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

NIS~~OURCE~~ INC.

Electric Operations

We generate, transmit and distribute electricity through our subsidiary NIPSCO to approximately 483,000 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 and Indiana Crossroads Wind went into service during December 2021. We also purchased energy generated from renewable sources through PPAs. 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. As of December 31, 2021 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

Norway

White County, IN

Hydro

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

~~For~~(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 ~~years~~managing partner of these joint ventures. Refer to Note 4, "Variable Interest Entities," in the Notes to Consolidated Financial Statements for more information.

NIPSCO’s transmission system, with voltages from 69,000 to 765,000 volts, consists of 3,024 circuit miles. NIPSCO is interconnected with eight neighboring electric utilities.

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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 transferred functional control of its electric transmission assets to MISO, and transmission service for NIPSCO occurs under the MISO Open Access Transmission Tariff. NIPSCO units are dispatched by MISO which takes into account economics, reliability of the MISO system and unit availability. During the year ended December 31, ~~2018, 2017~~2021, NIPSCO units were dispatched to meet 47.87% of its load requirements, and ~~2016,~~NIPSCO purchased 52.13% from the MISO market.

Business Strategy

We focus our business strategy on providing safe and reliable service through our core, rate-regulated asset-based utilities, which generate substantially all of our operating ~~income~~income. Our utilities continue to move forward 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, ensuring customer affordability and reducing emissions while generating sustainable returns.

The safety of our customers, communities and employees has been and remains our top priority. SMS is an established operating model within NiSource. With the continued support and advice from our Quality Review Board (a panel of third parties with safety operations expertise engaged by management to advise on safety matters), we are continuing to mature our SMS processes, capabilities and talent as we collaborate within and across industries to enhance safety and reduce operational risk. 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 ~~reconciliation~~cost effective manner.

In November 2021, we submitted our 2021 Integrated Resource Plan with the IURC. The plan calls for the replacement of ~~net revenues~~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 ~~most~~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.

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.

Natural Gas Competition. Open access to natural gas supplies over interstate pipelines and the deregulation of the gas supply has led to tremendous change in the energy markets. LDC customers can purchase gas directly ~~comparable GAAP measure, operating income, was~~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, 2021, 26.2% of our residential customers and 35.4% 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 ~~follows:~~propane and fuel oil. Gas Distribution Operations continues to be a strong competitor in the energy market as a result of strong 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.

Electric Competition. Indiana 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.

Year Ended December 31, (in millions)
2018 2017 2016 2018 vs. 2017 2017 vs. 2016
Operating Income $ 386.1
$ 367.4
$ 301.3
$ 18.7
$ 66.1

Year Ended December 31, (dollars in millions)
2018 2017 2016 2018 vs. 2017 2017 vs. 2016
Net Revenues
Operating revenues $ 1,708.2
$ 1,786.5
$ 1,661.6
$ (78.3 ) $ 124.9
Less: Cost of sales (excluding depreciation and amortization) 502.1
513.9
495.0
(11.8 ) 18.9
Net Revenues 1,206.1
1,272.6
1,166.6
(66.5 ) 106.0
Operating Expenses
Operation and maintenance 500.0
565.6
528.9
(65.6 ) 36.7
Depreciation and amortization 262.9
277.8
274.5
(14.9 ) 3.3
Loss on sale of assets —
1.9
—
(1.9 ) 1.9
Other taxes 57.1
59.9
61.9
(2.8 ) (2.0 )
Total Operating Expenses 820.0
905.2
865.3
(85.2 ) 39.9
Operating Income $ 386.1
$ 367.4
$ 301.3
$ 18.7
$ 66.1
Revenues
Residential $ 494.7
$ 476.9
$ 457.4
$ 17.8
$ 19.5
Commercial 492.6
501.2
456.6
(8.6 ) 44.6
Industrial 614.4
698.1
631.6
(83.7 ) 66.5
Wholesale 15.7
11.6
11.6
4.1
—
Other 90.8
98.7
104.4
(7.9 ) (5.7 )
Total $ 1,708.2
$ 1,786.5
$ 1,661.6
$ (78.3 ) $ 124.9
Sales (Gigawatt Hours)
Residential 3,535.2
3,301.7
3,514.8
233.5
(213.1 )
Commercial 3,844.6
3,793.5
3,878.7
51.1
(85.2 )
Industrial 8,829.5
9,469.7
9,281.8
(640.2 ) 187.9
Wholesale 114.3
32.5
19.0
81.8
13.5
Other 124.4
128.2
136.9
(3.8 ) (8.7 )
Total 16,448.0
16,725.6
16,831.2
(277.6 ) (105.6 )
Cooling Degree Days 1,180
837
988
343
(151 )
Normal Cooling Degree Days 806
806
806
—
—
% Warmer than Normal 46 % 4 % 23 %

Electric Customers
Residential 412,267
409,401
407,268
2,866
2,133
Commercial 56,605
56,134
55,605
471
529
Industrial 2,284
2,305
2,313
(21 ) (8 )
Wholesale 735
739
744
(4 ) (5 )
Other 2
2
2
—
—
Total 471,893
468,581
465,932
3,312
2,649

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ITEM 1. BUSINESS

NISOURCE INC.

Seasonality

A significant portion of our operations are subject to seasonal fluctuations in sales. During the heating and cooling seasons, revenues from gas and electric sales, respectively, are more significant than in other months. The heating season is primarily from November through March, and the cooling season is primarily from June through September.

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 Rates

Columbia of Pennsylvania(1)	10.95	%	None specified		$	98.3	$	58.5	March 30, 2021	Approved December 16, 2021	December 2021
Columbia of Maryland	10.85	%	9.65	%	$	4.8	$	2.4	May 14, 2021	Approved December 3, 2021	December 2021
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	11.50	%	10.39	%	$	87.8	$	47.1	March 3, 2008	Approved December 3, 2008	December 2008
NIPSCO - Gas	10.70	%	9.85	%	$	138.1	$	105.6	September 27, 2017	Approved September 19, 2018	October 2018
NIPSCO - Electric	10.80	%	9.75	%	$	21.4	$	(53.5)	October 31, 2018	Approved December 4, 2019	January 2020
Active Rate Cases
Columbia of Ohio	10.95	%	In process		$	221.4	In process		June 30, 2021	Order Expected Q3 2022	Q3 2022
NIPSCO - Gas(4)	10.50	%	In process		$	109.7	In process		September 29, 2021	Order Expected Q3 2022	September 2022

(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 without specifying ratemaking elements to establish the Company's revenue requirement. Pursuant to the settlement, for purposes of calculating its DSIC, Columbia of Pennsylvania shall use the equity return rate for gas utilities contained in the Pennsylvania Commission’s most recent Quarterly Report on the Earnings of Jurisdictional Utilities, including quarterly updates thereto.

(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)Proposed new rates would be implemented in 2 steps, with implementation of step 1 rates to be effective in September 2022 and step 2 rates to be effective in March 2023.

COVID-19 Regulatory Deferrals

In addition to the cost deferred to a regulatory asset as noted in Note 9, "Regulatory Matters," in the Notes to Consolidated Financial Statements, certain states have permitted us to track lost late and disconnect fee revenues due to the pandemic. While these costs do not qualify as regulatory assets under ASC 980, we will consider seeking recovery of these costs in future regulatory proceedings.

Competition and Changes in the Regulatory Environment

The regulatory frameworks 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. 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. Refer to Note 19-E, "Environmental Matters," in the Notes to Consolidated Financial Statements for more information regarding environmental regulations that are applicable to our operations.

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 upstream of the companies’ service territory, (ii) the sale of products and services in the companies’ service territories, and (iii) gas supply cost incentive mechanisms for service to their

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core markets. The upstream products are made up of transactions that occur between an individual Gas Distribution Operations utility and a buyer for the sales of unbundled or rebundled gas supply and capacity. 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 offers 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 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 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.

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 management practices. In October 2021, the Board renamed the Compensation Committee the “Compensation and Human Capital Committee” and clarified the Committee’s responsibilities in its Charter to include reviewing our human capital management function and programs, including related procedures, programs, policies and practices, and to make recommendations to management with respect to equal employment opportunity and diversity, equity and inclusion initiatives; employee engagement and corporate culture; and talent management. Our Board also reviews human capital management matters, including talent strategy, employee engagement and culture. Earlier in 2021, we hired a new Senior Vice President and Chief Human Resources Officer and a new Vice President and Chief Diversity Officer to lead these initiatives.

In addition to overseeing our human capital management practices, our Board 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 each comprise 30% of our Board.

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ITEM 1. BUSINESS

NISOURCE INC.

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 as a whole.

Workforce Composition.As of December 31, 2021, we had 7,272 full-time and 70 part-time employees. Thirty-six percent of our employees were subject to collective bargaining agreements with various labor unions and 32% of our employees were subject to collective bargaining agreements that are set to expire within one year. We are currently in the process of renegotiating these agreements.

Diversity, Equity and Inclusion.We are committed to accelerating and embedding diversity, equity and inclusion throughout the enterprise to reflect the communities and customers we serve. Our talent acquisition teams hired 748 external candidates in 2021 across all business segments. Thirty-eight percent of external hires were female and 21% were racially or ethnically diverse. In 2021, we engaged with community-based organizations, conducted career interest workshops in local schools, and focused our employee mentorship program on females. We also led a separate targeted development program for select employees to support the growth and development of female and ethnically diverse talent. We offer several employee resource groups (“ERGs”) and host mostly virtual activities throughout each year. We have ERGs to support African-American, Hispanic, veterans, LGBTQ+, female and Asian employees, among others, and held several sponsored conversations between senior executives and the ERGs.

In order to provide additional transparency, we are enhancing our corporate website to include more information on our diversity, equity and inclusion program and plans, which are led by our Chief Diversity, Equity and Inclusion Officer, with the full support of our Chief Human Resources Officer, executive leadership team, Compensation and Human Capital Committee and Board. We plan to post consolidated EEO-1 report data on our website by the end of the first quarter of 2022.

The following graph shows the percentage of total employees represented by females and males overall and for our officers as of December 31, 2021:

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NISOURCE INC.

The following graph shows the percentage of total employees represented by race/ethnicity overall and for our officers as of December 31, 2021:

Talent Development and Retention.We offer leadership development programs to enhance the behaviors and skills of our existing and future leaders. In 2021, we had participation from employees of all levels. We also offer extensive technical and non-technical employee development training programs.

We strive to provide promotion and advancement opportunities for employees. In 2021, 86% of all leadership positions at the supervisor and above level were filled internally. We develop and implement targeted development action plans to increase succession candidate readiness for leadership roles. We also monitor the risk and potential impact of talent loss and take action to increase retention of top talent. Retention at NiSource in 2021 was over 89%. Retention is calculated using the total number of separations divided by the average headcount for the annual period. In addition to voluntary separations, separations include involuntary separation (2.0%), resignation (4.6%), and retirement (4.2%).

Talent Attraction.To recruit and hire individuals with a variety of skills, talents, backgrounds and experiences, we value and cultivate relationships with community and diversity outreach sources. We also target jobs fairs including those focused on people of color, veteran and women candidates and partner with local colleges and universities to identify and recruit qualified applicants in the communities we serve.

Similar to other companies that are adjusting in a COVID-19 environment, we are focused on our future of work and creating a more flexible, agile model for roles that can be performed in a more virtual setting. We anticipate expanding our recruiting footprint for certain roles that do not require to be in-person within our operating states.

Succession Planning.We perform succession planning quarterly for officer-level and critical roles to ensure that we develop and sustain a strong bench of talent capable of performing at the highest levels. Not only is talent identified, but 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 Nominating and Governance Committee and the succession plans for executive officers (other than the CEO) and critical roles are reviewed by the Compensation and Human Capital Committee annually or more frequently as needed.

Employee and Workplace Health and Safety. We have a number of 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 and paid illness in

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family days, competitive medical, dental, vision, life and long term disability programs including employee health savings account company contributions.

We also have a robust program to support employee, contractor and public safety, which is led by our Chief Safety Officer and is under the oversight of the Environmental, Safety and Sustainability Committee of our Board. We plan to publish a comprehensive safety report on our corporate website either before or in conjunction with our upcoming integrated annual report to provide additional transparency on our safety program. In response to COVID-19, we have implemented procedures designed to protect our employees who work in the field and who continue to work in operational and corporate facilities, including social distancing and wearing face coverings. We have also implemented work-from-home policies and practices. We are continuously evaluating changes to the Centers for Disease Control and Prevention ("CDC") guidance, and updating our safety measures accordingly, in order to ensure employee and customer safety during the pandemic. We are following federal, state, and local laws, regulations and guidelines related to the COVID-19 vaccinations. For more information regarding our response to the pandemic, see “Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations – Executive Summary” in this report.

Culture and Engagement. Our culture is another important aspect of our ability to advance our strategic and operational objectives. In addition to our diversity, equity and inclusion, 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 executive communications to employees. 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, management forums and all-employee town hall meetings. These communications emphasize the importance of our values and culture in the workplace. In addition, we offer in-person and virtual employee community service opportunities and we support employees’ personal volunteering and charitable giving through our charitable matching program.

To instill and reinforce our values and culture, we require our employees to participate in regular training on rotating ethics and compliance topics each year, including, among others, raising concerns, treating others with respect, preventing discrimination in the workplace, anti-bribery and corruption, data protection, unconscious biases, harassment, conflicts of interest, and 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.

We measure and monitor culture and employee engagement through a variety of channels including pulse surveys and engagement surveys. 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.

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

NISOURCE INC.

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

Name

Age

Office(s) Held in Past 5 Years

Lloyd M. Yates

President and Chief Executive Officer of NiSource since February 2022

Executive Vice President, Customer and Delivery Operations, and President, Carolina Region, at Duke Energy Corporation, an electric power and natural gas company, from 2014 to 2019.

Donald E. Brown

Executive Vice President, Chief Financial Officer and President, NiSource Corporate Services

Executive Vice President of NiSource since May 2015.

Chief Financial Officer of NiSource since July 2015.

President, NiSource Corporate Services since June 2020.

Kimberly S. Cuccia

Vice President, Interim General Counsel and Corporate Secretary

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.

Shawn Anderson

Senior Vice President and Chief Strategy and Risk Officer of NiSource since June 2020.

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.

Charles E. Shafer, II

Senior Vice President and Chief Safety Officer of NiSource since October 2019.

Senior Vice President, Gas Engineering and Gas Support Services of NiSource Corporate Services Company from January 2019 to September 2019.

Senior Vice President, Customer Services and New Business of NiSource Corporate Services Company from May 2016 through December 2018.

Violet G. Sistovaris

Executive Vice President and Chief Experience Officer

Executive Vice President of NiSource since July 2015.

Chief Experience Officer of NiSource since June 2020.

President, NIPSCO, of NiSource from July 2015 to May 2020.

Pablo A. Vegas

Executive Vice President, Chief Operating Officer and President, NiSource Utilities.

Executive Vice President of NiSource since May 2016.

Chief Operating Officer and President, NiSource Utilities of NiSource since June 2020.

President, Gas Utilities of NiSource from January 2019 to May 2020.

Chief Restoration Officer of NiSource from September 2018 to December 2018.

Executive Vice President, Gas Business Segment and Chief Customer Officer of NiSource from May 2017 to September 2018.

President, Columbia Gas Group, of NiSource from May 2016 to May 2017.

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ITEM 1A. RISK FACTORS

NISOURCE INC.

SUMMARY OF RISK FACTORS

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 trading price of our common stock. This summary is not intended to be complete and should only be read together with the information set forth in “Item 1A, Risk Factors” in this report.

Operational Risks

•We may not be able to execute our business plan or growth strategy.

•Our gas distribution and transmission activities, as well as generation, transmission and distribution of electricity, involve a variety of inherent hazards and operating risks.

•Failure to adapt to advances in technology and manage the related costs could make us less competitive.

•Aging infrastructure may lead to disruptions in operations and increased capital expenditures and maintenance costs.

•Our insurance may not provide protection against all significant losses.

•The implementation of our electric generation strategy may not achieve intended results.

•Our capital projects and programs subject us to construction risks and natural gas costs and supply risks, and are subject to regulatory oversight.

•Fluctuations in weather, gas and electricity commodity costs, inflation and economic conditions impact demand of our customers and our operating 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.

•Failure to attract and retain an appropriately qualified workforce, and maintain good labor relations, could harm our results of operations.

•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.

•Actions of activist stockholders could negatively affect our business and stock price and cause us to incur significant expenses.

•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.

•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.

•Compliance with and changes in cybersecurity requirements have a cost and operational impact on our business.

•We are exposed to significant reputational risks, which make us vulnerable to a loss of cost recovery, increased litigation and negative public perception.

•We have continued financial liabilities related to the sale of the Massachusetts Business.

•The impacts of catastrophic events may disrupt operations and reduce the ability to service customers.

•The physical impacts of climate change and the transition to a lower carbon future are affecting our business.

•We are subject to risks associated with the implementation and efforts to achieve our carbon emission reduction goals.

Financial, Economic and Market Risks

•We have substantial indebtedness which could adversely affect our financial condition.

•A drop in our credit ratings could adversely impact our cash flows, results of operation, financial condition and liquidity.

•The global outbreak of the novel coronavirus and its variants (COVID-19) has adversely impacted and may continue to adversely impact our business, results of operations, financial condition, liquidity and cash flows.

•Adverse economic and market conditions could materially and adversely affect our business, results of operations, cash flows, financial condition and liquidity.

•Most of our revenues are subject to economic regulation and are exposed to the impact of regulatory rate reviews.

•The actions of regulators and legislators could result in outcomes that may adversely affect our earnings and liquidity.

•Our business operations are subject to economic conditions in certain industries.

•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.

•We are dependent on cash generated by our subsidiaries to meet our debt obligations and pay dividends on our stock.

•The trading prices for our Equity Units 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.

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ITEM 1A. RISK FACTORS

NISOURCE INC.

•The early settlement right triggered under certain circumstances and the supermajority rights of the mandatory convertible preferred stock following a fundamental change, could discourage a potential acquirer.

•Our Equity Units and the issuance and sale of common stock in settlement of the purchase contracts and conversion of mandatory convertible preferred stock may 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.

•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.

•Changes in the method for determining LIBOR and the potential replacement of the LIBOR benchmark interest rate could adversely affect our business, financial condition, results of operations and cash flows.

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.

•The Greater Lawrence Incident has materially adversely affected and may continue to materially adversely affect our financial condition, results of operations and cash flows.

•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.

•We could be materially adversely affected if we fail to comply with the laws, regulations and tariffs that apply to our businesses.

•The cost of compliance with environmental laws, and changes to or additions to, or reinterpretations of the laws, could be significant. Liability from the failure to comply with existing or changed environmental laws could have a material adverse effect on our business, results of operations, cash flows and financial condition.

•Changes in taxation and the ability to quantify such changes as well as challenges to tax positions could adversely affect our financial results.

OPERATIONAL RISKS

We may not be able to execute our business plan or growth strategy, including utility infrastructure investments.

Business or regulatory conditions may result in us not being able to execute our business plan or growth strategy, including identified, planned and other utility infrastructure investments, which includes investments related to natural gas pipeline modernization and investments related to our renewable energy projects and the build-transfer execution goals within our business plan. Our “NiSource Next” initiative, a comprehensive program designed to identify long-term sustainable capability enhancements and cost optimization improvements, 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, joint ventures 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, 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 impacting our ability to obtain materials for our gas and electric projects. Risks to our capital projects is described in a separate risk factor below.

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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 in the future result in serious injury or loss of life to employees and/or the general public, significant damage to property, environmental pollution, impairment of our operations, adverse regulatory rulings and reputational harm, which in turn could lead to substantial 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 litigation or administrative or other legal proceedings from time to time, both civil and criminal, which could result in substantial monetary judgments, fines, or penalties against us, be resolved on unfavorable terms, and require us to incur significant operational expenses. The occurrence of incidents has in certain instances adversely affected and could in the future adversely affect our reputation, cash flows, financial position and/or results of operations. We maintain insurance against some, but not all, of these risks and losses.

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 research, plan for, and implement new technologies that produce reliable, cost-efficient power or reduce power consumption and improve the impact on the environment. These technologies, many of which NiSource is implementing, include renewable energy, distributed generation, energy storage, and energy efficiency. Advances in technology, changes in laws or regulations (including subsidization) and other alternative methods of producing power could reduce the cost of electric generation from these sources to a level that is competitive with most central station power electric production, causing power sales to decline and the value of our generating facilities to decline. Other new technologies require us to make significant expenditures to remain competitive and may result in the obsolescence of certain operating assets.

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 would impact our ability to recover on our investments in our gas distribution assets.

In addition, customers are increasingly expecting additional communications, increased access to information, and expanded electronic capabilities regarding their electric and natural gas services, which, in some cases, involves additional investments in technology. We also rely on technology to adequately maintain key business records.

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, any unrecovered investment in obsolete assets. A failure by us to effectively adapt to changes in technology and manage the related costs could harm our ability to remain competitive in the marketplace for our products and services 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

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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 in order to improve infrastructure information and records and address emerging regulatory or risk management requirements, which increases our 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 gas materials. We may not be effective in ensuring that we can obtain adequate emergency supply on a timely basis in each state, that no compromises are being made on quality and that we have alternate suppliers available. The failure to operate our assets as desired could result in interruption of electric service, major component failure at generating facilities and electric substations, gas leaks and other incidents, and an inability to meet firm service and compliance obligations, which could adversely impact revenues, and could also result in increased capital expenditures and maintenance costs, which, if not fully recovered from customers, could negatively impact our financial results.

We may be unable to obtain insurance on acceptable terms or at all, and the insurance coverage we do obtain may not provide protection against all significant losses.

Our ability to obtain insurance, as well as the cost and coverage of such insurance, 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 certain perils such as wildfires as well as gas explosion events or other infrastructure-related risks. The utility insurance market continues to be impacted by a prevalence of severe losses, and despite significant increases in rates over the past few years, markets are experiencing unacceptable loss ratios. We have not been able to obtain liability insurance coverage at previously procured limits at rates that are acceptable to us. 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. The premiums we pay for our insurance coverage have significantly increased as a result of market conditions and the accumulated loss ratio over the history of our operations, and we do not expect those costs to decline. In addition, our insurance is not sufficient or effective under all circumstances and against all hazards or liabilities to which we are subject. For example, total expenses related to the Greater Lawrence Incident exceeded the total amount of liability coverage available under our policies. 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.

The implementation of NIPSCO’s electric generation strategy, including the retirement of its coal generation units, may not achieve intended results.

Our plan to replace our coal generation capacity by the end of 2028 with primarily renewable resources is well underway. We submitted an Integrated Resource Plan (the “Plan”) to the IURC, and our Preferred Energy Resource Plan, which refines the timeline to retire the Michigan City Generating Station to occur between 2026 and 2028. We submitted our 2021 Plan to the IURC in November 2021. 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. The precise timing of the retirement will be informed by regulatory and policy changes, our ability to maintain reliability of the system and our ability to secure replacement capacity. For additional information, see “Results and Discussion of Segment Operations - Electric Operations,” in Management's Discussion and Analysis of Financial Condition and Results of Operations.

There are inherent risks and uncertainties in executing the projects associated with the 2018 and 2021 plans both for what has been already executed and what capacity is still planned, including changes in market conditions, supply chain disruptions, regulatory approvals, environmental regulations, commodity costs and customer expectations, which may impede NIPSCO’s ability to achieve the intended results and associated timelines. Changes in the cost, availability and supply of generation capacity may affect the implementation of the results from the 2021 Plan. Advancements in technology in replacement resources may not become commercially available or economically feasible as projected in the 2021 Plan and the implementation execution may vary from that which has been communicated. NIPSCO’s future success will depend, in part, on its ability to successfully implement its long-term electric generation plans, to offer services that meet customer demands and evolving industry standards, and to recover all, or a significant portion of, any unrecovered investment in obsolete assets.

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NIPSCO’s electric generation strategy could 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 would negatively impact our generation transition timeline, 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. We are engaged in intrastate natural gas pipeline modernization programs to maintain system integrity and enhance service reliability and flexibility. NIPSCO also is currently engaged in a number of capital projects, including environmental improvements to its electric generating stations, the construction of new transmission and distribution facilities, and new projects related to renewable energy. 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 increasing. 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 unemployment, consumption and consumer confidence. Therefore, prevailing economic conditions affecting the demand of our customers may in turn affect our financial results.

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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.

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, or if capacity is inadequate, we may be unable to sell and deliver our gas and electricservices 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. Additionally, any regulatory changes requiring us to enforce a COVID-19 vaccination mandate and how such a mandate is implemented could impact the availability of, and our ability to attract and retain, sufficient qualified employees. We are also facing increasing risk of worker illness and availability due to more contagious COVID-19 variants. 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, several of which are currently being renegotiated. 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.

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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 the NiSource Next initiative 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.

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 stakeholder. Our response to suggested actions, proposals, director nominations and contests for the election of directors 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 shareholder 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. Increasing

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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, 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 cyber incident, such as a ransomware attack. Supplier non-compliance with cyber controls can also result in a cyber incident. Attacks can occur at any point in the supply chain or with any suppliers.

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 cyberattacks 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. 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.

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 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

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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.

We have continued financial liabilities related to the sale of the Massachusetts Business.

On October 9, 2020, we completed the sale of the Massachusetts Business to Eversource. The sale of the Massachusetts Business involves separation or carve-out activities and costs and possible disputes with Eversource. We have continued financial liabilities with respect to the business conducted by Columbia of Massachusetts, as we retain responsibility for, and have agreed to indemnify Eversource against, certain liabilities. This responsibility includes liabilities for any fines arising out of the Greater Lawrence Incident and liabilities of Columbia of Massachusetts or its affiliates pursuant to civil claims for injury of persons or damage to property to the extent such injury or damage occurred prior to the closing in connection with the Massachusetts Business. It may also be difficult to determine whether a claim from a third party is our responsibility, and we may expend substantial resources trying to determine whether we or Eversource has responsibility for the claim.

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.

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, terrorist attack, acts of war, 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 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.

The physical impacts of climate change and the transition to a lower carbon future are impacting our business.

Climate change is exacerbating the risks to our physical infrastructure by increasing the frequency of extreme weather, including heat stresses to power lines 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 stresses 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 possibly other 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 resulting 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, it may impact our ability to secure cost-efficient insurance as described above.

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, resulting 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. Conversely, demand for our services may increase as a result of

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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 opinions with respect to our environmental practices or our ability to meet the challenges posed by climate change formed by regulators, customers, investors or legislators could harm our reputation and change 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.

We are subject to operational and financial risks and liabilities associated with the implementation and efforts to achieve our carbon emission reduction goals.

NIPSCO’s electric generation transition is a key element of our goal to achieve a 90% reduction in our Scope 1 GHG emissions by 2030 compared with 2005 levels. 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 2030; 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 enhancement 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 $9,801.5 million outstanding as of December 31, 2021. Our substantial indebtedness could have important consequences. For example, it could:

•limit our ability to borrow additional funds or increase the cost of borrowing additional funds;

•reduce the availability of cash flow from operations to fund working capital, capital expenditures and other general corporate purposes;

•limit our flexibility in planning for, or reacting to, changes in the business and the industries in which we operate;

•lead parties with whom we do business to require additional credit support, such as letters of credit, in order for us to transact such business;

•place us at a competitive disadvantage compared to competitors that are less leveraged;

•increase vulnerability to general adverse economic and industry conditions; and

•limit our ability to execute on our growth strategy, which is dependent upon access to capital to fund our substantial infrastructure investment program.

Some of our debt obligations contain financial covenants related to debt-to-capital ratios and cross-default provisions. Our failure to comply with any of these covenants could result in an event of default, which, if not cured or waived, could result in the acceleration of outstanding debt obligations.

A drop in our credit ratings could adversely impact our cash flows, results of operation, financial condition and liquidity.

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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, in 2020 and 2021, the impacts of the COVID-19 pandemic. 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, 2021, the collateral requirement that would be required in the event of a downgrade below the ratings trigger levels would amount to approximately $56.2 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.

The global outbreak of the novel coronavirus and its variants (COVID-19) 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 and could lead to a prolonged reduction in economic activity, extended disruptions to supply chains and capital markets, and reduced labor availability and productivity. We continue to monitor how COVID-19 is affecting our workforce, customers, suppliers, operations, financial results and cash flow. The extent of the impact in the future will vary and depend on the duration and severity of the impact on the global, national and local economies.

Our future operating results and liquidity may continue to be impacted by the pandemic, but the extent of the impact remains uncertain. Primarily in 2020, we experienced lower revenues, higher expenses for personal protective equipment and supplies, and higher bad debt expense as a consequence of the pandemic, which negatively impacted our results of operations. Although our revenues were higher in 2021 compared to 2020, we may continue to experience ongoing impact of the pandemic, which includes, but is not limited to:

•Lower revenue and cash flow, resulting from the decrease in commercial and industrial gas and electric demand as businesses comply with operating restrictions and/or businesses experience negative economic impact from the pandemic, potentially offset by higher residential demand;

•Lower revenue and cash flow in the event of the suspension of late payment and reconnection fees in some jurisdictions;

•A decline in revenue due to an increase in customer attrition rates, as well as lower revenue growth if customer additions slow due to a prolonged economic downturn;

•A continued increase in bad debt and a decrease in cash flows resulting from the suspension of shut-offs and the inability of our customers to pay for their gas and electric service due to job loss or other factors, partially offset by regulatory deferrals;

•Lower revenues on a prolonged basis resulting from higher customer bankruptcies, predominately focused on commercial and industrial customers not able to sustain operations through any broader economic downturn;

•A continued delay in cash flows as more customers utilize the more flexible payment plans we offer; and

•An increase in internal labor costs from higher overtime.

We also face the risk of not achieving operational compliance and/or customer requirements because of work restrictions or unavailable employees due to the pandemic. For more information regarding the items above and additional items related to the pandemic that we are evaluating and monitoring, please see our discussion of these topics in Part II., Item 7. "Management

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Discussion and Analysis of Financial Condition and Results of Operations - Executive Summary - Introduction - COVID-19" in this report and in our future filings with the Securities and Exchange Commission. To the extent the pandemic adversely affects our business, results of operations, financial condition, liquidity or cash flows, it may also have the effect of heightening many of the other Risk Factors described herein.

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 geographic spread, severity and duration of the COVID-19 pandemic, including whether there are periods of increased COVID-19 cases; the further spread of the Delta variant, Omicron variant or 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 or otherwise comply with various mandates; the extent and duration of the impact on the U.S. or global economy, including the pace and extent of recovery when the COVID-19 pandemic subsides; and the actions that have been or may be taken by various governmental authorities in response to the outbreak.

Adverse economic and market conditions, including as a result of the COVID-19 pandemic, increases in interest rates 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. The continued spread of COVID-19 has resulted in widespread impacts on the global economy and financial markets and could lead to a prolonged reduction in economic activity, disruptions to supply chains and capital markets, and reduced labor availability and productivity.

In connection with the pandemic, certain state regulatory commissions instituted disconnection moratoriums and the suspension of collection of late payment fees, deposits and reconnection fees, which 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 record a regulatory asset for bad debt expense above levels currently in rates. We have reinstated our common credit mitigation practices as moratoriums have expired, but it is possible that such moratoriums will be reinstated as the pandemic continues.

In addition, the pandemic has impacted our physical business operations, resulting in delays in conducting certain residential work and additional costs required to comply with pandemic-related health and safety protocols.

Further, 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. Successful implementation of our long-term business strategies, including capital investment, is dependent upon our ability to access the capital and credit markets, including the banking and commercial paper markets, on competitive terms and rates. An economic downturn or uncertainty, market turmoil, changes in interest rates, changes in tax policy, challenges faced by financial institutions, changes in our credit ratings, or a change in investor sentiment toward us or the utilities industry generally could adversely affect our ability to raise additional capital or refinance debt. For example, because NIPSCO’s current generating facilities substantially rely on coal for its operations, certain financial institutions may choose not to participate in our financing arrangements. In addition, 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. Refer to Note 15, “Long-Term Debt,” in the Notes to Consolidated Financial Statements for information related to outstanding long-term debt and maturities of that debt. 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.

