I S OURCE I NC.
CONSOLIDATED BALANCE SHEETS

(in millions) | December 31, 2022 |  | December 31, 2021
ASSETS |  |  |
Property, Plant and Equipment |  |  |
Plant | $ | 27,551.3 |  |  | $ | 25,171.3 |
Accumulated depreciation and amortization | (7,708.7) |  |  | (7,289.5) |
Net Property, Plant and Equipment(1) | 19,842.6 |  |  | 17,881.8 |
Investments and Other Assets |  |  |
Unconsolidated affiliates | 1.6 |  |  | 0.8 |
Available-for-sale debt securities (amortized cost of $166.7 and $169.3, allowance for credit losses of $0.9 and $0.2, respectively) | 151.6 |  |  | 171.8 |
Other investments | 71.0 |  |  | 87.1 |
Total Investments and Other Assets | 224.2 |  |  | 259.7 |
Current Assets |  |  |
Cash and cash equivalents | 40.8 |  |  | 84.2 |
Restricted cash | 34.6 |  |  | 10.7 |
Accounts receivable | 1,065.8 |  |  | 849.1 |
Allowance for credit losses | (23.9) |  |  | (23.5) |
Accounts receivable, net | 1,041.9 |  |  | 825.6 |
Gas inventory | 531.7 |  |  | 327.4 |
Materials and supplies, at average cost | 151.4 |  |  | 139.1 |
Electric production fuel, at average cost | 68.8 |  |  | 32.2 |
Exchange gas receivable | 128.1 |  |  | 99.6 |
Regulatory assets | 233.2 |  |  | 206.2 |
Deposits to renewable generation asset developer | 143.8 |  |  | — |
Prepayments and other | 210.0 |  |  | 195.8 |
Total Current Assets(1) | 2,584.3 |  |  | 1,920.8 |
Other Assets |  |  |
Regulatory assets | 2,347.6 |  |  | 2,286.0 |
Goodwill | 1,485.9 |  |  | 1,485.9 |
Deferred charges and other | 252.0 |  |  | 322.7 |
Total Other Assets | 4,085.5 |  |  | 4,094.6 |
Total Assets | $ | 26,736.6 |  |  | $ | 24,156.9 |

(1)Includes $978.5 million and $695.9 million in 2022 and 2021, respectively, of net property, plant and equipment assets and $25.7 million and $14.3 million in 2022 and 2021, respectively, of current assets of consolidated VIEs that may be used only to settle obligations of the consolidated VIEs. Refer to Note 4, "Variable Interest Entities," for additional information.
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
N I S OURCE I NC.
CONSOLIDATED BALANCE SHEETS

(in millions, except share amounts) | December 31, 2022 |  | December 31, 2021
CAPITALIZATION AND LIABILITIES |  |  |
Capitalization |  |  |
Stockholders’ Equity |  |  |
Common stock - $0.01 par value, 600,000,000 shares authorized; 412,142,602 and 405,303,023 shares outstanding, respectively | $ | 4.2 |  |  | $ | 4.1 |
Preferred stock - $0.01 par value, 20,000,000 shares authorized; 1,302,500 and 1,302,500 shares outstanding, respectively | 1,546.5 |  |  | 1,546.5 |
Treasury stock | (99.9) |  |  | (99.9) |
Additional paid-in capital | 7,375.3 |  |  | 7,204.3 |
Retained deficit | (1,213.6) |  |  | (1,580.9) |
Accumulated other comprehensive loss | (37.1) |  |  | (126.8) |
Total NiSource Stockholders' Equity | 7,575.4 |  |  | 6,947.3 |
Noncontrolling interest in consolidated subsidiaries | 326.4 |  |  | 325.6 |
Total Stockholders’ Equity | 7,901.8 |  |  | 7,272.9 |
Long-term debt, excluding amounts due within one year | 9,523.6 |  |  | 9,183.4 |
Total Capitalization | 17,425.4 |  |  | 16,456.3 |
Current Liabilities |  |  |
Current portion of long-term debt | 30.0 |  |  | 58.1 |
Short-term borrowings | 1,761.9 |  |  | 560.0 |
Accounts payable | 899.5 |  |  | 697.8 |
Customer deposits and credits | 324.7 |  |  | 237.9 |
Taxes accrued | 246.2 |  |  | 277.1 |
Interest accrued | 138.4 |  |  | 105.5 |
Exchange gas payable | 147.6 |  |  | 107.7 |
Regulatory liabilities | 236.8 |  |  | 137.4 |
Accrued compensation and employee benefits | 167.5 |  |  | 182.7 |
Obligations to renewable generation asset developer | 347.2 |  |  | — |
Other accruals | 360.7 |  |  | 382.0 |
Total Current Liabilities(1) | 4,660.5 |  |  | 2,746.2 |
Other Liabilities |  |  |
Deferred income taxes | 1,854.5 |  |  | 1,659.4 |
Accrued liability for postretirement and postemployment benefits | 245.5 |  |  | 292.5 |
Regulatory liabilities | 1,775.8 |  |  | 1,842.6 |
Asset retirement obligations | 478.1 |  |  | 469.7 |
Other noncurrent liabilities and deferred credits | 296.8 |  |  | 690.2 |
Total Other Liabilities(1) | 4,650.7 |  |  | 4,954.4 |
Commitments and Contingencies (Refer to Note 19, "Other Commitments and Contingencies") |  |  |
Total Capitalization and Liabilities | $ | 26,736.6 |  |  | $ | 24,156.9 |

(1)Includes $128.2 million and $10.0 million in 2022 and 2021, respectively, of current liabilities and $30.6 million and $20.5 million in 2022 and 2021, respectively, of other liabilities of consolidated VIEs that creditors do not have recourse to our general credit. Refer to Note 4, "Variable Interest Entities," for additional information.
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
N I S OURCE I NC.
STATEMENTS OF CONSOLIDATED CASH FLOWS

Year Ended December 31, (in millions) | 2022 |  | 2021 |  | 2020
Operating Activities |  |  |  |  |
Net Income (Loss) | $ | 791.8 |  |  | $ | 588.8 |  |  | $ | (14.2) |
Adjustments to Reconcile Net Income to Net Cash from Operating Activities: |  |  |  |  |
Loss on early extinguishment of debt | — |  |  | — |  |  | 243.5 |
Depreciation and amortization | 820.8 |  |  | 748.4 |  |  | 725.9 |
Deferred income taxes and investment tax credits | 156.9 |  |  | 111.9 |  |  | (29.0) |
Stock compensation expense and 401(k) profit sharing contribution | 24.9 |  |  | 24.3 |  |  | 17.4 |
Loss (gain) on sale of assets | (105.3) |  |  | 5.6 |  |  | 409.8 |
Other adjustments | 5.7 |  |  | (0.7) |  |  | (0.3) |
Changes in Assets and Liabilities: |  |  |  |  |
Accounts receivable | (216.3) |  |  | (40.3) |  |  | (3.9) |
Inventories | (258.9) |  |  | (112.9) |  |  | (1.5) |
Accounts payable | 165.0 |  |  | 54.9 |  |  | (29.7) |
Exchange gas receivable/payable | 57.8 |  |  | (114.2) |  |  | (6.9) |
Other accruals | 73.4 |  |  | 43.0 |  |  | (175.1) |
Prepayments and other current assets | (9.8) |  |  | (36.6) |  |  | (5.9) |
Regulatory assets/liabilities | (129.4) |  |  | 76.8 |  |  | 70.8 |
Postretirement and postemployment benefits | 84.7 |  |  | (96.4) |  |  | (103.6) |
Deferred charges and other noncurrent assets | (4.1) |  |  | (4.7) |  |  | (15.0) |
Other noncurrent liabilities and deferred credits | (47.8) |  |  | (30.0) |  |  | 21.7 |
Net Cash Flows from Operating Activities | 1,409.4 |  |  | 1,217.9 |  |  | 1,104.0 |
Investing Activities |  |  |  |  |
Capital expenditures | (2,203.1) |  |  | (1,838.0) |  |  | (1,758.1) |
Insurance Recoveries | 105.0 |  |  | — |  |  | — |
Cost of removal | (151.7) |  |  | (121.1) |  |  | (138.2) |
Proceeds from disposition of assets | — |  |  | 0.7 |  |  | 1,115.9 |
Purchases of available-for-sale securities | (73.5) |  |  | (102.9) |  |  | (144.7) |
Sales of available-for-sale securities | 75.7 |  |  | 97.8 |  |  | 131.4 |
Payment to renewable generation asset developer | (323.9) |  |  | (240.4) |  |  | (85.3) |
Other investing activities | 1.3 |  |  | (1.0) |  |  | (0.1) |
Net Cash Flows used for Investing Activities | (2,570.2) |  |  | (2,204.9) |  |  | (879.1) |
Financing Activities |  |  |  |  |
Proceeds from issuance of long-term debt | 345.6 |  |  | — |  |  | 2,974.0 |
Repayments of long-term debt and finance lease obligations | (60.3) |  |  | (25.7) |  |  | (1,622.0) |
Issuance of short-term debt (maturity > 90 days) | 1,000.0 |  |  | — |  |  | 1,350.0 |
Repayment of short-term debt (maturity > 90 days) | — |  |  | — |  |  | (2,200.0) |
Change in short-term debt (maturity ≤ 90 days) | 202.2 |  |  | 57.0 |  |  | (420.1) |
Issuance of common stock, net of issuance costs | 154.3 |  |  | 299.6 |  |  | 211.4 |
Equity costs, premiums and other debt related costs | (13.0) |  |  | (18.2) |  |  | (246.5) |
Contributions from noncontrolling interest | 21.2 |  |  | 245.1 |  |  | 82.2 |
Distributions to noncontrolling interest | (6.0) |  |  | (0.6) |  |  | — |
Issuance of equity units, net of underwriting costs | — |  |  | 839.9 |  |  | — |
Dividends paid - common stock | (381.5) |  |  | (345.2) |  |  | (321.6) |
Dividends paid - preferred stock | (55.1) |  |  | (55.1) |  |  | (55.1) |
Contract liability payment | (66.1) |  |  | (40.5) |  |  | — |
Net Cash Flows from (used for) Financing Activities | 1,141.3 |  |  | 956.3 |  |  | (247.7) |
Change in cash, cash equivalents and restricted cash | (19.5) |  |  | (30.7) |  |  | (22.8) |
Cash, cash equivalents and restricted cash at beginning of period | 94.9 |  |  | 125.6 |  |  | 148.4 |
Cash, Cash Equivalents and Restricted Cash at End of Period | $ | 75.4 |  |  | $ | 94.9 |  |  | $ | 125.6 |

Reconciliation to Balance Sheet | 2022 |  | 2021 |  | 2020
Cash and cash equivalents | 40.8 |  | 84.2 |  | 116.5
Restricted Cash | 34.6 |  | 10.7 |  | 9.1
Total Cash, Cash Equivalents and Restricted Cash | 75.4 |  | 94.9 |  | 125.6

The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
N I S OURCE I NC.
STATEMENTS OF CONSOLIDATED STOCKHOLDERS' EQUITY

(in millions) | 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, 2020 | $ | 3.8 |  |  | $ | 880.0 |  |  | $ | (99.9) |  |  | $ | 6,666.2 |  |  | $ | (1,370.8) |  |  | $ | (92.6) |  |  | $ | — |  |  | $ | 5,986.7 |
Comprehensive Loss: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Net Income (Loss) | — |  |  | — |  |  | — |  |  | — |  |  | (17.6) |  |  | — |  |  | 3.4 |  |  | (14.2) |
Other comprehensive loss, net of tax | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (64.1) |  |  | — |  |  | (64.1) |
Dividends: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Common stock ($0.84 per share) | — |  |  | — |  |  | — |  |  | — |  |  | (321.7) |  |  | — |  |  | — |  |  | (321.7) |
Preferred stock (See Note 13) | — |  |  | — |  |  | — |  |  | — |  |  | (55.1) |  |  | — |  |  | — |  |  | (55.1) |
Contributions from noncontrolling interest | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 82.2 |  |  | 82.2 |
Stock issuances: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Employee stock purchase plan | — |  |  | — |  |  | — |  |  | 5.7 |  |  | — |  |  | — |  |  | — |  |  | 5.7 |
Long-term incentive plan | — |  |  | — |  |  | — |  |  | 8.4 |  |  | — |  |  | — |  |  | — |  |  | 8.4 |
401(k) and profit sharing | — |  |  | — |  |  | — |  |  | 13.4 |  |  | — |  |  | — |  |  | — |  |  | 13.4 |
ATM Program | 0.1 |  |  | — |  |  | — |  |  | 196.4 |  |  | — |  |  | — |  |  | — |  |  | 196.5 |
Balance as of December 31, 2020 | $ | 3.9 |  |  | $ | 880.0 |  |  | $ | (99.9) |  |  | $ | 6,890.1 |  |  | $ | (1,765.2) |  |  | $ | (156.7) |  |  | $ | 85.6 |  |  | $ | 5,837.8 |
Comprehensive Income: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Net Income | — |  |  | — |  |  | — |  |  | — |  |  | 584.9 |  |  | — |  |  | 3.9 |  |  | 588.8 |
Other comprehensive income, net of tax | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 29.9 |  |  | — |  |  | 29.9 |
Dividends: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Common stock ($0.88 per share) | — |  |  | — |  |  | — |  |  | — |  |  | (345.5) |  |  | — |  |  | — |  |  | (345.5) |
Preferred stock (See Note 13) | — |  |  | — |  |  | — |  |  | — |  |  | (55.1) |  |  | — |  |  | — |  |  | (55.1) |
Contributions from noncontrolling interest | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 236.7 |  |  | 236.7 |
Distributions to noncontrolling interest | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (0.6) |  |  | (0.6) |
Stock issuances: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Equity Units | — |  |  | 666.5 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 666.5 |
Employee stock purchase plan | — |  |  | — |  |  | — |  |  | 5.0 |  |  | — |  |  | — |  |  | — |  |  | 5.0 |
Long-term incentive plan | — |  |  | — |  |  | — |  |  | 11.8 |  |  | — |  |  | — |  |  | — |  |  | 11.8 |
401(k) and profit sharing | — |  |  | — |  |  | — |  |  | 9.5 |  |  | — |  |  | — |  |  | — |  |  | 9.5 |
ATM Program | 0.2 |  |  | — |  |  | — |  |  | 287.9 |  |  | — |  |  | — |  |  | — |  |  | 288.1 |
Balance as of December 31, 2021 | $ | 4.1 |  |  | $ | 1,546.5 |  |  | $ | (99.9) |  |  | $ | 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 13) | — |  |  | — |  |  | — |  |  | — |  |  | (55.1) |  |  | — |  |  | — |  |  | (55.1) |
Contributions from noncontrolling interest | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 19.1 |  |  | 19.1 |
Distributions to noncontrolling interest | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (6.0) |  |  | (6.0) |
Stock issuances: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Employee stock purchase plan | — |  |  | — |  |  | — |  |  | 5.2 |  |  | — |  |  | — |  |  | — |  |  | 5.2 |
Long-term incentive plan | — |  |  | — |  |  | — |  |  | 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 |  |  | $ | (99.9) |  |  | $ | 7,375.3 |  |  | $ | (1,213.6) |  |  | $ | (37.1) |  |  | $ | 326.4 |  |  | $ | 7,901.8 |

(1)Series A, Series B, and Series C shares have an aggregate liquidation preference of $400M, $500M, and $863M, respectively. See Note 13, "Equity," for additional information.
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
N I S OURCE I NC.
STATEMENTS OF CONSOLIDATED STOCKHOLDERS’ EQUITY (continued)

| Preferred |  | Common
(in thousands) | Shares |  | Shares |  | Treasury |  | Outstanding
Balance as of January 1, 2020 | 440 |  |  | 386,099 |  |  | (3,963) |  |  | 382,136 |
Issued: |  |  |  |  |  |  |
Employee stock purchase plan | — |  |  | 236 |  |  | — |  |  | 236 |
Long-term incentive plan | — |  |  | 385 |  |  | — |  |  | 385 |
401(k) and profit sharing plan | — |  |  | 544 |  |  | — |  |  | 544 |
ATM Program | — |  |  | 8,459 |  |  | — |  |  | 8,459 |
Balance as of December 31, 2020 | 440 |  |  | 395,723 |  |  | (3,963) |  |  | 391,760 |
Issued: |  |  |  |  |  |  |
Equity Units | 863 |  |  | — |  |  | — |  |  | — |
Employee stock purchase plan | — |  |  | 209 |  |  | — |  |  | 209 |
Long-term incentive plan | — |  |  | 418 |  |  | — |  |  | 418 |
401(k) and profit sharing plan | — |  |  | 391 |  |  | — |  |  | 391 |
ATM Program | — |  |  | 12,525 |  |  | — |  |  | 12,525 |
Balance as of December 31, 2021 | 1,303 |  |  | 409,266 |  |  | (3,963) |  |  | 405,303 |
Issued: |  |  |  |  |  |  |
Employee stock purchase plan | — |  |  | 186 |  |  | — |  |  | 186 |
Long-term incentive plan | — |  |  | 375 |  |  | — |  |  | 375 |
401(k) and profit sharing plan | — |  |  | 337 |  |  | — |  |  | 337 |
ATM Program | — |  |  | 5,942 |  |  | — |  |  | 5,942 |
Balance as of December 31, 2022 | 1,303 |  |  | 416,106 |  |  | (3,963) |  |  | 412,143 |

