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

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

OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2020
OR

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

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

DE |  | 35-2108964
(State or other jurisdiction of incorporation or organization) |  | (I.R.S. Employer Identification No.)
801 East 86th Avenue |  |
Merrillville, | IN |  | 46410
(Address of principal executive offices) |  | (Zip Code)

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

Title of Each Class | Trading Symbol(s) | Name of Each Exchange on Which Registered
Common Stock, par value $0.01 per share | NI | NYSE
Depositary Shares, each representing a 1/1,000th ownership interest in a share of 6.50% Series B | NI PR B | NYSE
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

Securities registered pursuant to Section 12(g) of the Act: None
I ndicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes þ No ¨
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. Yes ¨ No þ
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes þ No ¨
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).
Yes þ No ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definition of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and "emerging growth company" in Rule 12-b-2 of the Exchange Act.
Large accelerated filer þ Accelerated Filer ¨ Emerging Growth Company ☐ Non-accelerated Filer ¨ Smaller Reporting Company ☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☑
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No þ
The aggregate market value of the registrant's common stock, par value $0.01 per share (the "Common Stock") held by non-affiliates was approximately $8,671,854,266 based upon the June 30, 2020, closing price of $22.74 on the New York Stock Exchange.
There were 391,859,711 shares of Common Stock outstanding as of February 9, 2021.

Documents Incorporated by Reference
Part III of this report incorporates by reference specific portions of the Registrant’s Notice of Annual Meeting and Proxy Statement relating to the Annual Meeting of Stockholders to be held on May 25, 2021.

CONTENTS

|  | Page No.
Defined Terms | 3
Part I |  |
Item 1. | Business | 6
Item 1A. | Risk Factors | 11
Item 1B. | Unresolved Staff Comments | 24
Item 2. | Properties | 24
Item 3. | Legal Proceedings | 24
Item 4 | Mine Safety Disclosures | 24
Part II |  |
Item 5. | Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities | 26
Item 6. | Selected Financial Data | 27
Item 7. | Management’s Discussion and Analysis of Financial Condition and Results of Operations | 28
Item 7A. | Quantitative and Qualitative Disclosures About Market Risk | 49
Item 8. | Financial Statements and Supplementary Data | 50
Item 9. | Changes in and Disagreements With Accountants on Accounting and Financial Disclosure | 118
Item 9A. | Controls and Procedures | 118
Item 9B. | Other Information | 120
Part III |  |
Item 10. | Directors, Executive Officers and Corporate Governance | 121
Item 11. | Executive Compensation | 121
Item 12. | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters | 121
Item 13. | Certain Relationships and Related Transactions, and Director Independence | 121
Item 14. | Principal Accounting Fees and Services | 121
Part IV |  |
Item 15. | Exhibits, Financial Statement Schedules | 122
Item 16. | Form 10-K Summary | 128
Signatures | 129

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DEFINED TERMS
The following is a list of abbreviations or acronyms that are used in this report:
NiSource Subsidiaries, Affiliates and Former Subsidiaries |  |
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 |  | NiSource Inc. and its subsidiaries, unless otherwise indicated by the context
NIPSCO |  | Northern Indiana Public Service Company LLC
NiSource ("we," "us" or "our") |  | NiSource Inc.
NiSource Corporate Services |  | NiSource Corporate Services Company
Abbreviations |  |
ACE |  | Affordable clean energy
AFUDC |  | Allowance for funds used during construction
AMR |  | Automatic meter reading
AOCI |  | Accumulated Other Comprehensive Income
ASC |  | Accounting Standards Codification
ASU |  | Accounting Standards Update
ATM |  | At-the-market
Board |  | Board of Directors
BTA |  | Build-transfer agreement
CAP |  | Compliance Assurance Process
CCGT |  | Combined Cycle Gas Turbine
CCRs |  | Coal Combustion Residuals
CEP |  | Capital Expenditure Program
CERCLA |  | Comprehensive Environmental Response Compensation and Liability Act (also known as Superfund)
COVID-19 ("the COVID-19 pandemic" or "the pandemic") |  | Novel Coronavirus 2019
DPA |  | Deferred prosecution agreement
DPU |  | Department of Public Utilities
DSIC |  | Distribution System Investment Charge
DSM |  | Demand Side Management
EPA |  | 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
GAAP |  | Generally Accepted Accounting Principles
GCA |  | Gas cost adjustment
GHG |  | Greenhouse gas
GWh |  | Gigawatt hours

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DEFINED TERMS
HLBV |  | Hypothetical Liquidation at Book Value
IRP |  | Infrastructure Replacement Program
IRS |  | Internal Revenue Service
IURC |  | Indiana Utility Regulatory Commission
LDCs |  | Local distribution companies
LIBOR |  | London inter-bank offered rate
LIFO |  | Last-in, first-out
MA DOR |  | Massachusetts Department of Revenue
Massachusetts Business |  | All of the assets sold to, and liabilities assumed by, Eversource pursuant to the Asset Purchase Agreement
MGP |  | Manufactured Gas Plant
MISO |  | Midcontinent Independent System Operator
MMDth |  | Million dekatherms
MW |  | Megawatts
MWh |  | Megawatt hours
NOL |  | Net Operating Loss
NTSB |  | National Transportation Safety Board
NYMEX |  | The New York Mercantile Exchange
NYSE |  | 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
PPA |  | Power Purchase Agreement
PSC |  | Public Service Commission
PUC |  | Public Utility Commission
PUCO |  | Public Utilities Commission of Ohio
RCRA |  | Resource Conservation and Recovery Act
ROE |  | Return on Equity
Rosewater |  | Rosewater Wind Generation LLC
ROU |  | Right of use
SAVE |  | Steps to Advance Virginia's Energy Plan
SEC |  | Securities and Exchange Commission
SMRP |  | Safety Modification and Replacement Program
SMS |  | Safety Management System
STRIDE |  | Strategic Infrastructure Development and Enhancement
Sugar Creek |  | Sugar Creek electric generating plant
TCJA |  | Tax Cuts and Jobs Act of 2017
TDSIC |  | Transmission, Distribution and Storage System Improvement Charge
TSA |  | Transition Service Agreement
U.S. Attorney's Office |  | U.S. Attorney's Office for the District of Massachusetts
VIE |  | Variable Interest Entity
VSCC |  | Virginia State Corporation Commission

Note regarding forward-looking statements
This Annual Report on Form 10-K contains “forward-looking statements,” within the meaning of Section 27A of the Securities Act of 1933, as amended (the "Securities Act"), and Section 21E of the Securities Exchange Act of 1934, as amended (the
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"Exchange Act"). Investors and prospective investors should understand that many factors govern whether any forward-looking statement contained herein will be or can be realized. Any one of those factors could cause actual results to differ materially from those projected. These forward-looking statements include, but are not limited to, statements concerning our plans, strategies, objectives, expected performance, expenditures, recovery of expenditures through rates, stated on either a consolidated or segment basis, and any and all underlying assumptions and other statements that are other than statements of historical fact. Expressions of future goals and expectations and similar expressions, including "may," "will," "should," "could," "would," "aims," "seeks," "expects," "plans," "anticipates," "intends," "believes," "estimates," "predicts," "potential," "targets," "forecast," and "continue," reflecting something other than historical fact are intended to identify forward-looking statements. All forward-looking statements are based on assumptions that management believes to be reasonable; however, there can be no assurance that actual results will not differ materially.
Factors that could cause actual results to differ materially from the projections, forecasts, estimates and expectations discussed in this Annual Report on Form 10-K include, among other things, our ability to execute our business plan or growth strategy, including utility infrastructure investments; potential incidents and other operating risks associated with our business; our ability to adapt to, and manage costs related to, advances in technology; impacts related to our aging infrastructure; our ability to obtain sufficient insurance coverage and whether such coverage will protect us against significant losses; the success of our electric generation strategy; construction risks and natural gas costs and supply risks; fluctuations in demand from residential and commercial customers; fluctuations in the price of energy commodities and related transportation costs or an inability to obtain an adequate, reliable and cost-effective fuel supply to meet customer demands; the attraction and retention of a qualified workforce and ability to maintain good labor relations; our ability to manage new initiatives and organizational changes; the performance of third-party suppliers and service providers; potential cyber-attacks; any damage to our reputation; any remaining liabilities or impact related to the sale of Massachusetts Business; the impacts of natural disasters, potential terrorist attacks or other catastrophic events; the impacts of climate change and extreme weather conditions; our debt obligations; any changes to our credit rating or the credit rating of certain of our subsidiaries; adverse economic and capital market conditions or increases in interest rates; economic regulation and the impact of regulatory rate reviews; our ability to obtain expected financial or regulatory outcomes; continuing and potential future impacts from the COVID-19 pandemic; economic conditions in certain industries; the reliability of customers and suppliers to fulfill their payment and contractual obligations; the ability of our subsidiaries to generate cash; pension funding obligations; potential impairments of goodwill; changes in the method for determining LIBOR and the potential replacement of the LIBOR benchmark interest rate; the outcome of legal and regulatory proceedings, investigations, incidents, claims and litigation; potential remaining liabilities related to the Greater Lawrence Incident; compliance with the agreements entered into with the U.S. Attorney’s Office to settle the U.S. Attorney’s Office’s investigation relating to the Greater Lawrence Incident; compliance with applicable laws, regulations and tariffs; compliance with environmental laws and the costs of associated liabilities; changes in taxation; and other matters set forth in Item 1, “Business,” Item 1A, “Risk Factors” and Part II. Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” of this report, some of which risks are beyond our control. In addition, the relative contributions to profitability by each business segment, and the assumptions underlying the forward-looking statements relating thereto, may change over time.
All forward-looking statements are expressly qualified in their entirety by the foregoing cautionary statements. We undertake no obligation to, and expressly disclaim any such obligation to, update or revise any forward-looking statements to reflect changed assumptions, the occurrence of anticipated or unanticipated events or changes to the future results over time or otherwise, except as required by law.
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PART I
ITEM 1. BUSINESS
N I S OURCE I NC.
NiSource Inc. is an energy holding company under the Public Utility Holding Company Act of 2005 whose primary subsidiaries are fully regulated natural gas and electric utility companies, serving approximately 3.7 million customers in six states. NiSource is the successor to an Indiana corporation organized in 1987 under the name of NIPSCO Industries, Inc., which changed its name to NiSource on April 14, 1999.
NiSource’s principal subsidiaries include NiSource Gas Distribution Group, Inc., a natural gas distribution holding company, and NIPSCO, a gas and electric company. NiSource derives substantially all of its revenues and earnings from the operating results of these rate-regulated businesses.
On February 26, 2020, NiSource and Columbia of Massachusetts entered into an Asset Purchase Agreement with Eversource (the "Asset Purchase Agreement"). Upon the terms and subject to the conditions set forth in the Asset Purchase Agreement, NiSource and Columbia of Massachusetts agreed to sell to Eversource, with certain additions and exceptions: (1) substantially all of the assets of Columbia of Massachusetts and (2) all of the assets held by any of Columbia of Massachusetts’ affiliates that primarily relate to the Massachusetts Business, and (3) Eversource agreed to assume certain liabilities of Columbia of Massachusetts and its affiliates. The closing of the transaction occurred on October 9, 2020. Refer to Note 1-A, "Company Structure and Principles of Consolidation," Note 7, "Goodwill and Other Intangible Assets," Note 20-C. "Legal Proceedings," and Note 20-E. "Other Matters," in the Notes to Consolidated Financial Statements for more information.
The COVID-19 pandemic has had widespread effects, including impacts on the communities in which we serve as well as our business operations. NiSource has been pro-active in adjusting its operating procedures in response to the pandemic, including customer facing and field activities as well as our back-office support. Through 2020, we have not experienced material impacts to our ongoing or planned construction, replacement and maintenance activities as a result of the pandemic. Please refer to specific and potential impacts of the pandemic in Item 1A, "Risk Factors", Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations” and the Notes to Consolidated Financial Statements.
NiSource’s reportable segments are: Gas Distribution Operations and Electric Operations. The following is a summary of the business for each reporting segment. Refer to Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Note 24, "Segments of Business," in the Notes to Consolidated Financial Statements for additional information for each segment.
Gas Distribution Operations
Our natural gas distribution operations serve approximately 3.2 million customers in six states. We operate approximately 53,700 miles of distribution main pipeline plus the associated individual customer service lines and 1,700 miles of transmission main pipeline located in our service areas described below. Throughout our service areas we also have gate stations and other operations support facilities. Through our wholly-owned subsidiary NiSource Gas Distribution Group, Inc., we own five distribution subsidiaries that provide natural gas to approximately 2.4 million residential, commercial and industrial customers in Ohio, Pennsylvania, Virginia, Kentucky, and Maryland. Additionally, we distribute natural gas to approximately 848,000 customers in northern Indiana through our wholly-owned subsidiary NIPSCO.
Rates include provisions to adjust billings for fluctuations in the cost of natural gas. Revenues are adjusted for differences between actual costs, subject to reconciliation, and the amounts billed in current rates.
Electric Operations
We generate, transmit and distribute electricity through our subsidiary NIPSCO to approximately 479,000 customers in 20 counties in the northern part of Indiana and also engage in wholesale electric and transmission transactions. NIPSCO owns and operates two coal-fired electric generating stations: four units at R.M. Schahfer located in Wheatfield, IN and one unit at Michigan City located in Michigan City, IN. The two operating facilities have a generating capacity of 2,080 MW. NIPSCO also owns and operates (i) Sugar Creek, a CCGT plant located in West Terre Haute, IN with generating capacity of 571 MW; (ii) two gas-fired generating units located at R.M. Schahfer with a generating capacity of 155 MW; and (iii) two hydroelectric generating plants with a generating capacity of 10 MW (Oakdale located at Lake Freeman in Carroll County, IN and Norway located at Lake Schahfer in White County, IN). These facilities provide for a total system operating generating capacity of 2,816 MW. NIPSCO is the managing partner in Rosewater Wind Generation LLC, a joint venture that owns and operates 102 MW of nameplate generating capacity in White County, IN. Refer to Note 4 "Variable Interest Entities" in the Notes to Consolidated Financial Statements for more information.
In May 2018, NIPSCO completed the retirement of two coal-burning units at Bailly Generating Station, located in Chesterton, IN. These units had a generating capacity of approximately 460 MW, which was replaced through various electric purchase agreements.
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NIPSCO’s transmission system, with voltages from 69,000 to 765,000 volts, consists of 3,009 circuit miles. NIPSCO is interconnected with eight neighboring electric utilities. During the year ended December 31, 2020, NIPSCO generated 68.8% and purchased 31.2% of its electric requirements.
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.
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. 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) address changing customer conservation patterns, (ii) align our price structures with our cost structure, and (iii) embark on long-term investment programs. These strategies focus on improving safety and reliability, enhancing customer service, lowering customer bills and reducing emissions while generating sustainable returns.
The safety of our customers, communities and employees remains our top priority. The SMS transitioned in 2020 from an accelerated project launch to an established operating model within NiSource. With the continued support and advice from the 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.
In its 2018 Integrated Resource Plan submission to the IURC, NIPSCO laid out a plan to retire the R.M. Schahfer Generating Station by 2023 and Michigan City Generating Station by 2028. These units represent 72% of NIPSCO’s remaining generation capacity. The current replacement plan includes renewable sources of energy, including wind, solar, and battery storage, to be obtained through a combination of NIPSCO investment and PPAs. Refer to Note 20-E, "Other Matters," in the Notes to Consolidated Financial Statements for further discussion of these plans.
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
NIPSCO - Electric(1) | 10.80 | % | 9.75 | % | $ | 21.4 |  | $ | (53.5) |  | October 31, 2018 | Approved December 4, 2019 | January 2020
Columbia of Pennsylvania(2) | 9.86 | % | N/A | $ | 76.8 |  | In process | April 24, 2020 | Order Expected Q1 2021 | January 2021
Columbia of Maryland | 10.95 | % | None specified(3) | $ | 5.0 |  | $ | 2.0 |  | May 15, 2020 | Approved November 7, 2020 | December 2020