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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 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

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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, including the downturn resulting from the COVID-19 pandemic; 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 exposureby 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. As stated above, in connection with the COVID-19 pandemic, state regulatory moratoriums, which have now expired, impacted our ability to pursue our standard credit risk mitigation practices.

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 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 mandatory convertible preferred stock in connection with certain

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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 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.

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 as noted in Note 12, "Pension and Other Postretirement Benefits," in the Notes to Consolidated Financial Statements. 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 plan. 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, which requires us to maintain a debt to capitalization ratio that does not exceed 70%. As of December 31, 2021, the ratio was 57.4%.

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Changes in the method for determining LIBOR and the potential replacement of the LIBOR benchmark interest rate could adversely affect our business, financial condition, results of operations and cash flows.

Some of our indebtedness bears interest at a variable rate based on LIBOR. From time to time, we also enter into hedging instruments to manage our exposure to fluctuations in the LIBOR benchmark interest rate. In addition, these hedging instruments, as well as hedging instruments that our subsidiaries use for hedging natural gas price and basis risk, rely on LIBOR-based rates to calculate interest accrued on certain payments that may be required to be made under these agreements, such as late payments or interest accrued if any cash collateral should be held by a counterparty. Any changes announced by regulators in the method pursuant to which the LIBOR rates are determined may result in a sudden or prolonged increase or decrease in the reported LIBOR rates. If that were to occur, the level of interest payments we incur may change.

In July 2017, the United Kingdom Financial Conduct Authority (“FCA”), which regulates LIBOR, announced that the FCA intends to stop compelling banks to submit rates for the calculation of LIBOR after 2021. In November 2020, the Board of Governors of the U.S. Federal Reserve System, the Federal Deposit Insurance Corporation and the Office of the U.S. Comptroller of the Currency collectively issued a statement encouraging banks to stop entering into financial contracts that use LIBOR as a reference rate as soon as possible, and no later than December 31, 2021. In March 2021, the FCA announced that 1-week and 2‑month U.S. Dollar (“USD”) LIBOR will cease publication after December 31, 2021, and that the remaining USD LIBOR tenors will cease publication after June 30, 2023. It is not possible to predict the effect of these changes, other reforms or the establishment of alternative reference rates in the United Kingdom or elsewhere. In the United States, efforts to identify a set of alternative U.S. dollar reference interest rates include proposals by the Alternative Reference Rates Committee of the Federal Reserve Board and the Federal Reserve Bank of New York. The Alternative Reference Rates Committee has proposed the Secured Overnight Financing Rate ("SOFR") as its recommended alternative to LIBOR, and the Federal Reserve Bank of New York began publishing SOFR rates in April 2018. On February 18, 2022, we entered into an amended and restated revolving credit agreement which, among other things, amended the interest rate provisions applicable to borrowings under this agreement to utilize SOFR as the reference rate, rather than LIBOR. SOFR is intended to be a broad measure of the cost of borrowing cash overnight that is collateralized by U.S. Treasury securities. However, because SOFR is a broad U.S. Treasury repurchase agreement financing rate that represents overnight secured funding transactions, it differs fundamentally from LIBOR. Because of these and other differences, there is no assurance that SOFR will perform in the same way as LIBOR would have performed at any time, and there is no guarantee that it is a comparable substitute for LIBOR.

In addition, although certain of our LIBOR based obligations provide for alternative methods of calculating the interest rate payable on certain of our obligations if LIBOR is not reported, uncertainty as to the extent and manner of future changes may result in interest rates and/or payments that are higher than, lower than or that do not otherwise correlate over time with, the interest rates or payments that would have been made on our obligations if a LIBOR-based rate was available in its current form.

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 areinvolved 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 may 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.

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. 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

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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 was subsequently approved by the United States District Court for the District of Massachusetts (the "Court"). 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. 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. The cost of compliance with these laws, and changes to or additions to, or reinterpretations of the laws, could be significant. Liability from the failure to comply with existing or changed laws 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 coal combustion residuals. Compliance with these legal obligations require us to make expenditures for installation of pollution control equipment, remediation, environmental monitoring, emissions fees, and permits at many of our facilities. These expenditures are significant, and we expect that they will continue to be significant in the future. 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.

Existing environmental laws and regulations may be revised and new laws and regulations seeking to change environmental regulation of the energy industry may be adopted or become applicable to us, with an increasing focus on both coal and natural gas. Revised or additional laws and regulations may result in significant additional expense and operating restrictions on our facilities or increased compliance costs, which may not be fully recoverable from customers through regulated rates and could, therefore, impact our financial position, financial results and cash flow. Moreover, such costs could materially affect the continued economic viability of one or more of our facilities.

An area of significant uncertainty and risk are the laws concerning emission of GHG. While we continue to reduce GHG emissions through the retirement of coal-fired electric generation, increased sourcing of renewable energy, priority pipeline replacement, energy efficiency programs, and leak detection and repair, GHG emissions are currently an expected aspect of the electric and natural gas business. 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.

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ITEM 1A. RISK FACTORS

NISOURCE INC.

Even in instances where legal and regulatory requirements are already known or anticipated, the original cost estimates for environmental improvements, remediation of past environmental impact, or pollution reduction strategies and equipment can differ materially from the amount ultimately expended. The actual future expenditures depend 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. For example, the TCJA includes numerous provisions that affect businesses, including changes to U.S. corporate tax rates, business-related exclusions, deductions and credits. 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

NISOURCE INC.

None.

ITEM 2. PROPERTIES

Discussed below are the principal properties held by us and our subsidiaries as of December 31, 2021.

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 were 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-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

NISOURCE INC.

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 NiSource’s 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, 2022 meeting, the Board declared a quarterly common dividend of $0.235 per share, payable on February 18, 2022 to holders of record on February 8, 2022.

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, 2022, NiSource had 17,282 common stockholders of record and 405,385,010 shares outstanding.

The graph below compares the cumulative total shareholder return of NiSource’s common stock for the last five years 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, 2021, 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

NISOURCE INC.

Not applicable.

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

NISOURCE INC.


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
Environmental and Safety Matters			50

Market Risk Disclosures			51
Other Information			52

EXECUTIVE SUMMARY

This Management's Discussion and Analysis of Financial Condition and Results of Operations (Management's Discussion) analyzes our financial condition, results of operations and cash flows and those of our subsidiaries. It also 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" at the beginning of this report for a list of factors that may cause results to differ materially.

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 23, "Segments of Business," 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. The SMS is an established operating model within NiSource. With the continued support and advice from our Quality Review Board (a panel of third parties with safety operations expertise engaged by management to advise on safety matters), we are continuing to mature our SMS processes, capabilities and talent as we collaborate within and across industries to enhance safety and reduce operational risk. 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.

2021 Overview: In 2021, we made significant progress towards our strategic and financial goals and objectives. We commenced commercial operations of Indiana Crossroads Wind, adding 302 MW of renewable generating capacity to our Electric Operations. Additionally, we broke ground on two solar projects and received regulatory approval to complete another nine renewable energy projects by the end of 2023. We filed base rate cases in five states, completing three cases in 2021 with balanced outcomes supporting all stakeholders. We also invested $1.3 billion in infrastructure modernization to enhance safe, reliable service, including replacement of 390 miles of priority pipe, 54 miles of underground cable and 2,857 electric poles. Through the issuance of our Equity Units, we significantly de-risked our financing strategy and supported our investment grade credit rating.

We made advancements on 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 is well underway. As of December 31, 2021, 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 plan. On October 1, 2021, we completed

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

NISOURCE INC.

NIS~~OURCE~~ INC.

~~Electric Operations (continued)~~

~~Comparability~~the retirement of ~~line item operating results may be impacted by regulatory~~R.M. Schahfer Generating Station Units 14 and ~~depreciation trackers (other than those for cost of sales) that allow~~15. On October 21, 2021, we announced the Preferred Energy Resource Plan associated with our 2021 Integrated Resource Plan, which refines the timeline to retire the Michigan City Generating Station to occur between 2026 and 2028. The plan calls for the ~~recovery~~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 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 expected to occur between 2025 and 2028. Final retirement dates for these units, as well as Michigan City, will be subject to MISO approval. We filed our 2021 Integrated Resource Plan with the IURC in ~~rates~~November 2021. In December 2021, the formation of ~~certain costs. Therefore, increases~~the Indiana Crossroads Wind joint venture, one of our previously executed BTAs, was completed, and began commercial operations. For additional information, see Note 4, "Variable Interest Entities," in ~~these tracked operating expenses are offset~~the Notes to Consolidated Financial Statements and "Results and Discussion of Segment Operations - Electric Operations," in this Management's Discussion.

NiSource Next: In 2020, we launched a comprehensive, multi-year program designed to deliver long-term safety, sustainable capability enhancements and costs optimization improvements. This program advances the high priority we place on safety and risk mitigation, further enables our SMS, and enhances the customer experience. NiSource Next is designed to leverage our current scale, utilize technology, define clear roles and accountability with our leaders and employees, and standardize our processes to focus on operational rigor, quality management and continuous improvement.

In 2021, we optimized our workforce by ~~increases in net revenues~~redefining roles to sharpen our focus on safety and ~~have essentially no impact on net income.~~

~~2018 vs. 2017 Operating Income~~

~~For 2018, Electric Operations reported operating income~~risk mitigation, operational rigor, and adherence to process and procedures, as well as implemented consistent span of ~~$386.1 million, an~~control for leadership to increase individual responsibility and clear accountability. Additionally, we began to make advancements across our operations to improve safety, operational efficiencies, and customer satisfaction through continued standardization of ~~$18.7 million from~~work processes, the ~~comparable 2017 period.~~

~~Net revenues for 2018 were $1,206.1 million, a decrease of $66.5 million from the same period in 2017. The change in net revenues was primarily driven by:~~

~~Lower regulatory and depreciation trackers, which are offset in operating expense, of $35.6 million.~~

~~Decreased rates from~~ implementation of ~~regulatory outcomes~~new mobile technology to provide real-time access to information while serving our customers and enhanced customer self-service options to better meet customer expectations. These enhancements set the foundation for 2022 and beyond, to continue improving safety and customer experience through more significant technology investments.

COVID-19: The safety of our employees and customers, while providing essential services during the ongoing COVID-19 pandemic, is paramount. We continue to take a proactive, coordinated approach intended to prevent, mitigate and respond to COVID-19 by utilizing our Incident Command System (ICS). The ICS includes members of our executive council, a medical review professional, and members of functional teams from across our company. The ICS monitors state-by-state conditions and determines steps to conduct our operations safely for employees and customers.

We have implemented procedures designed to protect our employees who work in the field and who continue to work in operational and corporate facilities, including social distancing and wearing face coverings. We have also implemented work-from-home policies and practices. We continue to employ physical and cybersecurity measures to ensure that our operational and support systems remain functional. Our actions to date have mitigated the spread of COVID-19 amongst our employees and principal field contractors. We are also continuously evaluating changes to CDC guidance, and updating our safety measures accordingly, in order to ensure employee and customer safety during this pandemic. We are following federal, state, and local laws, regulations and guidelines related to the ~~TCJA of $32.9 million.~~COVID-19 vaccinations.

~~Decreased industrial usage of $17.1 million.~~

~~A revenue reserve of $16.2 million in 2018 resulting from~~Since the ~~probable future refund of certain collections from customers as a result~~beginning of the ~~lower income tax rate from~~COVID-19 pandemic, we have been helping our customers navigate this challenging time. We plan to continue our payment assistance programs and customer education and awareness of energy assistance programs such as the ~~TCJA .~~Low Income Home Energy Assistance Program (LIHEAP) to help customers deal with the impact of the pandemic. Regulatory deferrals for certain costs have been allowed by all of our state regulatory commissions.

~~Increased fuel handling costs~~We continue to monitor how COVID-19 is affecting our workforce, customers, suppliers, operations, financial results and cash flow. The extent of ~~$7.3 million.~~the impact in the future will vary and depend on the duration and severity of the impact on the global, national and local economies. For information on the impacts of COVID-19 for the year ended December 31, 2021, the state-specific suspension of disconnections, and COVID-19 regulatory filings see Note 3, ''Revenue Recognition,'' and Note 9, ''Regulatory Matters,'' in the Notes to Consolidated Financial Statements.

~~Partially offset by:~~

~~The effects of warmer weather of $25.2 million.~~

~~Increased rates from infrastructure replacement programs of $18.6 million.~~

~~Operating expenses were $85.2 million lower in 2018 than 2017. This change was primarily driven by:~~

~~Lower regulatory and depreciation trackers, which~~Economic Environment: We are ~~offset in net revenues, of $35.6 million.~~

~~Lower outside service costs of $32.1 million and lower material and supplies costs of $10.2 million primarily~~monitoring risks related to ~~the retirement~~increasing order and delivery lead times for construction and other materials, increasing risk of ~~Bailly Generating Station Units 7 and 8 on May 31, 2018.~~

~~Decreased employee and administrative costs~~unavailability of ~~$18.4 million.~~

~~Partially offset by:~~

~~Increased depreciation of $10.0 million~~materials due to ~~higher capital expenditures placed~~global shortages in ~~service.~~

~~2017 vs. 2016 Operating Income~~

~~For 2017, Electric Operations reported operating income~~raw materials, and risk of ~~$367.4 million, an increase~~decreased construction labor productivity in the event of ~~$66.1 million from~~disruptions in the ~~comparable 2016 period.~~

~~Net revenues for 2017 were $1,272.6 million, an increase~~availability of ~~$106.0 million from the same period in 2016. The change in net revenues was primarily driven by:~~

~~New rates from base-rate proceedings of $63.6 million.~~

~~Increased rates from incremental capital spend on electric transmission projects of $24.2 million.~~

~~Higher regulatory and depreciation trackers, which~~materials. We are ~~offset in operating expense, of $18.0 million.~~

~~New rates from infrastructure replacement programs of $6.0 million.~~

~~The effects of increased customer count of $3.4 million.~~

~~Partially offset by:~~

~~The effects of cooler weather of $16.1 million.~~

~~Operating expenses were $39.9 million higher in 2017 than 2016. This change was primarily driven by:~~

Higher outside service costs of $20.1 million, primarily due to increased spend on strategic initiatives to enhance safety, reliability and customer value, generation-related maintenance, IT service provider transition costs and vegetation management activities.

~~Higher employee and administrative costs of $19.2 million.~~

~~Increased regulatory and depreciation trackers, which are offset in net revenues, of $18.0 million.~~

also seeing increasing prices

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

NISOURCE INC.

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.

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 competitive and attractive appeal for potential recruits. With a focus on workforce planning, we are creating flexible work arrangements where we can, and being anticipatory in evaluating our talent footprint for the future 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 have also seen an increase in gas costs that we expect to have an effect on customer bills. For the year ended December 31, 2021, we have not seen this increase 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."

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, 2021, 2020 and 2019, are presented below:


							Favorable (Unfavorable)
Year Ended December 31, (in millions, except per share amounts)	2021		2020		2019		2021 vs. 2020		2020 vs. 2019
Operating Revenues	$	4,899.6	$	4,681.7	$	5,208.9	$	217.9	$	(527.2)
Operating Expenses
Cost of energy	1,392.3		1,109.3		1,534.8		(283.0)		425.5
Other Operating Expenses	2,500.4		3,021.6		2,783.4		521.2		(238.2)
Total Operating Expenses	3,892.7		4,130.9		4,318.2		238.2		187.3
Operating Income	1,006.9		550.8		890.7		456.1		(339.9)
Total Other Deductions, Net	(300.3)		(582.1)		(384.1)		281.8		(198.0)
Income Taxes	117.8		(17.1)		123.5		(134.9)		140.6
Net Income (Loss)	588.8		(14.2)		383.1		603.0		(397.3)
Net income (loss) attributable to noncontrolling interest	3.9		3.4		—		(0.5)		(3.4)
Net Income (Loss) attributable to NiSource	584.9		(17.6)		383.1		602.5		(400.7)
Preferred dividends	(55.1)		(55.1)		(55.1)		—		—
Net Income (Loss) Available to Common Shareholders	529.8		(72.7)		328.0		602.5		(400.7)
Basic Earnings (Loss) Per Share	$	1.35	$	(0.19)	$	0.88	$	1.54	$	(1.07)
Diluted Earnings (Loss) Per Share	$	1.27	$	(0.19)	$	0.87	$	1.46	$	(1.06)

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 2021 was primarily due to higher operating income for the year ended December 31, 2021 compared to the same period in 2020. Operating revenues were higher due to favorable rate case outcomes in 2021. Operating expenses were lower as we did not have expenses associated with the Massachusetts business in 2021, and the loss on sale of the Massachusetts business was primarily incurred in 2020. 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. In addition, we recognized a favorable change in total other deductions, which was partially offset by an increase in income tax expense in 2021. See below for the primary drivers of this change.

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

NISOURCE INC.

Other Deductions, Net

The change in Other deductions, net in 2021 compared to 2020 is primarily driven by the loss on early extinguishment of debt in 2020, lower long-term and short-term debt interest in 2021 and higher non-service pension benefits partially offset by charitable contributions in 2021. The lower interest in 2021 was due to the early extinguishment of high rate debt in 2020 and lower balances on short-term debt during the year ended December 31, 2021 compared to the same period in 2020. See Note 15, "Long-Term Debt," Note 16, "Short-Term Borrowings," and Note 12, "Pension and Other Postretirement Benefits," in the Notes to the Consolidated Financial Statements for additional information.

Income Taxes

The increase in income tax expense in 2021 compared to the same period in 2020 is primarily attributable to higher pre-tax income, resulting from the items discussed above, 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 are offset by decreased deferred tax expense recognized on the sale of the Columbia of Massachusetts' regulatory liability in 2020, established due to TCJA in 2017, that would have otherwise been recognized over the amortization period and one-time adjustments to deferred tax balances.

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)

NISOURCE INC.

Gas Distribution Operations

Financial and operational data for the Gas Distribution Operations segment for the years ended December 31, 2021, 2020 and 2019, are presented below:


										Favorable (Unfavorable)
Year Ended December 31, (in millions)	2021			2020			2019			2021 vs. 2020		2020 vs. 2019
Operating Revenues	$	3,183.5		$	3,140.1		$	3,522.8		$	43.4	$	(382.7)
Operating Expenses
Cost of energy	962.7			794.2			1,067.6			(168.5)		273.4
Operation and maintenance	993.8			1,138.0			935.7			144.2		(202.3)
Depreciation and amortization	383.0			363.1			403.2			(19.9)		40.1
Impairment of intangible assets	—			—			209.7			—		209.7
Loss on sale of fixed assets and impairments, net	8.7			412.4			0.1			403.7		(412.3)
Other taxes	217.8			233.3			231.1			15.5		(2.2)
Total Operating Expenses	2,566.0			2,941.0			2,847.4			375.0		(93.6)
Operating Income	$	617.5		$	199.1		$	675.4		$	418.4	$	(476.3)
Revenues
Residential	$	2,143.4		$	2,110.6		$	2,317.2		$	32.8	$	(206.6)
Commercial	731.0			679.7			775.1			51.3		(95.4)
Industrial	197.2			213.8			245.8			(16.6)		(32.0)
Off-System	71.3			41.0			77.7			30.3		(36.7)
Other	40.6			95.0			107.0			(54.4)		(12.0)
Total	$	3,183.5		$	3,140.1		$	3,522.8		$	43.4	$	(382.7)
Sales and Transportation (MMDth)
Residential	231.2			249.5			274.9			(18.3)		(25.4)
Commercial	167.0			170.5			189.6			(3.5)		(19.1)
Industrial	507.1			538.1			542.5			(31.0)		(4.4)
Off-System	21.6			23.3			32.9			(1.7)		(9.6)
Other	0.3			0.3			0.3			—		—
Total	927.2			981.7			1,040.2			(54.5)		(58.5)
Heating Degree Days	5,002			5,097			5,375			(95)		(278)
Normal Heating Degree Days	5,427			5,485			5,452			(58)		33
% Warmer than Normal	(8)		%	(7)		%	(1)		%
% Warmer than Prior Year	(2)		%	(5)		%
Gas Distribution Customers
Residential	2,970,157			2,954,478			3,221,178			15,679		(266,700)
Commercial	253,987			253,184			282,778			803		(29,594)
Industrial	4,921			4,968			5,982			(47)		(1,014)
Other	4			3			3			1		—
Total	3,229,069			3,212,633			3,509,941			16,436		(297,308)

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

NISOURCE INC.

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 2021 to 2020 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 2020 Annual Report on Form 10-K for discussion of underlying reasons for changes in our operating revenues and expenses for 2020 versus 2019.


	Favorable (Unfavorable)
Changes in Operating Revenues (in millions)	2021 vs 2020
Revenues associated with the Massachusetts Business in 2020	$	(223.1)
New rates from base rate proceedings and regulatory capital programs	115.9
The effects of customer growth	5.3
Higher revenue due to the effects of resuming common credit mitigation practices	5.0
The effects of weather fluctuations in 2021 compared to 2020	4.8
Other	3.8
Change in operating revenues (before cost of energy and other tracked items)	$	(88.3)
Operating revenues offset in operating expense
Higher cost of energy billed to customers	277.3
Cost of energy associated with the Massachusetts Business in 2020	(108.8)
Operation and maintenance trackers associated with the Massachusetts Business in 2020	(36.8)

Total change in operating revenues	$	43.4

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 decrease in total volumes sold and transported in 2021 compared to 2020 of 54.5 MMDth is primarily attributable to the sale of the Massachusetts Business in 2020.

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)

NISOURCE INC.

Gas Distribution Operations (continued)


	Favorable (Unfavorable)
Changes in Operating Expenses (in millions)	2021 vs 2020
Loss on sale of the Massachusetts Business of $6.8 million in 2021 compared to $412.4 million in 2020	$	405.6
Operating expenses associated with the Massachusetts Business in 2020	202.2
Lower expense related to the NiSource Next initiative in 2021 compared to 2020	3.6
Higher employee and administrative related expenses	(31.7)
Higher depreciation and amortization expense	(27.8)
Higher outside services expenses	(17.3)
Higher unrecoverable environmental remediation costs	(12.7)
Higher other than income taxes primarily related to property tax expense	(12.1)


Other	(3.1)
Change in operating expenses (before cost of energy and other tracked items)	$	506.7
Operating expenses offset in operating revenue
Higher cost of energy billed to customers	(277.3)
Cost of energy associated with the Massachusetts Business in 2020	108.8
Operation and maintenance trackers associated with the Massachusetts Business in 2020	36.8

Total change in operating expense	$	375.0

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, 2021 and 2020 of $6.8 million and $412.4 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 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)

NISOURCE INC.

Electric Operations

Financial and operational data for the Electric Operations segment for the years ended December 31, 2021, 2020 and 2019, are presented below:


										Favorable (Unfavorable)
Year Ended December 31, (in millions)	2021			2020			2019			2021 vs. 2020		2020 vs. 2019
Operating Revenues	$	1,697.1		$	1,536.6		$	1,699.2		$	160.5	$	(162.6)
Operating Expenses
Cost of energy	429.7			315.2			467.3			(114.5)		152.1
Operation and maintenance	493.6			497.6			495.0			4.0		(2.6)
Depreciation and amortization	329.4			321.3			277.3			(8.1)		(44.0)
Gain on sale of fixed assets and impairments, net	(0.9)			—			(0.1)			0.9		(0.1)
Other taxes	57.5			53.7			52.9			(3.8)		(0.8)
Total Operating Expenses	1,309.3			1,187.8			1,292.4			(121.5)		104.6
Operating Income	$	387.8		$	348.8		$	406.8		$	39.0	$	(58.0)
Revenues
Residential	$	568.0		$	527.8		$	481.6		$	40.2	$	46.2
Commercial	534.9			480.3			486.7			54.6		(6.4)
Industrial	494.1			412.9			608.4			81.2		(195.5)
Wholesale	15.7			12.3			11.7			3.4		0.6
Other	84.4			103.3			110.8			(18.9)		(7.5)
Total	$	1,697.1		$	1,536.6		$	1,699.2		$	160.5	$	(162.6)
Sales (Gigawatt Hours)
Residential	3,546.8			3,484.0			3,369.5			62.8		114.5
Commercial	3,698.0			3,550.0			3,760.3			148.0		(210.3)
Industrial	8,253.7			7,480.3			8,466.1			773.4		(985.8)
Wholesale	124.7			83.6			8.2			41.1		75.4
Other	108.5			106.0			117.2			2.5		(11.2)
Total	15,731.7			14,703.9			15,721.3			1,027.8		(1,017.4)
Cooling Degree Days	1,020			900			962			120		(62)
Normal Cooling Degree Days	803			803			803			—		—
% Warmer than Normal	27		%	12		%	20		%
% Warmer (Colder) than prior year	13		%	(6)		%
Electric Customers
Residential	422,436			418,871			415,534			3,565		3,337
Commercial	58,010			57,435			57,058			575		377
Industrial	2,137			2,154			2,256			(17)		(102)
Wholesale	714			722			726			(8)		(4)
Other	2			2			2			—		—
Total	483,299			479,184			475,576			4,115		3,608

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

NISOURCE INC.

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.

~~Increased depreciation~~The underlying reasons for changes in our operating revenues and expenses from 2021 to 2020 are presented in the respective tables below. Please refer to Part II, Item 7, "Management's Discussion and Analysis of ~~$5.6 million due to higher capital expenditures placed~~Financial Condition and Results of Operations - Results and Discussion of Segment Operations - Electric Operations," of the Company's 2020 Annual Report on Form 10-K for discussion of underlying reasons for changes in ~~service.~~our operating revenues and expenses for 2020 versus 2019.

~~Higher materials and supplies costs of $4.5 million driven by generation-related maintenance.~~

~~Partially offset by:~~

~~Plant retirement costs of $22.1 million in 2016.~~

~~Decreased amortization of regulatory assets of $10.8 million.~~


	Favorable (Unfavorable)
Changes in Operating Revenues (in millions)	2021 vs 2020
The effects of warmer weather in 2021 compared to 2020	$	17.4
Increased customer usage	13.9
New rates from regulatory capital and DSM programs	10.4
The effects of customer growth	5.0
Higher revenue due to the effects of resuming common credit mitigation practices	2.9
Increased fuel handling costs	(10.5)
Other	2.6
Change in operating revenues (before cost of energy and other tracked items)	$	41.7
Operating revenues offset in operating expense
Higher cost of energy billed to customers	114.5
Higher tracker deferrals within operation and maintenance, depreciation and tax	4.3
Total change in operating revenues	$	160.5

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~~comparison.

~~Weather~~Sales

The increase in total volumes sold in 2021 compared to 2020 of 1,027.8 GWh was primarily attributable to decreased usage by industrial and commercial customers during the ~~Electric Operations’ territories for 2018~~second and third quarters of 2020 due to COVID-19. There was ~~46% warmer than normal~~no significant variance during the first three months and ~~41% warmer than~~last three months of 2021 compared to the same period in ~~2017, increasing net revenues $25.2 million~~2020.

Commodity Price Impact

Cost of energy for the ~~year ended December 31, 2018 compared to 2017.~~

Weather in the Electric Operations’ territories for 2017 was 4% warmer than normal and 15% cooler than the same period in 2016, decreasing net revenues $16.1 million for the year ended December 31, 2017 compared to 2016.

~~Sales~~

Electric Operations ~~sales were 16,448.0 GWh~~segment is principally comprised of the cost of coal, natural gas purchased for ~~2018, a decrease of 277.6 GWh, or 1.7% compared to 2017. This decrease was primarily attributable to higher~~ internal generation ~~from large industrial customers in 2018, partially offset by increased volumes for residential and commercial customers resulting from warmer weather.~~

~~Electric Operations sales were 16,725.6 GWh for 2017, a decrease~~ of ~~105.6 GWh, or 0.6% compared to 2016.~~

~~BP Products North America.~~ ~~On March 29, 2018, WCE, which is currently owned by BP p.l.c ("BP") and BP Products North America, which operates the BP Refinery, filed a petition~~electricity at ~~the IURC asking that the combined operations of WCE and BP be treated as a single premise,~~NIPSCO, and the WCE generation be dedicated primarily to BP Refinery operations beginning in May 2019 as WCE has self-certified as a qualifying facility at FERC. BP Refinery plans to continue to purchase electric servicecost of power purchased from ~~NIPSCO at a reduced demand level beginning May 2019. Refer to Note 8, "Regulatory Matters," in the Notes to Consolidated Financial Statements for additional information.~~

~~Economic Conditions~~

third-party generators of electricity. NIPSCO has a state-approved recovery mechanism that provides a means for full recovery of prudently incurred fuel costs. ~~Fuel~~The majority of these fuel costs are ~~treated as pass-through costs~~passed through directly to the customer, and ~~have no impact on~~ the ~~net revenues recorded in the period. The~~ fuel costs included in operating revenues are matched with the fuel cost expense recorded in the ~~period and 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)

NISOURCE INC.

Electric Operations (continued)

NIPSCO's performance remains closely linked to the performance of the steel industry. NIPSCO’s MWh sales to steel-related industries accounted for approximately ~~49.67%~~48.1% and ~~54.5%~~45.9% of the total industrial MWh sales for the years ended December 31, ~~2018~~2021 and ~~2017,~~2020, respectively.


	Favorable (Unfavorable)
Changes in Operating Expenses (in millions)	2021 vs 2020
Increased operating expenses related to the retirement of the R.M. Schahfer Generating Station's coal Units 14 and 15	$	(9.5)
Higher depreciation and amortization expense	(6.8)
Higher other than income taxes primarily related to property tax and gross receipts tax expense	(3.8)
Higher employee and administrative expenses	(2.6)

Higher corporate insurance costs	(1.7)
Lower outside services expenses	15.1
Lower environmental costs	8.6


Other	(2.0)
Change in operating expenses (before cost of energy and other tracked items)	$	(2.7)
Operating expenses offset in operating revenue
Higher cost of energy billed to customers	(114.5)
Higher tracker deferrals within operation and maintenance, depreciation and tax	(4.3)
Total change in operating expense	$	(121.5)

Electric Supply and Generation Transition

~~Bailly~~NIPSCO continues to execute on an electric generation transition consistent with the preferred pathway from its 2018 Integrated Resource Plan, which outlines plans to retire its remaining coal-fired generation by 2028, to be replaced by lower-cost, reliable and cleaner options. We expect to have capital investment requirements of approximately $2.0 billion, primarily in 2022 and 2023, to replace the generation capacity of R.M. Schahfer Generating ~~Station.~~ ~~NIPSCO completed the retirement of Units 7 and 8 at Bailly~~Station's coal-fired units. We retired R.M. Schahfer Generating Station Units 14 and 15 on ~~May 31, 2018. These units had a generating capacity of approximately 460 MW.~~October 1, 2021. The remaining ~~net book value of the retired~~two units ~~is presented in "Regulatory assets (noncurrent)" on the Consolidated Balance Sheets. This balance continues~~are still scheduled to be ~~amortized at a rate consistent with its inclusion~~retired in ~~customer rates. The ongoing recovery of our remaining investment in these units will be addressed in NIPSCO's rate case filed on October 31, 2018.~~2023. Refer to Note ~~8, "Regulatory Matters,~~6, "Property, Plant and Equipment," and Note ~~18-E,~~19-F, "Other Matters," in the Notes to Consolidated Financial Statements for ~~additional~~further information.

~~NIPSCO 2018 Integrated Resource Plan.~~ Multiple factors, but primarily economic ones, including low natural gas prices, advancing cost effective renewable technology and increasing capital and operating costs associated with existing coal plants, have led

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

NIS~~OURCE~~ INC.

~~Electric Operations (continued)~~

NIPSCO to conclude in its October 2018 Integrated Resource Plan submission that NIPSCO’s current fleet of coal generation facilities will be retired earlier than previous Integrated Resource Plan’s had indicated.

The Integrated Resource Plan evaluated demand-side and supply-side resource alternatives to reliably and cost effectively meet NIPSCO customers' future energy requirements over the ensuing 20 years. The preferred option within the Integrated Resource Plan retires R.M. Schahfer Generating Station (Units 14, 15, 17, and 18) by 2023 and Michigan City Generating Station (Unit 12) by 2028. These units represent 2,080 MW of generating capacity, equal to 72% of NIPSCO’s remaining capacity after the retirement of Bailly Units 7 and 8 in May of 2018.