The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
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N I S OURCE I NC.
Notes to Consolidated Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
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 3.7 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, 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 the 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 (Loss). No material impairment charges were recorded for the years ended December 31, 2022, 2021 or 2020. Refer to Note 18, "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 charged and collected. 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.
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 9, "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.
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N I S OURCE I NC.
Notes to Consolidated Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
Non-utility property includes renewable generation assets owned by JVs of which we are the primary beneficiary and is generally depreciated on a straight-line basis over the life of the associated assets. Refer to Note 6, "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 3.4% in 2022, 3.3% in 2021 and 2.6% in 2020.
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 6, "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. 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 reasonable, 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 7, "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, 2022 and 2021 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 16, "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 9, "Regulatory Matters," for additional information.
K. Inventory. 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 $43.0 million and $44.9 million at December 31, 2022 and 2021, respectively. Based on the average cost of gas using the LIFO method, the estimated replacement cost of gas in storage was greater than the stated LIFO cost by $7.7 million at December 31, 2022 and was less than the stated LIFO cost by $13.6 million at December 31, 2021. 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 $488.7 million at December 31, 2022 and $282.4 million at December 31, 2021.
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.
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Notes to Consolidated Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
L. Accounting for Exchange and Balancing Arrangements of Natural Gas. Our Gas Distribution 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 a Gas Distribution Operations 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 10, "Risk Management Activities," for additional information.
N. Income Taxes and Investment Tax Credits. We record income taxes to recognize full interperiod tax allocations. 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.
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 pension 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. We had one such interim remeasurement in the second quarter of 2022. See Note 12, "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 undiscounted 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” 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 8, "Asset Retirement Obligations," and Note 19, "Other Commitments and Contingencies," for further information.
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Notes to Consolidated Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
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 (Loss).
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. VIEs and Allocation of Earnings. We fund a significant 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 adjusts 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 (Loss).
2. Recent Accounting Pronouncements
Recently Issued Accounting Pronouncements
We have evaluated recently issued accounting pronouncements and do not believe any pronouncements will have a significant impact on our Consolidated Financial Statements or Notes to the Consolidated Financial Statements.
Recently Adopted Accounting Pronouncements
In March 2020, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting and in January 2021, the FASB issued ASU 2021-01, Reference Rate Reform (Topic 848): Scope. These pronouncements provide temporary optional expedients and exceptions for applying GAAP principles to contract modifications and hedging relationships to ease the financial reporting burdens of the expected market transition from LIBOR and other interbank offered rates to alternative reference rates. These pronouncements were effective upon issuance on March 12, 2020 through December 31, 2022. In December 2022, the FASB issued ASU 2022-06, Reference Rate Reform (Topic 848): Deferral of the Sunset Date of Topic 848, to extend the temporary accounting rules under Topic 848 from December 31, 2022 to December 31, 2024, after which entities will no longer be permitted to apply the relief in Topic
848. During the third quarter of 2022, the company applied the practical expedient under Topic 848 which allowed for the continuation of cash flow hedge accounting for interest rate derivative contracts upon the transition from LIBOR to alternative reference rates. The application of this expedient had no material impact on the Consolidated Financial Statements.
In November 2021, the FASB issued ASU 2021-10, Government Assistance (Topic 832): Disclosures by Business Entities about Government Assistance. This pronouncement requires certain annual disclosures for transactions with a government that are accounted for by applying a grant or contribution accounting model by analogy to other accounting guidance. This pronouncement is effective for financial statements issued for annual periods beginning after December 15, 2021. The company
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Notes to Consolidated Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
adopted this pronouncement in the fourth quarter of 2022. The adoption of this pronouncement did not have an impact on the Notes to the Consolidated Financial Statements.
In September 2022, the FASB issued ASU 2022-04, Liabilities-Supplier Finance Programs (Topic 405-50) - Disclosure of Supplier Finance Program Obligations. This pronouncement requires that a buyer in a supplier finance program disclose sufficient information to allow a user of financial statements to understand the program’s nature, activity during the period, changes from period to period, and potential magnitude. This pronouncement is expected to improve financial reporting by requiring new disclosures about supplier finance programs, thereby allowing financial statement users to better consider the effect of such programs on an entity’s working capital, liquidity, and cash flows. This pronouncement is effective for fiscal years beginning after December 15, 2022. The company adopted this pronouncement as of January 1, 2023. We had no active supplier finance programs as of December 31, 2022.
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 Operations segment 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 Distributions Operations exchange agreement.
Revenue Disaggregation and Reconciliation. We disaggregate revenue from contracts with customers based upon reportable segment as well as by customer class.
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Notes to Consolidated Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
The tables below reconcile revenue disaggregation by customer class to segment revenue, as well as to revenues reflected on the Statements of Consolidated Income (Loss):

Year Ended December 31, 2022 (in millions) | Gas Distribution Operations |  | Electric Operations |  | Corporate and Other(2) |  | Total
Customer Revenues(1) |  |  |  |  |  |  |
Residential | $ | 2,609.7 |  |  | $ | 592.4 |  |  | $ | — |  |  | $ | 3,202.1 |
Commercial | 939.6 |  |  | 571.0 |  |  | — |  |  | 1,510.6 |
Industrial | 220.6 |  |  | 560.6 |  |  | — |  |  | 781.2 |
Off-system | 192.9 |  |  | — |  |  | — |  |  | 192.9 |
Miscellaneous | 40.3 |  |  | 11.5 |  |  | — |  |  | 51.8 |
Total Customer Revenues | $ | 4,003.1 |  |  | $ | 1,735.5 |  |  | $ | — |  |  | $ | 5,738.6 |
Other Revenues | 4.1 |  |  | 95.4 |  |  | 12.5 |  |  | 112.0 |
Total Operating Revenues | $ | 4,007.2 |  |  | $ | 1,830.9 |  |  | $ | 12.5 |  |  | $ | 5,850.6 |

(1)Customer revenue amounts exclude intersegment revenues. See Note 21, "Business Segment Information," for discussion of intersegment revenues.
(2)Other revenues related to the Transition Services Agreement entered into in connection with the sale of the Massachusetts Business, which was substantially completed as of June 30, 2022.

Year Ended December 31, 2021 (in millions) | Gas Distribution Operations |  | Electric Operations |  | Corporate and Other(2) |  | Total
Customer Revenues(1) |  |  |  |  |  |  |
Residential | $ | 2,109.4 |  |  | $ | 567.9 |  |  | $ | — |  |  | $ | 2,677.3 |
Commercial | 722.4 |  |  | 534.9 |  |  | — |  |  | 1,257.3 |
Industrial | 195.7 |  |  | 493.4 |  |  | — |  |  | 689.1 |
Off-system | 71.3 |  |  | — |  |  | — |  |  | 71.3 |
Miscellaneous | 27.3 |  |  | 8.2 |  |  | 0.8 |  |  | 36.3 |
Total Customer Revenues | $ | 3,126.1 |  |  | $ | 1,604.4 |  |  | $ | 0.8 |  |  | $ | 4,731.3 |
Other Revenues | 45.1 |  |  | 91.9 |  |  | 31.3 |  |  | 168.3 |
Total Operating Revenues | $ | 3,171.2 |  |  | $ | 1,696.3 |  |  | $ | 32.1 |  |  | $ | 4,899.6 |

(1)Customer revenue amounts exclude intersegment revenues. See Note 21, "Business Segment Information," for discussion of intersegment revenues.
(2)Other revenues related to the Transition Services Agreement entered into in connection with the sale of the Massachusetts Business.

Year Ended December 31, 2020 (in millions) | Gas Distribution Operations |  | Electric Operations |  | Corporate and Other(2) |  | Total
Customer Revenues(1) |  |  |  |  |  |  |
Residential | $ | 2,075.0 |  |  | $ | 527.8 |  |  | $ | — |  |  | $ | 2,602.8 |
Commercial | 670.5 |  |  | 480.3 |  |  | — |  |  | 1,150.8 |
Industrial | 212.8 |  |  | 412.1 |  |  | — |  |  | 624.9 |
Off-system | 41.0 |  |  | — |  |  | — |  |  | 41.0 |
Miscellaneous | 32.7 |  |  | 20.2 |  |  | 0.8 |  |  | 53.7 |
Total Customer Revenues | $ | 3,032.0 |  |  | $ | 1,440.4 |  |  | $ | 0.8 |  |  | $ | 4,473.2 |
Other Revenues | 96.1 |  |  | 95.5 |  |  | 16.9 |  |  | 208.5 |
Total Operating Revenues | $ | 3,128.1 |  |  | $ | 1,535.9 |  |  | $ | 17.7 |  |  | $ | 4,681.7 |

(1)Customer revenue amounts exclude intersegment revenues. See Note 21, "Business Segment Information," for discussion of intersegment revenues.
(2)Other revenues related to the Transition Services Agreement entered into in connection with the sale of the Massachusetts Business.
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
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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 (Loss) 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.
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 the 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, 2022, 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.

(in millions) | Customer Accounts Receivable, Billed (less reserve) |  | Customer Accounts Receivable, Unbilled (less reserve) |
Balance as of December 31, 2021 | $ | 459.6 |  |  | $ | 337.0 |  |
Balance as of December 31, 2022 | 560.5 |  |  | 453.0 |  |

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.
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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, 2022 and December 31, 2021, are presented in the tables below:

(in millions) | Gas Distribution Operations |  | Electric Operations |  | Corporate and Other |  | Total
Balance as of January 1, 2022 | $ | 18.9 |  |  | $ | 3.8 |  |  | $ | 0.8 |  |  | $ | 23.5 |
Current period provisions | 29.1 |  |  | 6.9 |  |  | — |  |  | 36.0 |
Write-offs charged against allowance | (52.1) |  |  | (5.3) |  |  | — |  |  | (57.4) |
Recoveries of amounts previously written off | 21.3 |  |  | 0.5 |  |  | — |  |  | 21.8 |
Balance as of December 31, 2022 | $ | 17.2 |  |  | $ | 5.9 |  |  | $ | 0.8 |  |  | $ | 23.9 |

(in millions) | Gas Distribution Operations |  | Electric Operations |  | Corporate and Other |  | Total
Balance as of January 1, 2021 | $ | 41.8 |  |  | $ | 9.7 |  |  | $ | 0.8 |  |  | $ | 52.3 |
Current period provisions | 5.8 |  |  | 1.4 |  |  | — |  |  | 7.2 |
Write-offs charged against allowance | (46.7) |  |  | (7.7) |  |  | — |  |  | (54.4) |
Recoveries of amounts previously written off | 18.0 |  |  | 0.4 |  |  | — |  |  | 18.4 |
Balance as of December 31, 2021 | $ | 18.9 |  |  | $ | 3.8 |  |  | $ | 0.8 |  |  | $ | 23.5 |

In connection with the COVID-19 pandemic, certain state regulatory commissions instituted regulatory moratoriums that impacted our ability to pursue our standard credit risk mitigation practices. Following the issuance of these moratoriums, certain of our regulated operations have been authorized to recognize a regulatory asset for bad debt costs above levels currently recovered in rates. At the balance sheet date, in addition to our evaluation of the allowance for credit losses discussed above, we considered benefits available under governmental COVID-19 relief programs, the impact of unemployment benefits initiatives, and flexible payment plans being offered to customers affected by or experiencing hardship as a result of the pandemic, which could help to mitigate the potential for increasing customer account delinquencies. We also considered the on-time bill payment promotion and robust customer marketing strategy for energy assistance programs that we have implemented. Based upon this evaluation, we have concluded that the allowance for credit losses as of December 31, 2022 adequately reflected the collection risk and net realizable value of our receivables. See Note 9, "Regulatory Matters," for additional information on regulatory moratoriums and regulatory assets.
4. 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. VIEs and Allocation of Earnings," for information on our accounting policy for the VIEs.
NIPSCO owns and operates two wind facilities, Rosewater and Indiana Crossroads Wind, which have 102 MW and 302 MW of nameplate capacity, respectively. NIPSCO also owns one solar facility, which is expected to go into service in 2023, Indiana Crossroads Solar, which has 200 MW of nameplate capacity. We control decisions that are significant to these entities' ongoing operations and economic results. Therefore, we have concluded that we are the primary beneficiary and have consolidated all three entities.
Members of the respective JVs are NIPSCO (who is the managing member) and tax equity partners. 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, and NIPSCO also assumed an obligation to the developers of the wind facilities representing the remaining economic interest. The developers of the wind facilities are not a partner in the JV for federal income tax purposes and do not receive any share of earnings, tax attributes, or cash flows of each JV. Once the tax equity partner has earned their negotiated rate of return and we have reached the agreed upon contractual date, NIPSCO has the option to purchase at fair market value from the tax equity partner the remaining interest in the respective JV. NIPSCO has an obligation to purchase, through a PPA at established market rates, 100% of the electricity generated by the JVs.
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
The following table displays the total contributions paid and obligations incurred in the periods presented:

(in millions) | December 31, 2022 |  | December 31, 2021 |  | December 31, 2020
NIPSCO Cash Contributions | $ | 151.8 |  |  | $ | 2.8 |  |  | $ | 0.7 |
Tax Equity Partner Cash Contributions | 21.2 |  |  | 245.1 |  |  | 86.1 |
NIPSCO's Obligation to Developer(1) | — |  |  | 277.5 |  |  | 69.7 |
Total Contributions | $ | 173.0 |  |  | $ | 525.4 |  |  | $ | 156.5 |

(1) Outstanding amounts in "Obligations to renewable generation asset developer" in the Consolidated Balance Sheets.
We did not provide any financial or other support during the year that was not previously contractually required, nor do we expect to provide such support in the future.
Our Consolidated Balance Sheets included the following assets and liabilities associated with VIEs.

(in millions) | December 31, 2022 |  | December 31, 2021
Net Property, Plant and Equipment | $ | 978.5 |  |  | $ | 695.9 |
Current assets | 25.7 |  |  | 14.3 |
Total assets(1) | 1,004.2 |  |  | 710.2 |
Current liabilities | 128.2 |  |  | 10.0 |
Asset retirement obligations | 30.6 |  |  | 20.5 |
Total liabilities | $ | 158.8 |  |  | $ | 30.5 |

(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 VIEss do not have recourse to the general credit of the primary beneficiary.
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. For the purposes of determining diluted EPS, the shares underlying the purchase contracts included within the Equity Units were included in the calculation of potential common stock outstanding for the years ended December 31, 2022 and 2021 using the if-converted method under US GAAP. This method assumes conversion at the beginning of the reporting period, or at time of issuance, if later. For the purchase contracts, the number of shares of our common stock that would be issuable at the end of each reporting period will be reflected in the denominator of our diluted EPS calculation. If the stock price falls below the initial reference price of $24.51, subject to anti-dilution adjustments, the number of shares of our common stock used in calculating diluted EPS will be the maximum number of shares per the contract as described in Note 13, "Equity." Conversely, if the stock price is above the initial reference price of $24.51, subject to anti-dilution adjustments, a variable number of shares of our common stock will be used in calculating diluted EPS. A numerator adjustment was reflected in the calculation of diluted EPS for interest expense incurred in 2022 and 2021, net of tax, related to the purchase contracts.
We adopted ASU 2020-06 on January 1, 2022, which resulted in additional dilution from our Equity Units by requiring us to assume share settlement of the remaining purchase contract payment balance based on the average share price during the period.
The shares underlying the Series C Mandatory Convertible Preferred Stock included within the Equity Units are contingently convertible as the conversion is contingent on a successful remarketing as described in Note 13, "Equity." Contingently convertible shares where conversion is not tied to a market price trigger are excluded from the calculation of diluted EPS until such time as the contingency has been resolved under the if-converted method. As of December 31, 2022 and 2021, the contingency was not resolved and thus no shares were reflected in the denominator in the calculation of diluted EPS for the years ended December 31, 2022 and 2021.
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Diluted EPS also includes the incremental effects of the various long-term incentive compensation plans and the open ATM forward agreements during the period under the treasury stock method when the impact would be dilutive. Refer to Note 13, "Equity," for more information on our ATM forward agreements.
For the year ended December 31, 2020, we had a net loss on the Statements of Consolidated Income (Loss) during the period, and any potentially dilutive shares would have had an anti-dilutive impact on EPS. The following table presents the calculation of our basic and diluted EPS:

Year Ended December 31, (in millions, except per share amounts) | 2022 |  | 2021 |  | 2020
Numerator: |  |  |  |  |
Net Income (Loss) Available to Common Shareholders - Basic | $ | 749.0 |  |  | $ | 529.8 |  |  | $ | (72.7) |
Dilutive effect of Equity Units | 2.0 |  |  | 1.6 |  |  | — |
Net Income (Loss) Available to Common Shareholders - Diluted | $ | 751.0 |  |  | $ | 531.4 |  |  | $ | (72.7) |
Denominator: |  |  |  |  |
Average common shares outstanding - Basic | 407.1 |  |  | 393.6 |  |  | 384.3 |
Dilutive potential common shares: |  |  |  |  |
Equity Units purchase contracts | 30.2 |  |  | 22.0 |  |  | — |
Equity Units purchase contract payment balance | 3.2 |  |  | — |  |  | — |
Shares contingently issuable under employee stock plans | 0.9 |  |  | 0.8 |  |  | — |
Shares restricted under employee stock plans | 0.5 |  |  | 0.3 |  |  | — |
ATM Forward agreements | 0.8 |  |  | 0.6 |  |  | — |
Average Common Shares - Diluted | 442.7 |  |  | 417.3 |  |  | 384.3 |
Earnings per common share: |  |  |  |  |
Basic | $ | 1.84 |  |  | $ | 1.35 |  |  | $ | (0.19) |
Diluted | $ | 1.70 |  |  | $ | 1.27 |  |  | $ | (0.19) |

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
6. Property, Plant and Equipment
Our property, plant and equipment on the Consolidated Balance Sheets are classified as follows:

At December 31, (in millions) | 2022 |  | 2021
Property, Plant and Equipment |  |  |
Gas Distribution Utility(1) | $ | 16,576.4 |  |  | $ | 15,240.6 |
Electric Utility(1) | 7,162.4 |  |  | 6,754.9 |
Corporate | 271.7 |  |  | 217.8 |
Construction Work in Process | 1,398.2 |  |  | 808.0 |
Renewable Generation Assets(2) | 702.2 |  |  | 702.4 |
Non-Utility and Other | 1,440.4 |  |  | 1,447.6 |
Total Property, Plant and Equipment | $ | 27,551.3 |  |  | $ | 25,171.3 |
Accumulated Depreciation and Amortization |  |  |
Gas Distribution Utility(1) | $ | (3,678.1) |  |  | $ | (3,490.2) |
Electric Utility(1) | (2,557.4) |  |  | (2,433.1) |
Corporate | (160.0) |  |  | (132.2) |
Renewable Generation Assets(2) | (29.7) |  |  | (6.5) |
Non-Utility and Other | (1,283.5) |  |  | (1,227.5) |
Total Accumulated Depreciation and Amortization | $ | (7,708.7) |  |  | $ | (7,289.5) |
Net Property, Plant and Equipment | $ | 19,842.6 |  |  | $ | 17,881.8 |

(1)NIPSCO’s common utility plant and associated accumulated depreciation and amortization are allocated between Gas Distribution Utility and Electric Utility Property, Plant and Equipment.
(2)Our renewable generation assets are part of our electric segment and represent Non-Utility Property, owned and operated by JVs between NIPSCO and unrelated tax equity partners, and depreciated straight-line over 30 years. Refer to Note 4, "Variable Interest Entities," for additional information.
On October 1, 2021, NIPSCO retired R.M. Schahfer Generating Station Units 14 and 15. The net book value of the retired units was reclassified from "Net Property, Plant and Equipment," to current and long-term ''Regulatory Assets.'' The estimated net book value of R.M. Schahfer Generating Station's coal Units 14 and 15 and other associated plant retired was approximately $600.0 million. See Note 9, "Regulatory Matters," for additional details regarding the recovery of the regulatory assets associated with retired generating stations.
The weighted average depreciation provisions for utility plant, as a percentage of the original cost, for the periods ended December 31, 2022, 2021 and 2020 were as follows:

| 2022 |  | 2021 |  | 2020
Electric Operations | 3.1 | % |  | 3.4 | % |  | 3.4 | %
Gas Distribution Operations | 2.3 | % |  | 2.2 | % |  | 2.3 | %