(1)Rates were implemented in two steps, with implementation of step 1 rates effective on January 2, 2020 and step 2 rates effective on March 2, 2020.
(2)On December 4, 2020, a Recommended Decision was issued by the Administrative Law Judge (ALJ) for the PUC to "deny the Company's request in its entirety because it has not met its burden of providing, by substantial evidence, that the proposed base rate revenue increase will result in just and reasonable rates, as required by 66 Pa.C.S.A. § 1301 during the current Coronavirus-2019 pandemic." Columbia of Pennsylvania filed Exceptions to the ALJ’s Recommended Decision on December 22, 2020 in which the Company proposed an increase of $76.8 million to be implemented in two steps: (1) an increase of $38.4 million to be effective January 23, 2021 through June 30, 2021, and defer revenue related to the remaining increase to regulatory assets during this phase, and (2) the remaining increase of $38.4 million to be implemented on July 1, 2021. Columbia of Pennsylvania proposed to recover the revenue deferred to a Regulatory Asset during the initial phase over a one-year period beginning January 1, 2022 and ending December 31, 2022. A Final Order from the PUC is expected during the first quarter of 2021 for rates effective retroactively on January 23, 2021.
(3)Columbia of Maryland'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 9.60% ROE for future Make Whole and Infrastructure Tracker filings.
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ITEM 1. BUSINESS
N I S OURCE I NC.
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 20-D, "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 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.
Increased efficiency of natural gas appliances and improvements in home building codes and standards has contributed to a long-term trend of declining average use per customer. While historical rate design at the distribution level has been structured such that a large portion of cost recovery is based upon throughput rather than in a fixed charge, operating costs are largely incurred on a fixed basis and do not fluctuate due to changes in customer usage. As a result, Gas Distribution Operations have pursued changes in rate design to more effectively match recoveries with costs incurred. Each of the states in which Gas Distribution Operations operate has different requirements regarding the procedure for establishing changes to rate design. Columbia of Ohio has adopted a decoupled 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. Columbia of Kentucky incorporates a weather normalization adjustment. 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.
Cost Recovery and Trackers. Comparability of our line item operating results are impacted by regulatory trackers that allow for the future recovery in rates of certain costs as described below. Increases in expenses that are the 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.
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 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. Our Gas Distribution Operations’ subsidiaries are involved in programs that provide customers the opportunity to purchase their natural gas requirements from third parties and use our Gas Distribution Operations’ subsidiaries for transportation services.
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ITEM 1. BUSINESS
N I S OURCE I NC.
Gas Distribution Operations competes with (i) investor-owned, municipal, and cooperative electric utilities throughout its service areas, (ii) other regulated and unregulated natural gas intra and interstate pipelines and (iii) other alternate fuels, such as propane and fuel oil. Gas Distribution Operations continues to be a strong competitor in the energy market as a result of strong 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.
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.
Human Capital
Human Capital Goals and Objectives. We have aligned our human capital goals to achieve the overall company 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, 2020, we had 7,301 full-time and 88 part-time employees. 2,728 employees were subject to collective bargaining agreements with various labor unions. Six of these agreements covering 527 employees are set to expire within one year.
Diversity. Our talent acquisition teams hired 612 external candidates in 2020 across all business segments. 35% of external hires were female and 18% were racially or ethnically diverse. In 2020, 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 offered several employee resource groups (“ERGs”) and hosted mostly virtual activities throughout 2020. We have ERGs set up to support African-American, LatinX, veterans, LGBTQ+, female and Asian employees, among others, and held several sponsored conversations between senior executives and the ERGs.
The following provides the diversity breakdown of NiSource as of December 31, 2020:
Talent Development. We offer leadership development programs to enhance the behaviors and skills of our existing and future leaders. In 2020, we had participation from employees of all levels. We also offer extensive technical and non-technical
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N I S OURCE I NC.
employee training programs. Additionally, we strive to provide promotion and advancement opportunities for employees. In 2020, 84% of all leadership positions at the supervisor and above level were filled internally. Succession planning is regularly conducted to ensure bench strength for leadership positions. We utilize retention bonuses and conduct stay conversations in order to retain talent. Retention at NiSource in 2020 was over 93%. Retention is calculated using the total number of terminations divided by the average headcount for the annual period, not including the impacts from the sale of the Massachusetts Business and voluntary separation programs.
Employee Safety and Wellness. 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 family days, competitive medical, dental, vision, life and long term disability programs including employee health savings account company contributions and no cost registered financial planner counseling.
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, wearing face coverings, temperature checks and more frequent cleaning of equipment and facilities. We have also implemented work-from-home policies and practices. We have minimized non-essential work that requires an employee to enter a customer premise and limited company vehicle occupancy to one person, where possible. 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. We will continue to follow the Centers for Disease Control and Prevention ("CDC") guidance and implement safety measures intended to ensure employee and customer safety during the pandemic.
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 certain 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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ITEM 1A. RISK FACTORS
N I S OURCE I NC.
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.
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, may not be effective. 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. Environmental activist groups, investors and governmental entities may continue to oppose natural gas delivery and infrastructure investments in the jurisdictions where we operate 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 energy. 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).
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, 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. 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 us. 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 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. These technologies 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 are reducing the cost of electric generation from these sources to a level that is competitive with most central station power electric production. This could cause power sales to decline and the value of our generating facilities to decline. New technologies may require us to make significant expenditures to remain competitive and may result in the obsolescence of certain operating assets.
Our natural gas business model leverages 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.
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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, 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, services and processes 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 infrastructure, including our electric and gas infrastructure assets. 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 inspections, maintenance, upgrading and replacement of the assets particularly challenging. Missing or incorrect infrastructure data may lead to (1) difficulty properly locating facilities, which can result in excavator damage and operational or emergency response issues, and (2) configuration and control risks associated with the modification of system operating pressures in connection with turning off or turning on service to customers, which can result in unintended outages or operating pressures. Also, additional maintenance and inspections are required in some instances in order to improve infrastructure information and records and address emerging regulatory or risk management requirements, which increases our costs. The failure to operate these 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 in our inability to meet firm service 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 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 is experiencing a hardening environment due to reductions in commercial suppliers and the capacity they are willing to issue, increases in overall demand for capacity, and a prevalence of severe losses. We have not been able to obtain liability insurance coverage at previously procured limits at rates that are acceptable to us. 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 expect that they will continue to increase as a result of hardening in market conditions. 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 80% of our coal generation capacity by mid-2023 and all of our coal generation by the end of 2028 with primarily renewable resources may not progress as anticipated. On October 31, 2018, NIPSCO submitted its 2018 Integrated Resource Plan with the IURC setting forth its short- and long-term electric generation plans in an effort to maintain affordability while providing reliable, flexible and cleaner sources of power. The Integrated Resource Plan evaluated demand-side and supply-side resource alternatives to meet NIPSCO customers' future energy requirements over the ensuing 20 years.
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The preferred option within the Integrated Resource Plan retires the R.M. Schahfer Generating Station by mid-2023 and the Michigan City Generating Station by the end of 2028. These stations represent 2,080 MW of generating capacity, equal to 72% of NIPSCO’s remaining generating capacity and 100% of NIPSCO's remaining coal-fired generating capacity. The current replacement plan includes renewable sources of energy, including wind, solar, and battery storage. In the second quarter of 2020, the MISO approved NIPSCO's plan to retire the R.M. Schahfer Generating Station in 2023. In February 2021, NIPSCO decided to submit modified Attachment Y Notices to MISO requesting accelerated retirement of two of the four units at R.M. Schahfer Generating Station. The two units are now expected to be retired by the end of 2021, with the remaining two units still scheduled to be retired in 2023. Refer to Note 20- E. "Other Matters - NIPSCO 2018 Integrated Resource Plan," in the Notes to Consolidated Financial Statements for additional information.
There are inherent risks and uncertainties in executing the Integrated Resource Plan, including changes in market conditions, regulatory approvals, environmental regulations, commodity costs and customer expectations, which may impede NIPSCO’s ability to achieve the intended results. 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. 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. As required by statute, NIPSCO plans to submit a new Integrated Resource Plan to the IURC by November 1, 2021. This submission will again outline NIPSCO's short and long term plans for meeting the energy supply needs of its customers, taking into account current perspectives on a range of factors including, but not limited to, new state and federal policy, wholesale market rules, forecasted customer demand, and available resource alternatives.The analysis, conclusions and Preferred Plan in the 2021 Integrated Resource Plan may be different from the analysis, conclusions and Preferred Plan in the 2018 Integrated Resource Plan.
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 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. Additionally, we may construct or purchase some of these projects and programs to capture anticipated future growth in natural gas production, 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 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.
On May 1, 2020, former President Donald Trump issued an executive order (the “EO”) prohibiting any transaction initiated after that day that (i) involves bulk-power system (“BPS”) equipment designed, developed, manufactured or supplied by persons owned by, controlled by or subject to the jurisdiction or direction of a foreign adversary and (ii) poses an unacceptable risk to national security. Implementing regulations from the U.S. Secretary of Energy are still pending. The EO also requires the U.S. Secretary of Energy to review the risk of existing bulk-power system equipment sourced from foreign adversaries and to establish a task force to review and recommend federal procurement policies and procedures consistent with the considerations identified in the EO. On July 8, 2020, the U.S. Department of Energy issued a Request for Information (“RFI”), seeking input from industry stakeholders to “understand the energy industry’s current practices to identify and mitigate vulnerabilities in the supply chain” for components of bulk-power system equipment. The RFI identifies the following governments as “foreign adversaries”: China, Cuba, Iran, North Korea, Russia and Venezuela. The RFI notes that the U.S. Secretary of Energy retains
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authority to amend this list at any time and such countries have been identified only for the purposes of the EO. Pursuant to the EO, on December 17, 2020, the U.S. Department of Energy issued a Prohibition Order (the “Prohibition Order”) prohibiting the acquisition, importation, transfer, or installment of specified BPS equipment from China that directly serves critical defense facilities. While the implications of the Prohibition Order are still being assessed, it could impact our procurement processes for BPS equipment. In the future, certain bulk-power system equipment owned or operated by NiSource could possibly be considered to be sourced from a foreign adversary within the meaning of the EO. These regulations, if implemented, may impact our procurement processes for bulk-power system equipment.
To the extent that delays occur, costs become unrecoverable, 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 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, 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. 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.
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. When appropriate, we use hedging 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 customers. If transportation is disrupted, or if capacity is inadequate, we may be unable to sell and deliver our gas and electric services to some or all of our customers. As a result, we may be required to procure additional or alternative electricity and/or natural gas supplies at then-current market rates, which, if recovery of related costs is disallowed, could have a material adverse effect on our businesses, financial condition, cash flows, results of operations and/or prospects.
Failure to attract and retain an appropriately qualified workforce, and maintain good labor relations, could harm our results of operations.
We operate in an industry that requires many of our employees to possess unique technical skill sets. Events such as an aging workforce without appropriate replacements, the mismatch of skill sets to future needs, or 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. In addition, current and prospective employees may determine that they do not wish to work for us due to market, economic, employment and other conditions. 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, safety, service reliability, customer satisfaction and our results of operations could be adversely affected.
Some of our employees are subject to collective bargaining agreements. Our collective bargaining agreements are generally negotiated on an operating company basis. Any failure to reach an agreement on new labor contracts or to negotiate these labor contracts might result in strikes, boycotts or other labor disruptions. Labor disruptions, strikes or significant negotiated wage
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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.
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. If we are unable to make decisions quickly, assess our opportunities and risks, and 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 and stockholders may be negatively impacted.
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. Global metrics indicate that deliveries from suppliers are slowing and that labor shortages are occurring in the energy sector. We outsource certain services to third parties in areas including construction services, information technology, materials, fleet, environmental, operational services and other areas. 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. If any 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 computer 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 computer 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., 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 large-scale corporate attacks in conjunction with more sophisticated threats continue to challenge power and utility companies. Any failure of our computer 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. 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, or a security breach of the information systems of our customers, suppliers or others with whom we do business, could (i) impact the reliability of our generation, transmission and distribution systems and potentially negatively impact our compliance with certain mandatory reliability 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.
We are exposed to significant reputational risks, which make us vulnerable to a loss of cost recovery, increased litigation and negative public perception.
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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 or other unanticipated events, as well as our own or third parties' actions or failure to act. We are also subject to adverse publicity related to actual or perceived environmental impacts. If customers, legislators, or regulators have or develop a negative opinion of us, this could result in less favorable legislative and regulatory outcomes or increased regulatory oversight, increased litigation and negative public perception. The adverse publicity and investigations we experienced as a result of the Greater Lawrence Incident may have an ongoing negative impact on the public’s perception of us. It is difficult to predict the ultimate impact of this adverse publicity. The foregoing may have continuing adverse effects on our business, results of operations, cash flow and financial condition.
The sale of the Massachusetts Business poses risks and challenges that could negatively impact our business, and we may not realize the expected benefits of 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.
Further, the sale of the Massachusetts Business may result in a dilutive impact to our future earnings if we are unable to offset the loss of revenue associated with the sale, which could have a material adverse effect on our results of operations and financial condition.
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. 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.
Climate change has the potential to affect our business.
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. In addition, climate change may exacerbate the risks to our physical infrastructure, including heat stresses to power lines, storms that damage infrastructure, lake and sea level changes that affect the manner in which services are currently provided, droughts or other stresses on water used to supply services, and other extreme weather conditions. Climate change and the transition to a lower carbon economy have the potential to affect our business by reducing our ability to serve customers, increasing the costs we incur in providing our products and services, impacting the demand for and consumption of our products and services (due to changes in costs, technology, reputation and weather patterns), and affecting the economic health of the regions in which we operate. 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.
Extreme weather conditions may negatively impact our operations.
We conduct our operations across a wide geographic area subject to varied and potentially extreme weather conditions, which may from time to time persist for sustained periods of time. Despite preventative maintenance efforts, persistent weather related stress on our infrastructure may reveal weaknesses in our systems not previously known to us or otherwise present various operational challenges across all business segments. Further, adverse weather may affect our ability to conduct operations in a manner that satisfies customer expectations or contractual obligations, including by causing service disruptions.
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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 $9,746.1 million outstanding as of December 31, 2020. 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.
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, 2020, the collateral requirement that would be required in the event of a downgrade below the ratings trigger levels would amount to approximately $53.9 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 novel coronavirus (COVID-19) pandemic adversely impacts our business, results of operations, financial condition, liquidity and cash flows.
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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, extended disruptions to supply chains and capital markets, and reduced labor availability and productivity. We have experienced lower revenues, higher expenses for personal protective equipment and supplies, and higher bad debt expense as a consequence of the pandemic, which has negatively impacted our results of operations as of December 31, 2020. Our future operating results and liquidity may continue to be impacted by the pandemic, but the extent of the impact remains uncertain. Such ongoing impact of the pandemic 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 re-opening plans in each state and as businesses experience negative economic impact from the pandemic, potentially offset by higher residential demand;
•Lower revenue and cash flow due to the continuing 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 deferral;
•Lower revenues on a prolonged basis resulting from higher customer bankruptcies, predominately focused on commercial and industrial customers not able to sustain operations through the broader economic downturn;
•A continued delay in cash flows as 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 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 degree to which the pandemic will impact us will depend in part on future developments, including the continued severity and duration of the outbreak, actions that may be taken by governmental authorities, and to what extent and when normal economic and operating conditions can resume.
Adverse economic and market conditions, including as a result of the COVID-19 pandemic, or increases in interest rates 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. While several of these moratoriums remain in place, we have reinstated our common credit mitigation practices where moratoriums have expired. It is possible that such moratoriums will be extended or 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
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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 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. 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.
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.
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 COVID-19 pandemic is another factor that will continue to influence the regulatory process, such as the implementation of disconnection moratoriums as discussed above and the risk of not being able to recover costs and/or returns on invested capital through raising rates during a pandemic, which has disproportionately impacted vulnerable customers and communities.
Additionally, the costs of complying with current and future changes in environmental and federal pipeline safety laws and regulations are expected to be significant, and their recovery through rates will also be contingent on regulatory approval.
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, increasing costs, and fluctuating demand for its products. In addition, our results of operations are negatively impacted by lower revenues resulting from higher bankruptcies, predominately focused on commercial and industrial customers not able to sustain operations through the economic disruptions related to the pandemic.
We are exposed to risk that customers will not remit payment for delivered energy or services, and that suppliers or counterparties will not perform under various financial or operating agreements.
Our extension of credit is governed by a Corporate Credit Risk Policy, involves considerable judgment by our employees and is based on an evaluation of a customer or counterparty’s financial condition, credit history and other factors. We monitor our credit risk exposure by obtaining credit reports and updated financial information for customers and suppliers, and by evaluating the financial status of our banking partners and other counterparties by reference to market-based metrics such as credit default swap pricing levels, and to traditional credit ratings provided by the major credit rating agencies. Adverse economic conditions result in an increase in defaults by customers, suppliers and counterparties. As stated above, in connection with the COVID-19 pandemic, certain state regulatory commissions instituted regulatory moratoriums that have impacted our ability to pursue our standard credit risk mitigation practices.
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ITEM 1A. RISK FACTORS
N I S OURCE I NC.
We are a holding company and are dependent on cash generated by our subsidiaries to meet our debt obligations and pay dividends on our stock.
We are a holding company and conduct our operations primarily through our subsidiaries, which are separate and distinct legal entities. Substantially all of our consolidated assets are held by our subsidiaries. Accordingly, our ability to meet our debt obligations or pay dividends on our common stock and preferred stock is largely dependent upon cash generated by these subsidiaries. In the event a major subsidiary is not able to pay dividends or transfer cash flows to us, our ability to service our debt obligations or pay dividends could be negatively affected.
Capital market performance and other factors may decrease the value of benefit plan assets, which then could require significant additional funding and impact earnings.
The performance of the capital markets affects the value of the assets that are held in trust to satisfy future obligations under defined benefit pension and other postretirement benefit plans. We have significant obligations in these areas and hold significant assets in these trusts 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, 2020, the ratio was 62.5%.
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, including borrowings under our revolving credit agreement, 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. 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. SOFR is intended to be a
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ITEM 1A. RISK FACTORS
N I S OURCE I NC.
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. For example, SOFR is a secured overnight rate, while LIBOR is an unsecured rate that represents interbank funding over different maturities. In addition, because SOFR is a transaction-based rate, it is backward-looking, whereas LIBOR is forward-looking. 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, which include, without limitation, requesting certain rates from major reference banks in London or New York, 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 are involved in legal and regulatory proceedings, investigations, inquiries, claims and litigation in connection with our business operations, including those related to the Greater Lawrence Incident, the most significant of which are summarized in Note 20, “Other Commitments and Contingencies” in the Notes to Consolidated Financial Statements. Our insurance does not cover all costs and expenses that we have incurred or that we may incur in the future 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. We have been subject to inquiries and investigations by government authorities and regulatory agencies regarding the Greater Lawrence Incident, including the Massachusetts DPU and the Massachusetts Attorney General's Office, as further described in Note 7, "Goodwill and Other Intangible Assets," Note 20-C. "Legal Proceedings," and Note 20-E. "Other Matters" in the Notes to Consolidated Financial Statements.
While we have recovered the full amount of our liability insurance coverage available under our policies, total expenses related to the incident have 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 the U.S. Attorney’s Office investigation as well as 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. If we are unable to recover the capital cost of the gas pipeline replacement through the pending property insurance litigation related to this matter, or we incur a material amount of other costs, our financial condition, results of operations, and cash flows could be materially and adversely affected.
Further, 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"). See Note 20-C. "Legal Proceedings” in the Notes to Consolidated Financial Statements. 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
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ITEM 1A. RISK FACTORS
N I S OURCE I NC.
to penalties, financial or otherwise, and subjects 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 laws, regulations and tariffs. We could be materially adversely affected if we fail to comply with such laws, regulations and tariffs or with any changes in or new interpretations of such laws, regulations and tariffs.
Our businesses are subject to various laws, regulations and tariffs, including, but not limited to, those relating to natural gas pipeline safety, employee safety, the environment and our energy infrastructure. Existing laws, regulations and tariffs may be revised or become subject to new interpretations, and new laws, regulations and tariffs may be adopted or become applicable to us and our operations. In some cases, compliance with new laws, regulations and tariffs increases our costs. 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 or tariffs, 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, and priority pipeline replacement, energy efficiency programs, 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.
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’
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ITEM 1A. RISK FACTORS
N I S OURCE I NC.
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
N I S OURCE I NC.
None.
ITEM 2. PROPERTIES
Discussed below are the principal properties held by us and our subsidiaries as of December 31, 2020.
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 20-C "Legal Proceedings" in the Notes to Consolidated Financial Statements.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
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SUPPLEMENTAL ITEM. INFORMATION ABOUT OUR EXECUTIVE OFFICERS
N I S OURCE I NC.
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
Joseph Hamrock |  | 57 |  |  | President and Chief Executive Officer of NiSource since July 2015.
Donald E. Brown |  | 49 |  |  | 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.
|  |  |  | Treasurer of NiSource from July 2015 to June 2016.
Anne-Marie W. D'Angelo |  | 44 |  |  | Executive Vice President, General Counsel and Corporate Secretary.
|  |  |  | Executive Vice President of NiSource since January 2021.
|  |  |  | Corporate Secretary and General Counsel of NiSource since September 2019.
|  |  |  | Senior Vice President of NiSource from September 2019 to January 2021.
|  |  |  | General Counsel of Global Brass & Copper Inc. from May 2017 to August 2019.
|  |  |  | Assistant General Counsel of McDonald’s USA from January 2015 to May 2017.
Shawn Anderson |  | 39 |  |  | 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 May 2020.
|  |  |  | Vice President, Regulatory Affairs and Financial of Columbia of Ohio from July 2015 to June 2016.
Charles E. Shafer, II |  | 51 |  |  | 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.
|  |  |  | Vice President, Engineering and Construction of NiSource Corporate Services Company from June 2012 to May 2016.
Violet G. Sistovaris |  | 59 |  |  | 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 |  | 47 |  |  | 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.
|  |  |  | President and Chief Operating Officer of American Electric Power Company of Ohio from May 2012 to May 2016.