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. ~~Refer to Note 18-E, "Other Matters,"~~NIPSCO has sold, and may in the ~~Notes~~future sell, renewable energy credits from this generation to ~~Consolidated Financial Statements~~third parties because this helps keep the cost of energy more affordable for ~~further discussion.~~

our customers. 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. 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)

NISOURCE INC.

NIS~~OURCE~~ INC.

Electric Operations (continued)

The following table summarizes the executed PPAs and BTAs from our generation transition:

Project Name

Transaction Type

Technology

Nameplate Capacity (MW)

Storage Capacity (MW)

IURC Approval

Targeted Construction Completion

Jordan Creek

20 year PPA

Wind

400

—

6/05/2019

In Service (12/10/2020)

Rosewater(1)

BTA

Wind

102

—

8/07/2019

In Service (12/29/2020)

Indiana Crossroads Wind(1)

BTA

Wind

302

—

2/19/2020

In Service (12/17/2021)

Greensboro

20 year PPA

Solar & Storage

100

1/27/2021

Q4 2022

Brickyard

20 year PPA

Solar

200

—

1/27/2021

Q4 2022

Cavalry(2)

BTA

Solar & Storage

200

5/5/2021

Q4 2023

Dunn's Bridge I(2)

BTA

Solar

265

—

5/5/2021

Q4 2022

Dunn's Bridge II(2)

BTA

Solar & Storage

435

5/5/2021

Q4 2023

Green River

20 year PPA

Solar

200

—

5/5/2021

Q2 2023

Gibson

22 year PPA

Solar

280

—

6/29/2021

Q2 2023

Fairbanks(2)

BTA

Solar

250

—

6/29/2021

Q3 2023

Indiana Crossroads Solar(2)

BTA

Solar

200

—

7/28/2021

Q4 2022

Elliott(2)

BTA

Solar

200

—

7/28/2021

Q2 2023

Indiana Crossroads II

15 year PPA

Wind

204

—

9/1/2021

Q4 2023

(1) Refer to Note 4, "Variable Interest Entities," in the Notes to Consolidated Financial Statementsfor additional information.

(2) Ownership of the facilities will be transferred to joint ventures whose members include NIPSCO and an unrelated tax equity partner.

To date, we have been informed of potential delays related to renewable energy projects, including delays related to the delivery of solar panels, local permitting processes and obtaining interconnection rights. The potential delays to solar panel deliveries relate to the U.S. Department of Homeland Security's June 24, 2021 Withhold Release Order on silica-based products made by Hoshine Silicon Industry Co., Ltd. For all affected projects, the sellers have informed us that they are working diligently to mitigate potential impacts and determine recovery plans, where applicable, in order to minimize potential delays or failures to perform under the agreements. We are also evaluating what, if any, additional flexibility can be afforded to the sellers under these agreements to aid in mitigating, or minimizing, potential delays or failures to perform under the agreements. We, along with the sellers of these generation projects, are continuously evaluating potential impacts to the targeted completion date of each project. At this time, the impact of any delays to materials, permitting or interconnection on the targeted completion dates has not been determined but could include a delay in the financial return of certain investments and timing of our electric generation transition.

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

NISOURCE INC.

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 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. 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, 2021, the ATM program (including the impact of the forward sale agreement) had approximately $300.0 million of equity available for issuance. On April 19, 2021, we completed the sale of 8.625 million Equity Units, which provided net proceeds of $835.5 million, after underwriting and issuance costs. We intend to use the net proceeds from the offering for renewable generation investments and general corporate purposes, including additions to working capital and repayment of existing indebtedness. 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 2022 and beyond.

Greater Lawrence ~~Incident:~~ Incident. As discussed in ~~the "Executive Summary"~~Part I, Item 1A, "Risk Factors," and in Note ~~18, “Other~~19, "Other Commitments and Contingencies,~~” we have recorded losses associated with~~" 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 ~~and~~will not continue to have invested capital to replace the entire affected 45-mile cast iron and bare steel pipeline system that delivers gas to the impacted area. As discussed in the Executive Summary and Note 18 referenced earlier in this paragraph, and Part I, Item 1A “Risk Factors,” in this report, we may incur additional expenses and liabilities in excess ofan adverse impact on our recorded liabilities and estimated additional costs associated with the Greater Lawrence Incident. The timing and amount of future financing needs arising from the Greater Lawrence Incident, if any, will depend on the ultimate timing and amount of payments made in connection with the Greater Lawrence Incident and the timing and amount of associated insurance recoveries.cash flows. Through income generated from operating activities, amounts available under ~~our~~the short-term revolving credit facility, ~~commercial paper program, accounts receivable securitization facilities, term loan borrowings, long-term debt agreements~~ and our ability to access ~~the~~ capital markets, we believe ~~there is~~we have adequate capital available to ~~fund these expenditures.~~settle remaining anticipated claims associated with the Greater Lawrence Incident.

Operating Activities

Net cash from operating activities for the year ended December 31, ~~2018~~2021 was ~~$540.1~~$1,217.9 million, ~~a decrease~~an increase of ~~$202.1~~$113.9 million from ~~2017.~~2020. This ~~decrease~~increase was primarily driven by cash spend for the Greater Lawrence Incident in 2018 offset by decreased pension plan contributions as discussed below as well as decreased operation and maintenance expenses (excluding expenses related to the Greater Lawrence Incident). Thea year over year decrease in cash from operations was further offset by higher sales due to colder weather during the 2018 winter heating season compared to 2017 and increased rates from infrastructure replacement programs and rate case outcomes.

~~Greater Lawrence Incident. During 2018, we paid approximately $731 million in operating cash flow~~net payments related to the Greater Lawrence Incident. ~~Refer~~During 2021, we paid $15.6 million compared to ~~Note 18-E "Other Matters" for further information.~~

~~Pension and Other Postretirement Plan Funding. In 2017, we contributed $282.3~~$226.7 million ~~to our pension plans (including a $277 million discretionary contribution made~~of payments during the ~~third quarter~~same period in 2020. This was offset by increased cash outflows related to inventory balances primarily due to lower purchasing and prices in 2020 as well as decreased cash inflows related to the under collection of ~~2017)~~gas and ~~$31.6 million to our other postretirement benefit plans.~~fuel costs.

In 2018, we contributed $2.9 million to our pension plans and $21.0 million to our other postretirement benefit plans. Given the current funded status of the pension plans, and barring unforeseen market volatility that may negatively impact the valuation of our plan assets, we do not believe additional material contributions to our pension plans will be requiredInvesting Activities

Net cash used for investing activities for the ~~foreseeable future.~~

~~Income Taxes.~~ ~~Rates for~~year ended December 31, 2021 was $2,204.9 million, an increase of $1,325.8 million from 2020. In 2020, our ~~regulated customers include provisions for the collection of U.S. federal income taxes. The reduction in the U.S. federal corporate income tax rate~~investing outflows were lower by $1,115.9 million as a result of proceeds from the ~~TCJA has led~~sale of the Massachusetts Business. Our current year investing activities were comprised of capital expenditures related to a decrease in the amount billed to customers through rates, ultimately resulting in lower cash collections from operating activities. As discussed in further detail in Note 7, "Regulatory Matters," in the Notessystem growth and reliability and payments made to the Consolidated Financial Statements, our regulated subsidiaries are engaged with the relevant state utility commissions to address the impacts of the TCJA on future customer rates. During 2018, billings to customers decreased approximately $57.6 million compared to the same period in 2017 as a result of adjustments to certain rates in our Kentucky, Ohio, Maryland, Pennsylvania, Massachusetts and Indiana jurisdictions. Additionally, during 2018, we recorded additional TCJA-related regulatory liabilities related to 2018 collections from customers, which are being refunded back to customers once new customer rates are approved by our regulators.

In addition, we will be required to pass back to customers “excess deferred taxes” which represent amounts collected from customers in the past to cover deferred tax liabilities which, as a result of the passage of the TCJA, are now less than the originally billed amounts. Approximately $1.5 billion of excess deferred taxes was recorded to "Regulatory liabilities (noncurrent)" on the Consolidated Balance Sheets as of December 31, 2017 as a result of implementing the TCJA. The majority of this balance related to temporary book-to-tax differences on utility property protected by IRS normalization rules. As modified rates are approved by eachdevelopers of our regulators, we expect this portion of the balance will be passed back to customers over the remaining average useful life of the associated property as required by the TCJA. The pass back period for the remainder of this balance will be determined by our state utility commissions in future proceedings. Our estimate of the amount and pass-back period of excess deferred taxes is subject to change pending final review by the utility commissions of the states in which we operate. As noted above, this pass back of excess deferred taxes has already begun in certain of our jurisdictions. As of December 31, 2018 we have approximately $1.4 billion of remaining regulatory liabilities associated with excess deferred taxes. See Note 8, "Regulatory Matters," for additional information.renewable generation assets.

As of December 31, 2018, we had a recorded deferred tax asset of $759.6 million related to a federal NOL carryforward, of which $508.5 million relates to years prior to the implementation of the TCJA. As a result of being in an NOL position, we were not

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

NISOURCE INC.

NIS~~OURCE~~ INC.

required to make any cash payments for federal income tax purposes during the three years ended December 31, 2018. The carryforward periods for pre-TCJA tax benefits expire in various tax years from 2028 to 2037, however, we expect to fully utilize the carryforward benefit prior to its expiration. Per the TCJA, utilization of NOL carryforwards generated after December 31, 2017 do not expire, but are limited to 80% of current year taxable income. Accordingly, we may be required to make cash payments for federal income taxes in future years despite having NOL carryforwards in excess of current taxes payable.

~~Investing Activities~~

~~Our cash used for investing activities varies year over year primarily as a result of changes in the level of annual capital expenditures.~~ Capital Expenditures. The table below reflects actual capital expenditures and certain other investing activities by segment for ~~2018, 2017 and 2016.~~2021.


	Actual
(in millions)	2021
Gas Distribution Operations
System Growth and Tracker	$	1,060.8
Maintenance	235.6
Total Gas Distribution Operations(1)	1,296.4
Electric Operations
System Growth and Tracker	248.6
Maintenance	172.0
Generation Transition Investments	62.5
Total Electric Operations(1)	483.1
Corporate and Other Operations - Maintenance(1)	160.9
Total(2)	$	1,940.4

(in millions) 2018 2017 2016
Gas Distribution Operations
System Growth and Tracker $ 1,073.7
$ 909.2
$ 835.0
Maintenance 241.6
216.4
219.4
Total Gas Distribution Operations 1,315.3
1,125.6
1,054.4
Electric Operations
System Growth and Tracker 346.0
435.3
314.1
Maintenance 153.3
157.1
106.5
Total Electric Operations 499.3
592.4
420.6
Corporate and Other Operations - Maintenance⁽¹⁾
—
35.8
15.4
Total⁽²⁾
$ 1,814.6

$ 1,753.8

$ 1,490.4

⁽¹⁾~~Zero~~Amounts differ from those presented in Note 23, "Segments of Business," in the Notes to Consolidated Financial Statements due to the allocation of Corporate and Other ~~capital expenditures in 2018 driven by~~Maintenance Costs to the ~~leasing of IT assets beginning in Q1 2018 versus historical practice of purchasing.~~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.

~~For 2018,~~We expect to make capital ~~expenditures~~investments totaling approximately $10 billion during the 2021-2024 period, comprised of annual investments of $1.9 to $2.2 billion for growth, safety and ~~certain~~reliability, and an additional $2.0 billion in renewable generation to replace the retiring coal-fired generation capacity of Schahfer Generating Station.

The following graph illustrates, in billions, the midpoint of forecasted capital investments by expected recovery period for the next three years:

Regulatory Capital Programs. We replace pipe and modernize our gas infrastructure to enhance safety and reliability by reducing leaks, which subsequently reduces GHG emissions. In 2021, 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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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)

NISOURCE INC.

The following table describes the most recent vintage of our regulatory programs to recover infrastructure replacement and other ~~investing activities were $1,814.6 million, which was $60.8 million higher than the 2017 capital program. This increased spending is due~~federally mandated compliance investments currently in ~~part~~rates or pending commission approval:


(in millions)
Company	Program	Incremental Revenue		Incremental Capital Investment		Investment Period	Costs Covered(1)	Rates Effective
Columbia of Ohio	IRP - 2021	$	22.2	$	212.6	1/20-12/20	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 2021
Columbia of Ohio	CEP - 2021	$	18.0	$	177.2	1/20-12/20	Assets not included in the IRP.	September 2021
NIPSCO - Gas	TDSIC 3	$	0.2	$	52.1	1/21-6/21	New or replacement projects undertaken for the purpose of safety, reliability, system modernization or economic development.	January 2022
NIPSCO - Gas	FMCA 7	$	0.5	$	32.8	4/21-9/21	Project costs to comply with federal mandates.	April 2022

Columbia of Virginia(2)	SAVE - 2022	$	4.0	$	63.0	1/22-12/22	Replacement projects that (1) enhance system safety or reliability, or (2) reduce, or potentially reduce, greenhouse gas emissions.	January 2022
Columbia of Kentucky	SMRP - 2021	$	2.6	$	40.0	1/21-12/21	Replacement of mains and inclusion of system safety investments.	May 2021
Columbia of Maryland	STRIDE - 2022	$	1.3	$	17.5	1/22-12/22	Pipeline upgrades designed to improve public safety or infrastructure reliability.	January 2022
NIPSCO - Electric(3)	TDSIC - 9	$	0.2	$	42.7	2/21-5/21	New or replacement projects undertaken for the purpose of safety, reliability, system modernization or economic development.	February 2022

(1)Programs do not include any costs already included in base rates.

(2)Columbia of Virginia filed its application to ~~costs associated~~amend and extend its SAVE program with the ~~Greater Lawrence Incident pipeline replacement, gas transmission projects, environmental~~Virginia SCC on August 12, 2021, requesting approval of a two-year SAVE program for calendar years 2022-2023 that includes incremental capital investments of $63.0 million and ~~system modernization projects.~~$72.0 million, respectively. The Commission approved the Company's application in its December 6, 2021 Order Approving SAVE Rider.

~~For 2017, capital expenditures~~(3)On April 1, 2021, NIPSCO filed a notice with the IURC that it intended to terminate its current Electric TDSIC plan effective May 31, 2021. 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. NIPSCO filed the TDSIC-9 petition on September 28, 2021, and ~~certain other investing activities were $1,753.8 million, which was $263.4 million higher than~~received an order on January 26, 2022 approving TDSIC-9.

Refer to Note 9, "Regulatory Matters," in the ~~2016 capital program. This increased spending is mainly due~~Notes to ~~electric transmission projects, environmental investments and system modernization projects.~~Consolidated Financial Statements for a further discussion of regulatory developments during 2021.

For 2019, we project to invest approximately $1.6 to $1.7 billion in our capital program. This projected level of spend is consistent with 2018 spend levels and is expected to focus primarily on the continuation of the modernization projects, segment growth across the Gas Distribution Operations segment, and TDSIC spend.

Financing Activities

~~Short-term Debt.~~Common Stock, Preferred Stock and Equity Unit Sale. Refer to Note ~~15, “Short-Term~~13, ''Equity,'' in the Notes to Consolidated Financial Statements for information on common stock, preferred stock and equity units activity.

Short-term Debt and Sale of Trade Accounts Receivables. 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 ~~14, “Long-Term~~15, "Long-Term Debt,”" in the Notes to Consolidated Financial Statements for information on long-term debt.

~~Net Available Liquidity.~~ ~~As of December 31, 2018, an aggregate of $974.6 million of net liquidity was available, including cash and credit available under~~Non-controlling Interest. Refer to Note 4, "Variable Interest Entities," in the ~~revolving credit facility and accounts receivable securitization programs.~~

Notes to Consolidated Financial Statements for information on contributions from noncontrolling interest activity.

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

NISOURCE INC.

NIS~~OURCE~~ INC.

Sources of Liquidity

The following table displays ~~NiSource's~~our liquidity position as of December 31, ~~2018~~2021 and ~~2017:~~2020:


Year Ended December 31, (in millions)	2021		2020
Current Liquidity
Revolving Credit Facility	$	1,850.0	$	1,850.0
Accounts Receivable Programs(1)	251.2		273.3
Less:
Commercial Paper	560.0		503.0

Letters of Credit Outstanding Under Credit Facility	18.9		15.2
Add:
Cash and Cash Equivalents	84.2		116.5
Net Available Liquidity	$	1,606.5	$	1,721.6

Year Ended December 31, (in millions)
2018 2017
Current Liquidity
Revolving Credit Facility $ 1,850.0
$ 1,850.0
Accounts Receivable Program⁽¹⁾
399.2
336.7
Less:
Commercial Paper 978.0
869.0
Accounts Receivable Program Utilized 399.2
336.7
Letters of Credit Outstanding Under Credit Facility 10.2
11.1
Add:
Cash and Cash Equivalents 112.8
29.0
Net Available Liquidity $ 974.6
$ 998.9

⁽¹⁾Represents the lesser of the seasonal limit or maximum borrowings supportable by the underlying receivables. Our accounts receivable programs' utilization was zero as of December 31, 2021 and 2020.

Debt Covenants. We are subject to a financial covenant under our revolving credit facility, ~~and term loan agreement,~~ which requires us to maintain a debt to capitalization ratio that does not exceed 70%. ~~A similar covenant in a 2005 private placement note purchase agreement requires us to maintain a debt to capitalization ratio that does not exceed 75%.~~ As of December 31, ~~2018,~~2021, the ratio was ~~61.4%~~57.4%.

~~Sale of Trade Accounts Receivables~~. ~~Refer to Note 17, “Transfers of Financial Assets,” in the Notes to Consolidated Financial Statements for information on the sale of trade accounts receivable.~~

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 ~~certain of our subsidiaries'~~NIPSCO's credit ratings and ratings outlook as of December 31, ~~2018.~~2021. 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+

~~Negative~~Stable

Baa2

Stable

BBB

Stable

NIPSCO

BBB+

~~Negative~~

Stable

Baa1

Stable

BBB

Stable

~~Columbia of Massachusetts~~

~~BBB+~~

~~Negative~~

~~Baa2~~

~~Stable~~

~~Not rated~~

Commercial Paper

A-2

~~Negative~~

Stable

P-2

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, ~~2018, the~~2021, a collateral requirement ~~that~~of approximately $56.2 million would be required in the event of a downgrade below ~~the ratings trigger levels would amount to approximately $53.8 million.~~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 ~~420,000,000~~620,000,000 shares, $0.01 par value, of which ~~400,000,000~~600,000,000 are common stock and 20,000,000 are preferred stock. As of December 31, ~~2018, 372,363,656~~2021, 405,303,023 shares of common stock and ~~420,000~~1,302,500 shares of preferred stock were outstanding. For more information regarding our common and preferred stock, see Note ~~12,~~13, "Equity," in the Notes to Consolidated Financial Statements.

Contractual Obligations, Cash Requirements and Off-Balance Sheet Arrangements

We have certain contractual obligations requiring payments at specified periods. Our material cash requirements are detailed below. We intend to use funds from the liquidity sources referenced above to meet these cash requirements.

Our calculated estimated interest payments for long-term debt are based on the stated coupon and payment dates. For 2022, we project that we will be required to make interest payments of approximately $338.5 million, which includes $335.7 million of interest payments related to our long-term debt outstanding as of December 31, 2021. At December 31, 2021, we had $560.0 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.

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

NISOURCE INC.

NIS~~OURCE~~ INC.

During 2022 and 2023, we expect to make cash payments of $610.5 million and $366.0 million, respectively, related to pipeline service obligations including demand for gas transportation, gas storage and gas purchases.

~~Contractual Obligations~~.We expect to 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 outsourcingcapital investment requirements of ~~IT services. The total contractual obligations in existence at December 31, 2018 and their maturities were:~~

(in millions) Total 2019 2020 2021 2022 2023 After
Long-term debt ⁽¹⁾
$ 7,029.6
$ 41.0
$ —
$ 63.6
$ 530.0
$ 600.0
$ 5,795.0
Capital leases⁽²⁾
322.4
23.0
22.5
22.6
22.1
19.8
212.4
Interest payments on long-term debt 6,311.7
319.8
318.6
318.6
315.0
289.0
4,750.7
Operating leases⁽³⁾
45.9
11.0
7.3
6.1
4.2
2.8
14.5
Energy commodity contracts 154.3
99.2
55.1
—
—
—
—
Service obligations:
Pipeline service obligations 3,566.7
592.3
487.7
450.5
437.5
260.8
1,337.9
IT service obligations 211.0
68.3
60.0
47.1
35.6
—
—
Other service obligations 86.7
33.5
43.6
9.6
—
—
—
Other liabilities 24.2
24.2
—
—
—
—
—
Total contractual obligations $ 17,752.5
$ 1,212.3
$ 994.8
$ 918.1
$ 1,344.4
$ 1,172.4
$ 12,110.5

⁽¹⁾ ~~Long-term debt balance excludes unamortized issuance costs and discounts of $68.5 million.~~

⁽²⁾ ~~Capital lease payments shown above are inclusive of interest totaling $114.6 million.~~

⁽³⁾Operating lease balances do not include amounts for fleet leases that can be renewed beyond the initial lease term. The Company anticipates renewing the leases beyond the initial term, but the anticipated payments associated with the renewals do not meet the definition of expected minimum lease payments and therefore are not included above. Expected payments are $26.7 million in 2019, $22.4 million in 2020, $16.6 million in 2021, $12.3 millionapproximately $2.0 billion, primarily in 2022 ~~$9.3 million~~and 2023, to replace the generation capacity of all R.M. Schahfer Generating Station's coal-fired units. These investments include our portion of the joint venture obligations including construction milestone payments included in ~~2023 and $8.8 million thereafter.~~

~~Our calculated estimated interest payments for long-term debt is based on~~ the stated coupon and payment dates. For 2019, we project that we will be required to make interest payments of approximately $363.1 million, which includes $319.8 million of interest payments related to our long-term debt outstanding as of December 31, 2018. At December 31, 2018, we had $1,977.2 million in short-term borrowings outstanding.agreements.

Our expected payments ~~included within “Other liabilities” in the table of contractual commitments above contains~~include employer contributions to pension and other postretirement benefits plans expected to be made in ~~2019.~~2022. Plan contributions beyond ~~2019~~2022 are dependent upon a number of factors, including actual returns on plan assets, which cannot be reliably estimated at this time. In ~~2019,~~2022, we expect to make contributions of approximately ~~$3.0~~$2.8 million to our pension plans and approximately ~~$20.6~~$21.5 million to our postretirement medical and life plans. Refer to Note ~~11, “Pension~~12, "Pension and Other Postretirement 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~~"Total Other ~~Liabilities”~~Liabilities" on the Consolidated Balance ~~Sheets, other than those described above.~~Sheets.

We also have obligations associated with income, property, gross receipts, franchise, ~~payroll,~~ sales and use, and various other taxes and expect to make tax payments of approximately ~~$240.6~~$291.1 million in ~~2019,~~2022. In addition, we have uncertain income tax positions for which we are ~~not included in~~unable to predict when the ~~table above.~~

matters will be resolved. Refer to Note ~~18-A, “Contractual Obligations,”~~11, "Income Taxes," in the Notes to Consolidated Financial Statements for ~~further~~more information.

~~In January 2019,~~ NIPSCO has executed ~~two 20 year~~several PPAs to purchase 100% of the output from renewable generation facilities at a fixed price per ~~mwh and a BTA~~MWh. NIPSCO has also executed several BTAs with ~~a developer~~developers to construct a renewable generation ~~facility. Payments under these agreement are not included in the table above as these agreements were executed in 2019~~facilities. See Note 19-A, "Contractual Obligations," and ~~remain subject to approval by the relevant regulatory authorities before the deals would commence. See 18-E.~~Note 19-F, "Other Matters - ~~NIPSCO 2018 Integrated Resource Plan,~~Generation Transition," in the Notes to Consolidated Financial Statements for additional information.

~~Off-Balance Sheet Arrangements~~

~~We,~~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 ~~18, “Other~~19, "Other Commitments and Contingencies,”" in the Notes to Consolidated Financial Statements for additional information ~~about such~~regarding our contractual obligations over the next 5 years and thereafter and our off-balance sheet arrangements.

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 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

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.

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. We continue to monitor the implementation of final and proposed legislation and regulations, including the Infrastructure Investment and Jobs Act, Build

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

NISOURCE INC.

NIS~~OURCE~~ INC.

Back Better legislation and the EPA's proposed methane regulations for the oil and natural gas industry, but we cannot predict their final form or impact on our business at this time.

On July 8, 2019, the EPA published the final ACE rule, which establishes emission guidelines for states to use when developing plans to limit carbon dioxide at coal-fired electric generating units based on heat rate improvement measures. The U.S. Court of Appeals for the D.C. Circuit vacated and remanded the rule on January 19, 2021. On October 29, 2021, the U.S. Supreme Court agreed to review the scope of the EPA’s authority to impose GHG emission standards under the Clean Air Act. We will continue to monitor this matter.

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.

In 2021, the Maryland Commission of Climate Change published a Building Energy Transition Plan. Policy recommendations included in this plan, such as the adoption of an all-electric construction code, are supported by the Commission but do not necessarily reflect current state policy. The report is intended to guide Maryland policy makers on decisions related to reducing GHG emissions from buildings in pursuit of achieving targets in Maryland's 2030 Greenhouse Gas Reduction Act Plan and the Commission's recommendation that Maryland achieve net-zero emissions by 2045. Columbia of Maryland will continue to monitor this matter, but we cannot predict its final impact on our business at this time.

In response to these transition risks, we continue to actively implement our plans to reduce Scope 1 GHG emissions by 90% from 2005 levels by 2030, and to significantly reduce methane emissions, a component of Scope 1 GHG emissions. These plans include the retirement of coal-fired electric generation, increased sourcing of renewable energy, and methane reductions from priority pipeline replacement, traditional leak detection and repair, and deployment of advanced leak detection and repair. As discussed above in this 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. We expect to have capital investment requirements of approximately $2.0 billion, primarily in 2022 and 2023, to replace the generation capacity previously supplied by R.M. Schahfer. We continue to expect to retire Michigan City Generating Station between 2026 and 2028. The preferred path of the 2021 Integrated Resource plan outlined new generation investments estimated to be up to $750 million, and we are currently evaluating future projects in line with the preferred path.

Additionally, we are active in several efforts to accelerate the development and demonstration of lower-carbon energy technologies and resources, such as hydrogen and renewable natural gas (RNG), to enable affordable pathways to economy-wide decarbonization.

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. ~~Risk management for us is~~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

~~We are exposed to~~Our Gas and Electric Operations have commodity price risk ~~as a result~~primarily related to the purchases of ~~our subsidiaries’ operations involving~~ 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 regulations allow recovery of prudently incurred purchased power, fuel and gas

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NISOURCE INC.

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 ~~states should explore additional regulatory reform,~~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.

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 9,10, "Risk Management Activities," in the Notes to the Consolidated Financial Statements for further information on our commodity price risk assets and liabilities as of December 31, ~~2018~~2021 and ~~2017.~~2020.

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 loan borrowings~~ 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 ~~$13.3~~$3.1 million and ~~$15.8~~$12.3 million for ~~2018~~2021 and ~~2017,~~2020, 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 9,10, "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, ~~2018~~2021 and ~~2017.~~2020.

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 ~~are~~ 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 closely monitor the financial status of our banking credit providers. 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.

Certain individual state regulatory commissions instituted regulatory moratoriums in connection with the COVID-19 pandemic that impacted our ability to pursue our credit risk mitigation practices for customer accounts receivable. Following the issuances of these moratoriums, certain of our regulated operations have been authorized to recognize a regulatory asset for bad debt costs above levels currently in rates. We have now resumed our common credit mitigation practices in all jurisdictions as these moratoriums have expired. See the COVID-19 discussion in Part I, Item 1A, "Risk Factors" for risks that have been identified related to the pandemic and refer to Note 9, "Regulatory Matters," in the Notes to Consolidated Financial Statements for state specific regulatory moratoriums.

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

NIS~~OURCE~~ INC.

Other Information

Critical Accounting Policies and Estimates

We apply certain accounting policies ~~based on the accounting requirements discussed below~~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:

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

NISOURCE INC.

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 ~~$2,237.5~~$2,492.2 million and ~~$2,660.0~~$1,980.0 million at December 31, ~~2018,~~2021, and ~~$1,801.2~~$1,930.5 million and ~~$2,795.6~~$2,065.5 million at December 31, ~~2017,~~2020, respectively. For additional information, refer to Note 8,9, “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 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. ~~Regulatory assets requiring specific regulatory action amounted to $320.4 million at December 31, 2018.~~ If we determine that the amounts included as regulatory assets ~~were not~~are no longer recoverable, a charge to income would immediately be required to the extent of the unrecoverable amounts.

~~The passage~~One of the ~~TCJA into law necessitated~~more significant items recorded through the ~~remeasurement of our deferred income tax balances to reflect the new U.S. corporate income tax rate of 21%. For our regulated entities, substantially all of the impact~~application of this ~~remeasurement was recorded~~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 joint ventures 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 ~~asset or regulatory liability, as appropriate, until such time that we receive final regulatory orders prescribing~~deferral of certain amounts representing the ~~required accounting treatment~~timing difference between the profit earned from the joint ventures and ~~related impact on future customer rates.~~the amount included in regulated rates to recover our approved investments in consolidated joint ventures. For additional information, refer to Note ~~10, "Income Taxes,~~1-S, "VIEs and Allocation of Earnings," in the Notes to Consolidated Financial Statements.

Equity Unit Transactions. 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 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.

~~As discussed~~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 ~~Note 18-E, "Other Matters - Greater Lawrence Pipeline Replacement," we incurred approximately $167 million~~impacts to net income through the recognition of ~~capital spend for pipeline replacement~~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 ~~affected communities during 2018.~~ computation of EPS.

We ~~estimate~~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 ~~replacement work will cost between $220 million and $230 million~~guidance would result in ~~total. Columbia of Massachusetts has provided notice~~materially different financial results. See Note 13, "Equity," in the Notes to ~~its property insurer~~Consolidated Financial Statements for additional details of the Greater Lawrence Incident and discussions around the claim and recovery have commenced. The recovery of any capital investment not reimbursed through insurance will be addressed in a future regulatory proceeding. The outcome of such a proceeding is uncertain. In accordance with ASC 980-360, if it becomes probable that a portion of the pipeline replacement cost will not be recoverable through customer rates and an amount can be reasonably estimated, we will reduce our regulated plant balance for the amount of the probable disallowance and record an associated charge to earnings. This could result in a material adverse effect to our financial condition, results of operations and cash flows. Additionally, if a rate order is received allowing recovery of the investment with no or reduced return on investment, a loss on disallowance may be required.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

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

NISOURCE INC.

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.

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

NIS~~OURCE~~ INC.

The discount rates, expected long-term rates of return on plan assets, health care cost trend rates and mortality rates are critical assumptions. Methods used to develop these assumptions are described below. While a third party actuarial firm assists with the development of many of these assumptions, we are ultimately responsible for selecting the final assumptions.

The discount rate is utilized principally in calculating the actuarial present value of pension and other postretirement benefit obligations and net periodic pension and other postretirement benefit plan costs. Our discount rates for both pension and other postretirement benefits are determined using spot rates along an AA-rated above median yield curve with cash flows matching the expected duration of benefit payments to be made to plan participants.

The expected long-term rate of return on plan assets is a component utilized in calculating annual pension and other postretirement benefit plan costs. We estimate the expected return on plan assets by evaluating expected bond returns, equity risk premiums, target asset allocations, the effects of active plan management, the impact of periodic plan asset rebalancing and historical performance. We also consider the guidance from our investment advisors in making a final determination of our expected rate of return on assets.