We recognized depreciation expense of $685.0 million, $672.1 million and $655.6 million for the years ended 2022, 2021 and 2020, respectively. The 2022 and 2021 depreciation expense amounts include an $11.0 million and $5.3 million increase related to the regulatory deferral of income (loss) associated with our JVs, which is not included in current rates. See Note 9, "Regulatory Matters," for additional details.
Amortization of on-premise Software Costs. We amortized $53.1 million, $49.4 million and $56.7 million in 2022, 2021 and 2020, respectively, related to software recorded as intangible assets. Our unamortized software balance was $190.1 million and $181.8 million at December 31, 2022 and 2021, respectively.
Amortization of Cloud Computing Costs. We amortized $11.1 million, $10.0 million and $3.4 million in 2022, 2021 and 2020, respectively, related to cloud computing costs to "Operation and maintenance" expense. Our unamortized cloud computing balance was $45.7 million and $42.4 million at December 31, 2022 and 2021, respectively.
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7. 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, 2022 and 2021. All our goodwill has been allocated to our Gas Distribution Operations segment.
For our annual goodwill impairment analysis performed as of May 1, 2022, we completed a qualitative "step 0" assessment and determined that it was more likely than not that the estimated fair value of the reporting unit substantially exceeded the related carrying value of our reporting unit. For this test, we assessed various assumptions, events and circumstances that would have affected the estimated fair value of the reporting units as compared to the baseline "step 1" fair value measurement performed May 1, 2020.
8. 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.
Changes in our liability for asset retirement obligations for the years 2022 and 2021 are presented in the table below:

(in millions) | 2022 |  | 2021
Beginning Balance | $ | 512.4 |  |  | $ | 495.6 |
Accretion recorded as a regulatory asset/liability | 17.1 |  |  | 16.0 |
Additions | 9.5 |  |  | 23.2 |
Settlements | (22.3) |  |  | (11.2) |
Change in estimated cash flows | (3.2) |  |  | (11.2) |
Ending Balance | $ | 513.5 |  |  | $ | 512.4 |

Certain non-legal costs of removal that 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.
9. 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.
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
Regulatory assets were comprised of the following items:

At December 31, (in millions) | 2022 |  | 2021
Regulatory Assets |  |  |
Unrecognized pension and other postretirement benefit costs (see Note 12) | $ | 607.5 |  |  | $ | 512.1 |
Deferred pension and other postretirement benefit costs (see Note 12) | 72.2 |  |  | 74.8 |
Environmental costs (see Note 19-E.) | 41.4 |  |  | 45.8 |
Regulatory effects of accounting for income taxes (see Note 1-N. and Note 11) | 158.0 |  |  | 194.8 |
Under-recovered gas and fuel costs (see Note 1-J.) | 85.5 |  |  | 73.6 |
Depreciation | 191.3 |  |  | 177.5 |
Post-in-service carrying charges | 251.5 |  |  | 237.9 |
Safety activity costs | 200.7 |  |  | 171.9 |
DSM programs | 37.5 |  |  | 39.2 |
Retired coal generating stations | 744.0 |  |  | 803.9 |
Losses on commodity price risk programs (See Note 10) | 10.0 |  |  | 9.6 |
Deferred property taxes | 68.5 |  |  | 65.1 |
Renewable energy investments (See Note 1-S. and Note 4) | 37.7 |  |  | 18.5 |
Other | 75.0 |  |  | 67.5 |
Total Regulatory Assets | $ | 2,580.8 |  |  | $ | 2,492.2 |
Less: Current Portion | 233.2 |  |  | 206.2 |
Total Noncurrent Regulatory Assets | $ | 2,347.6 |  |  | $ | 2,286.0 |

Regulatory liabilities were comprised of the following items:

At December 31, (in millions) | 2022 |  | 2021
Regulatory Liabilities |  |  |
Over-recovered gas and fuel costs (see Note 1-J.) | $ | 20.6 |  |  | $ | 5.4 |
Cost of removal (see Note 8) | 675.9 |  |  | 749.5 |
Regulatory effects of accounting for income taxes (see Note 1-N. and Note 11) | 996.3 |  |  | 1,040.8 |
Deferred pension and other postretirement benefit costs (see Note 12) | 66.8 |  |  | 75.9 |
Gains on commodity price risk programs (See Note 10) | 90.0 |  |  | 34.2 |
Customer Assistance Programs | 32.9 |  |  | 13.2 |
Rate Refunds | 51.4 |  |  | 8.2 |
Other | 78.7 |  |  | 52.8 |
Total Regulatory Liabilities | $ | 2,012.6 |  |  | $ | 1,980.0 |
Less: Current Portion | 236.8 |  |  | 137.4 |
Total Noncurrent Regulatory Liabilities | $ | 1,775.8 |  |  | $ | 1,842.6 |

Regulatory assets, including under-recovered gas and fuel costs and depreciation, of approximately $1,324.7 million and $1,207.0 million as of December 31, 2022 and 2021, respectively, are not earning a return on investment. These costs are recovered over a remaining life, the longest of which is 50 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.
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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. The majority of these amounts are driven by Columbia of Ohio. On January 26, 2023, the PUCO approved the joint stipulation in Columbia of Ohio's rate case. In the stipulation, Columbia agreed to forego the continuation of its pension and OPEB deferral prospectively as of March 31, 2021. Amounts deferred as of March 31, 2021 will be included in base rates.
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 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, however, starting in March 2023, the majority of these costs will be in base rates.
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, however, starting in March 2023, the majority of these costs will be in base rates.
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 will begin recovery in March 2023 through base rates.
DSM programs. Represents costs associated with Gas Distribution Operations and Electric Operations segments' 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 December 2019 NIPSCO electric rate case order allows for the recovery of, and on, the net book value of the stations by the end of 2032 and implements a revenue credit for the retired units. The credit is based on the difference between the net book value of Units 14 and 15 upon retirement and the last base rate case proceeding. The credit will be reset when new base rates are determined. See Note 6, "Property, Plant and Equipment," for further details.
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, however, starting in March 2023, the majority of these costs will be in base rates.
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. These amounts will be collected through base rates over the life of the renewable generating assets to which they relate. Refer to Note 1, "Nature of Operations and Summary of Significant Accounting Policies - S. VIEs and Allocation of Earnings," for additional information. Renewable energy formation and developer costs are also included in this regulatory asset.
Liabilities:
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Notes to Consolidated Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
Over-recovered gas and fuel costs. Represents the difference between the cost of gas and fuel 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 2022.
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.
Rate Refunds. Represents supplier refunds received by the company that are owed to customers and will be remitted.
NIPSCO change in accounting estimate
As part of the NIPSCO Gas Settlement and Stipulation Agreement filed on March 2, 2022, NIPSCO Gas agreed to change the depreciation methodology for its calculation of depreciation rates, which reduces depreciation expense and subsequent revenues and cash flows. An order was received on July 27, 2022 approving the rate case and rates were effective as of September 1, 2022. NIPSCO has proposed a similar change in depreciation methodology in its pending electric base rate case.
Columbia of Ohio regulatory filing update
On Wednesday, April 6, 2022, the PUCO Staff issued its Staff Report in Columbia of Ohio's base rate case, filed on June 21, 2021, which was filed in conjunction with applications for an alternative rate plan, approval of certain deferral authority, and updates to certain riders. Columbia of Ohio's application requested a net rate increase approximating a 21.3% or $221.4 million increase in revenue per year. On October 31, 2022, Columbia of Ohio filed a joint stipulation and recommendation with certain parties to settle the base rate case. The joint stipulation and recommendation includes a rate increase of 7.97%, or $68.2 million and includes adjustments to plant assets, pension expenses, environmental remediation costs and other operations and maintenance expenses. The joint stipulation and recommendation also proposes to extend both of Columbia of Ohio's capital investment riders, the IRP and CEP, for capital invested through the 2026 calendar year. Columbia of Ohio recorded the material effects of the joint stipulation in the fourth quarter. On January 26, 2023, the PUCO approved the joint stipulation and recommendation.
Regulatory deferral related to renewable energy investments
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 Comprehensive Income (Loss). Refer to Note 4, "Variable Interest Entities," and Note 6, "Property, Plant and Equipment," for additional information.
FAC Adjustment
As ordered by the IURC on June 15, 2022, NIPSCO is required to refund to customers $8.0 million of over-collected fuel costs. The remaining refund is recorded as a regulatory liability on the Consolidated Balance Sheets and is expected to be refunded in 2023.
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Notes to Consolidated Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
COVID-19 Regulatory Filings
In response to COVID-19, we received approvals or directives from the regulatory commissions in the states in which we operate. The ongoing impacts of these approvals or directives are described in the table below:

Jurisdiction | Regulatory Asset balance as of December 31, 2022 (in millions) | Regulatory Asset balance as of December 31, 2021 (in millions) | Deferred COVID-19 Costs
Columbia of Ohio | $ | — |  | $ | 2.1 |  | Incremental operation and maintenance expenses
NIPSCO | $ | 2.1 |  | $ | 2.2 |  | Incremental bad debt expense and the costs to implement the requirements of the COVID-19 related order
Columbia of Pennsylvania | $ | 2.8 |  | $ | 5.2 |  | Incremental bad debt expense incurred from March 13, 2020 through December 29, 2021, above levels currently in rates
Columbia of Virginia | $ | 1.9 |  | $ | 1.5 |  | Incremental incurred costs, including incremental bad debt expense
Columbia of Maryland | $ | 1.3 |  | $ | 0.9 |  | Incremental costs (including incremental bad debt expense) incurred to ensure that customers have essential utility service during the state of emergency in Maryland. Such incremental costs must be offset by any benefit received in connection with the pandemic

On January 26, 2023, the PUCO approved the joint stipulation in Columbia of Ohio's rate case. As part of this stipulation, Columbia agreed to forego recovery of its deferred COVID-19 costs.
The Pennsylvania PUC lifted its prior pandemic-related moratorium on service terminations for non-payments of utility bills beginning April 1, 2021. In CPA's recent rate case order, total COVID-19 deferrals were updated with the remaining balance being amortized over a four-year period.
For Columbia of Virginia, the moratorium on non-residential disconnections ended on October 6, 2020, and the moratorium on residential disconnections and late payment fees ended on August 30, 2021.
In connection with the Maryland Relief Act and the order issued by the PSC of Maryland on June 15, 2021, Columbia of Maryland received approximately $0.8 million of assistance that was applied to customer accounts in August 2021. Columbia of Maryland's recent rate case order includes continued amortization of operation and maintenance expenses. All termination moratoriums will be lifted after April 1, 2023 and normal collections procedures will be resumed.
Unless otherwise noted above, all other pandemic-related regulatory actions have expired or been lifted.
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Notes to Consolidated Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
10. 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 lower our cost of debt capital, manage interest rate exposure and limit volatility in the price of natural gas.
Risk management assets and liabilities on our derivatives are presented on the Consolidated Balance Sheets as shown below:

| December 31, 2022 |  | December 31, 2021
(in millions) | Assets |  | Liabilities |  | Assets |  | Liabilities
Current(1) |  |  |  |  |  |  |
Derivatives designated as hedging instruments | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | 136.4 |
Derivatives not designated as hedging instruments | 18.8 |  | 1.1 |  | 10.6 |  | 0.4
Total | $ | 18.8 |  |  | $ | 1.1 |  |  | $ | 10.6 |  |  | $ | 136.8 |
Noncurrent(2) |  |  |  |  |  |  |
Derivatives designated as hedging instruments | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |
Derivatives not designated as hedging instruments | 66.0 |  | 1.9 |  | 13.8 |  | 7.4
Total | $ | 66.0 |  |  | $ | 1.9 |  |  | $ | 13.8 |  |  | $ | 7.4 |

(1) Presented in "Prepayments and other" and "Other accruals", respectively, on the Consolidated Balance Sheets.
(2) Presented in "Deferred charges and other" and "Other noncurrent liabilities", 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, 2022. 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 $81.8 million and $16.6 million at December 31, 2022 and 2021, respectively.
Derivatives Not Designated as Hedging Instruments
C ommodity 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, 2022 and 2021, we had 99.0 MMDth and 124.5 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, 2022, the remaining terms of these instruments range from one to five years.
All gains and losses on these derivative contracts are deferred as regulatory liabilities or assets and are remitted to or collected from customers through NIPSCO’s quarterly GCA mechanism. These instruments are not designated as hedging instruments. Refer to Note 9, "Regulatory Matters," for additional information.
Derivatives Designated as Hedging Instruments
Interest rate risk management. As of December 31, 2022, we have no forward-starting interest rate swaps outstanding.
On June 7, 2022, we settled a $250.0 million forward-starting interest rate swap agreement contemporaneously with the issuance of $350.0 million of 5.00% senior unsecured notes maturing in 2052. The derivative contract was accounted for as a cash flow hedge. As part of the transaction, the associated net unrealized gain position of $10.2 million is being amortized from AOCI into interest expense over the life of the associated debt. Refer to Note 15, "Long-Term Debt," for additional information.
On December 21, 2022, we settled a $250.0 million forward-starting interest rate swap agreement that was designated as a cash flow hedge. As part of the transaction, the associated net unrealized gain position of $10.0 million was recognized immediately
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Notes to Consolidated Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
in "Other, net" on the Statements of Consolidated Income (Loss) due to the probability that the forecasted borrowing transaction would no longer occur.
Cash flow hedges included in "Accumulated other comprehensive loss" on the Consolidated Balance Sheets were:

(in millions) | AOCI(1) |  | Gain Expected to be Reclassified to Earnings During the Next 12 Months(1) |  | Maximum Term
Interest Rate | $ | (12.6) |  |  | (0.3) |  |  | 353 months

(1) All amounts are net of tax.
The net gain related to these swaps are recorded to AOCI. We amortize the net gain over the life of the debt associated with these swaps as we recognize interest expense. These amounts are immaterial in 2022, 2021 and 2020 and are recorded in "Interest expense, net" on the Statements of Consolidated Income (Loss).
There were no amounts excluded from effectiveness testing for derivatives in cash flow hedging relationships at December 31, 2021 and 2020.
Our derivative instruments measured at fair value as of December 31, 2022 and 2021 did not contain any credit-risk-related contingent features. Cash flows for derivative financial instruments are generally classified as operating activities.
11. Income Taxes
Income Tax Expense. The components of income tax expense (benefit) were as follows:

Year Ended December 31, (in millions) | 2022 |  | 2021 |  | 2020
Income Taxes |  |  |  |  |
Current |  |  |  |  |
Federal | $ | 0.4 |  |  | $ | (0.1) |  |  | $ | 0.2 |
State | 7.3 |  |  | 6.0 |  |  | 11.7 |
Total Current | 7.7 |  |  | 5.9 |  |  | 11.9 |
Deferred |  |  |  |  |
Federal | 181.0 |  |  | 99.2 |  |  | (0.4) |
State | (23.0) |  |  | 13.8 |  |  | (27.4) |
Total Deferred | 158.0 |  |  | 113.0 |  |  | (27.8) |
Deferred Investment Credits | (1.1) |  |  | (1.1) |  |  | (1.2) |
Income Taxes | $ | 164.6 |  |  | $ | 117.8 |  |  | $ | (17.1) |

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Notes to Consolidated Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
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:

Year Ended December 31, (in millions) | 2022 |  | 2021 |  | 2020
Book income (loss) before income taxes | $ | 956.4 |  |  |  |  | $ | 706.6 |  |  |  |  | $ | (31.3) |  |  |
Tax expense (benefit) at statutory federal income tax rate | 200.8 |  |  | 21.0 | % |  | 148.3 |  |  | 21.0 | % |  | (6.6) |  |  | 21.0 | %
Increases (reductions) in taxes resulting from: |  |  |  |  |  |  |  |  |  |  |
State income taxes, net of federal income tax benefit | 4.5 |  |  | 0.5 |  |  | 14.1 |  |  | 2.0 |  |  | (11.7) |  |  | 37.4 |
Amortization of regulatory liabilities | (38.5) |  |  | (4.0) |  |  | (39.1) |  |  | (5.5) |  |  | (38.4) |  |  | 122.7 |
Fines and penalties | 0.3 |  |  | — |  |  | — |  |  | — |  |  | 11.8 |  |  | (37.7) |
Employee stock ownership plan dividends and other compensation | (1.2) |  |  | (0.1) |  |  | (1.2) |  |  | (0.2) |  |  | (1.3) |  |  | 4.2 |
Deferred taxes on TCJA regulatory liability divested | — |  |  | — |  |  | — |  |  | — |  |  | 23.3 |  |  | (74.5) |
Tax accrual adjustments | 0.2 |  |  | — |  |  | (0.1) |  |  | — |  |  | 8.9 |  |  | (28.4) |
Federal tax credits | (2.3) |  |  | (0.2) |  |  | (2.1) |  |  | (0.3) |  |  | (2.5) |  |  | 8.0 |
Other adjustments | 0.8 |  |  | — |  |  | (2.1) |  |  | (0.3) |  |  | (0.6) |  |  | 1.9 |
Income Taxes | $ | 164.6 |  |  | 17.2 | % |  | $ | 117.8 |  |  | 16.7 | % |  | $ | (17.1) |  |  | 54.6 | %

The difference in tax expense year-over-year has a relative impact on the effective tax rate proportional to pretax income or loss. The 0.5% increase in effective tax rate in 2022 versus 2021 was primarily due to decreased amortization of excess deferred income taxes, offset by the state jurisdictional mix of pre-tax income in 2022 tax effected at statutory tax rates, and the reduction of the Pennsylvania corporate income tax rate.
The 37.9% decrease in effective tax rate in 2021 versus 2020 was primarily the result of higher pre-tax income, state jurisdictional mix of pre-tax income in 2021 tax effected at statutory tax rates and increased amortization of excess deferred federal income taxes in 2021 compared to 2020. These items were offset by decreased deferred tax expense recognized on the sale of Columbia of Massachusetts' regulatory liability in 2020, established due to TCJA in 2017, that would have otherwise been recognized over the amortization period, 2020 non-deductible penalties and valuation allowance related to Columbia of Massachusetts and 2020 one-time tax accrual adjustments.
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Notes to Consolidated Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
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 liability were as follows:

At December 31, (in millions) | 2022 |  | 2021
Deferred tax liabilities |  |  |
Accelerated depreciation and other property differences | $ | 2,527.9 |  |  | $ | 2,454.4 |
Other regulatory assets | 348.4 |  |  | 308.6 |
Total Deferred Tax Liabilities | 2,876.3 |  |  | 2,763.0 |
Deferred tax assets |  |  |
Other regulatory liabilities and deferred investment tax credits (including TCJA) | 294.3 |  |  | 284.7 |
Pension and other postretirement/postemployment benefits | 124.7 |  |  | 104.8 |
Net operating loss carryforward and AMT credit carryforward | 491.0 |  |  | 545.9 |
Environmental liabilities | 20.7 |  |  | 22.2 |
Other accrued liabilities | 55.9 |  |  | 42.1 |
Other, net | 43.0 |  |  | 111.7 |
Total Deferred Tax Assets | 1,029.6 |  |  | 1,111.4 |
Valuation Allowance | (7.8) |  |  | (7.8) |
Net Deferred Tax Assets | 1,021.8 |  |  | 1,103.6 |
Net Deferred Tax Liabilities | $ | 1,854.5 |  |  | $ | 1,659.4 |