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PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
N I S OURCE I NC.
NiSource’s common stock is listed and traded on the New York Stock Exchange under the symbol “NI.”
Holders of shares of NiSource’s common stock are entitled to receive dividends if and when declared by 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 27, 2021 meeting, the Board declared a quarterly common dividend of $0.22 per share, payable on February 19, 2021 to holders of record on February 9, 2021.
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 9, 2021, NiSource had 18,211 common stockholders of record and 391,859,711 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, 2020, 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. SELECTED FINANCIAL DATA
N I S OURCE I NC.
None.
On November 19, 2020, the SEC issued amendments to streamline and enhance certain financial disclosure requirements in Regulation S-K. These changes are effective for annual filings for the first fiscal year ending on or after August 9, 2021. Early adoption is permitted for companies after February 10, 2021, and companies are permitted to selectively early adopt the provisions of the final rules, provided an amended item is adopted in its entirety. We early adopted the amendments to Item 301 in their entirety, which removed the requirement to furnish selected financial data for each of the last five fiscal years.
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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
N I S OURCE I NC.

Index | Page
Executive Summary | 28
Summary of Consolidated Financial Results | 30
Results and Discussion of Segment Operations | 31
Gas Distribution Operations | 32
Electric Operations | 36
Liquidity and Capital Resources | 40
Off Balance Sheet Arrangements | 45
Market Risk Disclosures | 45
Other Information | 46