For measurement of ~~2019~~2021 net periodic benefit cost, we selected an expected pre-tax long-term rate of return of ~~6.10%~~5.20% and ~~5.80%~~5.50% 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 ~~use the Society of Actuaries’ most recently published mortality data in developing~~utilize a ~~best estimate of mortality as part of the calculation of the pension and other postretirement benefit obligations.~~

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

Impact on December 31, 2018 Projected Benefit Obligation Increase/(Decrease)
Change in Assumptions (in millions)
Pension Benefits Other Postretirement Benefits
+50 basis points change in discount rate $ (79.6 ) $ (23.6 )
-50 basis points change in discount rate 86.2
25.8
+50 basis points change in health care trend rates 12.5
-50 basis points change in health care trend rates (11.0 )

Impact on 2018 Expense Increase/(Decrease)⁽¹⁾
Change in Assumptions (in millions)
Pension Benefits Other Postretirement Benefits
+50 basis points change in discount rate $ (3.3 ) $ (0.7 )
-50 basis points change in discount rate 2.8
0.8
+50 basis points change in expected long-term rate of return on plan assets (10.3 ) (1.3 )
-50 basis points change in expected long-term rate of return on plan assets 10.3
1.3
+50 basis points change in health care trend rates 0.6
-50 basis points change in health care trend rates (0.5 )

⁽¹⁾~~Before labor capitalization and regulatory deferrals.~~

~~Table of Contents~~

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

NIS~~OURCE~~ INC.

~~In January 2017, we changed the method used~~full yield curve approach to estimate the service and interest components of net periodic benefit cost for pension and other postretirement benefits. This change, compared to the previous method, resulted in a decrease in the actuarially-determined service and interest cost components. Historically, we estimated service and interest cost utilizing a single weighted-average discount rate derived from the yield curve used to measure the benefit obligation at the beginning of the period. For fiscal 2017 and beyond, we now utilize a full yield curve approach to estimate these componentsbenefits 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 ~~11,~~12, “Pension and Other Postretirement Benefits,” in the Notes to Consolidated Financial Statements.

~~Goodwill.~~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. Due to the ongoing COVID-19 pandemic, we adjusted our mortality assumption through 2023 to reflect anticipated slow recovery.

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


	Impact on December 31, 2021 Projected Benefit Obligation Increase/(Decrease)
Change in Assumptions (in millions)	Pension Benefits		Other Postretirement Benefits
+50 basis points change in discount rate	$	(80.0)	$	(27.7)
-50 basis points change in discount rate	84.8		30.3



	Impact on 2021 Expense Increase/(Decrease)(1)
Change in Assumptions (in millions)	Pension Benefits		Other Postretirement Benefits
+50 basis points change in discount rate	$	(1.6)	$	(0.8)
-50 basis points change in discount rate	1.6		0.8
+50 basis points change in expected long-term rate of return on plan assets	(9.9)		(1.4)
-50 basis points change in expected long-term rate of return on plan assets	9.9		1.4

(1)Before labor capitalization and regulatory deferrals.

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

NISOURCE INC.

Goodwill and Other Intangible Assets. We have ~~seven~~six goodwill reporting units, comprised of the ~~seven~~six state operating companies within the Gas Distribution Operations reportable segment. Our goodwill assets at December 31, ~~2018~~2021 were ~~$1,690.7~~$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 ~~most recently finalized as of~~performed on May 1, 2018. In the third quarter of 2018, we determined the Greater Lawrence Incident represented a triggering event that required an impairment analysis of goodwill. The incident specifically impacts our Columbia of Massachusetts reporting unit. The quantitative impairment analysis as of September 30, 2018 determined the fair value of Columbia of Massachusetts reporting unit continued to exceed its carrying value. For additional information, refer to Note 6, "Goodwill and Other Intangible Assets," in the Notes to Consolidated Financial Statements.

We completed a quantitative ("step 1") fair value measurement of our reporting units during the May 1, 2016 goodwill test. Consistent with our historical impairment testing of goodwill, fair value of the reporting units was determined based on a weighting of income and market approaches. These approaches require significant judgments including appropriate long-term growth rates and discount rates for the income approach and appropriate multiples of earnings for peer companies and control premiums for the market approach.2021. A qualitative ("step 0") test was completed on May 1, ~~2018. We~~2021 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 ~~in our~~as compared to their baseline May 1, ~~2016 test.~~2020 "step 1" fair value measurement. The results of this assessment indicated 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; 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.

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 ~~its reporting unit fair values are less than the reporting unit carrying values and no impairments are necessary.~~

The discount rates were derived using peer company data compiled with the assistance of a third party valuation services firm. The discount rates used are subject to change based on changes in tax rates at both the state and federal level, debt and equity ratios at each reporting unit and general economic conditions.

The long-term growth rate was derived by evaluating historic growth rates, new business and investment opportunities beyond the near term horizon. The long-term growth rate is subject to change depending on inflationary impacts to the U.S. economy and the individual business environments in which each reporting unit operates.

~~The May 1, 2016 test indicated~~ the fair value of ~~each~~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 ~~reporting units~~assumptions could potentially result in the recording of an impairment that ~~carry or~~could have significant impacts on the Consolidated Financial Statements.

See Note 7, "Goodwill and Other Intangible Assets," 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 allocated goodwill exceeded their carrying values, indicating that no impairment existed under the step 1 annual impairment test. If the estimates of free cash flow used in this step 1 analysis had been 10% lower, the resulting fair values would have still been greater than the carrying value for each of the reporting units tested, holding all other assumptions constant.

~~Revenue Recognition.~~ ~~Revenue is recorded as products~~estimated and ~~services are delivered. Utility~~corresponding unbilled revenues are ~~billed to customers monthly on a cycle basis. Revenues are recorded on~~calculated. This unbilled revenue is estimated each month based upon historical usage, customer rates and weather. Significant fluctuations in energy demand for the ~~accrual basis and include estimates for electricity and gas delivered but not billed.~~

We adopted the provisions of ASC 606 beginning on January 1, 2018 using a modified retrospective method, which was applied to all contracts. No material adjustments were made to January 1, 2018 opening balances and no materialunbilled period or changes in the ~~amount or timing~~composition of ~~future revenue recognition occurred as a result~~customer classes could impact the accuracy of the ~~adoption of ASC 606.~~unbilled revenue estimate. Refer to Note 3, "Revenue Recognition," in the Notes to Consolidated Financial ~~Statements.~~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, 2021 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, 2021, 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.

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

NISOURCE INC.

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 7.7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Market Risk Disclosures.”

Table of Contents

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

NIS~~OURCE~~ INC.

NISOURCE INC.



Index			Page
Report of Independent Registered Public Accounting Firm			4658
Statements of Consolidated Income (Loss)			4861
Statements of Consolidated Comprehensive Income (Loss)			4962
Consolidated Balance Sheets			5063
Statements of Consolidated Cash Flows			5265
Statements of Consolidated Stockholders' Equity			5366
Notes to Consolidated Financial Statements			5668
11.. Nature of Operations and Summary of Significant Accounting Policies			5668
22.. Recent Accounting Pronouncements			5971
33.. Revenue Recognition			6272
44.. Variable Interest Entities			75
5. Earnings Per Share			6477
65.. Property, Plant and Equipment			6579
76.. Goodwill and Other Intangible Assets			6580
87.. Asset Retirement Obligations			6680
98.. Regulatory Matters			6781
109.. Risk Management Activities			7585
11~~10.~~. Income Taxes			7686
12~~11.~~. Pension and Other Postretirement Benefits			7989
13~~12.~~. Equity			8999
14~~13.~~. Share-Based Compensation			91103
15~~14.~~. Long-Term Debt			95107
16~~15.~~. Short-Term Borrowings			97108
17~~16. Fair Value~~. Leases			98109
18~~17. Transfers of Financial Assets~~. Fair Value			~~100~~111

19~~18.~~. Other Commitments and Contingencies			~~101~~115
20~~19.~~. Accumulated Other Comprehensive Loss			~~109~~119
21~~20.~~. Other, Net			~~109~~119
22~~21.~~. Interest Expense, Net			~~110~~119
23~~22.~~. Segments of Business			~~110~~120
~~23. Quarterly Financial Data (Unaudited)~~			~~112~~
24~~24.~~. Supplemental Cash Flow Information			~~113~~122

Schedule II			~~114~~123

Table of Contents

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

NISOURCE INC.

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, ~~2018~~2021 and ~~2017,~~2020, 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, ~~2018,~~2021, and the related notes and the schedule listed in the Index at ~~item~~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, ~~2018~~2021 and ~~2017,~~2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, ~~2018,~~2021, 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, ~~2018,~~2021, 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 ~~20, 2019,~~23, 2022, expressed an unqualified opinion on the Company's internal control over financial reporting.

Basis for Opinion

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

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

Critical Audit Matters

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

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)

NISOURCE INC.

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 (1) the likelihood of recovery in future rates of incurred costs and (2) the likelihood of refund 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 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 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 filings with the commissions and the filings with the commissions by intervenors that may impact the Company’s future rates, for any evidence that might contradict management’s assertions related to recoverability of recorded assets.

•We inquired of management about property, plant, and equipment that may be abandoned. For assets that were abandoned, we inquired of management about their considerations regarding the abandonment. 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.

•With the assistance of professionals in our firm with expertise in the application of ASC Topic 980, Regulated Operations, we evaluated management’s conclusions regarding the application of ASC Topic 980 to the timing differences between the amount of profit from the consolidated joint ventures and the amount included in regulated rates.

•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.

Table of Contents

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

NISOURCE INC.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Preferred Stock—2021 Equity Units - Refer to Notes 5, 13, 18 and 24 to the consolidated financial statements

Critical Audit Matter Description

On April 19, 2021, the Company completed the sale of 8.625 million equity units, initially consisting of corporate units, each with a stated amount of $100. Each corporate unit consists of a forward contract to purchase shares of the Company's common stock in the future (“Forward Contract”) and a 1/10th, or 10%, undivided beneficial ownership interest in one share of Series C Mandatory Convertible Preferred Stock (“Preferred Stock”) (collectively the “Equity Units”).

The Forward Contract obligates holders to purchase shares of the Company's common stock on December 1, 2023, subject to early settlement in certain situations. The purchase price to be paid under the Forward Contract is $100 per Equity Unit and the number of shares to be purchased will be determined near the settlement date, subject to a maximum settlement rate. The Preferred Stock was pledged upon issuance as collateral to secure the purchase of the Company's common stock under the related Forward Contract. The Company will pay quarterly contract adjustment payments at the rate of 7.75% per year on the stated amount of $100 per Equity Unit.

The Preferred Stock initially will not bear any dividends and is expected to be remarketed prior to December 1, 2023. Following a successful remarketing, dividends may become payable on the Preferred Stock and/or the minimum conversion rate of the Preferred Stock may be increased. Each share of Preferred Stock will automatically convert based on a conversion rate on the mandatory conversion date, which is expected to be on or about March 1, 2024, unless previously converted. If no successful remarketing of the Preferred Stock has previously occurred, effective as of December 1, 2023, the conversion rate will be zero, no shares of the Company's common stock will be delivered upon automatic conversion, and each share of Preferred Stock will be automatically transferred to the Company on the mandatory conversion date without any payment of cash or shares of the Company's common stock thereon. In the event of such a remarketing failure, any share of Preferred Stock held as part of Equity Units will be automatically delivered to the Company on December 1, 2023 in full satisfaction of the relevant holder’s obligation under the related Forward Contracts.

The Company has concluded that the Forward Contracts and the Preferred Stock host represent a single unit of account and has recorded the Equity Units in equity as Preferred Stock. The present value of the quarterly contract adjustment payments was recorded as a liability, with the offset recorded in Preferred Stock.

We identified the accounting for the Equity Units as a critical audit matter due to the significant judgments made by management in the application of accounting guidance. Auditing these judgments required specialized knowledge of accounting for financial instruments and extensive audit procedures to evaluate the accounting treatment associated with the Equity Units.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the accounting for the Equity Units included the following, among others:

•We tested the effectiveness of controls over management’s accounting assessment of the Equity Units.

•We read the applicable agreements and compared the key terms from the agreements to management’s analysis of the transaction.

•With the assistance of professionals in our firm with expertise in 1) accounting for financial instruments and 2) assessing probability of certain outcomes underlying the key accounting judgments, we evaluated management’s conclusions regarding the application of the appropriate accounting standards.

•We evaluated the Company's disclosure of the Equity Units transaction, including the related impacts to the financial statements.

/s/ DELOITTE & TOUCHE LLP

Columbus, Ohio

February ~~20, 2019~~23, 2022

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

Table of Contents

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

NISOURCE INC.

~~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, 2018, 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, 2018, 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 financial statements as of and for year ended December 31, 2018, of the Company and our report dated February 20, 2019, 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 20, 2019~~

~~Table of Contents~~

~~ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)~~

NIS~~OURCE~~ INC.

STATEMENTS OF CONSOLIDATED INCOME (LOSS)


Year Ended December 31, (in millions, except per share amounts)	2018			2017			2016			Year Ended December 31, (in millions, except per share amounts)	2021		2020		2019
Operating Revenues										Operating Revenues
Customer revenues	$	4,991.1		$	4,730.2		$	4,392.5		Customer revenues	$	4,731.3	$	4,473.2	$	5,053.4
Other revenues	123.4			144.4			100.0			Other revenues	168.3		208.5		155.5
Total Operating Revenues	5,114.5			4,874.6			4,492.5			Total Operating Revenues	4,899.6		4,681.7		5,208.9
Operating Expenses										Operating Expenses
Cost of sales (excluding depreciation and amortization)	1,761.3			1,518.7			1,390.2
Cost of energy										Cost of energy	1,392.3		1,109.3		1,534.8
Operation and maintenance	2,352.9			1,601.7			1,445.8			Operation and maintenance	1,456.0		1,585.9		1,354.7
Depreciation and amortization	599.6			570.3			547.1			Depreciation and amortization	748.4		725.9		717.4
Loss (Gain) on sale of assets and impairments, net	1.2			5.5			(1.0		)
Impairment of goodwill and intangible assets										Impairment of goodwill and intangible assets	—		—		414.5

Loss on sale of assets, net										Loss on sale of assets, net	7.7		410.6		—
Other taxes	274.8			257.2			244.3			Other taxes	288.3		299.2		296.8
Total Operating Expenses	4,989.8			3,953.4			3,626.4			Total Operating Expenses	3,892.7		4,130.9		4,318.2

Operating Income	124.7			921.2			866.1			Operating Income	1,006.9		550.8		890.7
Other Income (Deductions)										Other Income (Deductions)
Interest expense, net	(353.3		)	(353.2		)	(349.5		)	Interest expense, net	(341.1)		(370.7)		(378.9)
Other, net	43.5			(13.5		)	(3.0		)	Other, net	40.8		32.1		(5.2)
Loss on early extinguishment of long-term debt	(45.5		)	(111.5		)	—			Loss on early extinguishment of long-term debt	—		(243.5)		—
Total Other Deductions, Net	(355.3		)	(478.2		)	(352.5		)	Total Other Deductions, Net	(300.3)		(582.1)		(384.1)
Income (Loss) before Income Taxes	(230.6		)	443.0			513.6			Income (Loss) before Income Taxes	706.6		(31.3)		506.6
Income Taxes	(180.0		)	314.5			182.1			Income Taxes	117.8		(17.1)		123.5

Net Income (Loss)	(50.6		)	128.5			331.5			Net Income (Loss)	588.8		(14.2)		383.1
Net income attributable to noncontrolling interest										Net income attributable to noncontrolling interest	3.9		3.4		—
Net Income (Loss) attributable to NiSource										Net Income (Loss) attributable to NiSource	584.9		(17.6)		383.1
Preferred dividends	(15.0		)	—			—			Preferred dividends	(55.1)		(55.1)		(55.1)

Net Income (Loss) Available to Common Shareholders	(65.6		)	128.5			331.5			Net Income (Loss) Available to Common Shareholders	529.8		(72.7)		328.0

Earnings (Loss) Per Share										Earnings (Loss) Per Share

Basic Earnings (Loss) Per Share	$	(0.18	)	$	0.39		$	1.03		Basic Earnings (Loss) Per Share	$	1.35	$	(0.19)	$	0.88

Diluted Earnings (Loss) Per Share	$	(0.18	)	$	0.39		$	1.02		Diluted Earnings (Loss) Per Share	$	1.27	$	(0.19)	$	0.87

Basic Average Common Shares Outstanding	356.5			329.4			321.8			Basic Average Common Shares Outstanding	393.6		384.3		374.6
Diluted Average Common Shares	356.5			330.8			323.5			Diluted Average Common Shares	417.3		384.3		376.0

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

Table of Contents

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

NISOURCE INC.

STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME (LOSS)


Year Ended December 31, (in millions, net of taxes)	2021		2020		2019
Net Income (Loss)	$	588.8	$	(14.2)	$	383.1
Other comprehensive income (loss):
Net unrealized gain (loss) on available-for-sale securities(1)	(3.9)		2.7		5.7
Net unrealized gain (loss) on cash flow hedges(2)	25.4		(70.7)		(64.2)
Unrecognized pension and OPEB benefit(3)	8.4		3.9		3.1
Total other comprehensive income (loss)	29.9		(64.1)		(55.4)
Total Comprehensive Income (Loss)	$	618.7	$	(78.3)	$	327.7

Year Ended December 31, (in millions, net of taxes)
2018 2017 2016
Net Income (Loss) $ (50.6 ) $ 128.5
$ 331.5
Other comprehensive income (loss):
Net unrealized gain (loss) on available-for-sale securities⁽¹⁾
(2.6 ) 0.8
(0.1 )
Net unrealized gain (loss) on cash flow hedges⁽²⁾
22.7
(22.5 ) 8.6
Unrecognized pension and OPEB benefit (costs)⁽³⁾
(4.4 ) 3.4
1.5
Total other comprehensive income (loss) 15.7
(18.3 ) 10.0
Total Comprehensive Income $ (34.9 ) $ 110.2
$ 341.5

⁽¹⁾Net unrealized gain (loss) on available-for-sale securities, net of ~~$0.6~~$1.0 million tax benefit, ~~$0.4~~$0.7 million tax expense and ~~$0.1~~$1.5 million tax ~~benefit~~expense in ~~2018, 2017~~2021, 2020 and ~~2016,~~2019, respectively.

⁽²⁾Net unrealized gain (loss) on derivatives qualifying as cash flow hedges, net of ~~$7.5~~$8.4 million tax expense, ~~$13.9~~$23.4 million tax benefit and ~~$5.6~~$21.2 million tax ~~expense~~benefit in ~~2018, 2017~~2021, 2020 and ~~2016,~~2019, respectively.

⁽³⁾Unrecognized pension and OPEB benefit, ~~(costs),~~ net of ~~$1.5~~$3.8 million tax expense, $0.1 million tax benefit ~~$2.1~~and $1.6 million ~~tax expense and~~ ~~$0.1 million~~ tax expense in ~~2018, 2017~~2021, 2020 and ~~2016,~~2019, respectively.

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

Table of Contents

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

NISOURCE INC.

CONSOLIDATED BALANCE SHEETS


(in millions)	December 31, 2021		December 31, 2020
ASSETS
Property, Plant and Equipment
Plant	$	25,171.3	$	24,179.9
Accumulated depreciation and amortization	(7,289.5)		(7,560.4)


Net Property, Plant and Equipment(1)	17,881.8		16,619.5
Investments and Other Assets
Unconsolidated affiliates	0.8		—
Available-for-sale debt securities (amortized cost of $169.3 and $163.9, allowance for credit losses of $0.2 and $0.5, respectively)	171.8		170.9
Other investments	87.1		81.1
Total Investments and Other Assets	259.7		252.0
Current Assets
Cash and cash equivalents	84.2		116.5
Restricted cash	10.7		9.1
Accounts receivable	849.1		843.6
Allowance for credit losses	(23.5)		(52.3)
Accounts receivable, net	825.6		791.3
Gas inventory	327.4		191.2
Materials and supplies, at average cost	139.1		141.5
Electric production fuel, at average cost	32.2		68.4

Exchange gas receivable	99.6		34.1

Regulatory assets	206.2		135.7
Deferred property taxes	91.0		85.6

Prepayments and other	104.8		86.0
Total Current Assets(1)	1,920.8		1,659.4
Other Assets

Regulatory assets	2,286.0		1,794.8
Goodwill	1,485.9		1,485.9



Deferred charges and other	322.7		228.9
Total Other Assets	4,094.6		3,509.6
Total Assets	$	24,156.9	$	22,040.5

(in millions) December 31, 2018 December 31, 2017
ASSETS
Property, Plant and Equipment
Utility plant $ 22,780.8
$ 21,026.6
Accumulated depreciation and amortization (7,257.9 ) (6,953.6 )
Net utility plant 15,522.9
14,073.0
Other property, at cost, less accumulated depreciation 19.6
286.5
Net Property, Plant and Equipment 15,542.5
14,359.5
Investments and Other Assets
Unconsolidated affiliates 2.1
5.5
Other investments 204.0
204.1
Total Investments and Other Assets 206.1
209.6
Current Assets
Cash and cash equivalents 112.8
29.0
Restricted cash 8.3
9.4
Accounts receivable (less reserve of $21.1 and $18.3, respectively) 1,058.5
898.9
Gas inventory 286.8
285.1
Materials and supplies, at average cost 101.0
105.9
Electric production fuel, at average cost 34.7
80.1
Exchange gas receivable 88.4
45.8
Regulatory assets 235.4
176.3
Prepayments and other 129.5
132.8
Total Current Assets 2,055.4
1,763.3
Other Assets
Regulatory assets 2,002.1
1,624.9
Goodwill 1,690.7
1,690.7
Intangible assets, net 220.7
231.7
Deferred charges and other 86.5
82.0
Total Other Assets 4,000.0
3,629.3
Total Assets $ 21,804.0
$ 19,961.7
(1)Includes $695.9 million and $175.6 million in 2021 and 2020, respectively, of net property, plant and equipment assets and $14.3 million and $1.7 million in 2021 and 2020, 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.

Table of Contents

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

NISOURCE INC.

CONSOLIDATED BALANCE SHEETS


(in millions, except share amounts)	December 31, 2021		December 31, 2020
CAPITALIZATION AND LIABILITIES
Capitalization
Stockholders’ Equity
Common stock - $0.01 par value, 600,000,000 shares authorized; 405,303,023 and 391,760,051 shares outstanding, respectively	$	4.1	$	3.9
Preferred stock - $0.01 par value, 20,000,000 shares authorized; 1,302,500 and 440,000 shares outstanding, respectively	1,546.5		880.0
Treasury stock	(99.9)		(99.9)
Additional paid-in capital	7,204.3		6,890.1
Retained deficit	(1,580.9)		(1,765.2)
Accumulated other comprehensive loss	(126.8)		(156.7)
Total NiSource Stockholders' Equity	6,947.3		5,752.2
Noncontrolling interest in consolidated subsidiaries	325.6		85.6
Total Stockholders’ Equity	7,272.9		5,837.8
Long-term debt, excluding amounts due within one year	9,183.4		9,219.8
Total Capitalization	16,456.3		15,057.6
Current Liabilities
Current portion of long-term debt	58.1		23.3
Short-term borrowings	560.0		503.0
Accounts payable	697.8		589.0

Customer deposits and credits	237.9		243.3
Taxes accrued	277.1		244.1
Interest accrued	105.5		104.7

Exchange gas payable	107.7		48.5

Regulatory liabilities	137.4		161.3



Accrued compensation and employee benefits	182.7		141.8

Other accruals	382.0		220.4
Total Current Liabilities(1)	2,746.2		2,279.4
Other Liabilities

Deferred income taxes	1,659.4		1,470.6


Accrued liability for postretirement and postemployment benefits	292.5		336.1

Regulatory liabilities	1,842.6		1,904.2
Asset retirement obligations	469.7		477.1

Other noncurrent liabilities	690.2		515.5
Total Other Liabilities(1)	4,954.4		4,703.5
Commitments and Contingencies (Refer to Note 19, "Other Commitments and Contingencies")
Total Capitalization and Liabilities	$	24,156.9	$	22,040.5

(in millions, except share amounts) December 31, 2018 December 31, 2017
CAPITALIZATION AND LIABILITIES
Capitalization
Stockholders’ Equity
Common stock - $0.01 par value, 400,000,000 shares authorized; 372,363,656 and 337,015,806 shares outstanding, respectively $ 3.8
$ 3.4
Preferred stock - $0.01 par value, 20,000,000 shares authorized; 420,000 shares outstanding 880.0
—
Treasury stock (99.9 ) (95.9 )
Additional paid-in capital 6,403.5
5,529.1
Retained deficit (1,399.3 ) (1,073.1 )
Accumulated other comprehensive loss (37.2 ) (43.4 )
Total Stockholders’ Equity 5,750.9
4,320.1
Long-term debt, excluding amounts due within one year 7,105.4
7,512.2
Total Capitalization 12,856.3
11,832.3
Current Liabilities
Current portion of long-term debt 50.0
284.3
Short-term borrowings 1,977.2
1,205.7
Accounts payable 883.8
625.6
Customer deposits and credits 238.9
262.6
Taxes accrued 222.7
208.1
Interest accrued 90.7
112.3
Risk management liabilities 5.0
43.2
Exchange gas payable 85.5
59.6
Regulatory liabilities 140.9
58.7
Legal and environmental 18.9
32.1
Accrued compensation and employee benefits 149.7
195.4
Claims accrued 114.7
12.5
Other accruals 58.8
78.3
Total Current Liabilities 4,036.8
3,178.4
Other Liabilities
Risk management liabilities 46.7
28.5
Deferred income taxes 1,330.5
1,292.9
Deferred investment tax credits 11.2
12.4
Accrued insurance liabilities 84.4
80.1
Accrued liability for postretirement and postemployment benefits 389.1
337.1
Regulatory liabilities 2,519.1
2,736.9
Asset retirement obligations 352.0
268.7
Other noncurrent liabilities 177.9
194.4
Total Other Liabilities 4,910.9
4,951.0
Commitments and Contingencies (Refer to Note 18, "Other Commitments and Contingencies") —
—
Total Capitalization and Liabilities $ 21,804.0
$ 19,961.7
(1)Includes $10.0 million and $15.3 million in 2021 and 2020, respectively, of current liabilities and $20.5 million and $5.6 million in 2021 and 2020, 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.

Table of Contents

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

NISOURCE INC.

STATEMENTS OF CONSOLIDATED CASH FLOWS


Year Ended December 31, (in millions)	2021		2020		2019
Operating Activities
Net Income (Loss)	$	588.8	$	(14.2)	$	383.1
Adjustments to Reconcile Net Income (Loss) to Net Cash from Operating Activities:
Loss on early extinguishment of debt	—		243.5		—
Depreciation and amortization	748.4		725.9		717.4

Deferred income taxes and investment tax credits	111.9		(29.0)		118.2

Stock compensation expense and 401(k) profit sharing contribution	24.3		17.4		25.9
Impairment of goodwill and intangible assets	—		—		414.5

Loss (gain) on sale of assets	5.6		409.8		(0.6)


Other adjustments	(0.7)		(0.3)		(0.1)
Changes in Assets and Liabilities:
Accounts receivable	(40.3)		(3.9)		187.8

Inventories	(112.9)		(1.5)		(2.0)
Accounts payable	54.9		(29.7)		(299.9)



Exchange gas receivable/payable	(114.2)		(6.9)		55.5
Other accruals	43.0		(175.1)		138.3
Prepayments and other current assets	(36.6)		(5.9)		(33.6)
Regulatory assets/liabilities	76.8		70.8		(85.6)
Postretirement and postemployment benefits	(96.4)		(103.6)		(21.1)

Deferred charges and other noncurrent assets	(4.7)		(15.0)		(76.1)
Other noncurrent liabilities	(30.0)		21.7		61.6

Net Cash Flows from Operating Activities	1,217.9		1,104.0		1,583.3
Investing Activities
Capital expenditures	(1,838.0)		(1,758.1)		(1,802.4)
Cost of removal	(121.1)		(138.2)		(113.2)
Proceeds from disposition of assets	0.7		1,115.9		0.4
Purchases of available-for-sale securities	(102.9)		(144.7)		(140.4)
Sales of available-for-sale securities	97.8		131.4		132.1
Payment to renewable generation asset developer	(240.4)		(85.3)		—
Other investing activities	(1.0)		(0.1)		1.1

Net Cash Flows used for Investing Activities	(2,204.9)		(879.1)		(1,922.4)
Financing Activities
Proceeds from issuance of long-term debt	—		2,974.0		750.0
Repayments of long-term debt and finance lease obligations	(25.7)		(1,622.0)		(51.6)
Issuance of short-term debt (maturity > 90 days)	—		1,350.0		600.0
Repayment of short-term debt (maturity > 90 days)	—		(2,200.0)		(700.0)
Change in short-term borrowings, net (maturity ≤ 90 days)	57.0		(420.1)		(104.0)
Issuance of common stock, net of issuance costs	299.6		211.4		244.4

Equity costs, premiums and other debt related costs	(18.2)		(246.5)		(17.8)
Contributions from noncontrolling interest	245.1		82.2		—
Distributions to noncontrolling interest	(0.6)		—		—
Issuance of equity units, net of underwriting costs	839.9		—		—
Dividends paid - common stock	(345.2)		(321.6)		(298.5)
Dividends paid - preferred stock	(55.1)		(55.1)		(56.1)
Contract liability payment	(40.5)		—		—
Net Cash Flows from Financing Activities	956.3		(247.7)		366.4
Change in cash, cash equivalents and restricted cash	(30.7)		(22.8)		27.3
Cash, cash equivalents and restricted cash at beginning of period	125.6		148.4		121.1
Cash, Cash Equivalents and Restricted Cash at End of Period	$	94.9	$	125.6	$	148.4

Year Ended December 31, (in millions) 2018 2017 2016
Operating Activities
Net Income (Loss) $ (50.6 ) $ 128.5
$ 331.5
Adjustments to Reconcile Net Income (Loss) to Net Cash from Operating Actvities:
Loss on early extinguishment of debt 45.5
111.5
—
Depreciation and amortization 599.6
570.3
547.1
Deferred income taxes and investment tax credits (188.2 ) 306.7
182.3
Stock compensation expense and 401(k) profit sharing contribution 28.6
40.1
46.5
Amortization of discount/premium on debt 7.5
7.4
7.6
AFUDC equity (14.2 ) (12.6 ) (11.6 )
Other adjustments 1.7
6.6
(7.2 )
Changes in Assets and Liabilities:
Accounts receivable (186.2 ) (52.3 ) (188.0 )
Inventories 41.4
19.0
38.9
Accounts payable 268.4
49.0
108.8
Customer deposits and credits (25.4 ) (2.5 ) (52.3 )
Taxes accrued 20.2
10.2
12.1
Interest accrued (21.7 ) (33.9 ) (8.7 )
Exchange gas receivable/payable (21.5 ) (64.5 ) 36.9
Other accruals 43.5
31.8
(6.0 )
Prepayments and other current assets (14.5 ) (13.3 ) (0.4 )
Regulatory assets/liabilities (53.2 ) 57.5
(187.9 )
Postretirement and postemployment benefits 58.2
(380.9 ) (44.8 )
Deferred charges and other noncurrent assets 3.8
(2.0 ) (1.2 )
Other noncurrent liabilities (2.8 ) (34.4 ) (0.3 )
Net Cash Flows from Operating Activities 540.1
742.2
803.3
Investing Activities
Capital expenditures (1,818.2 ) (1,695.8 ) (1,475.2 )
Cost of removal (104.3 ) (109.0 ) (110.1 )
Purchases of available-for-sale securities (90.0 ) (168.4 ) (38.3 )
Sales of available-for-sale securities 82.3
163.1
33.0
Other investing activities 4.1
1.6
(12.4 )
Net Cash Flows used for Investing Activities (1,926.1 ) (1,808.5 ) (1,603.0 )
Financing Activities
Issuance of long-term debt 350.0
3,250.0
500.0
Repayments of long-term debt and capital lease obligations (1,046.1 ) (1,855.0 ) (434.6 )
Premiums and other debt related costs (46.0 ) (144.3 ) (3.7 )
Issuance of short-term debt (maturity > 90 days) 950.0
—
—
Change in short-term borrowings, net (maturity ≤ 90 days) (178.5 ) (282.4 ) 920.6
Issuance of common stock, net of issuance costs 848.2
336.7
23.1
Issuance of preferred stock, net of issuance costs 880.0
—
—
Acquisition of treasury stock (4.0 ) (7.2 ) (9.4 )
Dividends paid - common stock (273.3 ) (229.1 ) (205.5 )
Dividends paid - preferred stock (11.6 ) —
—
Net Cash Flows from Financing Activities 1,468.7
1,068.7
790.5
Change in cash, cash equivalents and restricted cash 82.7
2.4
(9.2 )
Cash, cash equivalents and restricted cash at beginning of period 38.4
36.0
45.2
Cash, Cash Equivalents and Restricted Cash at End of Period $ 121.1
$ 38.4
$ 36.0

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

~~Table of Contents~~

~~ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)~~

NIS~~OURCE~~ INC.