At December 31, 2022, we have federal net operating loss carryforwards of $410.0 million (tax effected). The federal net operating loss carryforwards are available to offset taxable income and will begin to expire in 2036. We believe it is more likely than not that we will realize the benefit from the federal net operating loss carryforwards.
We also have $73.2 million (tax effected, net of federal benefit) of state net operating loss carryforwards. Depending on the jurisdiction in which the state net operating loss was generated, the carryforwards will begin to expire in 2028.
We believe it is more likely than not that a portion of the benefit from certain state NOL carryforwards will not be realized. In recognition of this risk, we have provided a valuation allowance of $7.8 million (net) 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, 2022, (in millions) | 2022 |  | 2021 |  | 2020
Opening Balance | $ | 21.7 |  |  | $ | 21.7 |  |  | $ | 23.2 |
Gross decreases - tax positions in prior period | — |  |  | — |  |  | (1.5) |
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 present accrued interest on unrecognized tax benefits, accrued interest on other income tax liabilities and tax penalties in "Income Taxes" on our Statements of Consolidated Income (Loss). Interest expense recorded on unrecognized tax benefits and other income tax liabilities was immaterial for all periods presented. There were no accruals for penalties recorded in the Statements of Consolidated Income (Loss) for the years ended December 31, 2022, 2021 and 2020, and there were no balances for accrued penalties recorded on the Consolidated Balance Sheets as of December 31, 2022 and 2021.
We are subject to income taxation in the United States and various state jurisdictions, primarily Indiana, Pennsylvania, Kentucky, Massachusetts, Maryland and Virginia.
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Notes to Consolidated Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
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, 2022, tax years through 2021 have been audited and are effectively closed to further assessment. The Company has transitioned to the Bridge Phase of the IRS CAP for the year ended December 31, 2022, which will remain open until an audit is completed or the statute of limitation expires.
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, 2022, there were no state income tax audits in progress that would have a material impact on the consolidated financial statements.
12. 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, 2022 and December 31, 2021, the acceptable minimum and maximum ranges established by the policy for the pension and other postretirement benefit plans are as follows:

December 31, 2022 | Defined Benefit Pension Plan |  | Postretirement Benefit Plan
Asset Category | Minimum |  | Maximum |  | Minimum |  | Maximum
Domestic Equities | 7% |  | 27% |  | 0% |  | 55%
International Equities | 3% |  | 13% |  | 0% |  | 25%
Fixed Income | 69% |  | 81% |  | 20% |  | 100%
Real Estate | 0% |  | 3% |  | 0% |  | 0%
Private Equity | 0% |  | 3% |  | 0% |  | 0%
Short-Term Investments | 0% |  | 10% |  | 0% |  | 10%

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Notes to Consolidated Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

December 31, 2021 | Defined Benefit Pension Plan |  | Postretirement Benefit Plan
Asset Category | Minimum |  | Maximum |  | Minimum |  | Maximum
Domestic Equities | 7% |  | 27% |  | 0% |  | 55%
International Equities | 3% |  | 13% |  | 0% |  | 25%
Fixed Income | 69% |  | 81% |  | 20% |  | 100%
Real Estate | 0% |  | 3% |  | 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, 2022 and December 31, 2021 are as follows:

| Defined Benefit Pension Assets(1) |  | December 31, 2022 |  | Postretirement Benefit Plan Assets |  | December 31, 2022
Asset Class (in millions) | Asset Value |  | % of Total Assets |  | Asset Value |  | % of Total Assets
Domestic Equities | $ | 231.1 |  |  | 16.2 | % |  | $ | 86.9 |  |  | 38.6 | %
International Equities | 119.0 |  |  | 8.4 | % |  | 36.6 |  |  | 16.3 | %
Fixed Income | 1,004.3 |  |  | 70.6 | % |  | 94.7 |  |  | 42.1 | %
Real Estate | 5.0 |  |  | 0.3 | % |  | — |  |  | — |
Cash/Other | 63.4 |  |  | 4.5 | % |  | 6.7 |  |  | 3.0 | %
Total | $ | 1,422.8 |  |  | 100.0 | % |  | $ | 224.9 |  |  | 100.0 | %
| Defined Benefit Pension Assets(1) |  | December 31, 2021 |  | Postretirement Benefit Plan Assets |  | December 31, 2021
Asset Class (in millions) | Asset Value |  | % of Total Assets |  | Asset Value |  | % of Total Assets
Domestic Equities | $ | 324.3 |  |  | 16.4 | % |  | $ | 118.6 |  |  | 40.4 | %
International Equities | 150.9 |  |  | 7.6 | % |  | 50.5 |  |  | 17.2 | %
Fixed Income | 1,382.3 |  |  | 69.7 | % |  | 118.8 |  |  | 40.4 | %
Real Estate | 37.2 |  |  | 1.9 | % |  | — |  |  | — |
Cash/Other | 87.0 |  |  | 4.4 | % |  | 5.8 |  |  | 2.0 | %
Total | $ | 1,981.7 |  |  | 100.0 | % |  | $ | 293.7 |  |  | 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, 2022 and 2021. Assets are classified in their entirety based on the observability of inputs used in determining the fair value measurement. There were no investment assets in the pension and other postretirement benefits trusts classified within Level 3 for the years ended December 31, 2022 and 2021.
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Notes to Consolidated Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
We use the following valuation techniques to determine fair value. For the year ended December 31, 2022, 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.
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Notes to Consolidated Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
Fair Value Measurements at December 31, 2022:

(in millions) | December 31, 2022 |  | 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 | $ | 2.5 |  |  | $ | 2.0 |  |  | $ | 0.5 |  |  | $ | — |
Equity securities |  |  |  |  |  |  |
International equities | 0.5 |  |  | 0.5 |  |  | — |  |  | — |
Fixed income securities |  |  |  |  |  |  |
Government | 316.3 |  |  | — |  |  | 316.3 |  |  | — |
Corporate | 407.8 |  |  | — |  |  | 407.8 |  |  | — |
Mortgages/ Asset Backed Securities | 2.3 |  |  | — |  |  | 2.3 |  |  | — |
Other fixed income | 1.9 |  |  | 1.9 |  |  | — |  |  | — |
Mutual Funds |  |  |  |  |  |  |
U.S. multi-strategy | 97.4 |  |  | 97.4 |  |  | — |  |  | — |
International equities | 29.0 |  |  | 29.0 |  |  | — |  |  | — |
Fixed income | 0.2 |  |  | 0.2 |  |  | — |  |  | — |
Private equity limited partnerships(3) |  |  |  |  |  |  |
U.S. multi-strategy(1) | 6.3 |  |  | — |  |  | — |  |  | — |
International multi-strategy(2) | 2.3 |  |  | — |  |  | — |  |  | — |
Distressed opportunities | 0.1 |  |  | — |  |  | — |  |  | — |
Real estate(3) | 5.0 |  |  | — |  |  | — |  |  | — |
Commingled funds(3) |  |  |  |  |  |  |
Short-term money markets | 46.2 |  |  | — |  |  | — |  |  | — |
U.S. equities | 133.7 |  |  | — |  |  | — |  |  | — |
International equities | 89.6 |  |  | — |  |  | — |  |  | — |
Fixed income | 275.9 |  |  | — |  |  | — |  |  | — |
Pension plan assets subtotal | $ | 1,417.0 |  |  | $ | 131.0 |  |  | $ | 726.9 |  |  | $ | — |
Other postretirement benefit plan assets: |  |  |  |  |  |  |
Mutual funds |  |  |  |  |  |  |
U.S. multi-strategy | 76.2 |  |  | 76.2 |  |  | — |  |  | — |
International equities | 16.3 |  |  | 16.3 |  |  | — |  |  | — |
Fixed income | 94.7 |  |  | 94.7 |  |  | — |  |  | — |
Commingled funds(3) |  |  |  |  |  |  |
Short-term money markets | 17.4 |  |  | — |  |  | — |  |  | — |
U.S. equities | 10.7 |  |  | — |  |  | — |  |  | — |
International equities | 20.3 |  |  | — |  |  | — |  |  | — |
Other postretirement benefit plan assets subtotal | $ | 235.6 |  |  | $ | 187.2 |  |  | $ | — |  |  | $ | — |
Due to brokers, net(4) | (2.0) |  |  | — |  |  | (2.0) |  |  | — |
Receivables/payables | (10.7) |  |  | — |  |  | (10.7) |  |  | — |
Accrued income/dividends | 7.8 |  |  | 7.8 |  |  | — |  |  | — |
Total pension and other postretirement benefit plan assets | $ | 1,647.7 |  |  | $ | 326.0 |  |  | $ | 714.2 |  |  | $ | — |

(1)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.
(2)This class includes limited partnerships/fund of funds 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.
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
(3)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.
(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, 2022:

(in millions) | Fair Value |  | Unfunded Commitments |  | Redemption Frequency |  | Redemption Notice Period
Commingled Funds |  |  |  |  |  |  |
Short-term money markets | $ | 63.6 |  |  | $ | — |  |  | Daily |  | 1 day
U.S. equities | 144.4 |  |  | — |  |  | Daily |  | 1 day - 5 days
International equities | 109.9 |  |  | — |  |  | Monthly |  | 10 days-30 days
Fixed income | 275.9 |  |  | — |  |  | Daily |  | 3 days
Private Equity and Real Estate Limited Partnerships(1) | 13.7 |  |  | 11.6 |  |  | N/A |  | N/A
Total | $ | 607.5 |  |  | $ | 11.6 |  |  |  |  |

(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.
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Notes to Consolidated Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
Fair Value Measurements at December 31, 2021:

(in millions) | December 31, 2021 |  | 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 | $ | 10.3 |  |  | $ | 9.7 |  |  | $ | 0.6 |  |  | $ | — |
Equity securities |  |  |  |  |  |  |
International equities | 0.5 |  |  | 0.5 |  |  | — |  |  | — |
Fixed income securities |  |  |  |  |  |  |
Government | 387.3 |  |  | — |  |  | 387.3 |  |  | — |
Corporate | 645.9 |  |  | — |  |  | 645.9 |  |  | — |
Mutual Funds |  |  |  |  |  |  |
U.S. multi-strategy | 128.4 |  |  | 128.4 |  |  | — |  |  | — |
International equities | 38.7 |  |  | 38.7 |  |  | — |  |  | — |
Private equity limited partnerships(3) |  |  |  |  |  |  |
U.S. multi-strategy(1) | 10.9 |  |  | — |  |  | — |  |  | — |
International multi-strategy(2) | 4.5 |  |  | — |  |  | — |  |  | — |
Distressed opportunities | 0.1 |  |  | — |  |  | — |  |  | — |
Real estate(3) | 37.2 |  |  | — |  |  | — |  |  | — |
Commingled funds(3) |  |  |  |  |  |  |
Short-term money markets | 55.0 |  |  | — |  |  | — |  |  | — |
U.S. equities | 195.9 |  |  | — |  |  | — |  |  | — |
International equities | 111.7 |  |  | — |  |  | — |  |  | — |
Fixed income | 349.1 |  |  | — |  |  | — |  |  | — |
Pension plan assets subtotal | $ | 1,975.5 |  |  | $ | 177.3 |  |  | $ | 1,033.8 |  |  | $ | — |
Other postretirement benefit plan assets: |  |  |  |  |  |  |
Mutual funds |  |  |  |  |  |  |
U.S. multi-strategy | 103.8 |  |  | 103.8 |  |  | — |  |  | — |
International equities | 24.4 |  |  | 24.4 |  |  | — |  |  | — |
Fixed income | 118.5 |  |  | 118.5 |  |  | — |  |  | — |
Commingled funds(3) |  |  |  |  |  |  |
Short-term money markets | 5.8 |  |  | — |  |  | — |  |  | — |
U.S. equities | 14.8 |  |  | — |  |  | — |  |  | — |
International equities | 26.1 |  |  | — |  |  | — |  |  | — |
Other postretirement benefit plan assets subtotal | $ | 293.4 |  |  | $ | 246.7 |  |  | $ | — |  |  | $ | — |
Due to brokers, net(4) | (1.8) |  |  | — |  |  | (1.8) |  |  | — |
Receivables/payables | 0.3 |  |  | — |  |  | 0.3 |  |  | — |
Accrued income/dividends | 8.0 |  |  | 8.0 |  |  | — |  |  | — |
Total pension and other postretirement benefit plan assets | $ | 2,275.4 |  |  | $ | 432.0 |  |  | $ | 1,032.3 |  |  | $ | — |

(1)This class includes limited partnerships/fund of funds that invest in a diverse portfolio of private equity strategies, including buy-outs, venture capital, growth capital, special situations and secondary markets, primarily inside the United States.
(2)This class includes limited partnerships/fund of funds that invest in diverse portfolio of private equity strategies, including buy-outs, venture capital, growth capital, special situations and secondary markets, primarily outside the United States.
(3)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.
(4)This class represents pending trades with brokers.
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Notes to Consolidated Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
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, 2021:

(in millions) | Fair Value |  | Unfunded Commitments |  | Redemption Frequency |  | Redemption Notice Period
Commingled Funds |  |  |  |  |  |  |
Short-term money markets | $ | 60.8 |  |  | $ | — |  |  | Daily |  | 1 day
U.S. equities | 210.7 |  |  | — |  |  | Daily |  | 1 day -5 days
International equities | 137.8 |  |  | — |  |  | Monthly |  | 10 days - 30 days
Fixed income | 349.1 |  |  | — |  |  | Daily |  | 3 days
Private Equity and Real Estate Limited Partnerships(1) | 20.4 |  |  | 12.1 |  |  | N/A |  | N/A
Total | $ | 778.8 |  |  | $ | 12.1 |  |  |  |  |

(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.
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Notes to Consolidated Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
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:

| Pension Benefits |  | Other Postretirement Benefits
(in millions) | 2022 |  | 2021 |  | 2022 |  | 2021
Change in projected benefit obligation(1) |  |  |  |  |  |  |
Benefit obligation at beginning of year | $ | 1,852.4 |  |  | $ | 2,058.4 |  |  | $ | 556.2 |  |  | $ | 590.8 |
Service cost | 27.8 |  |  | 30.2 |  |  | 6.5 |  |  | 6.2 |
Interest cost | 40.5 |  |  | 31.4 |  |  | 12.0 |  |  | 9.9 |
Plan participants’ contributions | — |  |  | — |  |  | 4.1 |  |  | 4.2 |
Plan amendments | 0.2 |  |  | — |  |  | 2.1 |  |  | 0.1 |
Actuarial gain(2) | (318.7) |  |  | (68.7) |  |  | (89.9) |  |  | (14.8) |
Benefits paid | (174.8) |  |  | (198.9) |  |  | (42.3) |  |  | (40.6) |
Estimated benefits paid by incurred subsidy | — |  |  | — |  |  | 0.3 |  |  | 0.4 |
Projected benefit obligation at end of year | $ | 1,427.4 |  |  | $ | 1,852.4 |  |  | $ | 449.0 |  |  | $ | 556.2 |
Change in plan assets |  |  |  |  |  |  |
Fair value of plan assets at beginning of year | $ | 1,981.7 |  |  | $ | 2,117.7 |  |  | $ | 293.7 |  |  | $ | 286.4 |
Actual return on plan assets | (386.8) |  |  | 58.9 |  |  | (51.9) |  |  | 23.9 |
Employer contributions | 2.7 |  |  | 4.0 |  |  | 21.3 |  |  | 19.8 |
Plan participants’ contributions | — |  |  | — |  |  | 4.1 |  |  | 4.2 |
Benefits paid | (174.8) |  |  | (198.9) |  |  | (42.3) |  |  | (40.6) |
Fair value of plan assets at end of year | $ | 1,422.8 |  |  | $ | 1,981.7 |  |  | $ | 224.9 |  |  | $ | 293.7 |
Funded Status at end of year | $ | (4.6) |  |  | $ | 129.3 |  |  | $ | (224.1) |  |  | $ | (262.5) |
Amounts recognized in the statement of financial position consist of: |  |  |  |  |  |  |
Noncurrent assets | 18.3 |  |  | 159.3 |  |  | — |  |  | — |
Current liabilities | (2.6) |  |  | (2.8) |  |  | (1.0) |  |  | (1.0) |
Noncurrent liabilities | (20.3) |  |  | (27.2) |  |  | (223.1) |  |  | (261.5) |
Net amount recognized at end of year(3) | $ | (4.6) |  |  | $ | 129.3 |  |  | $ | (224.1) |  |  | $ | (262.5) |
Amounts recognized in accumulated other comprehensive income or regulatory asset/liability(4) |  |  |  |  |  |  |
Unrecognized prior service credit | $ | 0.4 |  |  | $ | 0.3 |  |  | $ | (3.4) |  |  | $ | (7.8) |
Unrecognized actuarial loss | 564.2 |  |  | 438.0 |  |  | 64.0 |  |  | 88.5 |
Net amount recognized at end of year | $ | 564.6 |  |  | $ | 438.3 |  |  | $ | 60.6 |  |  | $ | 80.7 |

(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 rate. The postretirement benefit gain was also primarily driven by an increase in discount 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 $607.5 million and zero, respectively, as of December 31, 2022, and $512.1 million and zero, respectively, as of December 31, 2021 that would otherwise have been recorded to accumulated other comprehensive loss.
Our accumulated benefit obligation for our pension plans was $1,416.8 million and $1,834.4 million as of December 31, 2022 and 2021, 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
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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."
Information for pension plans with a projected benefit obligation in excess of plan assets:

| December 31,
| 2022 |  | 2021
Accumulated Benefit Obligation | $ | 22.9 |  |  | $ | 30.0 |
Funded Status |  |  |
Projected Benefit Obligation | 22.9 |  |  | 30.0 |
Funded Status of Underfunded Pension Plans at End of Year(1) | $ | (22.9) |  |  | $ | (30.0) |

(1)As of December 31, 2022 and 2021, only our nonqualified plans were underfunded. These plans have no assets as they are not funded until benefits are paid.
Information for pension plans with plan assets in excess of the projected benefit obligation:

| December 31,
| 2022 |  | 2021
Accumulated Benefit Obligation | $ | 1,393.8 |  |  | $ | 1,804.3 |
Funded Status |  |  |
Projected Benefit Obligation | 1,404.5 |  |  | 1,822.4 |
Fair Value of Plan Assets | 1,422.8 |  |  | 1,981.7 |
Funded Status of Overfunded Pension Plans at End of Year | $ | 18.3 |  |  | $ | 159.3 |

Our pension plans were underfunded, in aggregate, by $4.6 million at December 31, 2022 compared to being overfunded by $129.3 million at December 31, 2021. The decline in the funded status was primarily due to unfavorable asset returns offset by an increase in discount rates. We contributed $2.7 million and $4.0 million to our pension plans in 2022 and 2021, respectively.
Our other postretirement benefit plans were underfunded by $224.1 million at December 31, 2022 compared to being underfunded by $262.5 million at December 31, 2021. The improvement in funded status was primarily due to increased discount rates offset by unfavorable asset returns. We contributed $21.3 million and $19.8 million to our other postretirement benefit plans in 2022 and 2021, respectively.
In 2022 and 2021, some of our qualified 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 $12.4 million and $11.4 million in 2022 and 2021, respectively. Net periodic pension benefit cost increased by $5.7 million and $4.0 million in 2022 and 2021, respectively, as the result of the remeasurement.
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Notes to Consolidated Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
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:

| Pension Benefits |  | Other Postretirement Benefits
| 2022 |  | 2021 |  | 2022 |  | 2021
Weighted-average assumptions to Determine Benefit Obligation |  |  |  |  |  |  |
Discount Rate | 5.14 | % |  | 2.76 | % |  | 5.17 | % |  | 2.85 | %
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 |  | 6.69 | % |  | 6.20 | %
Ultimate Trend | N/A |  | N/A |  | 4.75 | % |  | 4.50 | %
Year Ultimate Trend Reached | N/A |  | N/A |  | 2032 |  | 2030