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 24, "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) address changing customer conservation patterns, (ii) develop more contemporary pricing structures, and (iii) embark on long-term infrastructure investment and safety programs. These strategies focus on improving reliability and safety, enhancing customer service, lowering customer bills and reducing emissions while generating sustainable returns. 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. Refer also to the Electric Supply section of our Electric Operations Segment discussion for additional information on our long term electric generation strategy.
Columbia of Massachusetts Asset Sale: On February 26, 2020, NiSource and Columbia of Massachusetts entered into an Asset Purchase Agreement with Eversource (the "Asset Purchase Agreement"). Upon the terms and subject to the conditions set forth in the Asset Purchase Agreement, we sold the Massachusetts Business to Eversource for net proceeds of approximately $1,113 million in cash, subject to adjustment for the final working capital amount. The sale was approved by the Massachusetts DPU on October 7, 2020, and closed on October 9, 2020. As a result of the sale, we have transitioned to executing a TSA with Eversource. See Note 1, "Nature of Operations and Summary of Significant Accounting Policies," in the Notes to Consolidated Financial Statements for additional information.
Your Energy, Your Future: Our plan to replace 80% of our coal generation capacity by the end of 2023 and all of our coal generation by the end of 2028 with primarily renewable resources is well underway. In October 2020, we executed three BTAs for 900 MW solar nameplate capacity and 135 MW of storage capacity. In December 2020, the formation of the Rosewater Wind Generation joint venture, one of our previously executed BTAs, was completed, and has begun operation. We executed in December 2020 a PPA for an additional 280 MW of solar nameplate capacity. These projects were selected following a comprehensive review of bids submitted through the RFP process that NIPSCO underwent in late 2019. The projects complement previously executed BTAs and PPAs with a combined nameplate capacity of 400 MW and 1,300 MW, respectively. For additional information, see Note 4 "Variable Interest Entities" and "Results and Discussion of Segment Operation - Electric Operations," in this Management's Discussion.
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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
N I S OURCE I NC.
NiSource Next: We have launched a comprehensive, multi-year program designed to deliver long-term safety, sustainable capability enhancements and cost optimization improvements. This program will advance the high priority we place on safety and risk mitigation, further enable our safety management system ("SMS"), and enhance the customer experience. NiSource Next is designed to (i) leverage our current scale, (ii) utilize technology, (iii) define clear roles and accountability with our leaders and employees, and (iv) standardize our processes to focus on operational rigor, quality management and continuous improvement. An initial step in this program was the voluntary separation program announced in August 2020, with an expected total severance expense of approximately $38.0 million. The majority of these separation costs will be expensed in 2020 and approximately $21.2 million has been paid as of December 31, 2020. The NiSource Next initiative, along with the sale of the Massachusetts Business, is projected to achieve a reduction in ongoing operation and maintenance costs by approximately 8% in 2021 compared to 2020. For additional information, see Note 20-E, "Other Matters," in the Notes to Consolidated Financial Statements.
COVID-19: The safety of our employees and customers, while providing essential services during the COVID-19 pandemic, continues to be a key area of focus. Since March 2020, we have taken a proactive, coordinated approach intended to prevent, mitigate and respond to the pandemic, by utilizing our Incident Command System (ICS). The ICS includes members of our executive leadership team, 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, wearing face coverings, temperature checks and more frequent cleaning of equipment and facilities. We have also implemented work-from-home policies and practices. We have minimized non-essential work that requires an employee to enter a customer premise and limited company vehicle occupancy to one person, where possible. 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 will continue to follow CDC guidance and implement safety measures intended to ensure employee and customer safety during this pandemic. We are following all federal, state and local guidelines related to the COVID-19 vaccinations and will encourage employees to receive the vaccine when it is available to them.
Since the beginning of the pandemic, we have been helping our customers navigate this challenging time. We suspended disconnections soon after this outbreak began. As of December 2020, suspension of disconnections has been lifted in some, but not all, of our jurisdictions. We plan to continue our payment assistance programs across all of our operating territory to help customers deal with the impact of the pandemic. Additionally, we continue to have dialogue with the state regulatory commissions for each of our operating companies regarding the pandemic. Regulatory deferrals for certain costs have been allowed by all of our state regulatory commissions. Costs approved for deferral vary by state. For information on the state specific suspension of disconnections and COVID-19 regulatory filings, see Note 9, "Regulatory Matters," in the Notes to Consolidated Financial Statements. The CARES Act was enacted on March 27, 2020 and provides monetary-relief and financial aid to individuals, business, nonprofits, states and municipalities. The Coronavirus Relief Act was enacted on December 27, 2020 and extended or supplemented many of the programs from the CARES act. We are continuing to promote multiple resources available to customers including benefits from the CARES Act, such as additional funding for both the Low-Income Home Energy Assistance Program and the Community Services Block Grant to help support income-qualified customers. We are sharing energy efficiency tips to help customers save energy at home and promoting our budget plan program, which allows customers to pay about the same amount each month.
We have experienced lower revenue, higher expenses for personal protective equipment and supplies, and higher bad debt expense as a consequence of the pandemic, which has negatively impacted our results of operations through December 31, 2020. Refer to "Results and Discussion of Segment Operation" in this Management's Discussion for additional segment specific information. We did experience lower cash flows from operations for the year ended December 31, 2020 in comparison to the same period in 2019 due, in part, to slower collections of customer accounts receivable; however, we believe we have sufficient liquidity as a result of the issuance of $1.0 billion notes in April 2020, the remaining cash proceeds received from the sale of the Massachusetts Business in October 2020, the available capacity under our short-term revolving credit facility and accounts receivable securitization facilities, and our anticipated ability to access capital markets. Additionally, in the second quarter of 2020 we reduced our planned 2020 capital investments by $145 million. We did not make any other material changes to our capital construction programs or our renewable generation projects. While we have not experienced any significant issues in our supply chain, we are actively managing the materials, supplies, and contract services for our generation, transmission, distribution, and customer services functions.
Refer to Part I. Item 1A. "Risk Factors" for additional information related to the ongoing impact of the pandemic.
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Greater Lawrence Incident: For the year ended December 31, 2020, we have incurred $17 million of third-party claims and other incident-related costs associated with the Greater Lawrence Incident. For additional information, see Note 20-C, "Legal Proceedings" and Note 20-E "Other Matters," in the Notes to Consolidated Financial Statements.
We invested approximately $258 million of capital spend for specific pipeline replacement work that was completed in 2019. We maintain property insurance for gas pipelines and other applicable property. In 2019, Columbia of Massachusetts filed a proof of loss with its property insurer for this pipeline replacement work. In January 2020, we filed a lawsuit against the property insurer, seeking payment of our property claim. We are currently unable to predict the timing or amount of any insurance recovery under the property policy. See Note 1, "Nature of Operations and Summary of Significant Accounting Policies," in the Notes to Consolidated Financial Statements for additional information.
Refer to Note 20-C. "Legal Proceedings" and Note 20-E "Other Matters," in the Notes to Consolidated Financial Statements, "Summary of Consolidated Financial Results," "Results and Discussion of Segment Operation - Gas Distribution Operations," and "Liquidity and Capital Resources" in this Management's Discussion for additional information related to the Greater Lawrence Incident.
Summary of Consolidated Financial Results
A summary of our consolidated financial results for the years ended December 31, 2020, 2019 and 2018, are presented below:

Year Ended December 31, (in millions, except per share amounts) | 2020 |  | 2019 |  | 2018 |  | 2020 vs. 2019 |  | 2019 vs. 2018
Operating Revenues | $ | 4,681.7 |  |  | $ | 5,208.9 |  |  | $ | 5,114.5 |  |  | $ | (527.2) |  |  | $ | 94.4 |
Operating Expenses |  |  |  |  |  |  |  |  |
Cost of energy | 1,109.3 |  |  | 1,534.8 |  |  | 1,761.3 |  |  | (425.5) |  |  | (226.5) |
Other Operating Expenses | 3,021.6 |  |  | 2,783.4 |  |  | 3,228.5 |  |  | 238.2 |  |  | (445.1) |
Total Operating Expenses | 4,130.9 |  |  | 4,318.2 |  |  | 4,989.8 |  |  | (187.3) |  |  | (671.6) |
Operating Income | 550.8 |  |  | 890.7 |  |  | 124.7 |  |  | (339.9) |  |  | 766.0 |
Total Other Deductions, Net | (582.1) |  |  | (384.1) |  |  | (355.3) |  |  | (198.0) |  |  | (28.8) |
Income Taxes | (17.1) |  |  | 123.5 |  |  | (180.0) |  |  | (140.6) |  |  | 303.5 |
Net Income (Loss) | (14.2) |  |  | 383.1 |  |  | (50.6) |  |  | (397.3) |  |  | 433.7 |
Net income attributable to noncontrolling interest | 3.4 |  |  | — |  |  | — |  |  | 3.4 |  |  | — |
Net Income (Loss) attributable to NiSource | (17.6) |  |  | 383.1 |  |  | (50.6) |  |  | (400.7) |  |  | 433.7 |
Preferred dividends | (55.1) |  |  | (55.1) |  |  | (15.0) |  |  | — |  |  | (40.1) |
Net Income (Loss) Available to Common Shareholders | (72.7) |  |  | 328.0 |  |  | (65.6) |  |  | (400.7) |  |  | 393.6 |
Basic Earnings (Loss) Per Share | $ | (0.19) |  |  | $ | 0.88 |  |  | $ | (0.18) |  |  | $ | (1.07) |  |  | $ | 1.06 |
Basic Average Common Shares Outstanding | 384.3 |  |  | 374.6 |  |  | 356.5 |  |  | 9.7 |  |  | 18.1 |

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.
On a consolidated basis, we reported a net loss available to common shareholders of $72.7 million or $0.19 per basic share for the twelve months ended December 31, 2020 compared to income to common shareholders of $328.0 million or $0.88 per basic share for the same period in 2019. Additionally, we reported operating income of $550.8 million for the twelve months ended December 31, 2020 compared to $890.7 million for the same period in 2019. The decrease in both net income available to common shareholders and operating income during 2020 was primarily due to lower operating revenue related to the sale of the Massachusetts Business, as well as higher operating expenses due to insurance recoveries recorded in 2019, net of third-party claims and other costs, related to the Greater Lawrence Incident. Additionally, the decrease to net income available to common shareholders was also impacted by the loss on early extinguishment of debt in 2020 as well as partially offset by a change from income tax expense in 2019 to an income tax benefit in 2020.
Other Deductions, Net
Other deductions, net reduced income by $582.1 million in 2020 compared to a reduction in income of $384.1 million in 2019. This change is primarily due to the loss on early extinguishment of debt in 2020.
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Income Taxes
The decrease in income tax expense from 2019 to 2020 is primarily attributable to lower pre-tax income, resulting from the items discussed above in "Operating Income" and "Other Deductions, Net," state jurisdictional mix of pre-tax loss in 2020 tax effected at statutory tax rates and increased amortization of excess deferred federal income taxes in 2020 compared to 2019. These items are offset by increased deferred tax expense recognized on the sale of the Columbia of Massachusetts' regulatory liability, established due to TCJA in 2017, that would have otherwise been recognized over the amortization period, non-cash impairment of goodwill related to Columbia of Massachusetts in 2019 (see Note 7, "Goodwill and Other Intangible Assets" for additional information) 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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Gas Distribution Operations
Financial and operational data for the Gas Distribution Operations segment for the years ended December 31, 2020, 2019 and 2018, are presented below:

Year Ended December 31, (in millions) | 2020 |  | 2019 |  | 2018 |  | 2020 vs. 2019 |  | 2019 vs. 2018
Operating Revenues | $ | 3,140.1 |  |  | $ | 3,522.8 |  |  | $ | 3,419.5 |  |  | $ | (382.7) |  |  | $ | 103.3 |
Operating Expenses |  |  |  |  |  |  |  |  |
Cost of energy | 794.2 |  |  | 1,067.6 |  |  | 1,259.3 |  |  | (273.4) |  |  | (191.7) |
Operation and maintenance | 1,138.0 |  |  | 935.7 |  |  | 1,908.1 |  |  | 202.3 |  |  | (972.4) |
Depreciation and amortization | 363.1 |  |  | 403.2 |  |  | 301.0 |  |  | (40.1) |  |  | 102.2 |
Impairment of intangible assets | — |  |  | 209.7 |  |  | — |  |  | (209.7) |  |  | 209.7 |
Loss on sale of fixed assets and impairments, net | 412.4 |  |  | 0.1 |  |  | 0.2 |  |  | 412.3 |  |  | (0.1) |
Other taxes | 233.3 |  |  | 231.1 |  |  | 205.0 |  |  | 2.2 |  |  | 26.1 |
Total Operating Expenses | 2,941.0 |  |  | 2,847.4 |  |  | 3,673.6 |  |  | 93.6 |  |  | (826.2) |
Operating Income (Loss) | $ | 199.1 |  |  | $ | 675.4 |  |  | $ | (254.1) |  |  | $ | (476.3) |  |  | $ | 929.5 |
Revenues |  |  |  |  |  |  |  |  |
Residential | $ | 2,110.6 |  |  | $ | 2,317.2 |  |  | $ | 2,248.3 |  |  | $ | (206.6) |  |  | $ | 68.9 |
Commercial | 679.7 |  |  | 775.1 |  |  | 753.7 |  |  | (95.4) |  |  | 21.4 |
Industrial | 213.8 |  |  | 245.8 |  |  | 228.6 |  |  | (32.0) |  |  | 17.2 |
Off-System | 41.0 |  |  | 77.7 |  |  | 92.4 |  |  | (36.7) |  |  | (14.7) |
Other | 95.0 |  |  | 107.0 |  |  | 96.5 |  |  | (12.0) |  |  | 10.5 |
Total | $ | 3,140.1 |  |  | $ | 3,522.8 |  |  | $ | 3,419.5 |  |  | $ | (382.7) |  |  | $ | 103.3 |
Sales and Transportation (MMDth) |  |  |  |  |  |  |  |  |
Residential | 249.5 |  |  | 274.9 |  |  | 280.3 |  |  | (25.4) |  |  | (5.4) |
Commercial | 170.5 |  |  | 189.6 |  |  | 187.6 |  |  | (19.1) |  |  | 2.0 |
Industrial | 538.1 |  |  | 542.5 |  |  | 555.7 |  |  | (4.4) |  |  | (13.2) |
Off-System | 23.3 |  |  | 32.9 |  |  | 30.0 |  |  | (9.6) |  |  | 2.9 |
Other | 0.3 |  |  | 0.3 |  |  | — |  |  | — |  |  | 0.3 |
Total | 981.7 |  |  | 1,040.2 |  |  | 1,053.6 |  |  | (58.5) |  |  | (13.4) |
Heating Degree Days | 5,097 |  |  | 5,375 |  |  | 5,562 |  |  | (278) |  |  | (187) |
Normal Heating Degree Days | 5,485 |  |  | 5,452 |  |  | 5,610 |  |  | 33 |  |  | (158) |
% Warmer than Normal | (7) | % |  | (1) | % |  | (2) | % |  |  |  |
Gas Distribution Customers |  |  |  |  |  |  |  |  |
Residential | 2,954,478 |  |  | 3,221,178 |  |  | 3,194,662 |  |  | (266,700) |  |  | 26,516 |
Commercial | 253,184 |  |  | 282,778 |  |  | 281,517 |  |  | (29,594) |  |  | 1,261 |
Industrial | 4,968 |  |  | 5,982 |  |  | 5,833 |  |  | (1,014) |  |  | 149 |
Other | 3 |  |  | 3 |  |  | 3 |  |  | — |  |  | — |
Total | 3,212,633 |  |  | 3,509,941 |  |  | 3,482,015 |  |  | (297,308) |  |  | 27,926 |