~~STATEMENTS OF CONSOLIDATED STOCKHOLDERS’ EQUITY~~

(in millions)
Common
Stock

Treasury
Stock

Additional
Paid-In
Capital
Retained Deficit
Accumulated
Other
Comprehensive
Loss
Total
Balance as of January 1, 2016 $ 3.2
$ (79.3 ) $ 5,078.0
$ (1,123.3 ) $ (35.1 ) $ 3,843.5
Comprehensive Income:
Net Income —
—
—
331.5
—
331.5
Other comprehensive income, net of tax —
—
—
—
10.0
10.0
Common stock dividends ($0.64 per share) —
—
—
(205.7 ) —
(205.7 )
Treasury stock acquired —
(9.4 ) —
—
—
(9.4 )
Cumulative effect of change in accounting principle⁽¹⁾
—
—
—
25.3
—
25.3
Stock issuances:
Common stock 0.1
—
—
—
—
0.1
Employee stock purchase plan —
—
4.7
—
—
4.7
Long-term incentive plan —
—
20.9
—
—
20.9
401(k) and profit sharing —
—
41.4
—
—
41.4
Dividend reinvestment plan —
—
8.9
—
—
8.9
Balance as of December 31, 2016 $ 3.3
$ (88.7 ) $ 5,153.9
$ (972.2 ) $ (25.1 ) $ 4,071.2
Comprehensive Loss:
Net Income —
—
—
128.5
—
128.5
Other comprehensive loss, net of tax —
—
—
—
(18.3 ) (18.3 )
Common stock dividends ($0.70 per share) —
—
—
(229.4 ) —
(229.4 )
Treasury stock acquired —
(7.2 ) —
—
—
(7.2 )
Stock issuances:

Employee stock purchase plan —
—
5.0
—
—
5.0
Long-term incentive plan —
—
14.9
—
—
14.9
401(k) and profit sharing —
—
34.3
—
—
34.3
Dividend reinvestment plan —
—
6.4
—
—
6.4
ATM Program 0.1
—
314.6
—
—
314.7
Balance as of December 31, 2017 $ 3.4
$ (95.9 ) $ 5,529.1
$ (1,073.1 ) $ (43.4 ) $ 4,320.1

⁽¹⁾~~See Note 2, "Recent Accounting Pronouncements," for additional information.~~


Reconciliation to Balance Sheet	2021	2020	2019
Cash and cash equivalents	84.2	116.5	139.3
Restricted Cash	10.7	9.1	9.1
Total Cash, Cash Equivalents and Restricted Cash	94.9	125.6	148.4

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

Table of Contents

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

NISOURCE INC.

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, 2019	$	3.8	$	880.0	$	(99.9)	$	6,403.5	$	(1,399.3)	$	(37.2)	$	—	$	5,750.9
Comprehensive Income:
Net Income	—		—		—		—		383.1		—		—		383.1
Other comprehensive loss, net of tax	—		—		—		—		—		(55.4)		—		(55.4)

Dividends:
Common stock ($0.80 per share)	—		—		—		—		(298.5)		—		—		(298.5)
Preferred stock (See Note 13)	—		—		—		—		(56.1)		—		—		(56.1)


Stock issuances:


Employee stock purchase plan	—		—		—		5.6		—		—		—		5.6
Long-term incentive plan	—		—		—		10.4		—		—		—		10.4
401(k) and profit sharing	—		—		—		17.6		—		—		—		17.6

ATM Program	—		—		—		229.1		—		—		—		229.1
Balance as of December 31, 2019	$	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)
Contribution 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

(in millions) Common
Stock Preferred Stock Treasury
Stock Additional
Paid-In
Capital Retained Deficit Accumulated
Other
Comprehensive Loss Total
Balance as of December 31, 2017 $ 3.4
$ —
$ (95.9 ) $ 5,529.1
$ (1,073.1 ) $ (43.4 ) $ 4,320.1
Comprehensive Income:
Net Loss —
—
—
—
(50.6 ) —
(50.6 )
Other comprehensive income, net of tax —
—
—
—
—
15.7
15.7
Dividends:
Common stock ($0.78 per share) —
—
—
—
(273.5 ) —
(273.5 )
Preferred stock ($28.88 per share) —
—
—
—
(11.6 ) —
(11.6 )
Treasury stock acquired —
—
(4.0 ) —
—
—
(4.0 )
Cumulative effect of change in accounting principle⁽¹⁾
—
—
—
—
9.5
(9.5 ) —
Stock issuances:
Common stock - private placement 0.3
—
—
599.3
—
—
599.6
Preferred stock —
880.0
—
—
—
—
880.0
Employee stock purchase plan —
—
—
5.5
—
—
5.5
Long-term incentive plan —
—
—
15.4
—
—
15.4
401(k) and profit sharing —
—
—
21.8
—
—
21.8
ATM program 0.1
—
—
232.4
—
—
232.5
Balance as of December 31, 2018 $ 3.8
$ 880.0
$ (99.9 ) $ 6,403.5
$ (1,399.3 ) $ (37.2 ) $ 5,750.9

⁽¹⁾Series A, Series B, and Series C shares have an aggregate liquidation preference of $400M, $500M, and $863M, respectively. See Note ~~2, "Recent Accounting Pronouncements," for additional information.~~

~~Table of Contents~~

~~ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)~~

NIS~~OURCE~~ INC.

~~STATEMENTS OF CONSOLIDATED STOCKHOLDERS’ EQUITY~~

Preferred Common
(in thousands) Shares Shares Treasury Outstanding
Balance as of January 1, 2016 —
322,181
(3,071 ) 319,110
Treasury stock acquired (433 ) (433 )
Issued:
Employee stock purchase plan —
201
—
201
Long-term incentive plan —
2,103
—
2,103
401(k) and profit sharing plan —
1,793
—
1,793
Dividend reinvestment plan —
386
—
386
Balance as of December 31, 2016 —
326,664
(3,504 ) 323,160
Treasury stock acquired (293 ) (293 )
Issued:
Employee stock purchase plan —
207
—
207
Long-term incentive plan —
351
—
351
401(k) and profit sharing plan —
1,396
—
1,396
Dividend reinvestment plan —
264
—
264
ATM Program —
11,931
—
11,931
Balance as of December 31, 2017 —
340,813
(3,797 ) 337,016
Treasury stock acquired (166 ) (166 )
Issued:
Common stock - private placement⁽¹⁾
—
24,964
—
24,964
Preferred stock⁽¹⁾
420

Employee stock purchase plan —
223
—
223
Long-term incentive plan —
561
—
561
401(k) and profit sharing plan —
882
—
882
ATM program —
8,883
—
8,883
Balance as of December 31, 2018 420
376,326
(3,963 ) 372,363

⁽¹⁾~~See Note 12,~~13, "Equity," for additional information.

~~Accompanying~~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)

NISOURCE INC.

STATEMENTS OF CONSOLIDATED STOCKHOLDERS’ EQUITY (continued)


	Preferred	Common
(in thousands)	Shares	Shares	Treasury	Outstanding
Balance as of January 1, 2019	420	376,326	(3,963)	372,363
Issued:

Preferred stock(1)	20	—	—	—
Employee stock purchase plan	—	201	—	201
Long-term incentive plan	—	518	—	518
401(k) and profit sharing plan	—	631	—	631

ATM program	—	8,423	—	8,423
Balance as of December 31, 2019	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

(1)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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NISOURCE INC.

Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

1. Nature of Operations and Summary of Significant Accounting Policies


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 ~~4.0~~3.7 million customers in ~~seven~~six states. We generate substantially all of our operating income through these rate-regulated businesses. The consolidated financial statements include the accounts of us, ~~and~~ 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 ~~trust~~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 ~~date of 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 ~~weather.~~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, in the amounts of $324.2 million and $359.4 million as of December 31, 2018 and 2017, respectively.~~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 experience and in consideration of current market conditions. 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.~~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 ~~“Other investments”~~“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. ~~These~~At each reporting period these investments are ~~monitored~~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 ~~than temporary declines in market value. Realized gains~~comprehensive income and ~~losses and permanent impairments~~ are reflected in the Statements of Consolidated Income (Loss). No material impairment charges were recorded for the years ended December 31, ~~2018, 2017~~2021, 2020 or ~~2016.~~2019. Refer to Note ~~16,~~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.

InWe continually evaluate whether or not our operations are within 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 regulatory accounting. In such an event, a write-down of all or a portion of our existing regulatory assets and liabilities could result. If transition cost recovery was approved by the appropriate regulatory bodies that would meet the requirements under GAAP for continued accounting as regulatory assets and liabilities during such recovery period, the regulatory assets and liabilities would be reported at the recoverable amounts. If unable to continue to apply the provisions of regulatory accounting, we would be required to apply the provisionsscope of ASC ~~980-20,~~ ~~Discontinuation~~980 and rate regulations. As part of ~~Rate-Regulated Accounting~~.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 8,9, "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. ~~The~~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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NISOURCE INC.

Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

Non-utility property includes renewable generation assets owned by joint ventures of which we are the primary beneficiary and is generally depreciated on a straight-line basis over the life of the associated ~~asset.~~assets. Refer to Note 5,6, "Property, Plant and Equipment," for additional information related to depreciation expense.

For rate-regulated companies, 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 pre-tax rate for AFUDC was ~~3.5%~~3.3% in ~~2018, 4.0%~~2021, 2.6% in ~~2017~~2020 and ~~4.5%~~3.0% in ~~2016.~~2019.

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 ~~net amount is~~gross amounts are classified as ~~"Other property, at cost, less accumulated depreciation" on the Consolidated Balance Sheets.~~"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.

When our subsidiaries sell entire regulated operating units, or retire or sell nonregulated properties, the original cost and accumulated depreciation and amortization balances are removed from ~~"Property,~~"Net Property, Plant and Equipment" on the Consolidated Balance Sheets. Any gain or loss is recorded in earnings, unless otherwise required by the applicable regulatory body. Refer to Note 5,6, "Property, Plant and Equipment," for further information.

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, except for certain significant enterprise-wide technology investments which are amortized over a ten-year period.~~

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 -- generally up to a maximum of five years.~~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.

We have other intangible assets consisting primarily of franchise rights apart from goodwill that were identified as part of the purchase price allocations associated with the acquisition of Columbia of Massachusetts which is being amortized on a straight-line basis over forty years from the date of acquisition. See Note 6,7, "Goodwill and Other Intangible Assets," for additional information.

I. Accounts Receivable Transfer Program. 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, ~~2018~~2021 and ~~2017~~2020 Consolidated Balance ~~Sheets and~~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 ~~17, "Transfers of Financial Assets,~~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 8,9, "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 ~~$47.5~~$44.9 million and ~~$45.5~~$42.3 million at December 31, ~~2018~~2021 and ~~2017,~~2020, respectively. Based on the average cost of gas using the LIFO method, the estimated

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NIS~~OURCE~~ INC.

~~Notes to Consolidated Financial Statements~~

~~ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)~~

replacement cost of gas in storage was less than the stated LIFO cost by ~~$12.2~~$13.6 million and ~~$17.4~~$19.6 million at December 31, ~~2018~~2021 and ~~2017,~~2020, respectively. As all LIFO inventory costs are collected from customers through our rate-

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NISOURCE INC.

Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

regulated subsidiaries, no inventory impairment has been recorded. Gas inventory valued using the weighted average cost methodology was ~~$239.3~~$282.4 million at December 31, ~~2018~~2021 and ~~$239.6~~$148.8 million at December 31, ~~2017.~~2020.

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.

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 ~~have elected~~do not ~~to net~~offset the fair value amounts recognized for any of our derivative instruments oragainst the fair value amounts recognized for the right to ~~receive~~reclaim cash collateral or obligation to ~~pay~~return cash collateral ~~arising from those~~for derivative instruments ~~recognized at fair value, which are~~ executed with the same counterparty under a master netting arrangement. See Note 9,10, "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. ~~Previously recorded investment~~Investment tax credits ~~of the~~associated with regulated ~~subsidiaries were~~operations are deferred ~~on the balance sheet~~ and ~~are being~~ amortized as a reduction to ~~book~~ income tax expense over the ~~regulatory life~~estimated useful lives of the related ~~properties to conform to regulatory policy.~~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 ~~an agreement (the “Intercompany~~a tax sharing agreement. Income ~~Tax Allocation Agreement”) that provides for the allocation of consolidated tax liabilities. The Intercompany Income Tax Allocation Agreement generally provides that~~taxes recorded by each party ~~is allocated an amount of tax similar to~~represent amounts that ~~which~~ 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 first quarter of 2021. See Note 12, "Pension and Other Postretirement 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 ~~“Legal and environmental”~~“Other accruals” for short-term portions of these liabilities and “Other noncurrent liabilities” for the respective long-term portions of

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NISOURCE INC.

Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

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 ~~18,~~8, "Asset Retirement Obligations," and Note 19, "Other Commitments and Contingencies," for further information.

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NIS~~OURCE~~ INC.

~~Notes to Consolidated Financial Statements~~

~~ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)~~

P.Q. Excise Taxes. ~~We account~~ As an agent for some state and local governments, we invoice and collect certain excise taxes ~~that are customer liabilities~~levied by ~~separately stating~~state and local governments on ~~our invoices the tax to our~~ customers and ~~recording~~record these amounts ~~invoiced~~ 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).

Q.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. ~~Refer to Note 18-E "Other Matters" for further information on accrued insurance liabilities related~~

S. VIEs and Allocation of Earnings. We fund a significant portion of our renewable generation assets through joint ventures with tax equity partners. We consolidate these joint ventures 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 ~~Greater Lawrence Incident.~~joint ventures' ongoing operations and economic results (i.e., we are the primary beneficiary).

These joint ventures are subject to profit sharing arrangements in which the allocation of the joint ventures' 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 joint venture'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 joint ventures 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 joint ventures and the amount included in regulated rates to recover our approved investments in consolidated joint ventures. 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 are currently evaluating the impact of certain ASUs on our Consolidated Financial Statements orand Notes to Consolidated Financial Statements, which are described below:

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 issuedASU 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 are effective upon issuance on March 12, 2020, and will apply through December 31, 2022. We have evaluated the temporary expedients and options available under this guidance and identified the financial instruments to which the expedients could be applied, if deemed necessary. As of December 31, 2021, we have not applied any expedients and options available under these ASUs.



~~Standard~~	~~Description~~	~~Effective Date~~	~~Effect on the financial statements or other significant matters~~
~~ASU 2018-14,~~ ~~Compensation—Retirement Benefits—Defined Benefit Plans—General (Subtopic 715-20): Disclosure Framework—Changes to the Disclosure Requirements for Defined Benefit Plans~~	The pronouncement modifies the disclosure requirements for defined benefit pension and other postretirement benefit plans. The guidance removes disclosures that are no longer considered cost beneficial, clarifies the specific requirements of disclosures and adds disclosure requirements identified as relevant. The modifications affect annual period disclosures and must be applied on a retrospective basis to all periods presented.	~~Annual periods ending after December 15, 2020. Early adoption is permitted.~~	~~We are currently evaluating the effects of this pronouncement on our Notes to Consolidated Financial Statements. We tentatively expect to adopt this ASU on its effective date.~~
~~ASU 2016-13,~~ ~~Financial Instruments-Credit Losses (Topic 326)~~	The pronouncement changes the impairment model for most financial assets, replacing the current "incurred loss" model. ASU 2016-13 will require the use of an "expected loss" model for instruments measured at amortized cost. It will also require entities to record allowances for available-for-sale debt securities rather than impair the carrying amount of the securities. Subsequent improvements to the estimated credit losses of available-for-sale securities will be recognized immediately in earnings instead of over time as they are under historic guidance.	~~Annual periods beginning after December 15, 2019, including interim periods therein. Early adoption is permitted for annual or interim periods beginning after December 15, 2018.~~	We maintain investments in U.S. Treasury, corporate and mortgage-backed debt securities, which are pledged as collateral for trust accounts related to our wholly-owned insurance company. These debt securities are classified as available for sale. We also have recorded balances for trade receivables that fall within the scope of the standard. We are currently evaluating the impact of adoption, if any, on our Consolidated Financial Statements and Notes to 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 business entities to provide certain disclosures when they have received government assistance and use a grant or contribution accounting model by analogy to other accounting guidance. This

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NISOURCE INC.

Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

~~Recently Adopted Accounting Pronouncements~~



~~Standard~~	~~Adoption~~
~~ASU 2018-15,~~ ~~Intangibles—Goodwill and Other— Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract~~	~~In August 2018,~~pronouncement is applicable for financial statements issued for annual periods beginning after December 15, 2021. We are currently evaluating the impact of adoption, if any, on the FASB issued this ASU, which amends current guidance to align the accounting for costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing costs associated with developing or obtaining internal-use software. We elected to early adopt the ASU on a prospective basis, effective October 1, 2018. As a result of adopting this ASU, we will defer onto the Consolidated Balance Sheets up-front implementation costs of cloud computing arrangements if they would have been capitalized in a similar on-premise software solution.
~~ASU 2018-02,~~ ~~Income Statement—Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income~~	We adopted this ASU effective March 31, 2018. Upon adoption, $9.5 million of tax effects that were stranded in accumulated other comprehensive income (loss) as a result of the implementation of the TCJA were reclassified to retained deficit. This change is reflected on our Statements of Consolidated Stockholders' Equity.
~~ASU 2016-15,~~ ~~Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force)~~	~~We adopted this ASU effective January 1, 2018. The adoption of this standard did not have a material impact on our Consolidated Financial Statements or Notes to Consolidated Financial Statements.~~
~~ASU 2018-11, Leases (Topic 842): Targeted Improvements~~	We adopted the provisions of ASC 842 beginning on January 1, 2019, using the transition method provided in ASU 2018-11, which was applied to all existing leases at that date. As such, results for reporting periods beginning after January 1, 2019 will be presented under ASC 842, while prior period amounts will continue to be reported in accordance with ASC 840. To ease the process of implementing ASC 842, we elected a number of practical expedients, including the "practical expedient package" described in ASC 842-10-65-1 and the provisions of ASU 2018-01, which allows us to not evaluate existing land easements under ASC 842. We elected the short-term lease recognition exemption for all leases that qualify. As such, for those leases with terms less than 12 months, we will not recognize ROU assets or lease liabilities. Further, ASC 842 provides lessees the option of electing an accounting policy, by class of underlying asset, in which the lessee may choose not to separate nonlease components from lease components. We elected this practical expedient for our leases of fleet vehicles and railcars. We also elected to use a practical expedient that allows the use of hindsight in determining lease terms when evaluating leases that existed at the implementation date. We are the lessee for substantially all of our current leasing activity. Upon adopting ASC 842 we began recognizing right-of-use assets and liabilities associated with operating leases (other than short term operating leases) on our Consolidated Balance Sheets resulting in an increase in assets and liabilities of approximately $60 million. The adoption of ASC 842 did not have a material impact to our results of operations or cash flows. We have implemented key system functionality and internal controls to facilitate the preparation of financial information upon adoption. Our SEC filings will include expanded disclosures to comply with the provisions of ASC 842 beginning with our quarterly report on Form 10-Q for the first quarter of 2019.
~~ASU 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842~~
~~ASU 2016-02, Leases (Topic 842)~~

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Notes to Consolidated Financial ~~Statements~~Statements.

Recently Adopted Accounting Pronouncements

~~ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)~~



~~Standard~~	~~Adoption~~
~~ASU 2016-12,~~ ~~Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients~~	~~See Note 3, "Revenue Recognition," for our discussion of the effects of implementing these standards.~~
~~ASU 2016-08,~~ ~~Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations~~
~~ASU 2014-09,~~ ~~Revenue from Contracts with Customers (Topic 606)~~

~~We also adopted~~ In August 2020, the FASB issued ASU ~~2017-07,~~ ~~Compensation~~2020-06, Debt with Conversion and Other Options (Subtopic 470-20) and Derivative and Hedging - ~~Retirement Benefits (Topic 715)~~Contracts in Entity's Own Equity (Subtopic 815-40): ~~Improving~~Accounting for Convertible Instruments and Contracts in an Entity's Own Equity. This pronouncement simplifies the ~~Presentation~~accounting for certain financial instruments with characteristics of ~~Net Periodic Pension Cost~~liabilities and ~~Net Periodic Postretirement Benefit Cost,~~ ~~effective January 1, 2018. We continue~~equity, including convertible instruments and contracts on an entity's own equity. Specifically, the ASU "simplifies accounting for convertible instruments by removing major separation models required under current GAAP." In addition, the ASU "removes certain settlement conditions that are required for equity contracts to ~~present~~qualify for it" and "simplifies the ~~service cost~~diluted earnings per share (EPS) calculations in certain areas." Finally, this ASU "eliminates the cash conversion and beneficial conversion feature models that require an issuer of certain convertible debt and preferred stock to separately account for embedded conversion features as a component of ~~net periodic benefit cost~~equity." This pronouncement is effective for the annual period beginning after December 15, 2021, and interim periods within ~~"Operation and maintenance;" however, other components~~those fiscal years. This accounting pronouncement will impact the denominator in the calculation of diluted EPS for our Equity Units. Beginning Q1 2022, we will be required to assume share settlement of the ~~net periodic benefit cost (including regulatory deferrals and settlement charges) are now presented separately within "Other, net" on our Statements~~remaining purchase contract payment balance when applying the if-converted method. Moreover, we will also be required to utilize the average share price for the period instead of ~~Consolidated Income (Loss).~~

~~Changes in income statement presentation were implemented on a retrospective basis. The impact~~the end of period price. We have adopted this ASU on ~~previously issued annual financial statements is summarized in the tables below:~~its effective date.

Year Ended December 31, 2016 (in millions)
As Previously Reported
Effect of Change⁽¹⁾
As Adjusted
Operation and maintenance $ 1,453.7
$ (7.9 ) $ 1,445.8
Total Operating Expenses 3,634.3
(7.9 ) 3,626.4
Operating Income 858.2
7.9
866.1
Other Income (Deductions)
Other, net 1.5
(7.9 ) (6.4 )
Total Other Deductions $ (348.0 ) $ (7.9 ) $ (355.9 )

⁽¹⁾ The effect of this change is attributable to our business segments: Gas Distribution Operations, Electric Operations, and Corporate and Other in the amounts of $4.3 million, $(9.8) million, and $(2.4) million, respectively.

Year Ended December 31, 2017 (in millions)
As Previously Reported
Effect of Change⁽¹⁾
As Adjusted
Operation and maintenance $ 1,612.3
$ (10.6 ) $ 1,601.7
Total Operating Expenses 3,964.0
(10.6 ) 3,953.4
Operating Income 910.6
10.6
921.2
Other Income (Deductions)
Other, net (2.8 ) (10.6 ) (13.4 )
Total Other Deductions $ (467.5 ) $ (10.6 ) $ (478.1 )

⁽¹⁾The effect of this change is attributable to our business segments: Gas Distribution Operations, Electric Operations, and Corporate and Other in the amounts of $(4.4) million, $(2.6) million, and $(3.6) million, respectively.

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~~Notes to Consolidated Financial Statements~~

~~ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)~~

3. Revenue Recognition

~~ASC 606 Adoption.~~ In 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (ASC 606). ASU 2014-09 outlines a single, comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance. The core principle of the new standard is that an entity should recognize revenue to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. In 2016, the FASB issued ASU 2016-08, Revenue from Contracts with Customers (ASC 606): Principal versus Agent Considerations, and ASU 2016-12, Revenue from Contracts with Customers (ASC 606): Narrow-Scope Improvements and Practical Expedients. We adopted the provisions of ASC 606 beginning on January 1, 2018 using a modified retrospective method, which was applied to all contracts. No material adjustments were made to January 1, 2018 opening balances as a result of the adoption. As required under the modified retrospective method of adoption, results for reporting periods beginning after January 1, 2018 are presented under ASC 606, while prior period amounts are not adjusted and continue to be reported in accordance with ASC 605.

The table below provides results for the year ended December 31, 2018 as if it had been prepared under historic accounting guidance. We included operating revenue information for the years ended December 31, 2017 and 2016 for comparability.

Year Ended December 31, (in millions)
2018 2017 2016
Operating Revenues
Gas Distribution $ 2,348.4
$ 2,063.2
$ 1,850.9
Gas Transportation 1,055.2
1,021.5
964.6
Electric 1,707.4
1,785.5
1,660.8
Other 3.5
4.4
16.2
Total Operating Revenues $ 5,114.5
$ 4,874.6
$ 4,492.5

Beginning in 2018 with the adoption of ASC 606, the Statements of Consolidated Income (Loss) disaggregates “Customer revenues” (i.e. ASC 606 Revenues) from “Other revenues,” both of which are discussed in more detail below.

Customer Revenues. Substantially all of our revenues are ~~tariff-based, which we have concluded is within the scope of ASC 606.~~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. ASC 606 defines a~~ contract, ~~as an agreement between two or more parties, in this case us and the customer,~~ which creates enforceable rights and obligations. In order to be considered a contract, we have determined that it is probable that substantially all of the consideration to which we are entitled from customers will be collected upon satisfaction of performance obligations. We maintain common utility credit risk mitigation practices, including requiring deposits and actively pursuing collection of past due amounts. In addition, our regulated operations utilize certain regulatory mechanisms that facilitate recovery of bad debt costs within tariff-based rates, which provides further evidence of collectibility.

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."~~Credits" on the Consolidated Balance Sheets. Amounts in this account are reduced and revenue is recorded when customer usage ~~begins to exceed~~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~~"Regulatory Assets" or ~~liabilities~~"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. ~~In general,~~

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~~Notes~~Distribution revenues are generally considered daily or "at-will" contracts as customers may cancel their service at any time (subject to ~~Consolidated Financial Statements~~

~~ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)~~

notification requirements), and revenue ~~recognized from tariff-based sales is equivalent~~generally represents the amount we are entitled to ~~the value of natural gas or electricity supplied and billed each period, in addition to an estimate for deliveries completed during the period but not yet billed to the customer.~~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. ~~We have concluded that these sales are within the scope of ASC 606.~~ 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. ~~As our revenues are primarily earned over a period of time, and we do not earn a material amount of revenues at a point in time, revenues are not disaggregated as such below.~~ The Gas Distribution Operations segment provides natural gas service and transportation for residential, commercial and industrial customers in Ohio, Pennsylvania, Virginia, Kentucky, Maryland ~~Indiana~~ and ~~Massachusetts.~~Indiana. The Electric Operations segment provides electric service in 20 counties in the northern part of Indiana.

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NISOURCE INC.

Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

The ~~table~~tables below ~~reconciles~~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, 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

Year Ended December 31, 2018 (in millions)
Gas Distribution Operations Electric Operations Corporate and Other Total
Customer Revenues⁽¹⁾

Residential $ 2,250.0
$ 494.7
$ —
$ 2,744.7
Commercial 751.9
492.7
—
1,244.6
Industrial 228.0
613.6
—
841.6
Off-system 92.4
—
—
92.4
Miscellaneous 49.7
17.4
0.7
67.8
Total Customer Revenues $ 3,372.0
$ 1,618.4
$ 0.7
$ 4,991.1
Other Revenues 34.4
89.0
—
123.4
Total Operating Revenues $ 3,406.4
$ 1,707.4
$ 0.7
$ 5,114.5

⁽¹⁾Customer revenue amounts exclude intersegment revenues. See Note ~~22,~~23, "Segments of Business," 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 23, "Segments of Business," 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, 2019 (in millions)	Gas Distribution Operations		Electric Operations		Corporate and Other		Total
Customer Revenues(1)
Residential	$	2,309.0	$	481.6	$	—	$	2,790.6
Commercial	771.3		486.6		—		1,257.9
Industrial	245.2		607.7		—		852.9
Off-system	77.7		—		—		77.7
Miscellaneous	52.0		21.5		0.8		74.3
Total Customer Revenues	$	3,455.2	$	1,597.4	$	0.8	$	5,053.4
Other Revenues	54.5		101.0		—		155.5
Total Operating Revenues	$	3,509.7	$	1,698.4	$	0.8	$	5,208.9

(1)Customer revenue amounts exclude intersegment revenues. See Note 23, "Segments of Business," for discussion of intersegment revenues.

Other Revenues. As permitted by accounting principles generally accepted in the United States, regulated utilities have the ability to earn certain types of revenue that are outside the scope of ASC 606. These revenues primarily represent revenue earned under alternative revenue programs. Alternative revenue programs represent regulator-approved mechanisms that allow for the adjustment of billings and revenue for certain approved programs. We maintain a variety of these programs, including demand side management initiatives that recover costs associated with the implementation of energy efficiency programs, as

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Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

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 ~~years~~year ended December 31, ~~2018 and 2017~~2021, 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)⁽¹⁾

Customer Accounts Receivable, Unbilled (less reserve)⁽²⁾
Balance as of December 31, 2017 $ 477.0
$ 378.6
Balance as of December 31, 2018 540.5
349.1
Increase (Decrease) $ 63.5
$ (29.5 )

⁽¹⁾ ~~Customer billed receivables increased over the period due to November 2018 being colder than November 2017, leading to more gas usage included in December bills.~~

⁽²⁾ ~~Customer unbilled receivables decreased over the period due December 2018 being warmer than December 2017, leading to less estimated gas usage.~~

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~~Notes to Consolidated Financial Statements~~

~~ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)~~


(in millions)	Customer Accounts Receivable, Billed (less reserve)		Customer Accounts Receivable, Unbilled (less reserve)
Balance as of December 31, 2020	$	400.0	$	327.2
Balance as of December 31, 2021	459.6		337.0

Utility revenues are billed to customers monthly on a cycle basis. We ~~generally~~ expect that substantially all customer accounts receivable will be collected ~~within the month~~ following customer billing, as this revenue consists primarily of ~~monthly,~~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.

~~Other Revenues.~~ ~~As permitted by accounting principles generally accepted~~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, and final bill data. 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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NISOURCE INC.

Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

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, 2021 and December 31, 2020, are presented in the ~~United States, regulated utilities have~~tables below:



(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 millions)	Gas Distribution Operations		Electric Operations		Corporate and Other		Total
Balance as of January 1, 2020	$	9.1	$	3.1	$	0.8	$	13.0
Current period provisions	45.3		9.3		—		54.6
Write-offs charged against allowance	(26.7)		(3.0)		—		(29.7)
Recoveries of amounts previously written off	14.1		0.3		—		14.4
Balance as of December 31, 2020	$	41.8	$	9.7	$	0.8	$	52.3

In connection with the COVID-19 pandemic, certain state regulatory commissions instituted regulatory moratoriums that impacted our ability to ~~earn certain types of revenue that are outside~~pursue our standard credit risk mitigation practices. Following the scope of ASC 606. These revenues primarily represent revenue earned under alternative revenue programs. Alternative revenue programs represent regulator-approved programs that allow for the adjustment of billings and revenue for certain broad, external factors, or for additional billings if the entity achieves certain objectives, such as a specified reduction of costs. We maintain a varietyissuance of these ~~programs, including demand side management initiatives that recover costs associated with the implementation~~moratoriums, certain 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 Revenueour regulated operations have been ~~met, we establish~~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 ~~present revenue~~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, 2021 adequately reflected the collection risk and net realizable value of our receivables. We have now resumed our common credit mitigation practices in all jurisdictions as these moratoriums have expired (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-S, "VIEs and Allocation of Earnings," for information on our accounting policy for the VIEs.

We control decisions that are significant to Rosewater and Indiana Crossroads Wind's ongoing operations and economic results. Therefore, we have concluded that we are the primary beneficiary and have consolidated both.

Members of the respective joint ventures 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. 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 ~~alternative revenue programs on~~the tax equity partner the remaining interest in the respective joint venture. NIPSCO has an obligation to purchase, through a PPA at established market rates, 100% of the electricity generated by the joint ventures.