We expect to make contributions of approximately $2.6 million to our pension plans and approximately $23.7 million to our postretirement medical and life plans in 2023.
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:

(in millions) | Pension Benefits |  | Other Postretirement Benefits |  | Federal Subsidy Receipts
Year(s) |  |  |  |  |
2023 | $ | 150.5 |  |  | $ | 38.9 |  |  | $ | 0.4 |
2024 | 145.2 |  |  | 38.5 |  |  | 0.2 |
2025 | 141.2 |  |  | 37.8 |  |  | 0.2 |
2026 | 133.8 |  |  | 36.9 |  |  | 0.2 |
2027 | 128.1 |  |  | 36.4 |  |  | 0.2 |
2028-2032 | 563.2 |  |  | 172.0 |  |  | 0.9 |

The following table provides the components of the plans’ actuarially determined net periodic benefits cost for each of the three years ended December 31, 2022, 2021 and 2020:

| Pension Benefits |  | Other Postretirement Benefits
(in millions) | 2022 |  | 2021 |  | 2020 |  | 2022 |  | 2021 |  | 2020
Components of Net Periodic Benefit (Income) Cost(1) |  |  |  |  |  |  |  |  |  |  |
Service cost | $ | 27.8 |  |  | $ | 30.2 |  |  | $ | 32.0 |  |  | $ | 6.5 |  |  | $ | 6.2 |  |  | $ | 6.6 |
Interest cost | 40.5 |  |  | 31.4 |  |  | 51.6 |  |  | 12.0 |  |  | 9.9 |  |  | 15.4 |
Expected return on assets | (90.8) |  |  | (101.6) |  |  | (111.6) |  |  | (16.2) |  |  | (15.3) |  |  | (14.4) |
Amortization of prior service cost (credit) | 0.1 |  |  | 0.1 |  |  | 0.7 |  |  | (2.2) |  |  | (2.2) |  |  | (2.1) |
Recognized actuarial loss | 20.3 |  |  | 21.7 |  |  | 33.8 |  |  | 2.6 |  |  | 4.6 |  |  | 4.9 |
Settlement/curtailment loss | 12.4 |  |  | 11.4 |  |  | 10.5 |  |  | — |  |  | — |  |  | 1.5 |
Total Net Periodic Benefits (Income) Cost | $ | 10.3 |  |  | $ | (6.8) |  |  | $ | 17.0 |  |  | $ | 2.7 |  |  | $ | 3.2 |  |  | $ | 11.9 |

(1)Service cost is presented in "Operation and maintenance" on the Statements of Consolidated Income (Loss). Non-service cost components are presented within "Other, net."
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
The following table provides the key assumptions that were used to calculate the net periodic benefits cost for our various plans:

| Pension Benefits |  | Other Postretirement Benefits
| 2022 |  | 2021 |  | 2020 |  | 2022 |  | 2021 |  | 2020
Weighted-average Assumptions to Determine Net Periodic Benefit Cost |  |  |  |  |  |  |  |  |  |  |
Discount rate - service cost | 3.08 | % |  | 2.81 | % |  | 3.39 | % |  | 3.21 | % |  | 3.00 | % |  | 3.52 | %
Discount rate - interest cost | 2.11 | % |  | 1.57 | % |  | 2.65 | % |  | 2.24 | % |  | 1.73 | % |  | 2.76 | %
Expected Long-Term Rate of Return on Plan Assets | 4.80 | % |  | 5.20 | % |  | 5.70 | % |  | 5.72 | % |  | 5.50 | % |  | 5.67 | %
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 4.80% and 5.72% rate of return on pension and other postretirement plan assets, respectively, for our calculation of 2022 pension benefits and other postretirement benefits costs. These rates were primarily based on asset mix and historical rates of return and were adjusted in 2022 due to anticipated 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:

| Pension Benefits |  | Other Postretirement Benefits
(in millions) | 2022 |  | 2021 |  | 2022 |  | 2021
Other Changes in Plan Assets and Projected Benefit Obligations Recognized in Other Comprehensive Income or Regulatory Asset or Liability |  |  |  |  |  |  |
Net prior service cost | $ | 0.2 |  |  | $ | — |  |  | $ | 2.1 |  |  | $ | 0.1 |
Net actuarial loss (gain) | 158.9 |  |  | (26.0) |  |  | (21.8) |  |  | (23.3) |
Settlements/curtailments | (12.4) |  |  | (11.4) |  |  | — |  |  | — |
Less: amortization of prior service cost | (0.1) |  |  | (0.1) |  |  | 2.2 |  |  | 2.2 |
Less: amortization of net actuarial loss | (20.3) |  |  | (21.7) |  |  | (2.6) |  |  | (4.6) |
Total Recognized in Other Comprehensive Income or Regulatory Asset or Liability | $ | 126.3 |  |  | $ | (59.2) |  |  | $ | (20.1) |  |  | $ | (25.6) |
Amount Recognized in Net Periodic Benefits Cost and Other Comprehensive Income or Regulatory Asset or Liability | $ | 136.6 |  |  | $ | (66.0) |  |  | $ | (17.4) |  |  | $ | (22.4) |

13. 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 15, "Long-Term Debt," for more information. As of December 31, 2022, these covenants did not restrict the amount of dividends that were available to be paid.
Dividends paid to preferred shareholders vary based on the series of preferred stock owned. Holders of our shares of common stock are subject to the prior dividend rights of holders of our preferred stock or the depositary shares representing such preferred stock outstanding, and if full dividends have not been declared and paid on all outstanding shares of preferred stock in any dividend period, no dividend may be declared or paid or set aside for payment on our common stock.
Common and preferred stock activity for 2022, 2021 and 2020 is described further below.
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ATM Program. On November 1, 2018, we entered into five separate equity distribution agreements pursuant to which we were able to sell up to an aggregate of $500.0 million of our common stock. Four of these agreements were then amended on August 1, 2019 and one was terminated, pursuant to which we were able to sell up to an aggregate of $434.4 million of our common stock. These equity distribution agreements impacting fiscal year 2020 expired on December 31, 2020.
On February 22, 2021, we entered into six separate equity distribution agreements pursuant to which we are able to sell up to an aggregate of $750.0 million of our common stock.
On August 9, 2021, 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. From August 9, 2021 to September 1, 2021, the forward purchaser under our forward sale agreement borrowed 5,941,598 shares from third parties, which the forward purchaser sold, through its affiliated agent, at a weighted average price of $25.25 per share. On November 16, 2022, the forward sale agreement was settled for $23.90 per share, resulting in $142.0 million of net proceeds.
As of December 31, 2022, the ATM program had approximately $300.0 million of equity available for issuance. The program expires on December 31, 2023.
The following table summarizes our activity under the ATM program.

Year Ending December 31, | 2022 |  | 2021 |  | 2020
Number of shares issued | 5,941,598 |  |  | 12,525,215 |  |  | 8,459,430 |
Average price per share | $ | 25.25 |  |  | $ | 23.95 |  |  | $ | 23.60 |
Proceeds, net of fees (in millions) | $ | 141.9 |  |  | $ | 288.1 |  |  | $ | 196.5 |

Preferred Stock. On June 11, 2018, we completed the sale of 400,000 shares of 5.650% Series A Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Stock (the "Series A Preferred Stock") at a price of $1,000 per share. The transaction resulted in $400.0 million of gross proceeds or $393.9 million of net proceeds, after deducting commissions and sale expenses. The Series A Preferred Stock was issued in a private placement pursuant to SEC Rule 144A. On December 13, 2018, we filed a registration statement with the SEC enabling holders to exchange their unregistered shares of Series A Preferred Stock for publicly registered shares with substantially identical terms.
Dividends on the Series A Preferred Stock accrue and are cumulative from the date the shares of Series A Preferred Stock were originally issued to, but not including, June 15, 2023 at a rate of 5.650% per annum of the $1,000 liquidation preference per share. On and after June 15, 2023, dividends on the Series A Preferred Stock will accumulate for each five year period at a percentage of the $1,000 liquidation preference equal to the five-year U.S. Treasury Rate plus (i) in respect of each five year period commencing on or after June 15, 2023 but before June 15, 2043, a spread of 2.843% (the “Initial Margin”), and (ii) in respect of each five year period commencing on or after June 15, 2043, the Initial Margin plus 1.000%. The Series A Preferred Stock may be redeemed by us at our option on June 15, 2023, or on each date falling on the fifth anniversary thereafter, or in connection with a ratings event (as defined in the Certificate of Designation of the Series A Preferred Stock).
As of December 31, 2022 and 2021, Series A Preferred Stock had $1.0 million of cumulative preferred dividends in arrears, or $2.51 per share.
Holders of Series A Preferred Stock generally have no voting rights, except for limited voting rights with respect to (i) potential amendments to our certificate of incorporation that would have a material adverse effect on the existing preferences, rights, powers or duties of the Series A Preferred Stock, (ii) the creation or issuance of any security ranking on a parity with the Series A Preferred Stock if the cumulative dividends payable on then outstanding Series A Preferred Stock are in arrears, or (iii) the creation or issuance of any security ranking senior to the Series A Preferred Stock. The Series A Preferred Stock does not have a stated maturity and is not subject to mandatory redemption or any sinking fund. The Series A Preferred Stock will remain outstanding indefinitely unless repurchased or redeemed by us. Any such redemption would be effected only out of funds legally available for such purposes and will be subject to compliance with the provisions of our outstanding indebtedness.
On December 5, 2018, we completed the sale of 20,000,000 depositary shares with an aggregate liquidation preference of $500,000,000 under the Company’s registration statement on Form S-3. Each depositary share represents 1/1,000th ownership interest in a share of our 6.500% Series B Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Stock, liquidation preference $25,000 per share (equivalent to $25 per depositary share) (the “Series B Preferred Stock"). The transaction resulted in $500.0 million of gross proceeds or $486.1 million of net proceeds, after deducting commissions and sale expenses.
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
Dividends on the Series B Preferred Stock accrue and are cumulative from the date the shares of Series B Preferred Stock were originally issued to, but not including, March 15, 2024 at a rate of 6.500% per annum of the $25,000 liquidation preference per share. On and after March 15, 2024, dividends on the Series B Preferred Stock will accumulate for each five year period at a percentage of the $25,000 liquidation preference equal to the five-year U.S. Treasury Rate plus (i) in respect of each five year period commencing on or after March 15, 2024 but before March 15, 2044, a spread of 3.632% (the “Initial Margin”), and (ii) in respect of each five year period commencing on or after March 15, 2044, the Initial Margin plus 1.000%. The Series B Preferred Stock may be redeemed by us at our option on March 15, 2024, or on each date falling on the fifth anniversary thereafter, or in connection with a ratings event (as defined in the Certificate of Designation of the Series B Preferred Stock).
As of December 31, 2022 and 2021, Series B Preferred Stock had $1.4 million of cumulative preferred dividends in arrears, or $72.23 per share.
In addition, 20,000 shares of Series B–1 Preferred Stock, par value $0.01 per share, were outstanding as of December 31, 2022. Holders of Series B–1 Preferred Stock are not entitled to receive dividend payments and have no conversion rights. The Series B–1 Preferred Stock is paired with the Series B Preferred Stock and may not be transferred, redeemed or repurchased except in connection with the simultaneous transfer, redemption or repurchase of the underlying Series B Preferred Stock.
Holders of Series B Preferred Stock generally have no voting rights, except for limited voting rights with respect to (i) potential amendments to our certificate of incorporation that would have a material adverse effect on the existing preferences, rights, powers or duties of the Series B Preferred Stock, (ii) the creation or issuance of any security ranking on a parity with the Series B Preferred Stock if the cumulative dividends payable on then outstanding Series B Preferred Stock are in arrears, or (iii) the creation or issuance of any security ranking senior to the Series B Preferred Stock. In addition, if and whenever dividends on any shares of Series B Preferred Stock shall not have been declared and paid for at least six dividend periods, whether or not consecutive, the number of directors then constituting our Board of Directors shall automatically be increased by two until all accumulated and unpaid dividends on the Series B Preferred Stock shall have been paid in full, and the holders of Series B-1 Preferred Stock, voting as a class together with the holders of any outstanding securities ranking on a parity with the Series B-1 Preferred Stock and having like voting rights that are exercisable at the time and entitled to vote thereon, shall be entitled to elect the two additional directors. The Series B Preferred Stock does not have a stated maturity and is not subject to mandatory redemption or any sinking fund. The Series B Preferred Stock will remain outstanding indefinitely unless repurchased or redeemed by us. Any such redemption would be effected only out of funds legally available for such purposes and will be subject to compliance with the provisions of our outstanding indebtedness.
The following table summarizes preferred stock by outstanding series of shares:

|  |  | Year ended December 31, | December 31, |  | December 31,
|  |  | 2022 | 2021 | 2020 | 2022 |  | 2021
(in millions except shares and per share amounts) | Liquidation Preference Per Share | Shares | Dividends Declared Per Share | Outstanding
5.650% Series A | $ | 1,000.00 |  | 400,000 |  | $ | 56.50 |  | $ | 56.50 |  | $ | 56.50 |  | $ | 393.9 |  |  | $ | 393.9 |
6.500% Series B | 25,000.00 |  | 20,000 |  | 1,625.00 |  | 1,625.00 |  | 1,625.00 |  | 486.1 |  |  | 486.1 |
Series C(1) | $ | 1,000.00 |  | 862,500 |  | — |  | — |  | — |  | $ | 666.5 |  |  | $ | 666.5 |

(1) The Series C Mandatory Convertible Preferred Stock initially will not bear any dividends. We recorded the initial present value of the purchase contract payments as a liability with a corresponding reduction to preferred stock.
Equity Units. On April 19, 2021, we completed the sale of 8.625 million Equity Units, initially consisting of Corporate Units, each with a stated amount of $100. The offering generated net proceeds of $835.5 million, after underwriting and issuance expenses. Each Corporate Unit consists of a forward contract to purchase shares of our common stock in the future and a 1/10th, or 10%, undivided beneficial ownership interest in one share of Series C Mandatory Convertible Preferred Stock, par value $0.01 per share, with a liquidation preference of $1,000 per share.
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
Selected information about the Equity Units is presented below:

(in millions except contract rate) | Issuance Date | Units Issued | Total Net Proceeds(1) | Purchase Contract Annual Rate | Purchase Contract Liability
Equity Units | April 19, 2021 | 8.625 | $ | 835.5 |  | 7.75 | % | $ | 168.8 |

(1)Issuance costs of $27.0 million were recorded on a relative fair value basis as a reduction to preferred stock of $22.5 million and a reduction to the purchase contract liability of $4.5 million.
The purchase contract obligates holders to purchase shares of our common stock on December 1, 2023, subject to early settlement in certain situations. The purchase price paid under the purchase contract is $100 and the number of shares to be purchased will be determined under a settlement rate formula based on the volume-weighted average share price of our common stock near the settlement date, subject to a maximum settlement rate. The Series C Mandatory Convertible Preferred Stock will initially be pledged upon issuance as collateral to secure the purchase of common stock under the related purchase contracts.
The Series C Mandatory Convertible Preferred Stock is expected to be remarketed prior to December 1, 2023, and each share, unless previously converted, will automatically convert to common stock based on a conversion rate on the mandatory conversion date, which is expected to be on or about March 1, 2024. The conversion rate will be determined based on the volume-weighted average share price of our common stock near the conversion date, subject to a minimum and maximum conversion rate. Prior to December 1, 2023, the Series C Mandatory Convertible Preferred Stock will not bear any dividends and the liquidation preference will not accrete. Following a successful remarketing, dividends may become payable on the Series C Mandatory Convertible Preferred Stock and/or the minimum conversion rate of the Series C Mandatory Convertible Preferred Stock may be increased. If no successful remarketing of the Series C Mandatory Convertible Preferred Stock has previously occurred, effective as of December 1, 2023, the conversion rate will be zero, no shares of our common stock will be delivered upon automatic conversion and each share of Series C Mandatory Convertible Preferred Stock will be automatically transferred to us on the mandatory conversion date without any payment of cash or shares of our common stock thereon. In the event of such a remarketing failure, any shares of Series C Mandatory Convertible Preferred Stock held as part of Corporate Units will be automatically delivered to us on December 1, 2023 in full satisfaction of the relevant holder's obligation under the related purchase contracts.
We will pay quarterly contract adjustment payments at the rate of 7.75% per year on the stated amount of $100 per Equity Unit. The contract adjustment payments are payable in cash, shares of our common stock or a combination thereof, at our election. The payment of contract adjustment payments may also be deferred until the purchase contract settlement date, December 1, 2023, at our election. If we exercise our option to defer the payment of contract adjustment payments, then until the deferred contract adjustment payments have been paid, we will not declare or pay any dividends on, or make any distributions on, or redeem, purchase or acquire, or make a liquidation payment with respect to, any shares of our capital stock; make any payment of principal of, or interest or premium, if any, on, or repay, repurchase or redeem any of our debt securities that rank on parity with, or junior to, the contract adjustment payments; or make any guarantee payments under any guarantee by us of securities of any of our subsidiaries if our guarantee ranks on parity with, or junior to, the contract adjustment payments. As of December 31, 2022, no contract adjustment payments have been deferred with quarterly cash payments being remitted to the holders. As of December 31, 2022 and December 31, 2021 the purchase contract liability was $65.0 million and $129.4 million, respectively. Purchase contract payments are recorded against this liability. Accretion of the purchase contract liability is recorded as interest expense. Cash payments of $66.8 million and $41.2 million were made during the years ended December 31, 2022 and 2021, respectively.
The Series C Mandatory Convertible Preferred Stock and forward purchase contracts are legally detachable and separately exercisable, however, due to the economic linkage between the forward purchase contract and the Series C Mandatory Convertible Preferred Stock, we have concluded that the ability to separate the Corporate Units is non-substantive. Accordingly, we are accounting for the Corporate Units as a single unit of account. We recorded the initial present value of the purchase contract payments as a liability with a corresponding reduction to preferred stock. This liability is included in "Other accruals"go on the Consolidated Balance Sheets.
Refer to Note 5, "Earnings Per Share," for additional information regarding our treatment of the Equity Units for diluted EPS. Under the terms of the Equity Units, assuming no anti-dilution or other adjustments such as a fundamental change, the maximum number of shares of common stock we will issue under the purchase contracts is 35.2 million and maximum number
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
of shares of common stock we will issue under the Series C Mandatory Convertible Preferred Stock is 35.2 million. Had we settled the remaining purchase contract payment balance in shares at December 31, 2022, we would have issued approximately 2.5 million shares.
Noncontrolling Interest in Consolidated Subsidiaries. As of December 31, 2022 and 2021, NIPSCO and tax equity partners have completed their cash contributions into the Indiana Crossroads Wind and Rosewater JVs and made initial cash contributions into the Indiana Crossroads Solar JV. 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, "Variable Interest Entities," for more information.
14. 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, 2022, there were 8,704,201 shares available for future awards under the 2020 Omnibus Plan.
We recognized stock-based employee compensation expense of $19.0 million, $16.7 million and $13.5 million, during 2022, 2021 and 2020, respectively, as well as related tax benefits of $3.6 million, $4.0 million and $3.3 million, respectively. We recognized related excess tax benefit from the distribution of vested share-based employee compensation of $0.4 million in 2022 and 2021, and excess tax expense of $0.4 million in 2020.
As of December 31, 2022, the total remaining unrecognized compensation cost related to non-vested awards amounted to $27.0 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 477,292, 285,755, and 235,100 restricted stock units and shares of restricted stock to employees, subject to service conditions in 2022, 2021, and 2020, respectively. The total grant date fair value of the restricted stock units and shares of restricted stock during 2022, 2021, and 2020, respectively, was $12.5 million, $5.7 million, and $6.1 million 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, which will be expensed over the vesting period which is generally three years. As of December 31, 2022, 444,646, 218,465, and 135,404 non-vested restricted stock units and shares of restricted stock granted in 2022, 2021, and 2020, respectively, were outstanding.
If an employee terminates employment before the service conditions lapse under the 2020, 2021 or 2022 awards due to (1) retirement or disability (as defined in the award agreement), 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 award agreement), 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 will result in all unvested shares of restricted stock and restricted stock units awarded being forfeited effective on the employee’s date of termination.
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Notes to Consolidated Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
A summary of our restricted stock unit award transactions for the year ended December 31, 2022 is as follows:

(shares) | Restricted Stock Units |  | Weighted Average Award Date Fair Value Per Unit ($)
Non-vested at December 31, 2021 | 572,154 |  |  | 22.72 |
Granted | 477,292 |  |  | 26.29 |
Forfeited | (133,367) |  |  | 23.48 |
Vested | (117,564) |  |  | 24.44 |
Non-vested at December 31, 2022 | 798,515 |  |  | 24.48 |

Employee Performance Shares. We granted 566,086 performance shares subject to service, performance and/or market-based vesting conditions in 2022. 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 below. The number of shares that are eligible to vest based on these performance conditions will be adjusted based on performance of the magnifier framework for 2022 awards, outlined below. The operational magnifier framework for 2022 performance shares consists of three areas of focus, including safety, environment, and DE&I, representing 20%, 10% and 10%, respectively.
The financial measure is cumulative net operating earnings per share ("NOEPS"), which we define as income from continuing operations 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 relative shareholder return result within the first quartile will result in an increase in the NOEPS shares of 25%, while a relative shareholder return result within the fourth quartile will result in a decrease of 25%. 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 NOEPS 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. See table below for further details on these awards.
In 2021, we granted 973,885 performance shares subject to service, performance and/or market-based vesting conditions. With respect to 390,941 performance shares granted, the performance conditions are based on the achievement of relative total shareholder return. The number of shares that are eligible to vest based on the Company's relative total shareholder return performance will be adjusted based on a performance magnifier related to safety. 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 NOEPS 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. See table below for further details on these awards.
With respect to the remaining 582,944 performance shares granted in 2021, the performance conditions are based on the achievement of one non-GAAP financial measure, and/or achievement of relative total shareholder return. The number of shares that are eligible to vest based on these performance conditions will be adjusted based on performance of the magnifier framework for 2021 awards. The operational magnifier framework for 2021 performance shares consists of three areas of focus including safety, environment, and DE&I, representing 20%, 10% and 10%, respectively.
We granted 528,729 performance shares subject to service, performance and market-based vesting conditions in 2020. The performance conditions are based on the achievement of one non-GAAP financial measure, relative total shareholder return and additional operational measures as outlined below.
If a threshold level of cumulative NOEPS financial performance is achieved, additional operational measures, which we refer to as the customer value framework and which consists of equally weighted areas of focus, apply. Each area of focus represents an equal portion of the customer value framework shares, and the targets for all areas of focus must be met for the customer value framework shares to vest at 100%. The grant date fair value of the customer value framework shares is based on the average market price of our common stock on the grant date of each award less the present value of dividends not received during the vesting period, which will be expensed over the requisite service period of three years for those customer value framework shares that are granted. See table below for further details on these awards.
For the 2020 awards, the customer value framework consists of four equally weighted areas of focus including safety, customer satisfaction, culture and environmental, each representing 25% of the customer value framework shares.
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
The following table presents details of the performance awards described above.

Award Year | Service Conditions Lapse date | Performance Period | Award Conditions |  | Shares outstanding at 12/31/2022 (shares) | Grant Date Fair Value (in millions)
2022 | 02/28/25 | 01/01/2022- 12/31/2024 | Non-GAAP Financial Measure |  | 245,445 |  | $ | 7.4 |
Relative Total Shareholder Return |  | 245,445 |  | $ | 10.6 |
2021 | 02/28/24 | 01/01/2021- 12/31/2023 | Non-GAAP Financial Measure |  | 192,119 |  | $ | 6.5 |
Relative Total Shareholder Return |  | 192,119 |  | $ | 6.7 |
Relative Total Shareholder Return |  | 88,541 |  | $ | 3.2 |
02/28/23 | 01/01/2021- 12/31/2022 | Relative Total Shareholder Return |  | 179,703 |  | $ | 4.8 |
2020 | 02/28/23 | 01/01/2020- 12/31/2022 | Non-GAAP Financial Measure |  | 294,424 |  | $ | 11.7 |
Operational Measures |  | 67,943 |  | $ | 2.6 |

A summary of our performance award transactions for the year ended December 31, 2022 is as follows:

(shares) | Performance Awards |  | Weighted Average Grant Date Fair Value Per Unit ($)
Non-vested at December 31, 2021 | 1,798,151 |  |  | 23.78 |
Granted | 566,086 |  |  | 31.65 |
Forfeited | (427,607) |  |  | 24.34 |
Vested | (430,890) |  |  | 25.44 |
Non-vested at December 31, 2022 | 1,505,740 |  |  | 26.10 |

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, 2022, 228,604 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, 63,215 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 3% 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, 2022, 2021 and 2020, we recognized 401(k) match, profit sharing and non-elective contribution expense of $39.1 million, $39.1 million and $37.8 million, respectively.
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
15. Long-Term Debt
Our long-term debt as of December 31, 2022 and 2021 is as follows:

Long-term debt type | Maturity as of December 31, 2022 | Weighted average interest rate (%) |  | Outstanding balance as of December 31, (in millions)
| 2022 |  | 2021
Senior notes: |  |  |  |  |  |
NiSource | August 2025 | 0.95 | % |  | $ | 1,250.0 |  |  | 1,250.0 |
NiSource | May 2027 | 3.49 | % |  | 1,000.0 |  |  | 1,000.0 |
NiSource | December 2027 | 6.78 | % |  | 3.0 |  |  | 3.0 |
NiSource | September 2029 | 2.95 | % |  | 750.0 |  |  | 750.0 |
NiSource | May 2030 | 3.60 | % |  | 1,000.0 |  |  | 1,000.0 |
NiSource | February 2031 | 1.70 | % |  | 750.0 |  |  | 750.0 |
NiSource | December 2040 | 6.25 | % |  | 152.6 |  |  | 152.6 |
NiSource | June 2041 | 5.95 | % |  | 347.4 |  |  | 347.4 |
NiSource | February 2042 | 5.80 | % |  | 250.0 |  |  | 250.0 |
NiSource | February 2043 | 5.25 | % |  | 500.0 |  |  | 500.0 |
NiSource | February 2044 | 4.80 | % |  | 750.0 |  |  | 750.0 |
NiSource | February 2045 | 5.65 | % |  | 500.0 |  |  | 500.0 |
NiSource | May 2047 | 4.38 | % |  | 1,000.0 |  |  | 1,000.0 |
NiSource | March 2048 | 3.95 | % |  | 750.0 |  |  | 750.0 |
NiSource | June 2052 | 5.00 | % |  | 350.0 |  |  | $ | — |
Total senior notes |  |  |  | $ | 9,353.0 |  |  | $ | 9,003.0 |
Medium term notes: |  |  |  |  |  |
NiSource | May 2027 | 7.99 | % |  | $ | 29.0 |  |  | $ | 49.0 |
NIPSCO | June 2027 to August 2027 | 7.64 | % |  | 58.0 |  |  | 68.0 |
Columbia of Massachusetts | December 2025 to February 2028 | 6.37 | % |  | 15.0 |  |  | 15.0 |
Total medium term notes |  |  |  | $ | 102.0 |  |  | $ | 132.0 |
Finance leases: |  |  |  |  |  |
NiSource Corporate Services | December 2022 to December 2026 | 2.34 | % |  | $ | 48.6 |  |  | 51.4 |
NIPSCO | December 2027 to November 2035 | 1.87 | % |  | 16.5 |  |  | 18.7 |
Columbia of Ohio | December 2025 to March 2044 | 6.15 | % |  | 83.5 |  |  | 87.8 |
Columbia of Virginia | July 2029 to November 2039 | 6.26 | % |  | 17.0 |  |  | 17.7 |
Columbia of Kentucky | May 2027 | 3.79 | % |  | 0.2 |  |  | 0.2 |
Columbia of Pennsylvania | July 2027 to May 2035 | 6.28 | % |  | 8.9 |  |  | 9.8 |
Total finance leases |  |  |  | $ | 174.7 |  |  | 185.6 |
Unamortized issuance costs and discounts |  |  |  | $ | (76.1) |  |  | $ | (79.1) |
Total Long-Term Debt |  |  |  | $ | 9,553.6 |  |  | $ | 9,241.5 |

Details of our 2022 long-term debt related activity are summarized below:
•On April 1, 2022, we repaid $20.0 million of 7.99% medium term notes at maturity.
•On June 10, 2022, we completed the issuance and sale of $350.0 million of 5.00% senior unsecured notes maturing in 2052, which resulted in approximately $344.6 million of net proceeds after discount and debt issuance costs.
•On August 30, 2022, NIPSCO repaid $10.0 million of 7.40% medium term notes at maturity.
There was no long-term debt activity during 2021.
See Note 19, "Other Commitments and Contingencies - A. Contractual Obligations," for the outstanding long-term debt maturities at December 31, 2022.
Unamortized debt expense, premium and discount on long-term debt applicable to outstanding bonds are being amortized over the life of such bonds.
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
We are subject to a financial covenant under our revolving credit facility and term credit agreement which requires us to maintain a debt to capitalization ratio that does not exceed 70%. As of December 31, 2022, the ratio was 58.9%.
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, 2020. 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 million to $50 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.
16. Short-Term Borrowings
We generate short-term borrowings from our revolving credit facility, commercial paper program, accounts receivable transfer programs, and term credit agreement. 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. On February 18, 2022, we extended the termination date of our revolving credit facility to February 18, 2027. At December 31, 2022 and 2021, we had no outstanding borrowings under this facility.
Commercial Paper Program. Our commercial paper program has a program limit of up to $1.5 billion. We had $415.0 million and $560.0 million of commercial paper outstanding with weighted-average interest rates of 4.60% and 0.24% as of December 31, 2022 and 2021, 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 wholly-owned and consolidated special purpose entities. The three agreements expire between May 2023 and October 2023 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, 2022, the maximum amount of debt that could be recognized related to our accounts receivable programs is $500.0 million.
We had $347.2 million and no short-term borrowings related to the securitization transactions as of December 31, 2022 and 2021, respectively.
For the years ended December 31, 2022 and 2021, $347.2 million and zero, respectively, were recorded as cash flows from 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 $2.5 million, $1.4 million, and $2.6 million for the years ended December 31, 2022, 2021 and 2020, respectively. Columbia of Ohio, NIPSCO and Columbia of Pennsylvania remain responsible for collecting on the receivables securitized, and the receivables cannot be transferred to another party.
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
Term Credit Agreement. On December 20, 2022, we entered into a $1.0 billion term credit agreement with a syndicate of banks. The agreement matures on December 19, 2023 and interest charged on the borrowings depends on the variable rate structure elected at the time of each borrowing. The available variable rate structures from which we can choose are defined in the agreement. Under the agreement, we borrowed $1.0 billion on December 20, 2022 with an interest rate of SOFR plus 105 basis points. We had $1.0 billion outstanding with an interest rate of 5.37% as of December 31, 2022.
Items listed above, excluding the term credit agreement, are presented net in the Statements of Consolidated Cash Flows as their maturities are less than 90 days.
17. 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, fleet vehicles and certain IT assets. Our corporate and field office leases have remaining lease terms between 1 and 21 years with options to renew the leases for up to 25 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 5 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 lease the majority of our IT assets under 4 year lease terms. Ownership of leased IT assets is transferred to us at the end of the lease term.
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, 2022 and December 31, 2021 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:

Year Ended December 31, (in millions) | Income Statement Classification | 2022 |  | 2021
Finance lease cost |  |  |  |
Amortization of right-of-use assets | Depreciation and amortization | $ | 31.9 |  |  | $ | 28.8 |
Interest on lease liabilities | Interest expense, net | 8.5 |  |  | 9.4 |
Total finance lease cost |  | 40.4 |  |  | 38.2 |
Operating lease cost | Operation and maintenance | 10.4 |  |  | 15.6 |
Total lease cost |  | $ | 50.8 |  |  | $ | 53.8 |

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
Our right-of-use assets and liabilities are presented in the following lines on the Consolidated Balance Sheets:

At December 31, (in millions) | Balance Sheet Classification | 2022 |  | 2021
Assets |  |  |  |
Finance leases | Net Property, Plant and Equipment | $ | 153.4 |  |  | $ | 165.7 |
Operating leases | Deferred charges and other | 35.7 |  |  | 33.8
Total leased assets |  | $ | 189.1 |  |  | 199.5
Liabilities |  |  |  |
Current |  |  |  |
Finance leases | Current portion of long-term debt | $ | 30.0 |  |  | 28.1
Operating leases | Other accruals | 4.8 |  |  | 6.7
Noncurrent |  |  |  |
Finance leases | Long-term debt, excluding amounts due within one year | 144.7 |  |  | 157.5
Operating leases | Other noncurrent liabilities | 31.9 |  |  | 27.9
Total lease liabilities |  | $ | 211.4 |  |  | $ | 220.2 |

Other pertinent information related to leases was as follows:

Year Ended December 31, (in millions) | 2022 |  | 2021
Cash paid for amounts included in the measurement of lease liabilities |  |  |
Operating cash flows used for finance leases | $ | 8.6 |  |  | $ | 9.4 |
Operating cash flows used for operating leases | 10.3 |  |  | 15.4
Financing cash flows used for finance leases | 30.3 |  |  | 25.7
Right-of-use assets obtained in exchange for lease obligations |  |  |
Finance leases | 19.3 |  |  | 22.4
Operating leases | $ | 8.8 |  |  | $ | 6.0 |

| December 31, 2022 |  | December 31, 2021
Weighted-average remaining lease term (years) |  |  |
Finance leases | 9.9 |  | 10.6
Operating leases | 7.7 |  | 8.5
Weighted-average discount rate |  |  |
Finance leases | 5.1 | % |  | 5.0 | %
Operating leases | 4.0 | % |  | 3.7 | %

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Notes to Consolidated Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
Maturities of our lease liabilities as of December 31, 2022 were as follows:

As of December 31, 2022, (in millions) | Total | Finance Leases | Operating Leases
2023 | $ | 46.8 |  | $ | 38.9 |  | $ | 7.9 |
2024 | 37.3 |  | 30.9 |  | 6.4 |
2025 | 30.3 |  | 24.5 |  | 5.8 |
2026 | 24.7 |  | 19.4 |  | 5.3 |
2027 | 19.9 |  | 15.4 |  | 4.5 |
Thereafter | 110.8 |  | 97.4 |  | 13.4 |
Total lease payments | 269.8 |  | 226.5 |  | 43.3 |
Less: Imputed interest | (58.4) |  | (51.8) |  | (6.6) |
Total | $ | 211.4 |  | $ | 174.7 |  | $ | 36.7 |
Reported as of December 31, 2022 |  |  |
Short-term lease liabilities | 34.8 |  | 30.0 |  | 4.8 |
Long-term lease liabilities | 176.6 |  | 144.7 |  | 31.9 |
Total lease liabilities | $ | 211.4 |  | $ | 174.7 |  | $ | 36.7 |

18. 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, 2022 and December 31, 2021:

Recurring Fair Value Measurements December 31, 2022 (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 December 31, 2022
Assets |  |  |  |  |  |  |
Risk management assets | $ | — |  |  | $ | 84.8 |  |  | $ | — |  |  | $ | 84.8 |
Available-for-sale debt securities | — |  |  | 151.6 |  |  | — |  |  | 151.6 |
Total | $ | — |  |  | $ | 236.4 |  |  | $ | — |  |  | $ | 236.4 |
Liabilities |  |  |  |  |  |  |
Risk management liabilities | — |  |  | 3.0 |  |  | — |  |  | 3.0 |
Total | $ | — |  |  | $ | 3.0 |  |  | $ | — |  |  | $ | 3.0 |

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

Recurring Fair Value Measurements December 31, 2021 (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 December 31, 2021
Assets |  |  |  |  |  |  |
Risk management assets | $ | — |  |  | $ | 24.4 |  |  | $ | — |  |  | $ | 24.4 |
Available-for-sale debt securities | — |  |  | 171.8 |  |  | — |  |  | 171.8 |
Total | $ | — |  |  | $ | 196.2 |  |  | $ | — |  |  | $ | 196.2 |
Liabilities |  |  |  |  |  |  |
Risk management liabilities | $ | — |  |  | $ | 144.2 |  |  | $ | — |  |  | $ | 144.2 |
Total | $ | — |  |  | $ | 144.2 |  |  | $ | — |  |  | $ | 144.2 |

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, 2022 and 2021, 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 has entered into long-term forward natural gas purchase instruments to lock in a fixed price for its 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 10, “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
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
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, 2022 and December 31, 2021, we recorded $0.9 million and $0.2 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, 2022 and 2021 were:

December 31, 2022 (in millions) | Amortized Cost |  | Gross Unrealized Gains |  | Gross Unrealized Losses(1) |  | Allowance for Credit Losses |  | Fair Value
Available-for-sale debt securities |  |  |  |  |  |  |  |  |
U.S. Treasury debt securities | $ | 67.7 |  |  | $ | — |  |  | $ | (4.5) |  |  | $ | — |  |  | $ | 63.2 |
Corporate/Other debt securities | 99.0 |  |  | — |  |  | (9.7) |  |  | (0.9) |  |  | 88.4 |
Total | $ | 166.7 |  |  | $ | — |  |  | $ | (14.2) |  |  | $ | (0.9) |  |  | $ | 151.6 |
December 31, 2021 (in millions) | Amortized Cost |  | Gross Unrealized Gains |  | Gross Unrealized Losses(2) |  | Allowance for Credit Losses |  | Fair Value
Available-for-sale debt securities |  |  |  |  |  |  |  |  |
U.S. Treasury debt securities | $ | 52.8 |  |  | $ | 0.1 |  |  | $ | (0.4) |  |  | $ | — |  |  | $ | 52.5 |
Corporate/Other debt securities | 116.5 |  |  | 3.7 |  |  | (0.7) |  |  | (0.2) |  |  | 119.3 |
Total | $ | 169.3 |  |  | $ | 3.8 |  |  | $ | (1.1) |  |  | $ | (0.2) |  |  | $ | 171.8 |