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Gas Distribution Operations (continued)
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. These are tracked costs that are passed through directly to the customer resulting in an equal and offsetting amount reflected in operating revenue. In addition, 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. Therefore, increases in these tracked operating expenses are offset by increases in operating revenues and have essentially no impact on net income.
2020 vs. 2019 Operating Income
For 2020, Gas Distribution Operations reported operating income of $199.1 million, a decrease of $476.3 million from the comparable 2019 period.
Operating revenues for 2020 were $3,140.1 million, a decrease of $382.7 million from the same period in 2019. The change in operating revenues was primarily driven by:
•Lower cost of energy billed to customers, which is offset in operating expense, of $273.4 million.
•Lower revenues due to the sale of the Massachusetts Business of $102.2 million.
•Lower revenues from the effects of warmer weather in 2020 of $47.9 million.
•Lower regulatory, depreciation, and tax trackers, which are offset in operating expense, of $20.7 million.
•The effects of decreased commercial and industrial usage and decreased late and disconnection fees, both primarily related to the COVID-19 pandemic, of $11.3 million.
Partially offset by:
•New rates from base rate proceedings, infrastructure replacement programs and Columbia of Ohio's CEP of $57.1 million.
•The effects of increased residential usage primarily related to the pandemic of $5.0 million.
Operating expenses were $93.6 million higher in 2020 compared to 2019. This change was primarily driven by:
•Loss on sale of the Massachusetts Business of $412.4 million.
•Insurance recoveries recorded in 2019, net of third party claims and other costs, related to the Greater Lawrence Incident of $243.2 million.
•Severance and outside services expense related to NiSource Next initiative of $32.4 million.
•Increased expenses primarily due to the impact of the pandemic related to materials and supplies, outside services, and uncollectible expenses of $23.8 million, offset by $12.0 million of deferral of uncollectible and other expenses, net of benefits, related to the pandemic.
•Higher depreciation and amortization and property tax expense primarily due to higher capital expenditures placed in service of $24.3 million
Partially offset by:
•Lower cost of energy billed to customers, which is offset in operating revenue, of $273.4.
•Non-cash impairment of the Columbia of Massachusetts franchise rights of $209.7 million in 2019.
•Lower operation and maintenance and depreciation and amortization expenses due to the Massachusetts Business sale of $98.7 million.
•Lower employee and administrative expense of $28.9 million.
•Lower regulatory, depreciation, and tax trackers, which are offset in operating revenues, of $20.7 million.
2019 vs. 2018 Operating Income
For 2019, Gas Distribution Operations reported operating income of $675.4 million, an increase of $929.5 million from the comparable 2018 period.
Operating revenues for 2019 were $3,522.8 million, an increase of $103.3 million from the same period in 2018. The change in operating revenues was primarily driven by:
•New rates from base rate proceedings and infrastructure replacement programs of $243.2 million.
•Higher regulatory, depreciation and tax trackers, which are offset in operating expense, of $36.2 million.
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Gas Distribution Operations (continued)
•Higher revenues of $14.5 million resulting from an update in the weather-related normal heating degree day methodology, partially offset by a $7.1 million revenue decrease from the effects of warmer weather in 2019.
•The effects of commercial and residential customer growth of $12.8 million.
Partially offset by:
•Lower cost of energy billed to customers, which is offset in operating expenses of $191.7 million.
Operating expenses were $826.2 million lower in 2019 compared to 2018. This change was primarily driven by:
•Decreased expenses related to third-party claims and other costs for the Greater Lawrence Incident of $1,090.7 million, net of insurance recoveries recorded.
•Lower cost of energy billed to customers, which is offset in operating revenues of $191.7 million.
Partially offset by:
•Non-cash impairment of the Columbia of Massachusetts franchise rights of $209.7 million.
•Increased depreciation of $103.8 million due to the regulatory outcome of NIPSCO's gas rate case, an increase in amortization of depreciation previously deferred as a regulator asset resulting from Columbia of Ohio's CEP, and higher capital expenditures placed in service.
•Higher employee and administrative expenses of $50.2 million driven by resources shifting from the temporary assistance on the Greater Lawrence Incident restoration to normal operations (offset in the decreased Greater Lawrence Incident costs discussed above) and an increase in headcount.
•Increased regulatory, depreciation and tax trackers, which are offset in operating revenues, of $36.2 million.
•Higher property taxes of $22.2 million primarily due to increased amortization of property taxes previously deferred as a regulatory asset resulting from Columbia of Ohio's CEP, as well as higher capital expenditures placed in service.
•Higher outside services of $17.4 million primarily due to increased line location and safety-related work.
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.
The definition of “normal” weather was updated during the first quarter of 2019 to reflect more current weather pattern data and to more closely align with the regulators' jurisdictional definitions of “normal” weather. Impacts of the change in methodology will be reflected prospectively and disclosed to the extent it results in notable year-over-year variances in operating revenues.
Weather in the Gas Distribution Operations service territories for 2020 was about 7% warmer than normal and about 5% warmer than 2019, leading to decreased operating revenues of $47.9 million for the year ended December 31, 2020 compared to 2019. The majority of these amounts were driven by NIPSCO and Columbia of Pennsylvania.
Weather in the Gas Distribution Operations service territories for 2019 was about 1% warmer than normal and about 3% warmer than 2018; however, due to the aforementioned change in methodology, the change in operating revenues attributed to weather resulted in an increase of $7.4 million for the year ended December 31, 2019 compared to 2018. The variance is detailed further below:
•An update in the weather-related normal heating degree day methodology resulting in a favorable variance attributed to weather of $14.5 million, as discussed above.
Offset by:
•The effects of warmer weather in 2019 of $7.1 million.
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Gas Distribution Operations (continued)
Throughput
Total volumes sold and transported for the year ended December 31, 2020 were 981.7 MMDth, compared to 1,040.2 MMDth for 2019. This decrease is primarily attributable to warmer weather experienced in 2020 compared to 2019, the sale of the Massachusetts Business and decreased usage by commercial and industrial customers primarily due to the pandemic.
Total volumes sold and transported for the year ended December 31, 2019 were 1,040.2 MMDth, compared to 1,053.6 MMDth for 2018. This decrease is primarily attributable to warmer weather experienced in 2019 compared to 2018.
Commodity Price Impact
All of our Gas Distribution Operations companies have state-approved recovery mechanisms that provide a means for full recovery of prudently incurred gas costs. Gas costs are treated as pass-through costs and have no impact on the operating income recorded in the period. The gas costs included in revenues are matched with the gas cost expense recorded in the period and the difference is recorded on the Consolidated Balance Sheets as under-recovered or over-recovered gas cost to be included in future customer billings.
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. These programs serve to further reduce our exposure to gas prices.
Greater Lawrence Incident
Refer to Note 20-C. "Legal Proceedings," and Note 20-E. "Other Matters," in the Notes to Consolidated Financial Statements, "Summary of Consolidated Financial Results" and "Liquidity and Capital Resources" in this Management's Discussion, and Part I. Item 1A. "Risk Factors" for additional information related to the Greater Lawrence Incident.
Columbia of Massachusetts Asset Sale
On February 26, 2020, we entered into the Asset Purchase Agreement with Eversource providing for the sale of the Massachusetts Business to Eversource, subject to the terms and conditions set forth in the agreement. This sale was completed on October 9, 2020. For additional information, see Note 1, “Nature of Operations and Summary of Significant Accounting Policies,” in the Notes to Consolidated Financial Statements.
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Electric Operations
Financial and operational data for the Electric Operations segment for the years ended December 31, 2020, 2019 and 2018, are presented below:

Year Ended December 31, (in millions) | 2020 |  | 2019 |  | 2018 |  | 2020 vs. 2019 |  | 2019 vs. 2018
Operating Revenues | $ | 1,536.6 |  |  | $ | 1,699.2 |  |  | $ | 1,708.2 |  |  | $ | (162.6) |  |  | $ | (9.0) |
Operating Expenses |  |  |  |  |  |  |  |  |
Cost of energy | 315.2 |  |  | 467.3 |  |  | 502.1 |  |  | (152.1) |  |  | (34.8) |
Operation and maintenance | 497.6 |  |  | 495.0 |  |  | 500.0 |  |  | 2.6 |  |  | (5.0) |
Depreciation and amortization | 321.3 |  |  | 277.3 |  |  | 262.9 |  |  | 44.0 |  |  | 14.4 |
Gain on sale of fixed assets and impairments, net | — |  |  | (0.1) |  |  | — |  |  | 0.1 |  |  | (0.1) |
Other taxes | 53.7 |  |  | 52.9 |  |  | 57.1 |  |  | 0.8 |  |  | (4.2) |
Total Operating Expenses | 1,187.8 |  |  | 1,292.4 |  |  | 1,322.1 |  |  | (104.6) |  |  | (29.7) |
Operating Income | $ | 348.8 |  |  | $ | 406.8 |  |  | $ | 386.1 |  |  | $ | (58.0) |  |  | $ | 20.7 |
Revenues |  |  |  |  |  |  |  |  |
Residential | $ | 527.8 |  |  | $ | 481.6 |  |  | $ | 494.7 |  |  | $ | 46.2 |  |  | $ | (13.1) |
Commercial | 480.3 |  |  | 486.7 |  |  | 492.6 |  |  | (6.4) |  |  | (5.9) |
Industrial | 412.9 |  |  | 608.4 |  |  | 614.4 |  |  | (195.5) |  |  | (6.0) |
Wholesale | 12.3 |  |  | 11.7 |  |  | 15.7 |  |  | 0.6 |  |  | (4.0) |
Other | 103.3 |  |  | 110.8 |  |  | 90.8 |  |  | (7.5) |  |  | 20.0 |
Total | $ | 1,536.6 |  |  | $ | 1,699.2 |  |  | $ | 1,708.2 |  |  | $ | (162.6) |  |  | $ | (9.0) |
Sales (Gigawatt Hours) |  |  |  |  |  |  |  |  |
Residential | 3,484.0 |  |  | 3,369.5 |  |  | 3,535.2 |  |  | 114.5 |  |  | (165.7) |
Commercial | 3,550.0 |  |  | 3,760.3 |  |  | 3,844.6 |  |  | (210.3) |  |  | (84.3) |
Industrial | 7,480.3 |  |  | 8,466.1 |  |  | 8,829.5 |  |  | (985.8) |  |  | (363.4) |
Wholesale | 83.6 |  |  | 8.2 |  |  | 114.3 |  |  | 75.4 |  |  | (106.1) |
Other | 106.0 |  |  | 117.2 |  |  | 124.4 |  |  | (11.2) |  |  | (7.2) |
Total | 14,703.9 |  |  | 15,721.3 |  |  | 16,448.0 |  |  | (1,017.4) |  |  | (726.7) |
Cooling Degree Days | 900 |  |  | 962 |  |  | 1,180 |  |  | (62) |  |  | (218) |
Normal Cooling Degree Days | 803 |  |  | 803 |  |  | 806 |  |  | — |  |  | (3) |
% Warmer than Normal | 12 | % |  | 20 | % |  | 46 | % |  |  |  |
Electric Customers |  |  |  |  |  |  |  |  |
Residential | 418,871 |  |  | 415,534 |  |  | 412,267 |  |  | 3,337 |  |  | 3,267 |
Commercial | 57,435 |  |  | 57,058 |  |  | 56,605 |  |  | 377 |  |  | 453 |
Industrial | 2,154 |  |  | 2,256 |  |  | 2,284 |  |  | (102) |  |  | (28) |
Wholesale | 722 |  |  | 726 |  |  | 735 |  |  | (4) |  |  | (9) |
Other | 2 |  |  | 2 |  |  | 2 |  |  | — |  |  | — |
Total | 479,184 |  |  | 475,576 |  |  | 471,893 |  |  | 3,608 |  |  | 3,683 |