Rosewater

Rosewater owns and operates 102 MW of nameplate capacity wind generation assets. NIPSCO and the tax equity partner made cash contributions in December 2020 and March 2021 per the equity capital contribution agreement. NIPSCO also assumed an obligation to the developer of the wind generation assets representing the remaining economic interest, which comes due in 2023. From the contributed funds, Rosewater paid $7.4 million and $85.3 million to the developer of the wind generation assets

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Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

as of December 31, 2021 and 2020, respectively. The developer of the facility is not a partner in the joint venture for federal income tax purposes and does not receive any share of earnings, tax attributes, or cash flows of Rosewater.

Indiana Crossroads Wind

Indiana Crossroads Wind owns and operates 302 MW of nameplate capacity wind generation assets. NIPSCO and the tax equity partner made cash contributions in December 2021 per the equity capital contribution agreement. NIPSCO also assumed an obligation to the developer of the wind generation assets representing the remaining economic interest, which comes due in 2023. From the contributed funds, Indiana Crossroads Wind paid $233.0 million and zero to the developer of the wind generation assets as of December 31, 2021 and 2020, respectively. The developer of the facility is not a partner in the joint venture for federal income tax purposes and does not receive any share of earnings, tax attributes, or cash flows of Indiana Crossroads Wind.

The following table displays the Noncontrolling interest in consolidated subsidiaries included in the Consolidated Balance Sheets:



(in millions)	December 31, 2021		December 31, 2020
Rosewater	$	88.2	$	85.6
Indiana Crossroads Wind	237.4		—
Total	$	325.6	$	85.6

The following table displays the Net income (loss) attributable to noncontrolling interest included in the Statements of Consolidated Income (Loss) ~~as “Other revenues.” When amounts~~for the years ended December 31:



(in millions)	2021		2020		2019
Rosewater	$	(4.2)	$	3.4	$	—
Indiana Crossroads Wind	8.1		—		—
Total	$	3.9	$	3.4	$	—

The following table displays the contributions associated with each VIE:


(in millions)	December 31, 2021				December 31, 2020
	Rosewater		Indiana Crossroads Wind		Rosewater		Indiana Crossroads Wind
NIPSCO Cash Contribution	$	0.1	$	2.7	$	0.7	$	—
Tax Equity Partner Cash Contribution	7.5		237.6		86.1		—
NIPSCO's Obligation to Developer(1)	6.0		271.5		69.7		—
Total Contributions	$	13.6	$	511.8	$	156.5	$	—

(1)Included in "Other noncurrent liabilities" in the Consolidated Balance Sheets

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Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

We did not provide any financial or other support during the year that was not previously ~~recognized under Alternative Revenue accounting guidance are billed,~~contractually required, nor do we ~~reduce~~expect to provide such support in the ~~regulatory asset~~future.

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


(in millions)	December 31, 2021				December 31, 2020
	Rosewater		Indiana Crossroads Wind		Rosewater		Indiana Crossroads Wind
Net Property, Plant and Equipment	$	170.1	$	525.8	$	175.6	$	—
Current assets	6.2		8.1		1.7		—

Total assets(1)	176.3		533.9		177.3		—
Current liabilities	2.5		7.5		15.3		—
Asset retirement obligations	5.7		14.8		5.5		—
Other noncurrent liabilities	—		—		0.1		—
Total liabilities	$	8.2	$	22.3	$	20.9	$	—

(1)The assets of Rosewater and Indiana Crossroads represent assets of a ~~customer account receivable.~~consolidated VIE that can be used only to settle obligations of the respective consolidated VIE. The creditors of the liabilities of Rosewater and Indiana Crossroads do not have recourse to the general credit of the primary beneficiary.

4.5. Earnings Per Share

~~Basic~~The calculations of basic and diluted EPS ~~is computed by dividing net income attributable to common shareholders by~~are based on the ~~weighted-average~~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 ~~period. The weighted-average~~year ended December 31, 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 ~~outstanding for~~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 2021, net of tax, related to the purchase contracts.

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, 2021, the contingency was not resolved and thus no shares were reflected in the denominator in the calculation of diluted EPS for the year ended December 31, 2021.

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 ~~of such plans~~ would be dilutive. ~~The calculation~~Refer to Note 13, "Equity," for more information on our ATM forward agreements.

Table of diluted earnings per share excludes the impact of forward agreements (see Note 12, "Equity"), which had an anti-dilutive effect for the periods outstanding. The computation of diluted average common shares forContents

NISOURCE INC.

Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

For the year ended December 31, ~~2018 is not presented as~~2020, we ~~are presenting~~had a net loss on the Statements of Consolidated Income (Loss) ~~for~~during the period, and any ~~incremental~~potentially dilutive shares would have had an anti-dilutive impact on EPS. The ~~computation~~following table presents the calculation of our basic and diluted ~~average common shares is as follows:~~EPS:


Year Ended December 31, (in millions, except per share amounts)	2021		2020		2019
Numerator:
Net Income (Loss) Available to Common Shareholders - Basic	$	529.8	$	(72.7)	$	328.0
Dilutive effect of Equity Units	1.6		—		—
Net Income (Loss) Available to Common Shareholders - Diluted	$	531.4	$	(72.7)	$	328.0
Denominator:
Average common shares outstanding - Basic	393.6		384.3		374.6
Dilutive potential common shares:
Equity Units	22.0		—		—
Shares contingently issuable under employee stock plans	0.8		—		0.9
Shares restricted under employee stock plans	0.3		—		0.2
ATM Forward agreements	0.6		—		0.3
Average Common Shares - Diluted	417.3		384.3		376.0
Earnings per common share:
Basic	$	1.35	$	(0.19)	$	0.88
Diluted	$	1.27	$	(0.19)	$	0.87

Year Ended December 31, (in thousands)
2017 2016
Denominator
Basic average common shares outstanding 329,388
321,805
Dilutive potential common shares:
Shares contingently issuable under employee stock plans 547
165
Shares restricted under stock plans 821
1,554
Diluted Average Common Shares 330,756
323,524

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NISOURCE INC.

Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

5.6. Property, Plant and Equipment

Our property, plant and equipment on the Consolidated Balance Sheets are classified as follows:


At December 31, (in millions)	2021		2020
Property, Plant and Equipment
Gas Distribution Utility(1)	$	15,240.6	$	14,010.2
Electric Utility(1)	6,754.9		6,478.0
Corporate	217.8		197.3
Construction Work in Process	808.0		572.6
Renewable Generation Assets(2)	702.4		175.7
Non-Utility and Other(3)	1,447.6		2,746.1
Total Property, Plant and Equipment	$	25,171.3	$	24,179.9
Accumulated Depreciation and Amortization
Gas Distribution Utility(1)	$	(3,490.2)	$	(3,292.9)
Electric Utility(1)	(2,433.1)		(2,305.0)
Corporate	(132.2)		(109.3)
Renewable Generation Assets(2)	(6.5)		(0.1)
Non-Utility and Other(3)	(1,227.5)		(1,853.1)
Total Accumulated Depreciation and Amortization	$	(7,289.5)	$	(7,560.4)
Net Property, Plant and Equipment	$	17,881.8	$	16,619.5

At December 31, (in millions)
2018 2017
Property, Plant and Equipment
Gas Distribution Utility⁽¹⁾
$ 13,776.0
$ 12,531.0
Electric Utility⁽¹⁾
8,374.2
7,403.8
Corporate 155.8
141.3
Construction Work in Process 474.8
950.5
Non-Utility and Other⁽²⁾
38.7
623.3
Total Property, Plant and Equipment $ 22,819.5
$ 21,649.9
Accumulated Depreciation and Amortization
Gas Distribution Utility⁽¹⁾
$ (3,373.8 ) $ (3,227.8 )
Electric Utility⁽¹⁾
(3,809.5 ) (3,673.2 )
Corporate (74.6 ) (52.6 )
Non-Utility and Other⁽²⁾
(19.1 ) (336.8 )
Total Accumulated Depreciation and Amortization $ (7,277.0 ) $ (7,290.4 )
Net Property, Plant and Equipment $ 15,542.5
$ 14,359.5

⁽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 joint ventures between NIPSCO and unrelated tax equity partners, and depreciated straight-line over 30 years. Refer to Note 4, "Variable Interest Entities," for additional information.

(3)Non-Utility and Other as of December 31, ~~2017~~2020 includes net book value of ~~$247.8~~four coal units totaling $903.8 million related to ~~Bailly~~R.M. Schahfer Generating Station. Two of the four units were subsequently retired in 2021 and reclassified to current and long-term Regulatory Assets. Depreciation expense for the remaining net book value continues to be recorded at the composite depreciation rate approved by the IURC. As of December 31, 2021, Non-Utility and Other includes a net book value of $201.5 million related to the units not yet retired.

On October 1, 2021, NIPSCO retired R.M. Schahfer Generating Station ~~(Units 7~~Units 14 and ~~8) which~~15. The net book value of the retired units was reclassified from ~~Electric Utility in the fourth quarter~~"Net Property, Plant and Equipment," to current and long-term ''Regulatory Assets.'' The estimated net book value of ~~2016. In May 2018,~~R.M. Schahfer Generating Station's coal Units 714 and ~~8 were~~15 and other associated plant retired ~~from service and the remaining balance~~ was ~~reclassified to "Regulatory assets (noncurrent)" on the Consolidated Balance Sheets.~~approximately $600.0 million. See Note ~~18-E, "Other Matters," and Note 8,~~9, "Regulatory Matters," for additional ~~information.~~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, ~~2018, 2017~~2021, 2020 and ~~2016~~2019 were as follows:


	2021		2020		2019
Electric Operations(1)	3.4	%	3.4	%	2.8	%
Gas Distribution Operations	2.2	%	2.3	%	2.5	%

2018 2017 2016
Electric Operations⁽¹⁾
2.9 % 3.4 % 3.3 %
Gas Distribution Operations 2.2 % 2.1 % 2.1 %

⁽¹⁾~~Lower~~Increased rate beginning in 2020 primarily attributable to higher depreciation rates from the recent rate ~~in 2018 due to reduced EERM-related depreciation expense and higher depreciable base from transmission assets being placed into service in 2018.~~case proceeding.

We recognized depreciation expense of ~~$503.4~~$672.1 million, ~~$501.5~~$655.6 million and ~~$475.1~~$612.2 million for the years ended ~~2018, 2017~~2021, 2020 and ~~2016,~~2019, respectively. The 2021 depreciation expense amount includes a $5.3 million credit related to the regulatory deferral of income (loss) associated with our joint ventures, which is not included in current rates. See Note 9, "Regulatory Matters," for additional details.

Amortization of on-premise Software Costs. We amortized ~~$54.1~~$49.4 million, $56.7 million and $55.5 million in ~~2018, $44.0 million in 2017~~2021, 2020 and ~~$41.4 million in 2016~~2019, respectively, related to software ~~costs.~~recorded as intangible assets. Our unamortized software balance was ~~$159.5~~$181.8 million and ~~$189.0~~$136.4 million at December 31, ~~2018~~2021 and ~~2017,~~2020, respectively.

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6.NISOURCE INC.

Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

Amortization of Cloud Computing Costs. We amortized $10.0 million, $3.4 million and $1.6 million in 2021, 2020 and 2019, respectively, related to cloud computing costs to "Operation and maintenance" expense. Our unamortized cloud computing balance was $42.4 million and $12.7 million at December 31, 2021 and 2020, respectively.

7. Goodwill and Other Intangible Assets

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. ~~The following presents our~~Our goodwill balance ~~allocated by segment~~was $1,485.9 million as of December 31, ~~2018:~~

(in millions) Gas Distribution Operations Electric Operations Corporate and Other Total
Goodwill $ 1,690.7
$ —
$ —
$ 1,690.7

~~We applied the qualitative "step 0" analysis~~2021 and 2020. All our goodwill has been allocated to our ~~reporting units for the~~Gas Distribution Operations segment.

For our annual goodwill impairment ~~test~~analysis performed as of May 1, ~~2018.~~2021, 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 their ~~base line~~baseline May 1, ~~2016~~2020 "step 1" fair value measurement. ~~The results~~

Columbia of ~~this assessment indicated~~

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NIS~~OURCE~~ INC.

~~Notes to Consolidated Financial Statements~~

~~ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)~~

~~that it~~Massachusetts was not ~~more likely than not that our~~considered to be a reporting unit for May 1, 2020 fair ~~values were less than~~value measurement as the ~~reporting unit carrying values, accordingly, no "step 1"~~goodwill balance had been reduced to 0 as of December 31, 2019. During the fourth quarter of 2019, in connection with the preparation of the year-end financial statements, we assessed the matters related to the then proposed sale of the Massachusetts Business and determined a new impairment analysis was ~~required.~~

~~In the third quarter of 2018, we determined the Greater Lawrence Incident (see Note 18, "Other Commitments and Contingencies") represented a triggering event that~~ required ~~an impairment analysis of goodwill. This incident specifically impacts~~for our Columbia of Massachusetts reporting unit. Fair value of this reporting unit ~~in which~~was determined based on a weighting of income and market approaches. The income approach calculated discounted cash flows using updated cash flow projections, discount rates and return on equity assumptions. The market approach applied a combination of comparable company multiples and comparable transactions and used the ~~associated goodwill totaled $204.8 million immediately prior to the incident. We performed a quantitative~~most recent cash flow projections. The 2019 year-end impairment analysis ~~as of September 30, 2018 and determined~~indicated that the fair value of the Columbia of Massachusetts reporting unit ~~continues to exceed~~was below its carrying value. Therefore, no goodwill impairment charges were recorded in the third quarter of 2018. This interim analysis was performed using then-current cash flow projections reflecting the estimated ongoing impacts of the Greater Lawrence Incident on Columbia of Massachusetts' operations. We also updated other significant inputs to the fair value calculation (e.g. discount rate, market multiples) to reflect then-current market conditions and increased risk and uncertainty resulting from the incident. No additional facts came to light since the third quarter impairment analysis was completed that would indicate it was more likely than not that the fair value ofAs a result, we reduced the Columbia of Massachusetts reporting unit ~~would have decreased below its carrying value; therefore no~~goodwill balance to 0 and recognized a goodwill impairment ~~charges were recorded in the fourth quarter of 2018. We will continue~~charge totaling $204.8 million, which was non-deductible for tax purposes.

Intangible and Other Long-Lived Assets Impairment. Prior to ~~monitor the impacts of the incident for events that could trigger a new impairment analysis including, but not limited to, unfavorable regulatory outcomes and NTSB investigation results.~~

~~Intangible Assets.~~ ~~Our~~December 31, 2019, our intangible assets, apart from goodwill, ~~consist~~consisted of franchise ~~rights. Franchise~~ rights ~~were~~ identified as part of the purchase price allocations associated with the acquisition in February 1999 of Columbia of Massachusetts. ~~These amounts~~

During the fourth quarter of 2019, in connection with the preparation of the year-end financial statements, we assessed the changes in circumstances that occurred during the quarter to determine if it was more likely than not that the fair value of our long-lived assets (including franchise rights) were ~~$220.7~~below their carrying amount. As a result, we performed a year-end impairment test of our held and used long-lived assets in which we compared the book value of the Columbia of Massachusetts asset group to its undiscounted future cash flow and determined the carrying value of the asset group was not recoverable. We estimated the fair value of the Columbia of Massachusetts asset group using a weighting of income and market approaches and determined that the fair value was less than the carrying value. The resulting impairment was allocated to reduce the entire franchise rights book value to its fair value of zero, which resulted in an impairment charge totaling $209.7 million ~~and $231.7 million, net of accumulated amortization of $221.5 million and $210.5 million, at~~recorded in the Gas Distribution Operations segment during the year ended December 31, ~~2018~~2019.

As of December 31, 2021 and ~~2017, respectively, and are being amortized on a straight-line basis over forty years from~~2020, the ~~date~~carrying amount of ~~acquisition through 2039. NiSource~~the franchise rights was zero. We recorded zero amortization expense ofin 2021 and 2020 and $11.0 million in ~~2018, 2017, and 2016~~2019 related to ~~its~~our franchise ~~right~~rights intangible asset.

7.8. 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 joint venture 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 ~~a significant~~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.

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NISOURCE INC.

Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

Changes in our liability for asset retirement obligations for the years ~~2018~~2021 and ~~2017~~2020 are presented in the table below:


(in millions)	2021		2020
Beginning Balance	$	495.6	$	416.9
Accretion recorded as a regulatory asset/liability	16.0		17.3
Additions	23.2		5.5
Settlements	(11.2)		(13.9)
Change in estimated cash flows	(11.2)		86.0		(1)
Other	—		(16.2)		(2)
Ending Balance	$	512.4	$	495.6

(in millions) 2018 2017
Beginning Balance $ 268.7
$ 262.6

Accretion recorded as a regulatory asset/liability 11.1
10.3

Additions 63.3
⁽¹⁾
2.4

Settlements (5.9 ) (15.6 )
Change in estimated cash flows
14.8
⁽¹⁾
9.0
⁽²⁾
Ending Balance $ 352.0
$ 268.7

⁽¹⁾~~In 2018, $59.8 million of additions and $17.7 million of the~~The change in estimated cash flows ~~are~~for 2020 is primarily attributed to revisions to the estimated costs associated with refining the CCR compliance ~~plan. See Note 18-D, "Environmental Matters," for additional information on CCRs.~~

⁽²⁾~~The change in estimated cash flows for 2017 is primarily attributed to~~plan, changes in estimated costs ~~and settlement timing~~ for electric generating stations and the changes in estimated costs for retirement of gas mains. See Note 19-E, "Environmental Matters," for additional information on CCRs.

(2)Represents the Columbia of Massachusetts Asset Retirement Obligations that were included in the sale of the Massachusetts Business that occurred on October 9, 2020.

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.

669. Regulatory Matters

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NIS~~OURCE~~ INC.

~~Notes to Consolidated Financial Statements~~

~~ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)~~


8.	~~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 ifwhen the rates established are designed to recover the costs of providing the regulated service and it is probable that such rates ~~can~~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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NISOURCE INC.

Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

Regulatory assets were comprised of the following items:


At December 31, (in millions)	2021		2020
Regulatory Assets
Unrecognized pension and other postretirement benefit costs (see Note 12)	$	512.1	$	583.3
Deferred pension and other postretirement benefit costs (see Note 12)	74.8		72.4
Environmental costs (see Note 19-E)	45.8		56.6
Regulatory effects of accounting for income taxes (see Note 1-N and Note 11)	194.8		194.5
Under-recovered gas and fuel costs (see Note 1-J)	73.6		8.0
Depreciation	177.5		192.6

Post-in-service carrying charges	237.9		228.6



Safety activity costs	171.9		146.0
DSM programs	39.2		37.8
Retired coal generating stations	803.9		204.7
Losses on commodity price risk programs (See Note 10)	9.6		54.7
Deferred property taxes	65.1		62.9
Renewable energy investments (See Note 1-S and Note 4)	18.5		—
Other	67.5		88.4
Total Regulatory Assets	$	2,492.2	$	1,930.5
Less: Current Portion	206.2		135.7
Total Noncurrent Regulatory Assets	$	2,286.0	$	1,794.8

At December 31, (in millions)
2018 2017
Regulatory Assets
Unrecognized pension and other postretirement benefit costs (see Note 11) $ 798.3
$ 733.5
Deferred pension and other postretirement benefit costs (see Note 11) 74.1
70.7
Environmental costs (see Note 18-D) 61.5
63.4
Regulatory effects of accounting for income taxes (see Note 1-N and Note 10) 233.1
238.8
Under-recovered gas and fuel costs (see Note 1-K) 34.7
25.5
Depreciation 209.6
181.0
Post-in-service carrying charges 206.6
173.3
Safety activity costs 91.7
66.5
DSM programs 45.5
40.0
Bailly Generating Station 244.3
—
Other 238.1
208.5
Total Regulatory Assets $ 2,237.5
$ 1,801.2

Regulatory liabilities were comprised of the following items:


At December 31, (in millions)	2018		2017		At December 31, (in millions)	2021		2020
Regulatory Liabilities					Regulatory Liabilities
Over-recovered gas and fuel costs (see Note 1-K)	$	32.0	$	27.6
Cost of removal (see Note 7)	1,076.0		1,096.8
Regulatory effects of accounting for income taxes (see Note 1-O and Note 10)	1,428.3		1,563.4
Deferred pension and other postretirement benefit costs (see Note 11)	62.7		59.0
Over-recovered gas and fuel costs (see Note 1-J)					Over-recovered gas and fuel costs (see Note 1-J)	$	5.4	$	47.8
Cost of removal (see Note 8)					Cost of removal (see Note 8)	749.5		775.2
Regulatory effects of accounting for income taxes (see Note 1-N and Note 11)					Regulatory effects of accounting for income taxes (see Note 1-N and Note 11)	1,040.8		1,105.1
Deferred pension and other postretirement benefit costs (see Note 12)					Deferred pension and other postretirement benefit costs (see Note 12)	75.9		69.5
Gains on commodity price risk programs (See Note 10)					Gains on commodity price risk programs (See Note 10)	34.2		14.0
Other	61.0		48.8		Other	74.2		53.9
Total Regulatory Liabilities	$	2,660.0	$	2,795.6	Total Regulatory Liabilities	$	1,980.0	$	2,065.5
Less: Current Portion					Less: Current Portion	137.4		161.3
Total Noncurrent Regulatory Liabilities					Total Noncurrent Regulatory Liabilities	$	1,842.6	$	1,904.2

Regulatory assets, including under-recovered gas and fuel ~~cost,~~costs and depreciation, of approximately ~~$1,552.6~~$1,207.0 million and $1,260.6 million as of December 31, ~~2018~~2021 and 2020, respectively, are not earning a return on investment. These costs are recovered over a remaining life, the longest of ~~up to 41~~which is 48 years. Regulatory assets of approximately $1,917.1 million include expenses that are recovered as components of the cost of service and are covered by regulatory orders. Regulatory assets of approximately $320.4 million at December 31, 2018, require specific rate action.

Assets:

Unrecognized pension and other postretirement benefit costs. ~~In 2007, we adopted certain updates of ASC 715 which required, among other things,~~ Represents the ~~recognition in~~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. Certain~~costs by certain subsidiaries ~~defer these gains or losses as a regulatory asset in accordance with regulatory orders or as a result of regulatory precedent, to~~that will ultimately be recovered through base rates.

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NIS~~OURCE~~ INC.

~~Notes to Consolidated Financial Statements~~

~~ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)~~

Deferred pension and other postretirement benefit costs. Primarily relates to the difference between ~~postretirement~~defined benefit plan expense recorded by certain subsidiaries due to regulatory orders and the ~~postretirement~~corresponding expense that would otherwise be recorded in accordance with GAAP. ~~These~~The majority of these amounts are driven by Columbia of Ohio. The timeframe for the

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NISOURCE INC.

Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

recovery of these costs are expected to be addressed in our base rate case, and the costs are expected to be collected through future base rates, revenue riders or tracking mechanisms.

Environmental costs.Includes certain recoverable ~~costs of investigating, testing, remediating and other~~ costs related to gas plant sites, disposal sites or other sites onto which material may have ~~migrated. Certain~~migrated, the recovery of ~~our companies defer the costs as a regulatory asset in accordance with regulatory orders,~~which is to be ~~recovered~~addressed in future base rates, billing riders or tracking ~~mechanisms.~~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. In prior years, we have lowered customer rates in certain jurisdictions for the benefits of accelerated tax deductions. Amounts are expensed for financial reporting purposes as we recover 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. ~~Significant components~~The majority of this balance ~~include:~~

is driven by Columbia of ~~Ohio depreciation rates~~. Prior to 2005, the PUCO-approved depreciation rates for rate-making had been lower than those which would have been utilized if Columbia of Ohio were not subject to regulation resulting in the creation of a regulatory asset. In 2005, the PUCO authorized Columbia of Ohio to revise its depreciation accrual rates for the period beginning January 1, 2005. The revised depreciation rates are now higher than those which would have been utilized if Columbia of Ohio were not subject to regulation allowing for amortization of the previously created regulatory asset. The amount of depreciation that would have been recorded from 2005 through 2018 had Columbia of Ohio not been subject to rate regulation is a cumulative $806.8 million, $92.2 million less than that reflected in rates. The resulting regulatory asset balance was $39.5 million and $49.3 million as of December 31, 2018 and 2017, respectively.

~~Columbia of Ohio~~Ohio's IRP and ~~CEP.~~ ~~Columbia of Ohio also has PUCO approval to defer depreciation and debt-based post-in-service carrying charges (see "Post-in-service carrying charges"~~ below) associated with its IRP and CEP. As of December 31, 2018, depreciation of $29.1 million and $76.0 million was deferred for the respective programs. Depreciation deferral balances for the respective programs as of December 31, 2017 were $26.5 million and $49.8 million.CEP deferrals. Recovery of ~~the IRP depreciation~~these amounts is approved annually through the ~~IRP rider. The equivalent of annual depreciation expense, based on the average life of the~~ related assets, is included in the calculation of the IRP rider approved by the PUCO and billed to customers. Deferred depreciation expense is recognized as the IRP rider is billed to customers. The recovery mechanism for depreciation associated with the CEP is discussed in "Additional Regulatory Matters," below.

riders.

~~NIPSCO ECRM.~~ NIPSCO obtained approval from the IURC to recover certain environmental related costs including operation and maintenance and depreciation expense once the environmental facilities become operational. The ECRM deferred charges represent expenses that will be recovered from customers through an annual ECRM Cost Tracker (ECT) which authorizes the collection of deferred balances over a six month period. Recovery of these costs will continue until such assets are included in rate base through an electric base rate case. Depreciation of $14.4 million and $13.9 million was deferred to a regulatory asset as of December 31, 2018 and 2017, respectively.

~~NIPSCO TDSIC.~~ NIPSCO obtained approval from the IURC to recover costs for certain system modernization projects outside of a base rate proceeding. Eighty percent of the related costs, including depreciation, property taxes, and debt and equity based carrying charges (see ~~"Post-in-service carrying charges"~~ below) are recovered through a semi-annual recovery mechanism. Recovery of these costs will continue through the TDSIC tracker until such assets are included in rate base through a gas or electric base rate case, respectively. The remaining twenty percent of the costs are deferred until the next base rate case. As of December 31, 2018 and 2017, depreciation of $16.5 million and $10.3 million, respectively, was deferred as a regulatory asset.

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. ~~This~~The majority of this balance ~~includes:~~

is driven by Columbia of ~~Ohio IRP and CEP.~~ ~~See description of~~Ohio's IRP and CEP ~~programs above under the heading "Depreciation." As of December 31, 2018 and 2017, Columbia of Ohio had deferred PISCC of $197.1 million and $164.6 million, respectively.~~

deferrals.

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NIS~~OURCE~~ INC.

~~Notes to Consolidated Financial Statements~~

~~ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)~~

~~NIPSCO TDSIC.~~ ~~See description of TDSIC program above under the heading "Depreciation~~." Deferral of equity-based carrying charges for the TDSIC program is allowed; however, such amounts are not reflected in regulatory asset balances for financial reporting as equity-based returns do not meet the definition of incurred costs under ASC 980. As of December 31, 2018 and 2017, NIPSCO had deferred PISCC of $9.5 million and $8.7 million, respectively.

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 eligible cost deferrals represent necessary business expenses incurred in compliance with PHMSA regulations and are targeted to enhance the safety of the pipeline systems. Certain subsidiaries defer the excess costs as a regulatory asset in accordance with regulatory orders and recovery of these costs will be address in future base rate proceedings.

DSM programs. Represents costs associated with Gas Distribution Operations and Electric Operations segments' energy efficiency and conservation programs. Costs are recovered through tracking mechanisms.

~~Bailly Generating Station.~~ Retired coal generating stations. Represents the net book value of Units 7 and 8 of Bailly Generating Station that was retired during ~~2018.~~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.

~~Liabilities:~~Losses on commodity price risk programs. Represents the unrealized losses related to certain of our subsidiary's commodity price risk programs. These programs help to protect against the volatility of commodity prices and these amounts are collected from customers through their inclusion in customer rates.

Deferred property taxes. Represents the deferral and under collection of property taxes in the rate making process for Columbia of Ohio and is driven by the IRP and CEP deferrals.

Renewable energy investments. Represents the regulatory deferral of certain amounts representing the timing difference between the profit earned from the joint ventures and the amount included in regulated rates to recover our approved investments in consolidated joint ventures. These amounts will be collected through base rates over the life of the renewable generating assets to which they relate. Refer to Note 1-S, "VIEs and Allocation of Earnings," for additional information. Renewable energy formation and developer costs are also included in this regulatory asset.

Liabilities:

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 ~~and continue to be, included in~~collected through depreciation rates ~~and collected in customer rates of the rate-regulated subsidiaries~~ for future costs to be incurred.

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NISOURCE INC.

Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

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 that are established during the rate making process.~~customers. Balance includes excess deferred taxes recorded upon implementation of the TCJA in December 2017, net of amounts amortized ~~during 2018.~~through 2021.

Deferred pension and other postretirement benefit costs. Primarily represents cash contributions in excess of postretirement benefit expense that is deferred ~~as a regulatory liability~~ by certain ~~subsidiaries in accordance with regulatory orders.~~subsidiaries.

~~Cost Recovery and Trackers~~

~~Comparability~~Gains on commodity price risk programs. Represents the unrealized gains related to certain of our ~~line item operating results is impacted by~~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.

COVID-19 Regulatory Filings

In response to COVID-19, we received approvals or directives from the regulatory ~~trackers that allow for the recovery in rates of certain costs such as those described below. Increases~~commissions in the ~~expenses that~~states in which we operate. The ongoing impacts of these approvals or directives are described in the ~~subject of trackers generally result~~table below:


Jurisdiction	Moratorium in Place?	Regulatory Asset balance as of December 31, 2021 (in millions)		Regulatory Asset balance as of December 31, 2020 (in millions)		Deferred COVID-19 Costs
Columbia of Ohio	No	$	2.1	$	2.0	Incremental operation and maintenance expenses
NIPSCO	No	$	2.2	$	9.2	Incremental bad debt expense and the costs to implement the requirements of the COVID-19 related order
Columbia of Pennsylvania	No	$	5.2	$	5.4	Incremental bad debt expense incurred from March 13, 2020 through December 29, 2021, above levels currently in rates
Columbia of Virginia	No	$	1.5	$	—	Incremental incurred costs (including incremental bad debt expense), subject to an earnings test review
Columbia of Maryland	No	$	0.9	$	0.7	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

The Pennsylvania PUC adopted an order on March 11, 2021, and subsequently reaffirmed their stance in a ~~corresponding increase~~June 23, 2021 order, which lifted its prior pandemic-related moratorium on service terminations for non-payments of utility bills beginning April 1, 2021. Pursuant to that order, Pennsylvania utilities are required to offer payment plans on billing arrearages, with the length of such payment plans depending on a customer's income level. Pursuant to a subsequent order, Pennsylvania utilities were no longer required to offer these extended pandemic-related payment arrangements to customers in ~~operating revenues~~arrears as of October 1, 2021.On December 16, 2021, CPA received a final order approving its 2021 base rate case, which includes a provision to discontinue the deferral of COVID-19 uncollectible accounts as of December 29, 2021 and ~~therefore have essentially no impact on total operating income results.~~

~~Certain costs of our operating companies are significant, recurring in nature and generally outside the control of the operating companies. Some states allow the~~begin recovery of ~~such costs through cost tracking mechanisms. Such tracking mechanisms allow for abbreviated regulatory proceedings in order for~~amounts deferred as of 12/31/2020 over a five year period beginning on January 1, 2022.

For Columbia of Virginia, the operating companies to implement charges and recover appropriate costs. Tracking mechanisms allow for more timely recovery of such costs as compared with more traditional cost recovery mechanisms. Examples of such mechanisms include GCR adjustment mechanisms, tax riders, bad debt recovery mechanisms, electric energy efficiency programs, MISO non-fuel costs and revenues, resource capacity charges, federally mandated costs and environmental-related costs.

A portion of the Gas Distribution 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 procurement activity to determine prudence and to permit the recovery of prudently incurred costs related to the supply of gas for customers. Our distribution companies have historically been found prudent in the procurement of gas supplies to serve customers.