(1) 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 $61.0 and $85.5 million, respectively, at December 31, 2022.
(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 $36.2 million and $35.4 million, respectively, at December 31, 2021.
Realized gains and losses on available-for-sale securities were immaterial for the year-ended December 31, 2022 and 2021.
The cost of maturities sold is based upon specific identification. At December 31, 2022, approximately $5.2 million of U.S. Treasury debt securities and approximately $5.8 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, 2022 and 2021.
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.
Purchase Contract Liability. On April 19, 2021, we recorded the purchase contract liability at fair value using a discounted cash flow method and observable, market-corroborated inputs. This estimate was made at April 19, 2021, and will not be remeasured at each subsequent balance sheet date. It has been categorized within Level 2 of the fair value hierarchy. Refer to Note 13, "Equity," for additional information.
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
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, 2022 and 2021, 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:

At December 31, (in millions) | Carrying Amount 2022 |  | Estimated Fair Value 2022 |  | Carrying Amount 2021 |  | Estimated Fair Value 2021
Long-term debt (including current portion) | $ | 9,553.6 |  |  | $ | 8,479.4 |  |  | $ | 9,241.5 |  |  | $ | 10,415.7 |

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Notes to Consolidated Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
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, 2022 and their maturities were:

(in millions) | Total |  | 2023 |  | 2024 |  | 2025 |  | 2026 |  | 2027 |  | After
Long-term debt (1) | $ | 9,455.0 |  |  | $ | — |  |  | $ | — |  |  | $ | 1,260.0 |  |  | $ | — |  |  | $ | 1,090.0 |  |  | $ | 7,105.0 |
Interest payments on long-term debt | 5,890.4 |  |  | 351.6 |  |  | 351.6 |  |  | 351.6 |  |  | 339.1 |  |  | 319.7 |  |  | 4,176.8 |
Finance leases(2) | 226.5 |  |  | 38.9 |  |  | 30.9 |  |  | 24.5 |  |  | 19.4 |  |  | 15.4 |  |  | 97.4 |
Operating leases(3) | 43.3 |  |  | 7.9 |  |  | 6.4 |  |  | 5.8 |  |  | 5.3 |  |  | 4.5 |  |  | 13.4 |
Energy commodity contracts | 231.7 |  |  | 119.7 |  |  | 76.0 |  |  | 36.0 |  |  | — |  |  | — |  |  | — |
Service obligations: |  |  |  |  |  |  |  |  |  |  |  |  |
Pipeline service obligations | 2,484.9 |  |  | 642.2 |  |  | 556.9 |  |  | 410.5 |  |  | 337.2 |  |  | 328.8 |  |  | 209.3 |
IT service obligations | 177.4 |  |  | 71.9 |  |  | 50.0 |  |  | 41.3 |  |  | 11.4 |  |  | 2.8 |  |  | — |
Other liabilities(4) | 654.2 |  |  | 612.5 |  |  | 6.2 |  |  | 5.9 |  |  | 5.2 |  |  | 5.2 |  |  | 19.2 |
Total contractual obligations | $ | 19,163.4 |  |  | $ | 1,844.7 |  |  | $ | 1,078.0 |  |  | $ | 2,135.6 |  |  | $ | 717.6 |  |  | $ | 1,766.4 |  |  | $ | 11,621.1 |

(1) Long-term debt balance excludes unamortized issuance costs and discounts of $76.1 million.
(2) Finance lease payments shown above are inclusive of interest totaling $51.8 million.
(3) Operating lease payments shown above are inclusive of interest totaling $6.6 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 inclusive of the Rosewater, Indiana Crossroads Wind, and Indiana Crossroads Solar Developer payments due in 2023 and Equity Unit purchase contract liability payments to be made in 2023.
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 purchase obligations are for the purchase of physical quantities of natural gas, electricity and coal. Our service agreements encompass a broad range of business support and maintenance functions which are generally described below.
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, 2022.
NIPSCO has power purchase arrangements representing a total of 500 MW of wind power, with contracts expiring between 2024 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 2023 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 2028.
We have executed agreements with multiple IT service providers. The agreements extend for various periods through 2028.
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
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, 2022 and 2021, we issued stand-by letters of credit of $10.2 million and $18.9 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, 2022 and 2021, our guarantees for multiple BTAs totaled $841.6 million and $288.9 million, respectively. The amount of each guaranty will decrease upon the substantial completion of the construction of the facilities. See “- F. Other Matters - Generation Transition,” below for more information.
C. Legal Proceedings. On September 13, 2018, a series of fires and explosions occurred in Lawrence, Andover, and North Andover, Massachusetts related to the delivery of natural gas by Columbia of Massachusetts (the "Greater Lawrence Incident").
We have been subject to inquiries and investigations by government authorities and regulatory agencies regarding the Greater Lawrence Incident. On February 26, 2020, the Company and Columbia of Massachusetts entered into agreements with the U.S. Attorney's Office for the District of Massachusetts to resolve the U.S. Attorney's Office’s investigation relating to the Greater Lawrence Incident, as described below. The Company and Columbia of Massachusetts entered into an agreement with the Massachusetts Attorney General’s Office (among other parties) to resolve the Massachusetts DPU and the Massachusetts Attorney General’s Office investigations, that was approved by the Massachusetts DPU on October 7, 2020 as part of the sale of the Massachusetts Business to Eversource.
U.S. Department of Justice Investigation. On February 26, 2020, the Company and Columbia of Massachusetts entered into agreements with the U.S. Attorney's Office to resolve the U.S. Attorney's Office's investigation relating to the Greater Lawrence Incident. Columbia of Massachusetts agreed to plead guilty in the United States District Court for the District of Massachusetts (the "Court") to violating the Natural Gas Pipeline Safety Act (the “Plea Agreement”), and the Company entered into a Deferred Prosecution Agreement (the "DPA").
On March 9, 2020, Columbia of Massachusetts entered its guilty plea pursuant to the Plea Agreement. The Court sentenced Columbia of Massachusetts on June 23, 2020, in accordance with the terms of the Plea Agreement (as modified). On June 23, 2021, the Court terminated Columbia of Massachusetts' period of probation under the Plea Agreement, which marked the completion of all terms of the Plea Agreement.
Under the DPA, the U.S. Attorney's Office agreed to defer prosecution of the Company in connection with the Greater Lawrence Incident for a three-year period ending on February 26, 2023 (which three-year period may be extended for twelve (12) months upon the U.S. Attorney's Office's determination of a breach of the DPA) subject to certain obligations of the Company, including, but not limited to, the Company's agreement, as to each of the Company's subsidiaries involved in the distribution of gas through pipeline facilities in Massachusetts, Indiana, Ohio, Pennsylvania, Maryland, Kentucky and Virginia to implement and adhere to each of the recommendations from the NTSB stemming from the Greater Lawrence Incident. Pursuant to the DPA, if the Company complies with all of its obligations under the DPA, the U.S. Attorney's Office will not file any criminal charges against the Company related to the Greater Lawrence Incident.
Private Actions. Various lawsuits, including several purported class action lawsuits, were filed by various affected residents or businesses in Massachusetts state courts against the Company and/or Columbia of Massachusetts in connection with the Greater Lawrence Incident.
On March 12, 2020, the Court granted final approval of the settlement of the consolidated class action. With respect to claims not included in the consolidated class action, many of the asserted wrongful death and bodily injury claims have been settled, and we continue to discuss potential settlements with remaining claimants. The outcomes and impacts of such private actions are uncertain at this time.
FERC Investigation. In April 2022, NIPSCO was notified that the FERC Office of Enforcement (“OE”) is conducting an investigation of an industrial customer for allegedly manipulating the MISO Demand Response (“DR”) market. The customer and NIPSCO are cooperating with the investigation. If the OE ultimately were to seek to require the customer to repay any portion of the DR revenue received from MISO, it is reasonably possible that the OE would also seek to require NIPSCO to
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Notes to Consolidated Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
disgorge administrative fees and foregone margin charges that NIPSCO collected pursuant to its own IURC-approved tariff. NIPSCO currently estimates the maximum amount of its disgorgement exposure to be $9.7 million, and the investigation is still ongoing. NIPSCO intends to seek indemnification under its agreements with the customer for any liability NIPSCO incurs related to this matter.
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, none of which we believe to be individually material at this time.
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. 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.
D. Other Greater Lawrence Incident Matters. In connection with the Greater Lawrence Incident, Columbia of Massachusetts, in cooperation with the Massachusetts Governor’s office, replaced the entire affected pipeline system. We invested approximately $258 million of capital spend for the pipeline replacement; this work was completed in 2019. We maintain property insurance for gas pipelines and other applicable property. Columbia of Massachusetts filed a proof of loss with its property insurer for the pipeline replacement. In January 2020, we filed a lawsuit against the property insurer, seeking payment of our property claim. On October 27, 2021, NiSource and the property insurer filed cross motions for summary judgment, each asking the court to determine whether there was coverage under the policy. After the cross motions for summary judgment were fully briefed, we reached an agreement to settle the coverage dispute for $105.0 million. After settlement payment was made, NiSource and its property insurer stipulated to the dismissal of the lawsuit on March 16, 2022.
E. 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 9, "Regulatory Matters," for additional detail.
As of December 31, 2022 and 2021, we had recorded a liability of $86.5 million and $91.1 million, respectively, to cover environmental remediation at various sites. This liability is included in "Other accruals" and "Other noncurrent liabilities" 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. See Note 8, "Asset Retirement Obligations," for a discussion of all obligations, including those discussed below.
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, NIPSCO 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 Operations subsidiaries or predecessors may have liability. The program has identified 53 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.
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Notes to Consolidated Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
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. No material changes to the estimated future remediation costs were noted as a result of the refresh completed as of June 30, 2022. Our total estimated liability related to the facilities subject to remediation was $81.0 million and $85.1 million at December 31, 2022 and 2021, respectively. The liability represents our best estimate of the probable cost to remediate the MGP sites. We believe that it is reasonably possible that remediation costs could vary by as much as $17 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. We continue to meet the compliance requirements established in the EPA's final rule for the regulation of CCRs. The CCR rule also resulted in 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.
F. Other Matters
Generation Transition. 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. NIPSCO's purchase obligation under each respective BTA is dependent on satisfactory approval of the BTA by the IURC, successful execution by NIPSCO of an agreement with a tax equity partner and timely completion of construction. NIPSCO has received IURC approval for all of its BTAs and PPAs. NIPSCO and the tax equity partner, for each respective BTA, are obligated to make cash contributions to the JV that acquires the project at the date construction is substantially complete. Certain agreements require NIPSCO to make partial payments upon the developer's completion of significant construction milestones. 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.
Employee Separation Benefits. In the third quarter of 2020, we launched a program to evaluate our organizational structure under the auspices of NiSource Next, which continued into 2021. We recognized the majority of the related severance expense in 2020 when the employees accepted severance offers, absent a retention period. For employees that have a retention period, expense will be recognized over the remaining service period. The total severance expense for employees was approximately $38 million, with substantially all of it incurred and paid to date.
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Notes to Consolidated Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
20. Accumulated Other Comprehensive Loss
The following table displays the activity of Accumulated Other Comprehensive Loss, net of tax:

(in millions) | 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, 2020 | $ | 3.3 |  |  | $ | (77.2) |  |  | $ | (18.7) |  |  | $ | (92.6) |
Other comprehensive income (loss) before reclassifications | 3.3 |  |  | (70.8) |  |  | 2.9 |  |  | (64.6) |
Amounts reclassified from accumulated other comprehensive loss | (0.6) |  |  | 0.1 |  |  | 1.0 |  |  | 0.5 |
Net current-period other comprehensive income (loss) | 2.7 |  |  | (70.7) |  |  | 3.9 |  |  | (64.1) |
Balance as of December 31, 2020 | $ | 6.0 |  |  | $ | (147.9) |  |  | $ | (14.8) |  |  | $ | (156.7) |
Other comprehensive income (loss) before reclassifications | (3.5) |  |  | 25.3 |  |  | 6.6 |  |  | 28.4 |
Amounts reclassified from accumulated other comprehensive loss | (0.4) |  |  | 0.1 |  |  | 1.8 |  |  | 1.5 |
Net current-period other comprehensive income (loss) | (3.9) |  |  | 25.4 |  |  | 8.4 |  |  | 29.9 |
Balance as of December 31, 2021 | $ | 2.1 |  |  | $ | (122.5) |  |  | $ | (6.4) |  |  | $ | (126.8) |
Other comprehensive income (loss) 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 income (loss) | (13.3) |  |  | 109.9 |  |  | (6.9) |  |  | 89.7 |
Balance as of December 31, 2022 | $ | (11.2) |  |  | $ | (12.6) |  |  | $ | (13.3) |  |  | $ | (37.1) |

(1)All amounts are net of tax. Amounts in parentheses indicate debits.
21. Business Segment Information
At December 31, 2022, our operations are divided into two primary reportable segments, the Gas Distribution Operations and the Electric Operations segments. 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" 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 finance, dividends and taxes at the corporate level on a consolidated basis. 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.
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Notes to Consolidated Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

Year Ended December 31, (in millions) | 2022 |  | 2021 |  | 2020
Operating Revenues |  |  |  |  |
Gas Distribution Operations |  |  |  |  |
Unaffiliated | $ | 4,007.2 |  |  | $ | 3,171.2 |  |  | $ | 3,128.1 |
Intersegment | 12.6 |  |  | 12.3 |  |  | 12.1 |
Total | 4,019.8 |  |  | 3,183.5 |  |  | 3,140.2 |
Electric Operations |  |  |  |  |
Unaffiliated | 1,830.9 |  |  | 1,696.3 |  |  | 1,535.9 |
Intersegment | 0.8 |  |  | 0.8 |  |  | 0.7 |
Total | 1,831.7 |  |  | 1,697.1 |  |  | 1,536.6 |
Corporate and Other |  |  |  |  |
Unaffiliated | 12.5 |  |  | 32.1 |  |  | 17.7 |
Intersegment | 465.0 |  |  | 460.3 |  |  | 449.8 |
Total | 477.5 |  |  | 492.4 |  |  | 467.5 |
Eliminations | (478.4) |  |  | (473.4) |  |  | (462.6) |
Consolidated Operating Revenues | $ | 5,850.6 |  |  | $ | 4,899.6 |  |  | $ | 4,681.7 |

Year Ended December 31, (in millions) | 2022 |  | 2021 |  | 2020
Operating Income (Loss) |  |  |  |  |
Gas Distribution Operations(1) | $ | 915.8 |  |  | $ | 617.5 |  |  | $ | 199.1 |
Electric Operations | 362.4 |  |  | 387.8 |  |  | 348.8 |
Corporate and Other | (12.4) |  |  | 1.6 |  |  | 2.9 |
Consolidated Operating Income | $ | 1,265.8 |  |  | $ | 1,006.9 |  |  | $ | 550.8 |
Depreciation and Amortization |  |  |  |  |
Gas Distribution Operations | $ | 415.9 |  |  | $ | 383.0 |  |  | $ | 363.1 |
Electric Operations | 362.9 |  |  | 329.4 |  |  | 321.3 |
Corporate and Other | 42.0 |  |  | 36.0 |  |  | 41.5 |
Consolidated Depreciation and Amortization | $ | 820.8 |  |  | $ | 748.4 |  |  | $ | 725.9 |
Assets |  |  |  |  |
Gas Distribution Operations | $ | 16,986.5 |  |  | $ | 15,153.7 |  |  | $ | 13,433.0 |
Electric Operations | 7,992.6 |  |  | 7,178.9 |  |  | 6,443.1 |
Corporate and Other | 1,757.5 |  |  | 1,824.3 |  |  | 2,164.4 |
Consolidated Assets | $ | 26,736.6 |  |  | $ | 24,156.9 |  |  | $ | 22,040.5 |
Capital Expenditures(2) |  |  |  |  |
Gas Distribution Operations | $ | 1,682.3 |  |  | $ | 1,406.4 |  |  | $ | 1,266.9 |
Electric Operations | 574.5 |  |  | 517.4 |  |  | 422.8 |
Corporate and Other | 41.2 |  |  | 16.6 |  |  | 31.1 |
Consolidated Capital Expenditures | $ | 2,298.0 |  |  | $ | 1,940.4 |  |  | $ | 1,720.8 |

(1)In 2020, Gas Distribution Operations reflects the loss of $412.4 million on the sale of the Massachusetts Business.
(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.
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Notes to Consolidated Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
22. Other, Net
The following table displays the components of Other, Net included on the Statements of Consolidated Income (Loss):

Year Ended December 31, (in millions) | 2022 |  | 2021 |  | 2020
Interest income | $ | 4.3 |  |  | $ | 4.0 |  |  | $ | 5.5 |
AFUDC equity | 15.1 |  |  | 13.1 |  |  | 9.9 |
Charitable contributions | (4.4) |  |  | (11.5) |  |  | (1.5) |
Pension and other postretirement non-service cost(1) | 27.6 |  |  | 35.5 |  |  | 9.3 |
Sale of emission reduction credits | — |  |  | — |  |  | 4.6 |
Interest rate swap settlement gain(2) | 10.0 |  |  | — |  |  | — |
Miscellaneous | (0.4) |  |  | (0.3) |  |  | 4.3 |
Total Other, net | $ | 52.2 |  |  | $ | 40.8 |  |  | $ | 32.1 |

(1) See Note 12, "Pension and Other Postemployment Benefits," for additional information.
(2) See Note 10, "Risk Management Activities," for additional information.
23. Interest Expense, Net
The following table displays the components of Interest Expense, Net included on the Statements of Consolidated Income (Loss):

Year Ended December 31, (in millions) | 2022 |  | 2021 |  | 2020
Interest on long-term debt | $ | 344.5 |  |  | $ | 336.4 |  |  | $ | 354.2 |
Interest on short-term borrowings | 22.7 |  |  | 0.6 |  |  | 14.7 |
Debt discount/cost amortization | 11.7 |  |  | 11.0 |  |  | 9.1 |
Accounts receivable securitization fees | 2.5 |  |  | 1.4 |  |  | 2.6 |
Allowance for borrowed funds used and interest capitalized during construction | (6.7) |  |  | (4.6) |  |  | (7.0) |
Debt-based post-in-service carrying charges | (21.1) |  |  | (14.7) |  |  | (14.6) |
Other | 8.0 |  |  | 11.0 |  |  | 11.7 |
Total Interest Expense, net | $ | 361.6 |  |  | $ | 341.1 |  |  | $ | 370.7 |

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Notes to Consolidated Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
24. Supplemental Cash Flow Information
The following table provides additional information regarding our Consolidated Statements of Cash Flows for the years ended December 31, 2022, 2021 and 2020:

Year Ended December 31, (in millions) | 2022 |  | 2021 |  | 2020
Supplemental Disclosures of Cash Flow Information |  |  |  |  |
Non-cash transactions: |  |  |  |  |
Capital expenditures included in current liabilities | $ | 275.1 |  |  | $ | 245.7 |  |  | $ | 170.4 |
Assets acquired under a finance lease | 19.3 |  |  | 22.4 |  |  | 59.3 |
Assets acquired under an operating lease | 8.8 |  |  | 6.0 |  |  | 10.9 |
Reclassification of other property to regulatory assets(1) | — |  |  | 607.6 |  |  | — |
Assets recorded for asset retirement obligations(2) | 6.3 |  |  | 12.0 |  |  | 91.5 |
Obligation to developer at formation of JV(3) | — |  |  | 277.5 |  |  | 69.7 |
Purchase contract liability, net of fees and payments(4) | 65.0 |  |  | 129.4 |  |  | — |
Schedule of interest and income taxes paid: |  |  |  |  |
Cash paid for interest on long-term debt, net of interest capitalized amounts | $ | 343.8 |  |  | $ | 322.4 |  |  | $ | 349.0 |
Cash paid for interest on finance leases | 8.5 |  |  | 9.4 |  |  | 11.1 |
Cash paid for income taxes, net of refunds(5) | 7.2 |  |  | 5.4 |  |  | (1.0) |