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Electric Operations (continued)
Cost of energy for the Electric Operations segment is principally comprised of the cost of coal, related handling costs, natural gas purchased for internal generation of electricity at NIPSCO, and the cost of power purchased from third-party generators of electricity. The majority of these are tracked costs that are passed through directly to the customer resulting in an equal and offsetting amount reflected in operating revenue. In addition, 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. Therefore, increases in these tracked operating expenses are offset by increases in operating revenues and have essentially no impact on net income.
2020 vs. 2019 Operating Income
For 2020, Electric Operations reported operating income of $348.8 million, a decrease of $58.0 million from the comparable 2019 period.
Operating revenues for 2020 were $1,536.6 million, an decrease of $162.6 million from the same period in 2019. The change in operating revenues was primarily driven by:
•Lower cost of energy billed to customers, which is offset in operating expense, of $152.1 million.
•Lower regulatory and depreciation trackers, which are offset in operating expense, of $25.2 million.
•The effects of decreased commercial and industrial usage and decreased late and disconnection fees, both primarily related to the COVID-19 pandemic, of $24.9 million.
Partially offset by:
•Higher revenue from recent base rate proceedings of $22.5 million.
•The effects of increased residential usage primarily related to the pandemic of $13.5 million.
•The effects of customer growth of $4.0 million.
Operating expenses were $104.6 million lower in 2020 than 2019. This change was primarily driven by:
•Lower cost of energy billed to customers, which is offset in operating revenue, of $152.1 million.
•Lower regulatory and depreciation trackers, which are offset in operating revenues, of $25.2 million.
•Lower outside services costs of $16.0 million primarily related to lower generation-related maintenance.
•Lower employee and administrative costs of $8.1 million.
Partially offset by:
•Increased depreciation of $61.6 million primarily due to additional plant placed in service.
•Severance and outside services expenses related to the NiSource Next initiative of $13.0 million.
•Increased expenses primarily due to the impact of pandemic-related materials and supplies, outside services, uncollectible and sequestration expenses of $10.7 million, offset by a $5.3 million deferral of uncollectible and other expenses, related to the pandemic.
•Increased materials and supplies costs of $4.7 million
•Higher insurance expense of $2.7 million primarily driven by increased premiums.
•Increased environmental costs of $1.3 million.
2019 vs. 2018 Operating Income
For 2019, Electric Operations reported operating income of $406.8 million, an increase of $20.7 million from the comparable 2018 period.
Operating revenues for 2019 were $1,699.2 million, a decrease of $9.0 million from the same period in 2018. The change in operating revenues was primarily driven by:
•Lower cost of energy billed to customers, which is offset in operating expense, of $34.8 million.
•Lower revenues from the effects of cooler weather of $15.1 million.
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Electric Operations (continued)
•Decreased residential, commercial and industrial usage of $10.8 million.
Partially offset by:
•New rates from the recent rate case proceeding, incremental capital spend on infrastructure replacement programs, and electric transmission projects of $24.8 million.
•Decreased fuel handling costs of $11.0 million.
•Higher regulatory and depreciation trackers, which are offset in operating expense, of $8.4 million.
•Increased commercial and residential customer growth of $3.9 million.
Operating expenses were $29.7 million lower in 2019 than 2018. This change was primarily driven by:
•Lower cost of energy billed to customers, which is offset in operating revenue, of $34.8 million.
•Decreased materials and supplies costs of $7.8 million, primarily related to the retirement of Bailly Generating Station Units 7 and 8 on May 31, 2018.
•Decreased employee and administrative costs of $5.0 million.
Partially offset by:
•Higher regulatory and depreciation trackers, which are offset in operating revenues, of $8.4 million.
•Increased depreciation of $8.7 million due to higher capital expenditures placed in service.
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.
The definition of “normal” weather was updated during the first quarter of 2019 to reflect more current weather pattern data and to more closely align with the regulators' jurisdictional definitions of “normal” weather. Impacts of the change in methodology will be reflected prospectively and disclosed to the extent it results in notable year-over-year variances in operating revenues.
Weather in the Electric Operations’ territories for 2020 was 12% warmer than normal and 6% cooler than the same period in 2019, which had an immaterial impact on operating revenues for the year ended December 31, 2020 compared to 2019.
Weather in the Electric Operations’ territories for 2019 was 20% warmer than normal and 18% cooler than the same period in 2018, decreasing operating revenues $15.1 million for the year ended December 31, 2019 compared to 2018.
Sales
Electric Operations sales were 14,703.9 GWh for 2020, a decrease of 1,017.4 GWh, or 6.5% compared to 2019. This decrease was primarily attributable to decreased usage by industrial and commercial customers due to the pandemic and higher self-generation by industrial customers, partially offset by increased usage by residential customers primarily due to the pandemic.
Electric Operations sales were 15,721.3 GWh for 2019, a decrease of 726.7 GWh, or 4.4% compared to 2018. This decrease was primarily attributable to higher internal generation from large industrial customers in 2019 and the effects of cooler weather on residential and commercial customers.
Commodity Price Impact
NIPSCO has a state-approved recovery mechanism that provides a means for full recovery of prudently incurred fuel costs. Fuel costs are treated as pass-through costs and have no impact on the operating revenues recorded in the period. The fuel costs included in revenues are matched with the fuel cost expense recorded in the period and the difference is recorded on the Consolidated Balance Sheets as under-recovered or over-recovered fuel cost to be included in future customer billings.
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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 45.9% and 51.5% of the total industrial MWh sales for the years ended December 31, 2020 and 2019, respectively.
Electric Supply
NIPSCO 2018 Integrated Resource Plan. NIPSCO concluded 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 the R.M. Schahfer Generating Station by mid-2023 and the Michigan City Generating Station by the end of 2028. These stations represent 2,080 MW of generating capacity, equal to 72% of NIPSCO’s remaining capacity and 100% of NIPSCO's remaining coal-fired generating capacity. In the second quarter of 2020, the MISO approved NIPSCO's plan to retire the R.M. Schahfer Generating Station in 2023. The planned replacement by the end of 2023 of approximately 1,400 MW of retiring coal-fired generation station could provide incremental capital investment opportunities of approximately $1.8 to $2.0 billion, primarily in 2022 and 2023. Refer to Note 6, "Property, Plant and Equipment" and Note 20-E, "Other Matters," in the Notes to Consolidated Financial Statements for further information. In February 2021, NIPSCO decided to submit modified Attachment Y Notices to MISO requesting accelerated retirement of two of the four coal fired units at R.M. Schahfer Generating Station. The two units are now expected to be retired by the end of 2021, with the remaining two units still scheduled to be retired in 2023. At retirement, the net book value of the retired units will be reclassified from "Non-Utility and Other property", to current and long-term “Regulatory Assets.”
The current replacement plan includes renewable sources of energy, including wind, solar, and battery storage to be obtained through a combination of NIPSCO ownership and PPAs. 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. The following table summarizes the executed PPAs and BTAs that have not yet been placed into service:

Project Name | Transaction Type | Technology | Nameplate Capacity (MW) | Storage Capacity (MW) | Submitted to IURC | IURC Approval | Estimated Construction Completion
Jordan Creek | 20 year PPA | Wind | 400 | — | 02/01/2019 | 6/05/2019 | In Service (12/10/2020)
Rosewater(1) | BTA | Wind | 100 | — | 02/01/2019 | 8/07/2019 | In Service (12/29/2020)
Indiana Crossroads(2) | BTA | Wind | 300 | — | 10/22/2019 | 2/19/2020 | 12/31/2021
Greensboro | 20 year PPA | Solar & Storage | 100 | 30 | 7/17/2020 | 1/27/2021 | 6/30/2023
Brickyard | 20 year PPA | Solar | 200 | — | 7/17/2020 | 1/27/2021 | 6/30/2023
Green River | 20 year PPA | Solar | 200 | — | 12/23/2020 | Pending | 6/30/2023
Cavalry(2) | BTA | Solar & Storage | 200 | 60 | 11/30/2020 | Pending | 12/31/2023
Dunn's Bridge I(2) | BTA | Solar | 265 | — | 11/30/2020 | Pending | 12/31/2022
Dunn's Bridge II(2) | BTA | Solar & Storage | 435 | 75 | 11/30/2020 | Pending | 12/31/2023
Gibson | 22 year PPA | Solar | 280 | — | 01/29/2021 | Pending | 12/31/2023

(1) Ownership of the facility was transferred to a joint venture whose members include NIPSCO and an unrelated tax equity partner.
(2) Ownership of the facilities will be transferred to joint ventures whose members include NIPSCO and an unrelated tax equity partner.
We expect to secure additional agreements with counterparties and initiate regulatory compliance filings into 2021.
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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. 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 have also utilized an at-the-market (ATM) equity sales program that allowed us to issue and sell shares of our common stock up to an aggregate offering price of $434.4 million. The program expired on December 31, 2020, but we expect to issue additional equity under ATM offerings from time to time.
We believe these sources provide adequate capital to fund our operating activities and capital expenditures in 2021 and beyond.
Greater Lawrence Incident. As discussed in the "Executive Summary", Part I, Item 1A “Risk Factors,” and in Note 20, “Other Commitments and Contingencies” in the Notes to Consolidated Financial Statements, due to the inherent uncertainty of litigation, there can be no assurance that the outcome or resolution of any particular claim related to the Greater Lawrence Incident will not continue to have an adverse impact on our cash flows. Through income generated from operating activities, amounts available under the short-term revolving credit facility, and our ability to access capital markets, we believe we have adequate capital available to settle remaining anticipated claims associated with the Greater Lawrence Incident. Previous costs in excess of insurance recoveries were primarily funded through short-term borrowings. The sale of the Massachusetts Business was completed on October 9, 2020. On October 14, 2020, we used a portion of the proceeds from the Massachusetts Business sale to pay down these short-term borrowings.
Operating Activities
Net cash from operating activities for the year ended December 31, 2020 was $1,104.0 million, a decrease of $479.3 million from 2019. This decrease was primarily driven by a year over year increase in net payments related to the Greater Lawrence Incident. During 2020, we paid approximately $227 million compared to net receipts of $289 million, representing insurance recoveries offset by payments, during 2019. Refer to Note 20, "Other Commitments and Contingencies" in the Notes to Consolidated Financial Statements for further information related to the Greater Lawrence Incident.
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. See below for further details of our capital expenditures and related regulatory programs. In 2020, our typical investing cash outflows were offset by $1,115.9 million of proceeds from the sale of assets, driven by the sale of the Massachusetts Business. Refer to Note 1 "Nature of Operations and Summary of Significant Accounting Policies" for more information.
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Capital Expenditures. The table below reflects capital expenditures and certain other investing activities by segment for 2020, 2019 and 2018.

(in millions) | 2020 |  | 2019 |  | 2018(3)
Gas Distribution Operations |  |  |  |  |
System Growth and Tracker | $ | 975.7 |  |  | $ | 1,006.1 |  |  | $ | 897.5 |
Maintenance | 291.2 |  |  | 374.3 |  |  | 417.8 |
Total Gas Distribution Operations | 1,266.9 |  |  | 1,380.3 |  |  | 1,315.3 |
Electric Operations |  |  |  |  |
System Growth and Tracker | 222.1 |  |  | 279.5 |  |  | 346.0 |
Maintenance | 200.7 |  |  | 189.4 |  |  | 153.3 |
Total Electric Operations | 422.8 |  |  | 468.9 |  |  | 499.3 |
Corporate and Other Operations - Maintenance(1) | 31.1 |  |  | 18.6 |  |  | — |
Total(2) | $ | 1,720.8 |  |  | $ | 1,867.8 |  |  | $ | 1,814.6 |

(1) Corporate and Other capital expenditures were zero in 2018 as specific IT assets were leased in 2018. Certain IT and other maintenance related assets were purchased in 2019 and 2020.
(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.
(3) The 2018 capital expenditures for Gas Distribution Operations reflects reclassifying the Greater Lawrence Incident pipeline replacement from system growth and tracker to maintenance.
For 2020, capital expenditures and certain other investing activities were $1,720.8 million, which was $147.0 million lower than the 2019 capital program. This decrease in spending is primarily due to the sale of the Massachusetts Business and impact of COVID 19.
For 2019, capital expenditures and certain other investing activities were $1,867.8 million, which was $53.2 million higher than the 2018 capital program. This increased spending is primarily due to growth, safety and system modernization projects.
For 2021, we project to invest approximately $1.9 to $2.1 billion in our capital program. This projected level of spend is an increase from our 2020 spend levels and supports continued investment in safety and reliability through modernizing gas and electric systems while meeting customer growth demands.
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Regulatory Capital Improvement Programs. In 2020, we continued to move forward on core infrastructure and environmental investment programs supported by complementary regulatory and customer initiatives across all seven states of our operating area. The following table describes the most recent vintage of our regulatory programs to recover infrastructure replacement and other federally-mandated compliance investments currently in rates and those pending commission approval:

(in millions) |  |  |  |  |  |
Company | Program | Incremental Revenue | Incremental Capital Investment | Investment Period |  |  | Costs Covered(1) | Rates Effective
Columbia of Ohio | IRP - 2020 | $ | 32.9 |  | $ | 234.4 |  | 1/19-12/19 |  |  | 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 installation of AMR devices. | May 2020
Columbia of Ohio | CEP - 2020 | $ | 18.0 |  | $ | 185.1 |  | 1/19-12/19 |  |  | Assets not included in the IRP. | September 2020
NIPSCO - Gas | TDSIC 1 | $ | 0.6 |  | $ | 26.0 |  | 1/20-6/20 |  |  | New or replacement projects undertaken for the purpose of safety, reliability, system modernization or economic development. | January 2021
NIPSCO - Gas | FMCA 5 | $ | 4.8 |  | $ | 42.3 |  | 4/20-9/20 |  |  | Project costs to comply with federal mandates. | April 2021
Columbia of Pennsylvania | DSIC-Q4 2020(2) | $ | 0.8 |  | $ | 25.0 |  | 9/20-11/20 |  |  | Eligible project costs including piping, couplings, gas service lines, excess flow valves, risers, meter bars, meters, and other related capitalized cost, to improve the distribution system. | January 2021
Columbia of Virginia | SAVE - 2021 | $ | 5.2 |  | $ | 46.4 |  | 1/21-12/21 |  |  | Replacement projects that (1) enhance system safety or reliability, or (2) reduce, or potentially reduce, greenhouse gas emissions. | January 2021
Columbia of Kentucky | SMRP - 2021(3) | $ | 5.8 |  | $ | 50.0 |  | 1/21-12/21 |  |  | Replacement of mains and inclusion of system safety investments. | Q2 2021
Columbia of Maryland | STRIDE - 2021 | $ | 1.3 |  | $ | 16.9 |  | 1/21-12/21 |  |  | Pipeline upgrades designed to improve public safety or infrastructure reliability. | January 2021
NIPSCO - Electric | TDSIC - 7(4) | $ | 11.3 |  | $ | 122.3 |  | 7/19-7/20 |  |  | New or replacement projects undertaken for the purpose of safety, reliability, system modernization or economic development. | February 2021
NIPSCO - Electric | FMCA - 13(5)(6) | $ | (1.2) |  | $ | — |  | 9/19-2/20 |  |  | Project costs to comply with federal mandates. | August 2020

(1)Programs do not include any costs already included in base rates.
(2)Due to a cap on the revenues permitted to flow through the DSIC, Columbia Gas of Pennsylvania is only able to request recovery of a portion of the capital investment for this period.
(3)On December 17, 2020, the Kentucky PSC issued an Order suspending the rates through May 30, 2021. An Order for approval can be received from the Commission prior to this date.
(4)Incremental capital and revenue are net of amounts included in the step 2 rates. See Part 1, Item 1. "Business" for additional information.
(5)Incremental revenue is inclusive of tracker eligible operations and maintenance expense.
(6)No eligible capital investments were made during the investment period.
Refer to Note 9, “Regulatory Matters” and Note 20-E, "Other Matters," in the Notes to Consolidated Financial Statements for a further discussion of regulatory developments during 2020.
Financing Activities
Short-term Debt. Refer to Note 16, “Short-Term Borrowings,” in the Notes to Consolidated Financial Statements for information on short-term debt.
Long-term Debt. Refer to Note 15, “Long-Term Debt,” in the Notes to Consolidated Financial Statements for information on long-term debt.
Net Available Liquidity. As of December 31, 2020, an aggregate of $1,721.6 million of net liquidity was available, including cash and credit available under the revolving credit facility and accounts receivable securitization programs.
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Sources of Liquidity
The following table displays our liquidity position as of December 31, 2020 and 2019:

Year Ended December 31, (in millions) | 2020 | 2019
Current Liquidity |  |
Revolving Credit Facility | $ | 1,850.0 |  | $ | 1,850.0 |
Accounts Receivable Program(1) | 273.3 |  | 353.2 |
Less: |  |
Commercial Paper | 503.0 |  | 570.0 |
Accounts Receivable Programs Utilized | — |  | 353.2 |
Letters of Credit Outstanding Under Credit Facility | 15.2 |  | 10.2 |
Add: |  |
Cash and Cash Equivalents | 116.5 |  | 139.3 |
Net Available Liquidity | $ | 1,721.6 |  | $ | 1,409.1 |

(1)Represents the lesser of the seasonal limit or maximum borrowings supportable by the underlying receivables.
Debt Covenants. We are subject to a financial covenant under our revolving credit facility, which requires us to maintain a debt to capitalization ratio that does not exceed 70%. As of December 31, 2020, the ratio was 62.5%.
Sale of Trade Accounts Receivables. Refer to Note 19, “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' credit ratings and ratings outlook as of December 31, 2020. In February 2020, S&P changed our and certain of our subsidiaries' outlook from Negative to Stable. There were no other changes to the below credit ratings or outlooks since December 31, 2019.
A credit rating is not a recommendation to buy, sell or hold securities, and may be subject to revision or withdrawal at any time by the assigning rating organization.

| S&P | Moody's | Fitch
| Rating | Outlook | Rating | Outlook | Rating | Outlook
NiSource | BBB+ | Stable | Baa2 | Stable | BBB | Stable
NIPSCO | BBB+ | Stable | Baa1 | Stable | BBB | Stable
Columbia of Massachusetts | BBB+ | Stable | Baa2 | Stable | Not rated | Not rated
Commercial Paper | A-2 | Stable | P-2 | Stable | F2 | Stable

Certain of our subsidiaries have agreements that contain “ratings triggers” that require increased collateral if our credit ratings or the credit ratings of certain of our subsidiaries are below investment grade. These agreements are primarily for insurance purposes and for the physical purchase or sale of power. As of December 31, 2020, the collateral requirement that would be required in the event of a downgrade below the ratings trigger levels would amount to approximately $53.9 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.
Equity. Our authorized capital stock consists of 620,000,000 shares, $0.01 par value, of which 600,000,000 are common stock and 20,000,000 are preferred stock. As of December 31, 2020, 391,760,051 shares of common stock and 440,000 shares of preferred stock were outstanding. For more information regarding our common and preferred stock, see Note 13, "Equity," in the Notes to Consolidated Financial Statements.
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Contractual Obligations
We have certain contractual obligations requiring payments at specified periods. The obligations include long-term debt, lease obligations, energy commodity contracts and obligations for various services including pipeline capacity and outsourcing of IT services. The total contractual obligations in existence at December 31, 2020 and their maturities were:

(in millions) | Total |  | 2021 |  | 2022 |  | 2023 |  | 2024 |  | 2025 |  | After
Long-term debt (1) | $ | 9,135.0 |  |  | $ | — |  |  | $ | 30.0 |  |  | $ | — |  |  | $ | — |  |  | $ | 1,260.0 |  |  | $ | 7,845.0 |
Interest payments on long-term debt | 6,046.3 |  |  | 336.3 |  |  | 335.7 |  |  | 334.1 |  |  | 334.1 |  |  | 334.1 |  |  | 4,372.0 |
Finance leases(2) | 264.7 |  |  | 32.7 |  |  | 32.2 |  |  | 28.8 |  |  | 20.8 |  |  | 16.1 |  |  | 134.1 |
Operating leases(3) | 48.0 |  |  | 11.7 |  |  | 5.2 |  |  | 4.7 |  |  | 4.5 |  |  | 3.7 |  |  | 18.2 |
Energy commodity contracts | 42.1 |  |  | 42.1 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Service obligations: |  |  |  |  |  |  |  |  |  |  |  |  |
Pipeline service obligations(4) | 1,495.6 |  |  | 468.7 |  |  | 422.5 |  |  | 256.0 |  |  | 150.5 |  |  | 56.2 |  |  | 141.7 |
IT service obligations | 240.3 |  |  | 74.9 |  |  | 74.0 |  |  | 38.1 |  |  | 30.5 |  |  | 22.8 |  |  | — |
Other service obligations(5) | 12.6 |  |  | 12.6 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Other liabilities(6) | 116.9 |  |  | 26.0 |  |  | 0.8 |  |  | 90.1 |  |  | — |  |  | — |  |  | — |
Total contractual obligations | $ | 17,401.5 |  |  | $ | 1,005.0 |  |  | $ | 900.4 |  |  | $ | 751.8 |  |  | $ | 540.4 |  |  | $ | 1,692.9 |  |  | $ | 12,511.0 |

(1) Long-term debt balance excludes unamortized issuance costs and discounts of $86.9 million.
(2) Finance lease payments shown above are inclusive of interest totaling $69.7 million.
(3) Operating lease payments shown above are inclusive of interest totaling $7.8 million. Operating lease balances do not include obligations for possible fleet vehicle lease renewals beyond the initial lease term. While we have the ability to renew these leases beyond the initial term, we are not reasonably certain (as that term is defined in ASC 842) to do so as they are renewed month-to-month after the first year. If we were to continue the fleet vehicle leases outstanding at December 31, 2020, payments would be $30.0 million in 2021, $27.7 million in 2022, $24.9 million in 2023, $22.0 million in 2024, $19.0 million in 2025 and $21.5 million thereafter.
(4)In February 2021, the demand rate increased for our pipeline service obligations, resulting in a total increase of $638.6 million in addition to our future pipeline service obligations shown above.
(5)On February 9, 2021, a rail transportation contract for the transportation of coal was fully executed between NIPSCO and a counterparty, replacing the prior agreement. The minimum coal tonnage shipment commitment for 2021 was eliminated under the new agreement, reducing our contractual obligation for 2021 by $12.1 million.
(6)Other liabilities shown above are inclusive of the Rosewater Developer payment due in 2023.
Our calculated estimated interest payments for long-term debt is based on the stated coupon and payment dates. For 2021, we project that we will be required to make interest payments of approximately $339.4 million, which includes $336.3 million of interest payments related to our long-term debt outstanding as of December 31, 2020. At December 31, 2020, we had $503.0 million in short-term borrowings outstanding.
Our expected payments included within “Other liabilities” in the table of contractual commitments above contains employer contributions to pension and other postretirement benefits plans expected to be made in 2021. Plan contributions beyond 2021 are dependent upon a number of factors, including actual returns on plan assets, which cannot be reliably estimated at this time. In 2021, we expect to make contributions of approximately $2.9 million to our pension plans and approximately $21.8 million to our postretirement medical and life plans. Refer to Note 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 long-term obligations classified as “Total Other Liabilities” on the Consolidated Balance Sheets, other than those described above.
We also have obligations associated with income, property, gross receipts, franchise, sales and use, and various other taxes and expect to make tax payments of approximately $253.4 million in 2021, which are not included in the table above. In addition, we have uncertain income tax positions that are not included in the table above as we are unable to predict when the matters will be resolved. Refer to Note 14, "Income Taxes," in the Notes to Consolidated Financial Statements for more information.
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NIPSCO has executed several PPAs to purchase 100% of the output from renewable generation facilities at a fixed price per MWh. Each facility supplying the energy will have an associated nameplate capacity, and payments under the PPAs will not begin until the associated generation facility is constructed by the owner/seller. NIPSCO has also executed several BTAs with developers to construct renewable generation facilities. NIPSCO's purchase requirement under the BTAs is dependent on satisfactory approval of the BTA by the IURC, successful execution of an agreement with a tax equity partner and timely completion of construction. NIPSCO and the tax equity partner are obligated to make cash contributions to the partnership at the date construction is substantially complete. Once the tax equity partner has earned their negotiated rate of return and we have reached the agreed upon contractual date, NIPSCO has the option to purchase at fair market value from the tax equity partner the remaining interest in the aforementioned joint venture. See Note 20-A, “Contractual Obligations,” and Note 20-E. “Other Matters - NIPSCO 2018 Integrated Resource Plan,” in the Notes to Consolidated Financial Statements for additional information.
Off-Balance Sheet Arrangements
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 20, “Other Commitments and Contingencies,” in the Notes to Consolidated Financial Statements for additional information about such arrangements.
Market Risk Disclosures
Risk is an inherent part of our businesses. The extent to which we properly and effectively identify, assess, monitor and manage each of the various types of risk involved in our businesses is critical to our profitability. We seek to identify, assess, monitor and manage, in accordance with defined policies and procedures, the following principal market risks that are involved in our businesses: commodity price risk, interest rate risk and credit risk. We manage risk through a multi-faceted process with oversight by the Risk Management Committee that requires constant communication, judgment and knowledge of specialized products and markets. Our senior management takes an active role in the risk management process and has developed policies and procedures that require specific administrative and business functions to assist in the identification, assessment and control of various risks. These may include, but are not limited to market, operational, financial, compliance and strategic risk types. In recognition of the increasingly varied and complex nature of the energy business, our risk management process, policies and procedures continue to evolve and are subject to ongoing review and modification.
Commodity Price Risk
We are exposed to commodity price risk as a result 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, since regulations allow recovery of prudently incurred purchased power, fuel and gas costs through the rate-making process, including gains or losses on these derivative instruments. If states should explore additional regulatory reform, 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 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, 2020 and 2019.
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, accounts receivable programs and now-settled term loan, 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 $12.3 million and $19.0 million for 2020 and 2019, 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.
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Refer to Note 10, "Risk Management Activities," in the Notes to Consolidated Financial Statements for further information on our interest rate risk assets and liabilities as of December 31, 2020 and 2019.
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, Risk Management Committee 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 reinstated our common credit mitigation practices where moratoriums have expired. See the COVID-19 pandemic 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.
Other Information
Critical Accounting Policies
We apply certain accounting policies based on the accounting requirements discussed below that have had, and may continue to have, significant impacts on our operations and Consolidated Financial Statements.
Basis of Accounting for Rate-Regulated Subsidiaries. ASC Topic 980, Regulated Operations, provides that rate-regulated subsidiaries account for and report assets and liabilities consistent with the economic effect of the way in which regulators establish rates, if the rates established are designed to recover the costs of providing the regulated service and if the competitive environment makes it probable that such rates can be charged and collected. Certain expenses and credits subject to utility regulation or rate determination normally reflected in income are deferred on the Consolidated Balance Sheets and are recognized in income as the related amounts are included in service rates and recovered from or refunded to customers. The total amounts of regulatory assets and liabilities reflected on the Consolidated Balance Sheets were $1,930.5 million and $2,065.5 million at December 31, 2020, and $2,239.6 million and $2,512.2 million at December 31, 2019, respectively. For additional information, refer to Note 9, “Regulatory Matters,” in the Notes to Consolidated Financial Statements.
In the event that regulation significantly changes the opportunity for us to recover our costs in the future, all or a portion of our regulated operations may no longer meet the criteria for the application of ASC Topic 980, Regulated Operations. In such event, a write-down of all or a portion of our existing regulatory assets and liabilities could result. If transition cost recovery is approved by the appropriate regulatory bodies that would meet the requirements under GAAP for continued accounting as regulatory assets and liabilities during such recovery period, the regulatory assets and liabilities would be reported at the recoverable amounts. If we were unable to continue to apply the provisions of ASC Topic 980, Regulated Operations, we would be required to apply the provisions of ASC Topic 980-20, Discontinuation of Rate-Regulated Accounting. In management’s opinion, our regulated subsidiaries will be subject to ASC Topic 980, Regulated Operations for the foreseeable future.
Certain of the regulatory assets reflected on our Consolidated Balance Sheets require specific regulatory action in order to be included in future service rates. Although recovery of these amounts is not guaranteed, we believe that these costs meet the requirements for deferral as regulatory assets. If we determine that the amounts included as regulatory assets are no longer recoverable, a charge to income would immediately be required to the extent of the unrecoverable amounts.
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The passage of the TCJA into law in December 2017 necessitated the remeasurement of our deferred income tax balances to reflect the change in the statutory federal tax rate from 35% to 21%. For our regulated entities, substantially all of the impact of this remeasurement was recorded to a regulatory liability and is being passed backed to customers, as established during the rate making process. For additional information, refer to Note 9, "Regulatory Matters," and Note 11, "Income Taxes," in the Notes to Consolidated Financial Statements.
Pension and Postretirement Benefits. We have defined benefit plans for both pension and other postretirement benefits. The calculation of the net obligations and annual expense related to the plans requires a significant degree of judgment regarding the discount rates to be used in bringing the liabilities to present value, expected long-term rates of return on plan assets, health care trend rates, and mortality rates, among other assumptions. Due to the size of the plans and the long-term nature of the associated liabilities, changes in the assumptions used in the actuarial estimates could have material impacts on the measurement of the net obligations and annual expense recognition. Differences between actuarial assumptions and actual plan results are deferred into AOCI or a regulatory balance sheet account, depending on the jurisdiction of our entity. These deferred gains or losses are then amortized into the income statement when the accumulated differences exceed 10% of the greater of the projected benefit obligation or the fair value of plan assets (known in GAAP as the “corridor” method) or when settlement accounting is triggered.
The discount rates, expected long-term rates of return on plan assets, health care cost trend rates and mortality rates are critical assumptions. Methods used to develop these assumptions are described below. While a third party actuarial firm assists with the development of many of these assumptions, we are ultimately responsible for selecting the final assumptions.
The discount rate is utilized principally in calculating the actuarial present value of pension and other postretirement benefit obligations and net periodic pension and other postretirement benefit plan costs. Our discount rates for both pension and other postretirement benefits are determined using spot rates along an AA-rated above median yield curve with cash flows matching the expected duration of benefit payments to be made to plan participants.
The expected long-term rate of return on plan assets is a component utilized in calculating annual pension and other postretirement benefit plan costs. We estimate the expected return on plan assets by evaluating expected bond returns, equity risk premiums, target asset allocations, the effects of active plan management, the impact of periodic plan asset rebalancing and historical performance. We also consider the guidance from our investment advisors in making a final determination of our expected rate of return on assets. For measurement of 2021 net periodic benefit cost, we selected an expected pre-tax long-term rate of return of 5.20% and 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 utilize a full yield curve approach to estimate the service and interest components of net periodic benefit cost for pension and other postretirement benefits by applying the specific spot rates along the yield curve used in the determination of the benefit obligation to the relevant projected cash flows. For further discussion of our pension and other postretirement benefits, see Note 12, “Pension and Other Postretirement Benefits,” in the Notes to Consolidated Financial Statements.
Typically, we use the Society of Actuaries’ most recently published mortality data in developing a best estimate of mortality as part of the calculation of the pension and other postretirement benefit obligations. Due to the ongoing COVID-19 pandemic, we adjusted our mortality assumption through 2023 to reflect anticipated slow recovery.
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The following tables illustrate the effects of changes in these actuarial assumptions while holding all other assumptions constant:

| Impact on December 31, 2020 Projected Benefit Obligation Increase/(Decrease)
Change in Assumptions (in millions) | Pension Benefits |  | Other Postretirement Benefits
+50 basis points change in discount rate | $ | (88.7) |  |  | $ | (29.8) |
-50 basis points change in discount rate | 96.5 |  |  | 32.7 |
| Impact on 2020 Expense Increase/(Decrease)(1)
Change in Assumptions (in millions) | Pension Benefits |  | Other Postretirement Benefits
+50 basis points change in discount rate | $ | (2.0) |  |  | $ | (0.8) |
-50 basis points change in discount rate | 1.6 |  |  | 0.9 |
+50 basis points change in expected long-term rate of return on plan assets | (9.8) |  |  | (1.3) |
-50 basis points change in expected long-term rate of return on plan assets | 9.8 |  |  | 1.3 |