~~A portion of the Electric Operations revenue is related to the recovery of fuel costs to generate power~~moratorium on non-residential disconnections ended on October 6, 2020, and the ~~fuel costs related~~moratorium on residential disconnections and late payment fees ended on August 30, 2021. Legislative and regulatory requirements extending COVID-19 payment plans between 6 and 24 months remain in place.

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 ~~purchased power. These costs are recovered through a FAC, a quarterly~~customer accounts in August 2021. As such, all termination moratoriums were lifted and normal collections procedures resumed on November 1, 2021.

Unless otherwise noted above, all other pandemic-related regulatory ~~proceeding in Indiana.~~

~~Infrastructure Replacement and Federally-Mandated Compliance Programs~~

~~Certain of our operating companies~~actions have ~~completed rate proceedings involving infrastructure replacement~~expired or ~~enhancement or are embarking upon regulatory initiatives to replace significant portions of their operating systems that are nearing the end of their~~

been lifted.

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Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

~~useful lives. Each operating company's approach to cost recovery may be unique, given the different laws, regulations and precedent that exist in each jurisdiction.~~

~~Columbia of Ohio, IRP~~ - On December 3, 2008, the PUCO issued an order which established Columbia of Ohio’s IRP. Pursuant to that order, the IRP provides for recovery of costs resulting from: (1) the maintenance, repair and replacement of customer-owned service lines that have been determined by Columbia of Ohio to present an existing or probable hazard to persons and property; (2) Columbia of Ohio’s replacement of cast iron, wrought iron, unprotected coated steel and bare steel pipe and associated company and customer-owned metallic service lines; (3) the replacement of customer-owned natural gas risers identified by the PUCO as prone to failure; and (4) the installation of AMR devices on all residential and commercial meters served by Columbia of Ohio. Recoverable costs include a return on investment, depreciation and property taxes, offset by specified cost savings. Columbia of Ohio’s five-year IRP plan renewal was last approved on January 31, 2018 for the years 2018-2022.

~~NIPSCO Gas and Electric, TDSIC~~ - On April 30, 2013, the Indiana Governor signed Senate Enrolled Act 560, known as the TDSIC statute, into law. Among other provisions, the TDSIC statute provides for cost recovery outside of a base rate proceeding for new or replacement electric and gas transmission, distribution, and storage projects that a public utility undertakes for the purposes of safety, reliability, system modernization or economic development. Provisions of the TDSIC statute require that, among other things, requests for recovery include a seven-year plan of eligible investments. Once the plan is approved by the IURC, eighty percent of eligible costs can be recovered using a periodic rate adjustment mechanism, known as the TDSIC mechanism. Recoverable costs include a return on the investment, including AFUDC, PISCC, operation and maintenance expenses, depreciation and property taxes. The remaining twenty percent of recoverable costs are deferred for future recovery in NIPSCO's next general rate case. The semi-annual rate adjustment mechanism is capped at an annual increase of two percent of total retail revenues.

~~NIPSCO Electric, ECRM~~ - NIPSCO has approval from the IURC to recover certain environmental related costs through an ECT (environmental cost tracker). Under the ECT, NIPSCO is permitted to recover (1) AFUDC and a return on the capital investment expended by NIPSCO to implement environmental compliance plan projects and (2) related operation and maintenance and depreciation expenses once the environmental facilities become operational.

~~NIPSCO Gas and Electric, FMCA~~ - The FMCA statute provides for cost recovery outside of a base rate proceeding for projected federally mandated costs. Once the plan is approved by the IURC, eighty percent of eligible costs can be recovered using a periodic rate adjustment mechanism, known as the FMCA mechanism. Recoverable costs include a return on the investment, including AFUDC, PISCC, mandated operation and maintenance expenses, depreciation and property taxes. The remaining twenty percent of recoverable costs are deferred for future recovery in NIPSCO's next general rate case. Actual costs that exceed the projected federally mandated costs of the approved compliance project by more than twenty-five percent shall require specific justification by NIPSCO and specific approval by the IURC before being authorized in the next general rate case.

~~Columbia of Massachusetts, GSEP~~ - On July 7, 2014, the Governor of Massachusetts signed into law Chapter 149 of the Acts of 2014, an Act Relative to Natural Gas Leaks (“the Act”). The Act authorizes natural gas distribution companies to file a GSEP for capital investments made on or after January 1, 2015, that are not included in the Company’s current rate base as determined in the most recent base rate case, with the Massachusetts DPU to (1) address the replacement or improvement of existing aging natural gas pipeline infrastructure to improve public safety or infrastructure reliability, and (2) reduce the lost and unaccounted for natural gas through a reduction in natural gas system leaks. In addition, the Act provides that the Massachusetts DPU may, after review of the plan, allow the proposed estimated costs of the plan into rates as of May 1 of the subsequent year. Recoverable costs include a return on investment, depreciation and property taxes, offset by identified operations and maintenance cost savings. Rates are subject to a capped annual revenue increase of one and a half percent of total annual delivery and cost of gas revenues from sales and transportation, including imputed gas revenues for transportation, for the calendar year preceding the projected GSEP calendar year being filed. At the end of each 12-month period, in May of the subsequent year, Columbia of Massachusetts must file a reconciliation of the amount collected and actual costs. Any over-collection or under-collection balance is passed back to, or recovered from, customers over a 12-month period beginning in November. Once new base rates are established under a base rate proceeding, the GSEP factor is re-set to remove the capital investment and associated revenue reflected in the base rates.

~~Columbia of Pennsylvania, DSIC~~ - On February 14, 2012, the Governor of Pennsylvania signed into law Act 11 of 2012, which provided a DSIC mechanism for certain utilities to recover costs related to repair, replacement or improvement of eligible distribution property that has not previously been reflected in rates or rate base. Through a DSIC, a utility may recover the fixed costs of eligible infrastructure incurred during the three months ended one month prior to the effective date of the charge, thereby reducing the historical regulatory lag associated with cost recovery through the traditional rate-making process. On March 14, 2013, the Pennsylvania PUC approved Columbia of Pennsylvania’s petition to implement a DSIC as of April 1, 2013. Accordingly, Columbia of Pennsylvania is authorized to recover the cost of eligible plant associated with repair, replacement or improvement that was not

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~~Notes to Consolidated Financial Statements~~

~~ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)~~

previously reflected in rate base and has been placed in service during the applicable three-month period. After the initial charge is established, the DSIC is updated quarterly to recover the cost of further plant additions and cannot exceed five percent of distribution revenues. Recoverable costs include a return on investment, exclusive of accumulated deferred income taxes from the calculation of rate base, and depreciation. Once new base rates are established under a base rate proceeding, the DSIC is set to zero. Additionally, the DSIC rate is also reset to zero if, in any quarter, the data reflected in the Columbia of Pennsylvania's most recent quarterly financial earnings report show that the utility will earn an overall rate of return that would exceed the allowable rate of return used to calculate its fixed costs under the DSIC mechanism. A utility is exempt from filing a quarterly financial earnings report when a base rate proceeding is pending before the Pennsylvania PUC.

~~Columbia of Virginia, SAVE -~~ On March 11, 2010, the Virginia Governor signed legislation into law that allows natural gas utilities to implement programs to replace qualifying infrastructure on an expedited basis and provides for timely cost recovery. Known as the SAVE Act, the law allows natural gas utilities to file programs with the VSCC providing a timeline and estimated costs for replacing eligible infrastructure. Eligible infrastructure replacement projects are those that (1) enhance safety or reliability by reducing system integrity risks associated with customer outages, corrosion, equipment failures, material failures, or natural forces; (2) do not increase revenues by directly connecting the infrastructure replacement to new customers; (3) reduce or have the potential to reduce greenhouse gas emissions; (4) are not included in the natural gas utility’s rate base in its most recent rate case; and (5) are commenced on or after January 1, 2010. The SAVE Act provides for recovery of costs associated with the eligible infrastructure through a rate rider. Recoverable costs include a return on investment, depreciation and property taxes. Columbia of Virginia’s current five year SAVE plan was approved by the VSCC in 2016 and amended in 2017 for the years 2016 through 2020.

~~Columbia of Kentucky, AMRP~~ - On October 26, 2009, the Kentucky PSC approved a mechanism for recovering the costs of Columbia of Kentucky’s AMRP not previously reflected in rate base through an annual fixed monthly rate rider filed in October.In its 2013 rate case, Columbia of Kentucky was allowed to base the AMRP rider on the expected annual cost of service. Recoverable costs include a return on investment, depreciation and property taxes, offset by specific cost savings. At the end of each 12-month period, Columbia of Kentucky must file a reconciliation of the amount collected and actual costs. Any over-collection or under-collection balance is passed back to, or recovered from, customers through the surcharge over a 12-month period beginning in June of the subsequent year. Once new base rates are established under a base rate proceeding, the AMRP rider is set to zero.

~~Columbia of Maryland, STRIDE~~ - On May 2, 2013, the Governor of Maryland signed Senate Bill 8 into law, authorizing gas companies to accelerate recovery of eligible infrastructure replacement, effective June 1, 2013. The STRIDE statute provides recovery for gas pipeline upgrades outside of the context of a base rate proceeding through an annual surcharge, IRIS, as approved by, Maryland PSC. The STRIDE statute directs gas utilities to file a plan to invest in eligible infrastructure replacement projects and to list the specific projects and elements in any such STRIDE plan with the Maryland PSC. The calendar year projected capital projects to be placed into plant in service and included in Columbia of Maryland's surcharge recovery request must satisfy a number of criteria per the statute, including a requirement that they be designed to improve public safety or infrastructure reliability. Columbia of Maryland’s five-year STRIDE Plan renewal for years 2019 through 2023, as with the preceding five years, is focused on replacing (1) existing cast iron and bare steel mains, (2) associated services and meters, and (3) identified prone-to-failure vintage plastic piping. Columbia of Maryland’s IRIS mechanism recovers a return on investment, depreciation and property taxes of the STRIDE-eligible capital infrastructure statutorily capped at $2 per month for residential customers, and proportionally capped for commercial and industrial customer classes, and is reconciled to actual costs on an annual basis. Any over-collection or under-collection balance is passed back to, or recovered from, customers through the surcharge effective in May of the subsequent year.

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~~Notes to Consolidated Financial Statements~~

~~ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)~~

~~The following table describes regulatory programs to recover infrastructure replacement and other federally-mandated compliance investments currently in rates and those pending commission approval:~~

(in millions)
Company Program Incremental Revenue Incremental Capital Investment Investment Period Filed Status
Rates
Effective
Columbia of Ohio
IRP - 2018⁽¹⁾
$ 2.3
$ 207.0
1/17-12/17 February 27, 2018 Approved
April 25, 2018 May 2018
NIPSCO - Gas TDSIC 7 $ 1.5
$ 59.0
1/17-6/17 August 31, 2017 Approved
December 28, 2017 January 2018
NIPSCO - Gas TDSIC 8 $ 1.8
$ 54.0
7/17-12/17 February 27, 2018 Approved
August 22, 2018 September 2018
NIPSCO - Gas
TDSIC 9⁽¹⁾⁽²⁾
$ (10.6 ) $ 54.4
1/18 - 6/18 August 28, 2018 Approved
December 27, 2018 January 2019
NIPSCO - Gas FMCA 1 $ 9.9
$ 1.5
11/17-9/18 November 30, 2018 Order Expected
Q1 2019 April 2019
Columbia of Massachusetts
GSEP - 2018⁽¹⁾⁽³⁾
$ 6.5
$ 80.0
1/18-12/18 October 31, 2017 Approved
April 30, 2018 May 2018
Columbia of Massachusetts
GSEP - 2019⁽⁴⁾
$ 10.7
$ 64.0
1/19-12/19 October 31, 2018 Order expected
Q2 2019 May 2019
Columbia of Pennsylvania DSIC - 2018 $ 0.4
$ 14.8
12/17-2/18 March 22, 2018 Approved
March 29, 2018 April 2018
Columbia of Pennsylvania DSIC - 2018 $ 0.9
$ 31.8
3/18-5/18 June 20, 2018 Approved
June 28, 2018 July 2018
Columbia of Pennsylvania DSIC - 2018 $ 1.6
$ 55.4
6/18-8/18 September 20, 2018 Approved
September 28, 2018 October 2018
Columbia of Virginia SAVE - 2018 $ 2.9
$ 33.3
1/18-12/18 August 18, 2017 Approved
December 13, 2017 January 2018
Columbia of Virginia SAVE - 2019 $ 2.4
$ 36.0
1/19-12/19 August 17, 2018 Approved
October 26, 2018 January 2019
Columbia of Kentucky AMRP - 2018 $ 4.5
$ 24.0
1/18-12/18 October 13, 2017 Approved
December 22, 2017 January 2018
Columbia of Kentucky AMRP - 2019 $ 3.6
$ 30.1
1/19-12/19 October 15, 2018 Approved
December 5, 2018 January 2019
Columbia of Maryland STRIDE - 2018 $ 1.2
$ 20.8
1/18-12/18 November 1, 2017 Approved
December 20, 2017 January 2018
Columbia of Maryland STRIDE - 2019 $ 1.2
$ 19.7
1/19-12/19 November 1, 2018 Approved
December 12, 2018 January 2019
NIPSCO - Electric TDSIC - 3 $ (2.0 ) $ 75.0
5/17-11/17 January 30, 2018 Approved
May 30, 2018 June 2018
NIPSCO - Electric
TDSIC - 4⁽¹⁾
$ (11.8 ) $ 72.2
12/17-5/18 July 31, 2018 Approved
November 28, 2018 December 2018
NIPSCO - Electric
TDSIC - 5⁽¹⁾
$ 15.9
$ 58.8
6/18-11/18 January 29, 2019 Order Expected
Q2 2019 June 2019
NIPSCO - Electric ECRM - 31 $ (2.1 ) $ 2.9
6/17-12/17 January 31, 2018 Approved
April 25, 2018 May 2018
NIPSCO - Electric ECRM - 32 $ 1.0
$ —
1/18-6/18 July 31, 2018 Approved
October 11, 2018 November 2018
NIPSCO - Electric FMCA - 8 $ 1.3
$ 4.4
4/17-9/17 November 1, 2017 Approved
January 31, 2018 February 2018
NIPSCO - Electric FMCA - 9 $ 4.1
$ 90.2
10/17-3/18 April 27, 2018 Approved
July 25, 2018 August 2018
NIPSCO - Electric FMCA - 10 $ 2.2
$ 45.7
4/18-8/18 October 18, 2018 Approved
January 29, 2019 February 2019

⁽¹⁾~~Incremental revenue is net of amounts due back to customers as a result of the TCJA.~~

⁽²⁾~~Incremental revenue is net of $5.2 million of adjustments in the TDSIC-9 settlement.~~

⁽³⁾~~A cap waiver was approved by the Massachusetts DPU on June 21, 2018 and related rates became effective July 2018.~~

⁽⁴⁾~~The filing included a request for approval of a waiver to allow collection of the $2.9 million revenue requirement that exceeds the GSEP cap provision.~~

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~~Notes to Consolidated Financial Statements~~

~~ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)~~

~~Rate Case Actions~~

~~The following table describes current rate case actions as applicable in each of our jurisdictions net of tracker impacts:~~

(in millions)
Company Requested Incremental Revenue Approved Incremental Revenue Filed Status
Rates
Effective
NIPSCO - Gas⁽¹⁾
$ 138.1
$ 107.3
September 27, 2017 Approved
September 19, 2018 October 2018
Columbia of Massachusetts $ 24.1
N/A
April 13, 2018 Withdrawn
September 19, 2018 N/A
Columbia of Pennsylvania $ 46.9
$ 26.0
March 16, 2018 Approved
December 6, 2018 December 2018
Columbia of Virginia⁽²⁾
$ 14.2
In process
August 28, 2018 Order expected
Second half of 2019 February 2019
Columbia of Maryland $ 4.6
$ 2.2
April 13, 2018 Approved
November 21, 2018 November 2018
NIPSCO - Electric $ 21.4
In process
October 31, 2018 Order expected
Q3 2019 September 2019

⁽¹⁾Rates will be implemented in three steps, with implementation of step 1 rates effective October 1, 2018. Step 2 rates will be effective on or about March 1, 2019, and step 3 rates will be effective on January 1, 2020. The IURC’s order also dismissed NIPSCO from phase 2 of the IURC’s TCJA investigation.

⁽²⁾~~Rates implemented subject to refund pending a final order from the VSCC.~~

~~Additional Regulatory Matters~~

~~Columbia of Ohio.~~ On December 1, 2017, Columbia of Ohio filed an application that requested authority to implement a rider to begin recovering plant and associated deferrals related to its CEP. The CEP was established in 2011 and allows for deferral of interest, depreciation and property taxes on certain plant investments not recovered through its IRP modernization tracker. The application requested authority to increase annual revenues, through the requested rider, by approximately $70 million, with biennial increases up to approximately $98 million in 2022. On May 9, 2018, the PUCO appointed an independent auditor to assist the PUCO with the review of the accounting accuracy, prudency and compliance of Columbia of Ohio with its PUCO-approved CEP deferrals. The independent audit report was filed on September 4, 2018 and the PUCO Staff's Report on the investigation was filed on September 14, 2018. On October 25, 2018, a joint stipulation and recommendation was filed recommending an initial revenue requirement of $74.5 million to recover CEP investments and deferrals through December 31, 2017, with annual adjustments for capital investments made in subsequent years. Additionally, the signatory parties to the stipulation agreed to a reduction in rates to adjust for the impacts of the TCJA and for a base rate case filing to be made by Columbia of Ohio with a test period of calendar year 2021. On November 28, 2018 the PUCO issued an order unanimously approving the settlement filed on October 25, 2018, without modification, for rates effective beginning November 29, 2018. This order finalizes Columbia of Ohio's TCJA resolution related to the CEP tracker, as well as base rates.

~~NIPSCO Gas.~~ On November 8, 2017, NIPSCO filed a petition with the IURC seeking approval of NIPSCO’s federally mandated pipeline safety compliance plan. As part of the settlement agreement filed in NIPSCO’s gas base rate case proceeding, NIPSCO and the parties to the settlement agreement settled all issues in this proceeding as well, including moving certain costs from the base rate proceeding to this pipeline safety compliance plan. The updated four year compliance plan includes a total estimated $91.5 million of capital costs and $35.5 million of expected operating and maintenance costs. NIPSCO received approval for accounting and rate-making relief, including establishment of a periodic rate adjustment mechanism. NIPSCO filed the first tracker proceeding in this case on November 30, 2018. On December 31, 2018, NIPSCO filed a petition with the IURC seeking approval of an additional PHMSA compliance plan including capital expenditures of $228.8 million. An IURC order is expected in the second half of 2019.

On January 3, 2018, the IURC initiated an investigation to review and consider the possible implications of the TCJA on utility rates. The IURC ordered a two phase investigation. Phase 1 solely dealt with the prospective changes in rates to reflect the change in tax rates. In accordance with the procedural schedule, on March 26, 2018, NIPSCO filed revised gas tariffs reflecting the impact of the change in tax rate for its applicable rates and charges. The IURC approved NIPSCO's Phase 1 filing on April 26, 2018. The revised tariffs were effective May 1, 2018. The stipulation and settlement agreement filed on April 20, 2018, in NIPSCO’s gas rate case resolved all issues in Phase 2, including the return of excess income tax revenue recovered through its base rates and any

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~~Notes to Consolidated Financial Statements~~

~~ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)~~

~~applicable charges between January 1, 2018 and April 30, 2018. Beginning January 2019, and continuing through June 2019, NIPSCO is passing back the excess tax expense through the TDSIC mechanism.~~

On December 27, 2018, the IURC issued an order for TDSIC-9 approving the settlement agreement filed on November 4, 2018. This order, along with the Court of Appeals dismissal on December 31, 2018 and January 8, 2019, resolved all outstanding issues related to the appeals of TDSIC-4 though TDSIC-8.

~~Columbia of Massachusetts.~~ On October 9, 2018, Columbia of Massachusetts filed an application with the Massachusetts DPU, seeking authority to pass back approximately $95.8 million in excess deferred taxes associated with TCJA with an effective date of rates to be determined by the Massachusetts DPU. On December 21, 2018 the Massachusetts DPU issued an order approving the treatment of TCJA-related excess deferred taxes. Columbia Gas of Massachusetts filed a compliance filing on January 4, 2019, reflecting revised LDAF rates inclusive of credit factors to return excess deferred taxes associated with TCJA to customers for rates effective on February 1, 2019, per the Massachusetts DPU’s order.

~~Columbia of Kentucky.~~ On April 30, 2018, Columbia of Kentucky received an order from the Kentucky PSC requiring implementation of interim proposed rates effective May 1, 2018 reflecting the impact of TCJA subject to future adjustment. The order directed Columbia of Kentucky to file, by September 1, 2018, revised TCJA adjustment factors reflecting the tax expense savings from January 1, 2018 through April 30, 2018, and an estimate of the annual reduction due to the excess deferred taxes to be effective with the first billing cycle of October 2018. On August 31, 2018, Columbia of Kentucky filed updated rate schedules with the Kentucky PSC for rates proposed to be effective October 1, 2018. On October 25, 2018, the Kentucky PSC authorized the TCJA adjustment factors, as proposed, with an October 29, 2018 effective date to pass-back the overcollection of taxes over a six month period.

~~Columbia of Maryland.~~ On February 13, 2018, Columbia of Maryland filed a proposal with the Maryland PSC to reduce rates as a result of TCJA with an annual revenue decrease of $1.3 million. Columbia of Maryland was directed to account for any revenues associated with the difference between previous and current income tax rates and excess deferred taxes as regulatory liabilities effective January 1, 2018. On March 14, 2018, Columbia of Maryland received approval, effective April 2, 2018, to implement new rates and pass-back the overcollection of taxes from the first quarter of 2018 over a seven month period.

~~NIPSCO Electric.~~ On October 31, 2018, NIPSCO submitted its 2018 Integrated Resource Plan with the IURC. The plan evaluated demand-side and supply-side resource alternatives to reliably and cost effectively meet NIPSCO customers' future energy requirements over the ensuing 20 years. Refer to Note 18-E, "Other Matters," in the Notes to Consolidated Financial Statements for additional information.

On March 29, 2018, WCE, which is currently owned by BP p.l.c ("BP") and BP Products North America, which operates the BP Refinery, filed a petition at the IURC asking that the combined operations of WCE and BP be treated as a single premise, and the WCE generation be dedicated primarily to BP Refinery operations beginning in May 2019 as WCE has self-certified as a qualifying facility at FERC. BP Refinery planned to continue to purchase electric service from NIPSCO at a reduced demand level beginning in May 2019. A settlement agreement was filed on November 2, 2018 agreeing that BP and WCE would not move forward with construction of a private transmission line to serve BP until conclusion of NIPSCO’s pending electric rate case.

On February 1, 2018, NIPSCO and certain other MISO transmission owners filed with the FERC a request for waiver of tariff provisions to allow for implementation of TCJA tax rate change provisions into 2018 transmission formula rates. On March 15, 2018, the FERC issued an order granting the request for waiver and set the effective date of the waiver at January 1, 2018. In the March billing cycle, the MISO began billing the new transmission rates reflecting the lower federal tax rate. In addition, the MISO began to re-bill January and February 2018 affected revenues and costs in the March 2018 billing cycle, and completed the re-settlement in the April 2018 billing cycle. The new 2018 transmission formula rates will reduce revenue by $8.5 million in 2018 associated with NIPSCO's multi-value projects. Additionally, on November 1, 2018, MISO submitted revised tariffs to provide for adjustments to income tax, including accumulated deferred income tax, resulting from tax law or rate changes. On December 20, 2018, FERC accepted the submission, effective January 1, 2019, as requested.

As noted above in the NIPSCO Gas regulatory matters, the IURC initiated an investigation on January 3, 2018, to review and consider the implications of the TCJA on utility rates. The commission ordered a two phase investigation. Phase 1 solely dealt with the prospective changes in rates to reflect the change in tax rates. On March 26, 2018, NIPSCO filed revised electric tariffs reflecting the impact of the change in tax rate for its applicable rates and charges. The IURC approved NIPSCO's phase 1 filing on April 26, 2018. The revised tariffs were effective May 1, 2018. On July 31, 2018, NIPSCO filed an unopposed motion requesting that the over-collection of income taxes from January 1, 2018 through April 30, 2018 be passed back in NIPSCO’s TDSIC-4 filing,

~~Table of Contents~~

NIS~~OURCE~~ INC.

~~Notes to Consolidated Financial Statements~~

~~ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)~~

also filed on July 31, 2018, and requesting that all other phase 2 issues be handled in a rate case filing to be made in the fourth quarter of 2018. On August 15, 2018, the IURC approved the motion to pass back the over-collection through the TDSIC-4 rates effective December 2018 through May 2019. All other phase 2 issues are addressed in the base rate case filed October 31, 2018.


9.	10. Risk Management Activities

We are exposed to certain risks ~~relating~~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, 2021				December 31, 2020
(in millions)	Assets		Liabilities		Assets		Liabilities
Current(1)
Derivatives designated as hedging instruments	$	—	$	136.4	$	—	$	70.9
Derivatives not designated as hedging instruments	10.6		0.4		10.4		7.3
Total	$	10.6	$	136.8	$	10.4	$	78.2
Noncurrent(2)
Derivatives designated as hedging instruments	$	—	$	—	$	—	$	99.5
Derivatives not designated as hedging instruments	13.8		7.4		2.8		45.1
Total	$	13.8	$	7.4	$	2.8	$	144.6

December 31, (in millions)
2018 2017
Risk Management Assets - Current⁽¹⁾

Interest rate risk programs $ —
$ 14.0
Commodity price risk programs 1.1
0.5
Total $ 1.1
$ 14.5
Risk Management Assets - Noncurrent⁽²⁾

Interest rate risk programs $ 18.5
$ 5.6
Commodity price risk programs 4.4
1.0
Total $ 22.9
$ 6.6
Risk Management Liabilities - Current
Interest rate risk programs $ —
$ 38.6
Commodity price risk programs 5.0
4.6
Total $ 5.0
$ 43.2
Risk Management Liabilities - Noncurrent
Interest rate risk programs $ 9.5
$ —
Commodity price risk programs 37.2
28.5
Total $ 46.7
$ 28.5

⁽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.

~~Commodity Price Risk Management~~

Derivatives Not Designated as Hedging Instruments

Commodity price risk management. We, along with our utility customers, are exposed to variability in cash flows associated with natural gas purchases and volatility in natural gas prices. We purchase natural gas for sale and delivery to our retail, commercial and industrial customers, and for most customers the variability in the market price of gas is passed through in their rates. Some of our utility subsidiaries offer programs whereby variability in the market price of gas is assumed by the respective utility. The objective of our commodity price risk programs is to mitigate the gas cost variability, for us or on behalf of our customers, associated with natural gas purchases or sales by economically hedging the various gas cost components using a combination of futures, options, forwards or other derivative contracts. At December 31, 2021, we had 124.5 MMDth 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. The term of these~~ instruments ~~range from five to ten years~~ and is limited to ~~twenty percent~~20% of NIPSCO’s average annual GCA purchase volume. ~~Gains~~As of December 31, 2021, the remaining terms of these instruments range from one to six 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.~~and FAC mechanisms, respectively. These instruments are not designated as accounting hedges. Refer to Note 9, "Regulatory Matters," for additional information.

Derivatives Designated as Hedging Instruments

Interest ~~Rate Risk Management~~

rate risk management. As of December 31, ~~2018,~~2021, we have two forward-starting interest rate swaps with an aggregate notional value totaling $500.0 million to hedge the variability in cash flows attributable to changes in the benchmark interest rate ~~during the periods from the effective dates of the swaps to the anticipated dates of~~associated with forecasted debt ~~issuances, which are expected to take place by the end of 2024.~~issuances. These interest rate swaps are designated as cash flow hedges.

Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheets were:

(in millions)

AOCI(1)

Amounts Expected to be Reclassified to Earnings During the Next 12 Months(1)

Maximum Term

Interest Rate

25.4

0.8

371 months

(1) All amounts are net of tax.

The ~~effective portions of~~actual amounts reclassified from Accumulated Other Comprehensive Income (Loss) to Net Income can differ from the ~~gains and losses related~~estimate above due to ~~these swaps are~~

market price changes.

Table of Contents

NISOURCE INC.

Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

The gains and losses related to these swaps are recorded to ~~AOCI~~AOCI. Upon issuance, we amortize the gains and losses over the life of the debt associated with these swaps as we recognize interest expense. These amounts are immaterial in 2021, 2020 and 2019 and are ~~recognized~~recorded in "Interest expense, net" ~~concurrently with the recognition of interest expense~~ on the ~~associated debt, once issued.~~ Statements of Consolidated Income (Loss).

If it becomes probable that a hedged forecasted transaction will no longer occur, the accumulated gains or losses on the derivative will be recognized currently in "Other, net" in the Statements of Consolidated Income (Loss).

The passage of the TCJA and Greater Lawrence Incident led to significant changes to our long-term financing plan. As a result, during 2018, we settled forward-starting interest rate swaps with a notional value of $750.0 million. These derivative contracts were accounted for as cash flow hedges. As part of the transactions, the associated net unrealized gain of $46.2 million was recognized immediately in "Other, net" on the Statements of Consolidated Income (Loss) due to the probability associated with the forecasted borrowing transactions no longer occurring.

There were no amounts excluded from effectiveness testing for derivatives in cash flow hedging relationships at December 31, ~~2018, 2017~~2021, 2020 and ~~2016.~~2019.

Our derivative instruments measured at fair value as of December 31, ~~2018~~2021 and ~~2017~~2020 do not contain any credit-risk-related contingent features. Cash flows for derivative financial instruments are generally classified in cash flows from operating activities.

~~10.~~11. Income Taxes

On December 22, 2017, the President signed into law the TCJA, which, among other things, enacted significant changes to the Internal Revenue Code, as amended, including a reduction in the maximum U.S. federal corporate income tax rate from 35% to 21%, and certain other provisions related specifically to the public utility industry, including the continuation of certain interest expense deductibility. These changes were effective January 1, 2018. Under GAAP, the effects of a change in tax law are recorded as a discrete item in the period of enactment.

Rates for our regulated customers include provisions for the collection of U.S. federal income taxes. Accordingly, accounting effects related to changes in tax rates here that would normally be recognized as a componentIncome Tax Expense. The components of income tax expense ~~may instead be deferred~~(benefit) were as a regulatory asset or liability and reflected in future rate-making. In December 2017, we remeasured our deferred tax assets and liabilities to the new federal corporate income tax rate. The result of this remeasurement was a reduction in the net deferred tax liability of approximately $1.3 billion, including approximately $0.4 billion of regulatory "gross up" to account for over-collection of past taxes from customers. Offsetting the reduction in net deferred tax liabilities was an increase in regulatory liabilities of approximately $1.5 billion and an increase in income tax expense of $0.2 billion. In 2018, we received regulatory orders from most of the jurisdictions in which we operate regarding the treatment and pass back of excess deferred taxes. As a result of these orders we reduced our regulatory liability related to excess deferred income taxes by $120.7 million (net of tax). This adjustment is reflected in "Income Taxes" on our Consolidated Statements of Income (Loss).follows:

On December 22, 2017, the SEC issued Staff Accounting Bulletin 118 (“SAB 118”), which provides guidance on accounting for tax effects of the TCJA. SAB 118 provides a measurement period that should not extend beyond one year from the TCJA enactment date for companies to complete the accounting under ASC 740. There were no adjustments recorded in the SAB 118 remeasurement period in 2018.


Year Ended December 31, (in millions)	2021		2020		2019
Income Taxes
Current
Federal	$	(0.1)	$	0.2	$	—
State	6.0		11.7		5.2
Total Current	5.9		11.9		5.2
Deferred
Federal	99.2		(0.4)		110.7
State	13.8		(27.4)		9.0
Total Deferred	113.0		(27.8)		119.7
Deferred Investment Credits	(1.1)		(1.2)		(1.4)
Income Taxes	$	117.8	$	(17.1)	$	123.5

Table of Contents

NISOURCE INC.

Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

Statutory Rate Reconciliation.The ~~components~~following table represents a reconciliation of income tax expense ~~(benefit) were as follows:~~

Year Ended December 31, (in millions)
2018 2017 2016
Income Taxes
Current
Federal $ —
$ —
$ —
State 8.2
7.8
(0.1 )
Total Current 8.2
7.8
(0.1 )
Deferred
Federal (209.4 ) 302.7
165.6
State 22.2
5.0
18.0
Total Deferred (187.2 ) 307.7
183.6
Deferred Investment Credits (1.0 ) (1.0 ) (1.4 )
Income Taxes $ (180.0 ) $ 314.5
$ 182.1

~~Total income taxes were different from the amount that would be computed by applying~~at the statutory federal income tax rate to ~~book~~the actual income ~~before income tax. The major reasons for this difference were as follows:~~tax expense from continuing operations:


Year Ended December 31, (in millions)	2018					2017					2016					Year Ended December 31, (in millions)	2021				2020				2019
Book income (loss) before income taxes	$	(230.6	)			$	443.0				$	513.6				Book income (loss) before income taxes	$	706.6			$	(31.3)			$	506.6
Tax expense (benefit) at statutory federal income tax rate	(48.4		)	21.0	%	155.0			35.0	%	179.8			35.0	%	Tax expense (benefit) at statutory federal income tax rate	148.3		21.0	%	(6.6)		21.0	%	106.5		21.0	%
Increases (reductions) in taxes resulting from:																Increases (reductions) in taxes resulting from:
State income taxes, net of federal income tax benefit	24.7			(10.7	)	6.9			1.5		11.3			2.2		State income taxes, net of federal income tax benefit	14.1		2.0		(11.7)		37.4		10.1		2.0
Amortization of regulatory liabilities	(29.3		)	12.7		(2.4		)	(0.5	)	(1.5		)	(0.3	)	Amortization of regulatory liabilities	(39.1)		(5.5)		(38.4)		122.7		(29.4)		(5.8)
Goodwill impairment																Goodwill impairment	—		—		—		—		43.0		8.5
Fines and penalties																Fines and penalties	—		—		11.8		(37.7)		11.5		2.3

Charitable contribution carryover	—			—		(1.2		)	(0.3	)	2.8			0.5		Charitable contribution carryover	—		—		—		—		(2.5)		(0.5)
State regulatory proceedings	(127.8		)	55.4		—			—		—			—		State regulatory proceedings	—		—		—		—		(9.5)		(1.9)
Remeasurement due to TCJA	—			—		161.1			36.4		—			—
Employee stock ownership plan dividends and other compensation	(2.2		)	1.0		(6.5		)	(1.5	)	(9.5		)	(1.8	)	Employee stock ownership plan dividends and other compensation	(1.2)		(0.2)		(1.3)		4.2		(2.0)		(0.4)

Deferred taxes on TCJA regulatory liability divested																Deferred taxes on TCJA regulatory liability divested	—		—		23.3		(74.5)		—		—
Tax accrual adjustments																Tax accrual adjustments	(0.1)		—		8.9		(28.4)		—		—
Federal tax credits																Federal tax credits	(2.1)		(0.3)		(2.5)		8.0		—		—
Other adjustments	3.0			(1.3	)	1.6			0.4		(0.8		)	(0.1	)	Other adjustments	(2.1)		(0.3)		(0.6)		1.9		(4.2)		(0.8)
Income Taxes	$	(180.0	)	78.1	%	$	314.5		71.0	%	$	182.1		35.5	%	Income Taxes	$	117.8	16.7	%	$	(17.1)	54.6	%	$	123.5	24.4	%



~~Delaware~~ DE		35-2108964
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

801 East 86th Avenue ~~Merrillville, Indiana~~		~~46410~~
Merrillville,	IN	46410
(Address of principal executive offices)		(Zip Code)



	Title of ~~each class~~ Each Class	Trading Symbol(s)		Name of ~~each exchange~~Each Exchange on ~~which registered~~	Which Registered
	Common Stock, par value $0.01 per share	NI		~~New York~~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



~~Large accelerated filer~~ þ	~~Accelerated filer~~ ¨	~~Emerging growth company~~ ¨
~~Non-accelerated filer~~ ¨	~~Smaller reporting company~~ ¨



		Page No.
Defined Terms		3
Part I
Item 1.	Business	6
Item 1A.	Risk Factors	914
Item 1B.	Unresolved Staff Comments	1932
Item 2.	Properties	1932
Item 3.	Legal Proceedings	1932
Item 4.4	Mine Safety Disclosures	1932
~~Supplemental Item. Executive Officers of the Registrant~~	20
Part II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	2133
Item 6.	~~Selected Financial Data~~Reserved	2334
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	2535
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	4456
Item 8.	Financial Statements and Supplementary Data	4557
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	~~115~~124
Item 9A.	Controls and Procedures	~~115~~124
Item 9B.	Other Information	~~115~~126
Item 9C.	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	126
Part III
Item 10.	Directors, Executive Officers and Corporate Governance	~~116~~127
Item 11.	Executive Compensation	~~116~~127
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	~~116~~127
Item 13.	Certain Relationships and Related Transactions, and Director Independence	~~116~~127
Item 14.	Principal Accounting Fees and Services	~~116~~127
Part IV
Item 15.	Exhibits, Financial Statement Schedules	~~117~~128
Item 16.	Form 10-K Summary	134
Signatures		~~122~~135


DEFINED TERMS

Thefollowingisalistoffrequentlyusedabbreviationsoracronymsthatarefoundinthisreport:

NiSource Subsidiaries ~~Affiliates~~ and ~~Former Subsidiaries~~Affiliates
~~Capital Markets (former subsidiary)~~		~~NiSource Capital Markets, Inc.~~
~~Columbia (former subsidiary)~~	~~Columbia Energy Group~~
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.
~~Company~~NIPSCO			~~NiSource Inc. and its subsidiaries, unless otherwise indicated by the context~~
~~CPG (former subsidiary)~~	~~Columbia Pipeline Group, Inc.~~
~~NIPSCO~~	Northern Indiana Public Service Company LLC
NiSource ("we," "us" or "our")			NiSource Inc.
~~NiSource Corporate Services~~Rosewater			~~NiSource Corporate Services Company~~Rosewater Wind Generation LLC and its wholly owned subsidiary, Rosewater Wind Farm LLC
~~NiSource Finance (former subsidiary)~~Indiana Crossroads Wind			~~NiSource Finance Corporation~~Indiana Crossroads Wind Generation LLC and its wholly owned subsidiary, Indiana Crossroads Wind Farm LLC
Abbreviations and Other
~~Abbreviations~~ACE			Affordable Clean Energy
~~ACE~~AFUDC			~~Affordable clean energy~~
~~AFUDC~~	Allowance for funds used during construction
~~AMR~~AOCI			~~Automatic meter reading~~
~~AMRP~~	~~Accelerated Main Replacement Program~~
~~AOCI~~	Accumulated Other Comprehensive Income (Loss)
ASC			Accounting Standards Codification
ASU			Accounting Standards Update
ATM			At-the-market
~~Board~~BTA			~~Board of Directors~~Build-transfer agreement
~~BTA~~CAP			~~Build-transfer agreement~~
~~CAA~~	~~Clean Air Act~~
~~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)
CO2 Corporate Units			~~Carbon dioxide~~Series A Corporate Units
~~CPP~~COVID-19 ("the COVID-19 pandemic" or "the pandemic")			~~Clean Power Plan~~Novel Coronavirus 2019 and its variants, including the Delta and Omicron variants, and any other variant that may emerge
DPU			Department of Public Utilities
~~DSIC~~DSM			~~Distribution System Investment Charge~~
~~DSM~~	Demand Side Management
~~ECT~~EPA			United States Environmental ~~Cost Tracker~~Protection Agency
~~EERM~~EPS			~~Environmental Expense Recovery Mechanism~~Earnings per share
~~EGUs~~Equity Units			~~Electric~~Series A Equity Units
FAC			Fuel adjustment clause
FMCA			Federally Mandated Cost Adjustment
GAAP			Generally Accepted Accounting Principles
GCA			Gas cost adjustment
GHG			Greenhouse gases
GWh			Gigawatt hours
HLBV			Hypothetical Liquidation at Book Value
IRP			Infrastructure Replacement Program
IRS			Internal Revenue Service
IURC			Indiana Utility ~~Steam Generating Units~~Regulatory Commission

~~DEFINED TERMS~~

~~ELG~~			~~Effluence limitations guidelines~~DEFINED TERMS
~~EPA~~LDCs		~~United States Environmental Protection Agency~~
~~EPS~~	~~Earnings per share~~
~~FAC~~	~~Fuel adjustment clause~~
~~FASB~~	~~Financial Accounting Standards Board~~
~~FERC~~	~~Federal Energy Regulatory Commission~~
~~FMCA~~	~~Federally Mandated Cost Adjustment~~
~~FTRs~~	~~Financial Transmission Rights~~
~~GAAP~~	~~Generally Accepted Accounting Principles~~
~~GCA~~	~~Gas cost adjustment~~
~~GCR~~	~~Gas cost recovery~~
~~GHG~~	~~Greenhouse gas~~
~~GSEP~~	~~Gas System Enhancement Program~~
~~GWh~~	~~Gigawatt hours~~
~~IRIS~~	~~Infrastructure Replacement and Improvement Surcharge~~
~~IRP~~	~~Infrastructure Replacement Program~~
~~IRS~~	~~Internal Revenue Service~~
~~IURC~~	~~Indiana Utility Regulatory Commission~~
~~LDCs~~	Local distribution companies
LIBOR		London ~~inter-bank offered rate~~InterBank Offered Rate
LIFO		Last-in, first-out
~~MGP~~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
~~Mizuho~~MMDth		~~Mizuho Corporate Bank Ltd.~~Million dekatherms
~~MMDth~~MW		~~Million dekatherms~~Megawatts
MWMWh		~~Megawatts~~Megawatt hours
~~MWh~~NOL		~~Megawatt hours~~
~~NOL~~	Net Operating Loss
NTSB		National Transportation Safety Board
NYMEX		The New York Mercantile Exchange
~~NYSE~~OPEB		~~The New York Stock Exchange~~
~~OPEB~~	Other Postretirement and Postemployment Benefits
PCB		Polychlorinated biphenyls
PHMSA		~~U.S. Department of Transportation~~ Pipeline and Hazardous Materials Safety Administration
~~PISCC~~PPA		~~Post-in-service carrying charges~~Power Purchase Agreement
~~PPA~~PSC		~~Purchase plan agreement~~
~~PSC~~	Public Service Commission
~~PTC~~PUC		~~Production Tax Credits~~
~~PUC~~	~~Public Utility Commission~~
~~PUCO~~	Public Utilities Commission ~~of Ohio~~
RCRA		Resource Conservation and Recovery Act
~~ROU~~ROE		Return on Equity
ROU		Right of ~~use~~Use
~~SAB~~SAVE		~~Staff accounting bulletin~~
~~SAVE~~	Steps to Advance Virginia's Energy Plan

~~DEFINED TERMS~~
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)
~~Separation~~SEC		The separation of our natural gas pipeline, midstream and storage business from our natural gas and electric utility business accomplished through a pro rata distribution to holders of our outstanding common stock of all the outstanding shares of common stock of CPG. The separation was completed on July 1, 2015.
~~SEC~~	Securities and Exchange Commission
~~STRIDE~~SMRP		Safety Modification and Replacement Program
SMS		Safety Management System
STRIDE		Strategic Infrastructure Development and Enhancement
~~Sugar Creek~~TCJA		~~Sugar Creek electric generating plant~~
~~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~~2017)
TDSIC		Transmission, Distribution and Storage System Improvement Charge
~~VIE~~U.S. Attorney's Office		U.S. Attorney's Office for the District of Massachusetts
VIE		Variable Interest Entity
~~VSCC~~	~~Virginia State Corporation Commission~~
~~WCE~~	~~Whiting Clean Energy~~



~~Name~~	~~Age~~	~~Office(s) Held in Past 5 Years~~
~~Joseph Hamrock~~	55	~~President and Chief Executive Officer of NiSource since July 1, 2015.~~
		~~Executive Vice President and Group Chief Executive Officer of NiSource from May 2012 to July 2015.~~
~~Donald E. Brown~~	47	~~Executive Vice President and Chief Financial Officer of NiSource since June 2016.~~
		~~Executive Vice President, Chief Financial Officer and Treasurer of NiSource from July 2015 to June 2016.~~
		~~Executive Vice President, Finance Department of NiSource from March 2015 to July 2015.~~
		~~Vice President and Chief Financial Officer of UGI Utilities, a division of UGI Corporation (gas and electric utility company) from 2010 to March 2015.~~
~~Peter T. Disser~~	50	~~Vice President, Internal Audit of NiSource since January 2019.~~
		~~Chief Operating Officer of NiSource Corporate Services from September 2018 through December 2018.~~
		~~Vice President, Audit of NiSource from November 2017 to September 2018.~~
		~~Vice President of Planning and Analysis of NiSource from June 2016 to November 2017.~~
		~~Chief Financial Officer of NIPSCO from 2012 to June 2016.~~
~~Carrie J. Hightman~~	61	~~Executive Vice President and Chief Legal Officer of NiSource since 2007.~~
~~Violet G. Sistovaris~~	57	~~Executive Vice President and President, NIPSCO since October 2016.~~
		~~Executive Vice President, NIPSCO from June 2015 to October 2016.~~
		~~Senior Vice President and Chief Information Officer of NiSource from May 2014 to June 2015.~~
		~~Senior Vice President and Chief Information Officer of NiSource Corporate Services from 2008 to May 2014.~~
~~Suzanne K. Surface~~	54	~~Chief Services Officer of NiSource since January 2019.~~
		~~Vice President, Audit of NiSource from September 2018 through December 2018.~~
		~~Vice President, Transformation Office of NiSource from August 2018 to September 2018.~~
		~~Vice President, Corporate Services Customer Value of NiSource Corporate Services from November 2017 to August 2018.~~
		~~Vice President, Audit of NiSource from July 2015 to November 2017.~~
		~~Vice President Regulatory Strategy and Support of NiSource from July 2009 through June 2015.~~
~~Pablo A. Vegas~~	45	~~Executive Vice President and President, Gas Utilities since January 2019.~~
		~~Executive Vice President and Chief Restoration Officer of NiSource Corporate Services since September 2018 through December 2018.~~
		~~Executive President, Gas Segment and Chief Customer Officer of NiSource from May 2017 to September 2018.~~
		~~Executive Vice President and President, Columbia Gas Group from May 2016 to May 2017.~~
		~~President and Chief Operating Officer of American Electric Power Ohio Company from May 2012 to May 2016.~~



(in millions)	December 31, 2018			December 31, 2017
ASSETS
Property, Plant and Equipment
Utility plant	$	22,780.8		$	21,026.6
Accumulated depreciation and amortization	(7,257.9		)	(6,953.6		)
Net utility plant	15,522.9			14,073.0
Other property, at cost, less accumulated depreciation	19.6			286.5
Net Property, Plant and Equipment	15,542.5			14,359.5
Investments and Other Assets
Unconsolidated affiliates	2.1			5.5
Other investments	204.0			204.1
Total Investments and Other Assets	206.1			209.6
Current Assets
Cash and cash equivalents	112.8			29.0
Restricted cash	8.3			9.4
Accounts receivable (less reserve of $21.1 and $18.3, respectively)	1,058.5			898.9
Gas inventory	286.8			285.1
Materials and supplies, at average cost	101.0			105.9
Electric production fuel, at average cost	34.7			80.1
Exchange gas receivable	88.4			45.8
Regulatory assets	235.4			176.3
Prepayments and other	129.5			132.8
Total Current Assets	2,055.4			1,763.3
Other Assets
Regulatory assets	2,002.1			1,624.9
Goodwill	1,690.7			1,690.7
Intangible assets, net	220.7			231.7
Deferred charges and other	86.5			82.0
Total Other Assets	4,000.0			3,629.3
Total Assets	$	21,804.0		$	19,961.7



(in millions)	Common Stock		Preferred Stock		Treasury Stock			Additional Paid-In Capital		Retained Deficit			Accumulated Other Comprehensive Loss			Total
Balance as of December 31, 2017	$	3.4	$	—	$	(95.9	)	$	5,529.1	$	(1,073.1	)	$	(43.4	)	$	4,320.1
Comprehensive Income:
Net Loss	—		—		—			—		(50.6		)	—			(50.6		)
Other comprehensive income, net of tax	—		—		—			—		—			15.7			15.7
Dividends:
Common stock ($0.78 per share)	—		—		—			—		(273.5		)	—			(273.5		)
Preferred stock ($28.88 per share)	—		—		—			—		(11.6		)	—			(11.6		)
Treasury stock acquired	—		—		(4.0		)	—		—			—			(4.0		)
Cumulative effect of change in accounting principle⁽¹⁾	—		—		—			—		9.5			(9.5		)	—
Stock issuances:
Common stock - private placement	0.3		—		—			599.3		—			—			599.6
Preferred stock	—		880.0		—			—		—			—			880.0
Employee stock purchase plan	—		—		—			5.5		—			—			5.5
Long-term incentive plan	—		—		—			15.4		—			—			15.4
401(k) and profit sharing	—		—		—			21.8		—			—			21.8
ATM program	0.1		—		—			232.4		—			—			232.5
Balance as of December 31, 2018	$	3.8	$	880.0	$	(99.9	)	$	6,403.5	$	(1,399.3	)	$	(37.2	)	$	5,750.9



Year Ended December 31, 2016 (in millions)	As Previously Reported			Effect of Change⁽¹⁾			As Adjusted
Operation and maintenance	$	1,453.7		$	(7.9	)	$	1,445.8
Total Operating Expenses	3,634.3			(7.9		)	3,626.4
Operating Income	858.2			7.9			866.1
Other Income (Deductions)
Other, net	1.5			(7.9		)	(6.4		)
Total Other Deductions	$	(348.0	)	$	(7.9	)	$	(355.9	)



Year Ended December 31, (in thousands)	2017	2016
Denominator
Basic average common shares outstanding	329,388	321,805
Dilutive potential common shares:
Shares contingently issuable under employee stock plans	547	165
Shares restricted under stock plans	821	1,554
Diluted Average Common Shares	330,756	323,524



December 31, (in millions)	2018		2017
Risk Management Assets - Current⁽¹⁾
Interest rate risk programs	$	—	$	14.0
Commodity price risk programs	1.1		0.5
Total	$	1.1	$	14.5
Risk Management Assets - Noncurrent⁽²⁾
Interest rate risk programs	$	18.5	$	5.6
Commodity price risk programs	4.4		1.0
Total	$	22.9	$	6.6
Risk Management Liabilities - Current
Interest rate risk programs	$	—	$	38.6
Commodity price risk programs	5.0		4.6
Total	$	5.0	$	43.2
Risk Management Liabilities - Noncurrent
Interest rate risk programs	$	9.5	$	—
Commodity price risk programs	37.2		28.5
Total	$	46.7	$	28.5


At December 31, 2021, (in millions)	2021		2020		2019
Opening Balance	$	21.7	$	23.2	$	1.2

Gross decreases - tax positions in prior period	—		(1.5)		(0.6)
Gross increases - current period tax positions	—		—		22.6
Ending Balance	$	21.7	$	21.7	$	23.2

Offset for net operating loss carryforwards	(21.7)		(21.7)		(22.6)
Balance, Less Net Operating Loss Carryforwards	$	—	$	—	$	0.6


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%



			þ☑			ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)



			¨☐			TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)


	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	%

	Defined Benefit Pension Assets(1)		December 31, 2020		Postretirement Benefit Plan Assets		December 31, 2020
Asset Class (in millions)	Asset Value		% of Total Assets		Asset Value		% of Total Assets
Domestic Equities	$	446.3	21.0	%	$	108.8	38.0	%
International Equities	230.1		10.9	%	48.2		16.8	%
Fixed Income	1,291.2		61.0	%	122.0		42.6	%
Real Estate	52.9		2.5	%	—		—
Cash/Other	97.2		4.6	%	7.4		2.6	%
Total	$	2,117.7	100.0	%	$	286.4	100.0	%



	Defined Benefit Pension Assets		December 31, 2018		Postretirement Benefit Plan Assets		December 31, 2018
Asset Class (in millions)	Asset Value		% of Total Assets		Asset Value		% of Total Assets
Domestic Equities	$	355.5	19.0	%	$	78.8	36.4	%
International Equities	165.5		8.9	%	17.5		8.1	%
Fixed Income	1,241.9		66.5	%	115.1		53.2	%
Real Estate	52.7		2.8	%	—		—
Cash/Other	52.1		2.8	%	4.9		2.3	%
Total	$	1,867.7	100.0	%	$	216.3	100.0	%

	Defined Benefit Pension Assets		December 31, 2017		Postretirement Benefit Plan Assets		December 31, 2017
Asset Class (in millions)	Asset Value		% of Total Assets		Asset Value		% of Total Assets
Domestic Equities	$	698.2	32.3	%	$	96.0	36.6	%
International Equities	351.0		16.2	%	39.8		15.2	%
Fixed Income	977.6		45.3	%	117.5		44.8	%
Real Estate	49.9		2.3	%	—		—
Cash/Other	83.3		3.9	%	9.2		3.4	%
Total	$	2,160.0	100.0	%	$	262.5	100.0	%


(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	$	—



	Balance at January 1, 2018		Total gains or losses (unrealized / realized)			Purchases		(Sales)			Balance at December 31, 2018
Private equity limited partnerships
U.S. multi-strategy	26.7		2.4			0.7		(11.3		)	18.5
International multi-strategy	19.1		(0.6		)	—		(6.0		)	12.5
Distressed opportunities	3.2		(0.8		)	—		—			2.4
Real estate	49.9		1.7			1.8		(0.7		)	52.7
Total	$	98.9	$	2.7		$	2.5	$	(18.0	)	$	86.1


(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


(in millions)	December 31, 2020		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	$	11.9	$	11.9	$	—	$	—
Equity securities
U.S. equities	2.4		2.4		—		—

Fixed income securities
Government	243.4		—		243.4		—
Corporate	692.6		—		692.6		—


Mutual Funds
U.S. multi-strategy	161.3		161.3		—		—
International equities	55.4		55.4		—		—
Fixed income	0.1		0.1		—		—
Private equity limited partnerships(3)
U.S. multi-strategy(1)	10.9		—		—		—
International multi-strategy(2)	6.6		—		—		—
Distressed opportunities	0.3		—		—		—
Real Estate	52.9		—		—		—
Commingled funds(3)
Short-term money markets	78.8		—		—		—
U.S. equities	279.7		—		—		—
International equities	176.8		—		—		—
Fixed income	337.6		—		—		—
Pension plan assets subtotal	2,110.7		231.1		936.0		—
Other postretirement benefit plan assets:
Mutual funds
U.S. multi-strategy	94.8		94.8		—		—
International equities	24.1		24.1		—		—
Fixed income	121.8		121.8		—		—
Commingled funds(3)
Short-term money markets	7.6		—		—		—
U.S. equities	14.0		—		—		—
International equities	24.1		—		—		—
Other postretirement benefit plan assets subtotal	286.4		240.7		—		—
Due to brokers, net(4)	(1.6)		—		(1.6)		—
Accrued income/dividends	8.6		8.6		—		—

Total pension and other postretirement benefit plan assets	$	2,404.1	$	480.4	$	934.4	$	—



	Balance at January 1, 2017		Total gains or losses (unrealized / realized)			Purchases		(Sales)			Balance at December 31, 2017
Fixed income securities
Other fixed income	$	0.1	$	(0.1	)	$	—	$	—		$	—
Private equity limited partnerships
U.S. multi-strategy	34.8		2.1			0.9		(11.1		)	26.7
International multi-strategy	24.9		1.1			0.1		(7.0		)	19.1
Distress opportunities	4.1		0.4			—		(1.3		)	3.2
Real estate	9.2		(0.6		)	42.1		(0.8		)	49.9
Total	$	73.1	$	2.9		$	43.1	$	(20.2	)	$	98.9


	December 31,
	2021		2020
Accumulated Benefit Obligation	$	30.0	$	32.1
Funded Status
Projected Benefit Obligation	30.0		32.1
Fair Value of Plan Assets	—		—
Funded Status of Underfunded Pension Plans at End of Year(1)	$	(30.0)	$	(32.1)



(in millions)	1% point increase		1% point decrease
Effect on service and interest components of net periodic cost	$	1.3	$	(1.1	)
Effect on accumulated postretirement benefit obligation	25.0		(22.0		)


(in millions)	Pension Benefits		Other Postretirement Benefits		Federal Subsidy Receipts		(in millions)	Pension Benefits		Other Postretirement Benefits		Federal Subsidy Receipts
Year(s)							Year(s)
2019	$	177.4	$	34.3	$	0.5
2020	176.0		35.0		0.5
2021	176.5		35.7		0.5
2022	174.4		36.0		0.4		2022	$	157.3	$	38.1	$	0.4
2023	166.5		35.8		0.4		2023	150.4		37.4		0.4
2024-2028	748.7		171.8		1.7
2024							2024	145.6		36.9		0.3
2025							2025	143.1		36.5		0.3
2026							2026	135.7		35.8		0.3
2027-2031							2027-2031	598.9		168.7		1.1


	Pension Benefits						Other Postretirement Benefits
(in millions)	2021		2020		2019		2021		2020		2019
Components of Net Periodic Benefit (Income) Cost(1)
Service cost	$	30.2	$	32.0	$	29.2	$	6.2	$	6.6	$	5.1
Interest cost	31.4		51.6		72.3		9.9		15.4		19.2
Expected return on assets	(101.6)		(111.6)		(108.8)		(15.3)		(14.4)		(13.1)

Amortization of prior service cost (credit)	0.1		0.7		0.2		(2.2)		(2.1)		(3.2)
Recognized actuarial loss	21.7		33.8		45.2		4.6		4.9		2.0


Settlement/curtailment loss	11.4		10.5		9.5		—		1.5		—
Total Net Periodic Benefits (Income) Cost	$	(6.8)	$	17.0	$	47.6	$	3.2	$	11.9	$	10.0


Year Ending December 31,	2021		2020		2019
Number of shares issued	12,525,215		8,459,430		8,422,498
Average price per share	$	23.95	$	23.60	$	27.75
Proceeds, net of fees (in millions)	$	288.1	$	196.5	$	229.1


				Year ended December 31,						December 31,		December 31,
				2021		2020		2019		2021		2020
(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	$	1,674.65	$	486.1	$	486.1
Series C(1)	$	1,000.00	862,500	—		—		—		$	666.5	$	—


(in millions except contract rate)	Issuance Date	Units Issued	Total Net Proceeds(1)		Purchase Contract Annual Rate		Purchase Contract Liability(2)
Equity Units	April 19, 2021	8.625	$	835.5	7.75	%	$	168.8


(shares)	Restricted Stock Units		Weighted Average Award Date Fair Value Per Unit ($)	(shares)	Restricted Stock Units	Weighted Average Award Date Fair Value Per Unit ($)
Non-vested at December 31, 2017	698,126		15.09
Non-vested at December 31, 2020				Non-vested at December 31, 2020	478,227	24.51
Granted	158,689		21.94	Granted	285,755	19.83
Forfeited	(6,890	)	21.42	Forfeited	(36,697)	23.72
Vested	(671,247	)	14.91	Vested	(155,131)	22.66
Non-vested at December 31, 2018	178,678		21.82
Non-vested at December 31, 2021				Non-vested at December 31, 2021	572,154	22.72



(shares)	Performance Awards		Weighted Average Grant Date Fair Value Per Unit ($)⁽¹⁾
Non-vested at December 31, 2017	1,184,773		19.52
Granted	514,338		22.51
Forfeited	(64,393	)	26.79
Vested	—		—
Non-vested at December 31, 2018	1,634,718		20.45


Award Year	Service Conditions Lapse date	Performance Period	Award Conditions	Shares outstanding at 12/31/2021 (shares)	Grant Date Fair Value (in millions)
2021	02/28/24	01/01/2021- 12/31/2023	Non-GAAP Financial Measure	278,328	$	6.5
			Relative Total Shareholder Return	278,328	$	6.7

			Relative Total Shareholder Return	124,200	$	3.2
	02/28/23	01/01/2021- 12/31/2022	Relative Total Shareholder Return	252,082	$	4.8
2020	02/28/23	01/01/2020- 12/31/2022	Non-GAAP Financial Measure	349,686	$	11.7
			Operational Measures	80,696	$	2.6
2019	02/28/22	01/01/2019- 12/31/2021	Non-GAAP Financial Measure	353,302	$	11.7
			Operational Measures	81,528	$	2.5


Long-term debt type	Maturity as of December 31, 2021	Weighted average interest rate (%)		Outstanding balance as of December 31, (in millions)
				2021		2020
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
Total senior notes				$	9,003.0	$	9,003.0
Medium term notes:
NiSource	April 2022 to May 2027	7.99	%	$	49.0	$	49.0
NIPSCO	August 2022 to August 2027	7.61	%	68.0		68.0
Columbia of Massachusetts	December 2025 to February 2028	6.37	%	15.0		15.0
Total medium term notes				$	132.0	$	132.0
Finance leases:
NiSource Corporate Services	March 2022 to December 2025	1.73	%	51.4		49.4
NIPSCO	December 2027 to January 2033	1.86	%	18.7		16.0
Columbia of Ohio	December 2025 to March 2044	6.15	%	87.8		91.2
Columbia of Virginia	July 2029 to November 2039	6.28	%	17.7		18.4
Columbia of Kentucky	May 2027	3.79	%	0.2		0.3
Columbia of Pennsylvania	August 2027 to May 2035	6.35	%	9.8		19.7
Total finance leases				185.6		195.0
Unamortized issuance costs and discounts				$	(79.1)	$	(86.9)
Total Long-Term Debt				$	9,241.5	$	9,243.1



Long-term debt type	Maturity as of December 31, 2018	Weighted average interest rate (%)		Outstanding balance as of December 31, (in millions)
Long-term debt type	Maturity as of December 31, 2018	Weighted average interest rate (%)		2018			2017
Senior notes:
NiSource	March 2018	6.40	%	—			275.1
NiSource	January 2019	6.80	%	—			255.1
NiSource	September 2020	5.45	%	—			325.1
NiSource	December 2021	4.45	%	63.6			63.6
NiSource	March 2022	6.13	%	—			180.0
NiSource	November 2022	2.65	%	500.0			500.0
NiSource	February 2023	3.85	%	250.0			250.0
NiSource	June 2023	3.65	%	350.0			—
NiSource	November 2025	5.89	%	265.0			265.0
NiSource	May 2027	3.49	%	1,000.0			1,000.0
NiSource	December 2027	6.78	%	3.0			3.0
NiSource	December 2040	6.25	%	250.0			250.0
NiSource	June 2041	5.95	%	400.0			400.0
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
Total senior notes				$	6,831.6		$	7,516.9
Medium term notes:
NiSource	April 2022 to May 2027	7.99	%	$	49.0		$	49.0
NIPSCO	August 2022 to August 2027	7.61	%	68.0			68.0
Columbia of Massachusetts	December 2025 to February 2028	6.30	%	40.0			40.0
Total medium term notes				$	157.0		$	157.0
Capital leases:
NIPSCO	May 2018	3.95	%	$	—		$	3.8
NiSource Corporate Services	January 2019 to October 2022	3.68	%	11.6			1.4
Columbia of Ohio	October 2021 to June 2038	6.33	%	91.5			88.5
Columbia of Virginia	July 2029 to December 2037	7.12	%	15.2			5.2
Columbia of Kentucky	May 2027	3.79	%	0.3			0.4
Columbia of Pennsylvania	August 2027 to June 2036	5.42	%	30.0			31.0
Columbia of Massachusetts	December 2033 to November 2043	5.48	%	45.7			22.8
Total capital leases				194.3			153.1
Pollution control bonds - NIPSCO	April 2019	5.85	%	41.0			41.0
Unamortized issuance costs and discounts				(68.5		)	$	(71.5	)
Total Long-Term Debt				$	7,155.4		$	7,796.5



Year Ended December 31, (in millions)	Income Statement Classification	2021		2020
Finance lease cost
Amortization of right-of-use assets	Depreciation and amortization	$	28.8	$	23.4
Interest on lease liabilities	Interest expense, net	9.4		11.1
Total finance lease cost		38.2		34.5
Operating lease cost	Operation and maintenance	15.6		20.3


Total lease cost		$	53.8	$	54.8