(1)See Note 9, "Regulatory Matters," for additional information.
(2)See Note 8, "Asset Retirement Obligations," for additional information.
(3)Represents investing non-cash activity. See Note 4, "Variable Interest Entities," for additional information.
(4)Refer to Note 13, "Equity," for additional information.
(5)Amount of refunds in 2020 was greater than the amount of tax payments due to overpayments in 2019.
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
NISOURCE INC.
SCHEDULE II – VALUATION AND QUALIFYING ACCOUNTS

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 |
Twelve months ended December 31, 2021
|  |  | Additions |  |  |  |  |
($ in millions) | Balance Jan. 1, 2021 |  | Charged to Costs and Expenses |  | Charged to Other Account (1) |  |  | Deductions for Purposes for which Reserves were Created |  | Balance Dec. 31, 2021
Reserves Deducted in Consolidated Balance Sheet from Assets to Which They Apply: |  |  |  |  |  |  |  |  |  |
Reserve for accounts receivable | $ | 52.3 |  |  | $ | 18.3 |  |  | $ | 6.4 |  |  |  | $ | 53.5 |  |  | $ | 23.5 |
Reserve for deferred charges and other | — |  |  | — |  |  | 2.3 |  |  |  | — |  |  | 2.3 |
Twelve months ended December 31, 2020
|  |  | Additions |  |  |  |  |
($ in millions) | Balance Jan. 1, 2020 |  | Charged to Costs and Expenses |  | Charged to Other Account (1) |  |  | Deductions for Purposes for which Reserves were Created |  | Balance Dec. 31, 2020
Reserves Deducted in Consolidated Balance Sheet from Assets to Which They Apply: |  |  |  |  |  |  |  |  |  |
Reserve for accounts receivable | $ | 19.2 |  |  | $ | 31.6 |  |  | $ | 33.0 |  |  |  | $ | 31.5 |  |  | $ | 52.3 |
Reserve for other investments | 3.0 |  |  | — |  |  | — |  |  |  | 3.0 |  |  | — |

(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.
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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 chief executive officer and chief financial officer 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 chief executive officer and chief financial officer, 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 chief executive officer and chief financial officer 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 chief executive officer and chief financial officer, 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 2022, 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.
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.
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ITEM 9A. CONTROLS AND PROCEDURES
N I S OURCE I NC.
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, 2022, 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, 2022, 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, 2022, of the Company and our report dated February 22, 2023, 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 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 22, 2023
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ITEM 9B. OTHER INFORMATION
N I S OURCE I NC.
Not applicable.
ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS
Not applicable.
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PART III
N I S OURCE I NC.
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, 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 23, 2023.
ITEM 11. EXECUTIVE COMPENSATION
The information required by this Item 11 is incorporated herein by reference to the discussion in "Corporate Governance - Compensation Committee Interlocks and Insider Participation," "2022 Director Compensation," "2022 Executive Compensation," "Compensation Discussion and Analysis (CD&A)," and "Compensation and Human Capital Committee Report" of the Proxy Statement for the Annual Meeting of Stockholders to be held on May 23, 2023.
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 23, 2023.
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 23, 2023.
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 23, 2023.
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PART IV
N I S OURCE I NC.
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) | 56
Statements of Consolidated Income (Loss) | 58
Statements of Consolidated Comprehensive Income (Loss) | 59
Consolidated Balance Sheets | 60
Statements of Consolidated Cash Flows | 62
Statements of Consolidated Stockholders’ Equity | 63
Notes to Consolidated Financial Statements | 65
Schedule II | 118

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, 2021).
(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, 2021).
(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).
(2.2) | Asset Purchase Agreement, dated as of February 26, 2020, by and among NiSource Inc., Bay State Gas Company d/b/a Columbia Gas of Massachusetts and Eversource Energy (incorporated by reference to Exhibit 2.1 of the NiSource Inc. Form 8-K filed on February 27, 2020). (incorporated by reference to Exhibit 2.2 to the NiSource Inc. Form 10-K filed on February 17, 2021).
(3.1) | Amended and Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 to the Registrant’s Form 10-Q, filed with the Commission on August 3, 2015).
(3.2) | Certificate of Amendment of Amended and Restated Certificate of Incorporation of NiSource dated May 7, 2019 (incorporated by reference to Exhibit 3.1 of the NiSource Inc. Form 8-K filed on May 8, 2019).
(3.3) | Bylaws of NiSource Inc., as amended and restated through August 9, 2022 (incorporated by reference to Exhibit 3.1 to the NiSource Inc. Form 8-K filed on August 10, 2022).
(3.4) | Certificate of Designations of 5.65% Series A Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Stock (incorporated by reference to Exhibit 3.1 of the NiSource Inc. Form 8-K filed on June 12, 2018).
(3.5) | 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).
(3.6) | 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).
(3.7) | Certificate of Designations with respect to the Series C Mandatory Convertible Preferred Stock, dated April 19, 2021 (incorporated by reference to Exhibit 3.1 of the NiSource Inc. Form 8-K filed on April 19, 2021).

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(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) | Form of 2.650% Notes due 2022 (incorporated by reference to Exhibit 4.1 to the NiSource Inc. Form 8-K filed on November 14, 2017).
(4.10) | 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)).
(4.11) | 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).
(4.12) | 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).
(4.13) | Third Supplemental Indenture, dated as of June 11, 2018, by and between NiSource Inc. and The Bank of New York Mellon, as trustee (including form of 3.650% Notes due 2023) (incorporated by reference to Exhibit 4.1 of the NiSource Inc. Form 8-K filed on June 12, 2018).
(4.14) | 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).
(4.15) | Form of Depositary Receipt (incorporated by reference to Exhibit 4.1 of the NiSource Inc. Form 8-K filed on December 6, 2018).
(4.16) | 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).
(4.17) | Form of Depositary Receipt (incorporated by reference to Exhibit 4.1 to the NiSource Inc. Form 8-K filed on December 27, 2018).
(4.18) | 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).

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(4.19) | 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).
(4.20) | Description of NiSource Inc.’s Securities Registered Under Section 12 of the Exchange Act. (incorporated by reference to Exhibit 4.20 of the NiSource Form 10-K filed on February 28, 2020)
(4.21) | 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).
(4.22) | 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).
(4.23) | 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).
(4.24) | Purchase Contract and Pledge Agreement, dated April 19, 2021, between NiSource Inc. and U.S. Bank National Association, in its capacity as the purchase contract agent, collateral agent, custodial agent and securities intermediary (incorporated by reference to Exhibit 4.1 of the NiSource Inc. Form 8-K filed on April 19, 2021).
(4.25) | Form of Series A Corporate Units Certificate (incorporated by reference to Exhibit 4.1 of the NiSource Inc. Form 8-K filed on April 19, 2021).
(4.26) | Form of Series A Treasury Units Certificate (incorporated by reference to Exhibit 4.1 of the NiSource Inc. Form 8-K filed on April 19, 2021).
(4.27) | Form of Series A Cash Settled Units Certificate (incorporated by reference to Exhibit 4.1 of the NiSource Inc. Form 8-K filed on April 19, 2021).
(4.28) | Form of Series C Mandatory Convertible Preferred Stock Certificate (incorporated by reference to Exhibit 3.1 of the NiSource Inc. Form 8-K filed on April 19, 2021).
(4.29) | 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).
(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 Amended and Restated 2013 Performance Share Agreement effective on implementation of the spin-off on July 1, 2015, (under the 2010 Omnibus Incentive Plan)(incorporated by reference to Exhibit 10.1 to the NiSource Inc. Form 10-Q filed on November 3, 2015).*
(10.6) | Form of Amended and Restated 2014 Performance Share Agreement effective on the implementation of the spin-off on July 1, 2015, (under the 2010 Omnibus Incentive Plan)(incorporated by reference to Exhibit 10.2 to the NiSource Inc. Form 10-Q filed on November 3, 2015).*
(10.7) | 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).*
(10.8) | NiSource Inc. Nonemployee Director Retirement Plan, as amended and restated effective May 13, 2008 (incorporated by reference to Exhibit 10.2 to the NiSource Inc. Form 10-K filed on February 27, 2009).*
(10.9) | 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).*

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(10.10) | Revised Form of Change in Control and Termination Agreement (incorporated by reference to Exhibit 10.2 to the NiSource Inc. Form 8-K filed on October 23, 2015.)*
(10.11) | Form of Restricted Stock Agreement under the 2010 Omnibus Incentive Plan (incorporated by reference to Exhibit 10.18 to the NiSource Inc. Form 10-K filed on February 28, 2011).*
(10.12) | Form of Restricted Stock Unit Award Agreement for Non-employee directors under the Non-employee Director Stock Incentive Plan (incorporated by reference to Exhibit 10.19 to the NiSource Inc. Form 10-K filed on February 28, 2011).*
(10.13) | 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).*
(10.14) | Form of Restricted Stock Unit Award Agreement under the 2010 Omnibus Incentive Plan (incorporated by reference to Exhibit 10.17 to the NiSource Inc. Form 10-K filed on February 22, 2017).*
(10.15) | 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). *
(10.16) | 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).*
(10.17) | NiSource Inc. Executive Severance Policy, as amended and restated, effective January 1, 2015 (incorporated by reference to Exhibit 10.21 to the NiSource Inc. Form 10-K filed on February 18, 2015).*
(10.18) | 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).
(10.19) | 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).
(10.20) | Letter Agreement, dated as of March 17, 2015, by and between NiSource Inc. and Donald Brown. (incorporated by reference Exhibit 10.1 to the NiSource Inc. Form 10-Q filed on April 30, 2015).*
(10.21) | Letter Agreement, dated as of February 23, 2016, by and between NiSource Inc. and Pablo A. Vegas. (incorporated by reference Exhibit 10.29 to the NiSource Inc. Form 10-K filed on February 22, 2017).*
(10.22) | Employee Matters Agreement, dated as of June 30, 2015, by and between NiSource Inc. and Columbia Pipeline Group, Inc. (incorporated by reference to Exhibit 10.2 of the NiSource Inc. Form 8-K filed on July 2, 2015).
(10.23) | 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).*
(10.24) | Form of Performance Share Award Agreement under the 2010 Omnibus Incentive Plan (incorporated by reference to Exhibit 10.33 to the NiSource Form 10-K filed on February 20, 2018).*
(10.25) | Form of Restricted Stock Unit Award Agreement under the 2010 Omnibus Incentive Plan (incorporated by reference to Exhibit 10.34 to the NiSource Form 10-K filed on February 20, 2018).*
(10.26) | Common Stock Subscription Agreement, dated as of May 2, 2018, by and among NiSource Inc. and the purchasers named therein (incorporated by reference to Exhibit 10.1 of the NiSource Inc. Form 8-K filed on May 2, 2018).
(10.27) | 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).
(10.28) | Purchase Agreement, dated as of June 6, 2018, by and among NiSource Inc. and Credit Suisse Securities (USA) LLC, J.P. Morgan Securities LLC, Morgan Stanley & Co. LLC and MUFG Securities Americas Inc., as representatives, relating to the 5.650% Series A Preferred Stock (incorporated by reference to Exhibit 10.1 of the NiSource Inc. Form 8-K filed on June 12, 2018).

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(10.29) | Purchase Agreement, dated as of June 6, 2018, by and among NiSource Inc. and Credit Suisse Securities (USA) LLC, J.P. Morgan Securities LLC, Morgan Stanley & Co. LLC and MUFG Securities Americas Inc., as representatives, relating to the 3.650% Notes due 2023 (incorporated by reference to Exhibit 10.2 of the NiSource Inc. Form 8-K filed on June 12, 2018).
(10.30) | Registration Rights Agreement, dated as of June 11, 2018, by and among NiSource Inc. and Credit Suisse Securities (USA) LLC, J.P. Morgan Securities LLC, Morgan Stanley & Co. LLC and MUFG Securities Americas Inc., as representatives, relating to the 5.650% Series A Preferred Stock (incorporated by reference to Exhibit 10.3 of the NiSource Inc. Form 8-K filed on June 12, 2018).
(10.31) | Registration Rights Agreement, dated as of June 11, 2018, by and among NiSource Inc. and Credit Suisse Securities (USA) LLC, J.P. Morgan Securities LLC, Morgan Stanley & Co. LLC and MUFG Securities Americas Inc., as representatives, relating to the 3.650% Notes due 2023 (incorporated by reference to Exhibit 10.4 of the NiSource Inc. Form 8-K filed on June 12, 2018).
(10.32) | Form of 2019 Performance Share Award Agreement under the 2010 Omnibus Incentive Plan. (incorporated by reference to Exhibit 10.45 of the NiSource Inc. Form 10-K filed on February 20, 2019).*
(10.33) | 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).
(10.34) | Form of Performance Share Award Agreement (incorporated by reference to Exhibit 10.39 of the NiSource Form 10-K filed on February 28, 2020).*
(10.35) | Form of Restricted Stock Unit Award Agreement (incorporated by reference to Exhibit 10.40 of the NiSource Form 10-K filed on February 28, 2020). *
(10.36) | Form of Cash-Based Award Agreement (incorporated by reference to Exhibit 10.41 of the NiSource Form 10-K filed on February 28, 2020). *
(10.37) | Columbia Gas of Massachusetts Plea Agreement dated February 26, 2020 (incorporated by reference to Exhibit 10.2 of the NiSource Inc. Form 8-K filed on February 27, 2020).
(10.38) | NiSource Deferred Prosecution Agreement dated February 26, 2020 (incorporated by reference to Exhibit 10.1 of the NiSource Inc. Form 8-K filed on February 27, 2020).
(10.39) | 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).*
(10.40) | Settlement Agreement, dated July 2, 2020, by and among Bay State Gas Company d/b/a Columbia Gas of Massachusetts, NiSource Inc., Eversource Gas Company of Massachusetts, Eversource Energy, the Massachusetts Attorney General’s Office, the Massachusetts Department of Energy Resources the Low-Income Weatherization and Fuel Assistance Program Network (incorporated by reference to Exhibit 10.1 of the NiSource Inc. Form 8-K filed on July 6, 2020).
(10.41) | 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).*
(10.42) | Addendum to Plea Agreement filed on or about June 21, 2020 in the United States District Court for the District of Massachusetts (incorporated by reference to Exhibit 10.4 of the NiSource Inc. Form 10-Q filed on August 5, 2020).
(10.43) | Letter Agreement by and among NiSource Inc., Bay State Gas Company d/b/a Columbia Gas of Massachusetts and Eversource Energy Relating to Asset Purchase Agreement, dated October 9, 2020 (incorporated by reference to Exhibit 10.3 to the NiSource Inc. Form 10-Q filed on November 2, 2020).***
(10.44) | 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).*
(10.45) | 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).
(10.46) | 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).*

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(10.47) | 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).*
(10.48) | 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).*
(10.49) | Letter Agreement dated October 19, 2020 by and between NiSource Inc. and Carrie Hightman (incorporated by reference to Exhibit 10.9 to the NiSource Inc. Form 10-Q filed on November 2, 2020).*
(10.50) | Amendment to Settlement Agreement by and among Bay State Gas Company d/b/a Columbia Gas of Massachusetts, NiSource Inc., Eversource Gas Company of Massachusetts, Eversource Energy, the Massachusetts Attorney General’s Office, the Massachusetts Department of Energy Resources and the Low-Income Weatherization and Fuel Assistance Program Network, dated September 29, 2020 (incorporated by reference to Exhibit 10.2 to the NiSource Inc. Form 10-Q filed on November 2, 2020).
(10.51) | 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).*
(10.52) | 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).*
(10.53) | 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).*
(10.54) | 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).
(10.55) | 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)
(10.56) | 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)
(10.57) | Form of Restricted Stock Unit Award Agreement.* **
(10.58) | Form of Performance Share Unit Award Agreement.* **
(10.59) | Form of Restricted Stock Unit Award Agreement.* **
(10.60) | Form of Performance Share Unit Award Agreement.* **
(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).**
(101.INS) | Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document. **

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(101.SCH) | Inline XBRL Schema Document.**
(101.CAL) | Inline XBRL Calculation Linkbase Document.**
(101.LAB) | Inline XBRL Labels Linkbase Document.**
(101.PRE) | Inline XBRL Presentation Linkbase Document.**
(101.DEF) | Inline XBRL Definition Linkbase Document.**
(104) | Cover page Interactive Data File (formatted as inline XBRL, and contained in Exhibit 101.)

* | 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.

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.
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ITEM 16. FORM 10-K SUMMARY
None.
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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)
Date: February 22, 2023 | 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 | Date: February 22, 2023
|  |  | Lloyd M. Yates |  | Executive Officer and Director (Principal Executive Officer) |
|  | /s/ | DONALD E. BROWN |  | Executive Vice President and | Date: February 22, 2023
|  |  | Donald E. Brown |  | Chief Financial Officer (Principal Financial Officer) |
|  | /s/ | GUNNAR J. GODE |  | Vice President and | Date: February 22, 2023
|  |  | Gunnar J. Gode |  | Chief Accounting Officer (Principal Accounting Officer) |
|  | /s/ | KEVIN T. KABAT |  | Chairman of the Board | Date: February 22, 2023
|  |  | Kevin T. Kabat |  |  |
|  | /s/ | PETER A. ALTABEF |  | Director | Date: February 22, 2023
|  |  | Peter A. Altabef |  |  |
|  | /s/ | SONDRA L. BARBOUR |  | Director | Date: February 22, 2023
|  |  | Sondra L. Barbour |  |  |
|  | /s/ | THEODORE H. BUNTING, JR. |  | Director | Date: February 22, 2023
|  |  | Theodore H. Bunting, Jr. |  |  |
|  | /s/ | ERIC L. BUTLER |  | Director | Date: February 22, 2023
|  |  | Eric L. Butler |  |  |
|  | /s/ | ARISTIDES S. CANDRIS |  | Director | Date: February 22, 2023
|  |  | Aristides S. Candris |  |  |
|  | /s/ | DEBORAH A. HENRETTA |  | Director | Date: February 22, 2023
|  |  | Deborah A. Henretta |  |  |
|  | /s/ | DEBORAH A.P. HERSMAN |  | Director | Date: February 22, 2023
|  |  | Deborah A. P. Hersman |  |  |
|  | /s/ | MICHAEL E. JESANIS |  | Director | Date: February 22, 2023
|  |  | Michael E. Jesanis |  |  |
|  | /s/ | WILLIAM D. JOHNSON |  | Director | Date: February 22, 2023
|  |  | William D. Johnson |  |  |
|  | /s/ | CASSANDRA S. LEE |  | Director | Date: February 22, 2023
|  |  | Cassandra S. Lee |  |  |

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