(1)Before labor capitalization and regulatory deferrals.
Goodwill and Other Intangible Assets. We have six goodwill reporting units, comprised of the six state operating companies within the Gas Distribution Operations reportable segment. Our goodwill assets at December 31, 2020 were $1,486 million, most of which resulted from the acquisition of Columbia on November 1, 2000.
As required by GAAP, we test for impairment of goodwill on an annual basis and on an interim basis when events or circumstances indicate that a potential impairment may exist. Our annual goodwill test takes place in the second quarter of each year and was performed on May 1, 2020.
A quantitative ("step 1") test was completed on May 1, 2020 for all reporting units. Columbia of Massachusetts was not considered to be a reporting unit for the May 1, 2020 fair value measurement as the goodwill balance had been reduced to zero as of December 31, 2019. Consistent with our historical impairment testing of goodwill, fair value of the reporting units was determined based on a weighting of income and market approaches. These approaches require significant judgments including appropriate long-term growth rates and discount rates for the income approach and appropriate multiples of earnings for peer companies and control premiums for the market approach. The discount rates were derived using peer company data compiled with the assistance of a third party valuation services firm. The discount rates used are subject to change based on changes in tax rates at both the state and federal level, debt and equity ratios at each reporting unit and general economic conditions. The long-term growth rate was derived by evaluating historic growth rates, new business and investment opportunities beyond the near term horizon. The long-term growth rate is subject to change depending on inflationary impacts to the U.S. economy and the individual business environments in which each reporting unit operates. The Step 1 analysis performed indicated that the fair value of each of the reporting units exceeds their carrying value. As a result, no impairment charges were recorded.
We recorded impairment charges related to goodwill and other intangible assets in 2019. See Note 7, "Goodwill and Other Intangible Assets," in the Notes to Consolidated Financial Statements for information regarding our 2019 analyses and assumptions.
Revenue Recognition. Revenue is recorded as products and services are delivered. Utility revenues are billed to customers monthly on a cycle basis. Revenues are recorded on 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 material changes in the amount or timing of future revenue recognition occurred as a result of the adoption of ASC 606. Refer to Note 3 "Revenue Recognition," in the Notes to Consolidated Financial Statements for additional information regarding our significant judgments and estimates related to revenue recognition.
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Variable Interest Entities. A VIE is an entity in which the controlling interest is determined through means other than a majority voting interest. The primary beneficiary of a VIE is the business enterprise which has the power to direct the activities of the VIE that most significantly impact the VIE’s economic performance. Also, the primary beneficiary either absorbs a significant amount of the VIE’s losses or has the right to receive benefits that could be significant to the VIE. We consider these qualitative elements in determining whether we are the primary beneficiary of a VIE, and we consolidate those VIEs for which we are determined to be the primary beneficiary. As the managing member of a partnership, we would control decisions that are significant to the ongoing operations and economic results. Therefore, we have concluded that we are the primary beneficiary of Rosewater and have consolidated Rosewater even though we own less than 100% of the total equity membership interest.
We have determined that the use of HLBV accounting is reasonable and appropriate to attribute income and loss to the noncontrolling interest held by the tax equity partner. HLBV accounting was selected as the allocation of Rosewater's economic results to members differ from the members' relative ownership percentages. Using the HLBV method, our earnings are calculated based on how the partnership would distribute its cash if it were to hypothetically sell all of its assets for their carrying amounts and liquidate at each reporting period. Under HLBV, we calculate the liquidation value allocable to each partner at the beginning and end of each period based on the contractual liquidation waterfall and adjust our income for the period to reflect the change our associated book value. Refer to Note 4, "Variable Interest Entities" in the Notes to Consolidated Financial Statements.
Recently Issued Accounting Pronouncements
Refer to Note 2, "Recent Accounting Pronouncements," in the Notes to Consolidated Financial Statements.
Quantitative and Qualitative Disclosures about Market Risk are reported in Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Market Risk Disclosures.”
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
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Index | Page
Report of Independent Registered Public Accounting Firm | 51
Statements of Consolidated Income (Loss) | 53
Statements of Consolidated Comprehensive Income (Loss) | 54
Consolidated Balance Sheets | 55
Statements of Consolidated Cash Flows | 57
Statements of Consolidated Stockholders' Equity | 58
Notes to Consolidated Financial Statements | 60
1. Nature of Operations and Summary of Significant Accounting Policies | 60
2. Recent Accounting Pronouncements | 63
3. Revenue Recognition | 65
4. Variable Interest Entities | 68
5. Earnings Per Share | 69
6. Property, Plant and Equipment | 70
7. Goodwill and Other Intangible Assets | 71
8. Asset Retirement Obligations | 71
9. Regulatory Matters | 72
10. Risk Management Activities | 76
11. Income Taxes | 77
12. Pension and Other Postretirement Benefits | 80
13. Equity | 90
14. Share-Based Compensation | 93
15. Long-Term Debt | 96
16. Short-Term Borrowings | 97
17. Leases | 98
18. Fair Value | 101
19. Transfers of Financial Assets | 104
20. Other Commitments and Contingencies | 105
21. Accumulated Other Comprehensive Loss | 112
22. Other, Net | 112
23. Interest Expense, Net | 113
24. Segments of Business | 113
25. Quarterly Financial Data (Unaudited) | 115
26. Supplemental Cash Flow Information | 116
Schedule II | 117

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
N I S OURCE I NC.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the shareholders and the Board of Directors of NiSource Inc.
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of NiSource Inc. and subsidiaries (the "Company") as of December 31, 2020 and 2019, 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, 2020, and the related notes and the schedule listed in the Index at Item 15 (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020 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, 2020, 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 17, 2021, expressed an unqualified opinion on the Company's internal control over financial reporting.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Impact of Rate Regulation on the Financial Statements - Refer to Note 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 commissions' regulation of rates is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital. Decisions to be made by the commission in the future will impact the accounting for regulated operations, including
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
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.
• We obtained an analysis from management regarding probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities not yet addressed in a regulatory order to assess management’s assertion that amounts are probable of recovery or a future reduction in rates.
/s/ DELOITTE & TOUCHE LLP
Columbus, Ohio
February 17, 2021
We have served as the Company's auditor since 2002.
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
N I S OURCE I NC.
STATEMENTS OF CONSOLIDATED INCOME (LOSS)

Year Ended December 31, (in millions, except per share amounts) | 2020 |  | 2019 |  | 2018
Operating Revenues |  |  |  |  |
Customer revenues | $ | 4,473.2 |  |  | $ | 5,053.4 |  |  | $ | 4,991.1 |
Other revenues | 208.5 |  |  | 155.5 |  |  | 123.4 |
Total Operating Revenues | 4,681.7 |  |  | 5,208.9 |  |  | 5,114.5 |
Operating Expenses |  |  |  |  |
Cost of energy | 1,109.3 |  |  | 1,534.8 |  |  | 1,761.3 |
Operation and maintenance | 1,585.9 |  |  | 1,354.7 |  |  | 2,352.9 |
Depreciation and amortization | 725.9 |  |  | 717.4 |  |  | 599.6 |
Impairment of goodwill and intangible assets | — |  |  | 414.5 |  |  | — |
Loss on sale of assets, net | 410.6 |  |  | — |  |  | 1.2 |
Other taxes | 299.2 |  |  | 296.8 |  |  | 274.8 |
Total Operating Expenses | 4,130.9 |  |  | 4,318.2 |  |  | 4,989.8 |
Operating Income | 550.8 |  |  | 890.7 |  |  | 124.7 |
Other Income (Deductions) |  |  |  |  |
Interest expense, net | (370.7) |  |  | (378.9) |  |  | (353.3) |
Other, net | 32.1 |  |  | (5.2) |  |  | 43.5 |
Loss on early extinguishment of long-term debt | (243.5) |  |  | — |  |  | (45.5) |
Total Other Deductions, Net | (582.1) |  |  | (384.1) |  |  | (355.3) |
Income (Loss) before Income Taxes | (31.3) |  |  | 506.6 |  |  | (230.6) |
Income Taxes | (17.1) |  |  | 123.5 |  |  | (180.0) |
Net Income (Loss) | (14.2) |  |  | 383.1 |  |  | (50.6) |
Net income attributable to noncontrolling interest | 3.4 |  |  | — |  |  | — |
Net Income (Loss) attributable to NiSource | (17.6) |  |  | 383.1 |  |  | (50.6) |
Preferred dividends | (55.1) |  |  | (55.1) |  |  | (15.0) |
Net Income (Loss) Available to Common Shareholders | (72.7) |  |  | 328.0 |  |  | (65.6) |
Earnings (Loss) Per Share |  |  |  |  |
Basic Earnings (Loss) Per Share | $ | (0.19) |  |  | $ | 0.88 |  |  | $ | (0.18) |
Diluted Earnings (Loss) Per Share | $ | (0.19) |  |  | $ | 0.87 |  |  | $ | (0.18) |
Basic Average Common Shares Outstanding | 384.3 |  |  | 374.6 |  |  | 356.5 |
Diluted Average Common Shares | 384.3 |  |  | 376.0 |  |  | 356.5 |

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

Year Ended December 31, (in millions, net of taxes) | 2020 |  | 2019 |  | 2018
Net Income (Loss) | $ | (14.2) |  |  | $ | 383.1 |  |  | $ | (50.6) |
Other comprehensive income (loss): |  |  |  |  |
Net unrealized gain (loss) on available-for-sale securities(1) | 2.7 |  |  | 5.7 |  |  | (2.6) |
Net unrealized gain (loss) on cash flow hedges(2) | (70.7) |  |  | (64.2) |  |  | 22.7 |
Unrecognized pension and OPEB benefit (costs)(3) | 3.9 |  |  | 3.1 |  |  | (4.4) |
Total other comprehensive income (loss) | (64.1) |  |  | (55.4) |  |  | 15.7 |
Total Comprehensive Income (Loss) | $ | (78.3) |  |  | $ | 327.7 |  |  | $ | (34.9) |

(1) Net unrealized gain (loss) on available-for-sale securities, net of $0.7 million tax expense, $1.5 million tax expense and $0.6 million tax benefit in 2020, 2019 and 2018, respectively.
(2) Net unrealized gain (loss) on derivatives qualifying as cash flow hedges, net of $23.4 million tax benefit, $21.2 million tax benefit and $7.5 million tax expense in 2020, 2019 and 2018, respectively.
(3) Unrecognized pension and OPEB benefit (costs), net of $0.1 million tax benefit, $1.6 million tax expense and $1.5 million tax benefit in 2020, 2019 and 2018, respectively.
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
N I S OURCE I NC.
CONSOLIDATED BALANCE SHEETS

(in millions) | December 31, 2020 |  | December 31, 2019
ASSETS |  |  |
Property, Plant and Equipment |  |  |
Plant | $ | 24,179.9 |  |  | $ | 24,541.9 |
Accumulated depreciation and amortization | (7,560.4) |  |  | (7,629.7) |
Net Property, Plant and Equipment(1) | 16,619.5 |  |  | 16,912.2 |
Investments and Other Assets |  |  |
Unconsolidated affiliates | — |  |  | 1.3 |
Available-for-sale debt securities (amortized cost of $163.9 and $150.1, allowance for credit losses of $0.5 and $0, respectively) | 170.9 |  |  | 154.2 |
Other investments | 81.1 |  |  | 74.7 |
Total Investments and Other Assets | 252.0 |  |  | 230.2 |
Current Assets |  |  |
Cash and cash equivalents | 116.5 |  |  | 139.3 |
Restricted cash | 9.1 |  |  | 9.1 |
Accounts receivable | 843.6 |  |  | 876.1 |
Allowance for credit losses | (52.3) |  |  | (19.2) |
Accounts receivable, net | 791.3 |  |  | 856.9 |
Gas inventory | 191.2 |  |  | 250.9 |
Materials and supplies, at average cost | 141.5 |  |  | 120.2 |
Electric production fuel, at average cost | 68.4 |  |  | 53.6 |
Exchange gas receivable | 34.1 |  |  | 48.5 |
Regulatory assets | 135.7 |  |  | 225.7 |
Deferred property taxes | 85.6 |  |  | 79.5 |
Prepayments and other | 86.0 |  |  | 70.2 |
Total Current Assets(1) | 1,659.4 |  |  | 1,853.9 |
Other Assets |  |  |
Regulatory assets | 1,794.8 |  |  | 2,013.9 |
Goodwill | 1,485.9 |  |  | 1,485.9 |
Deferred charges and other | 228.9 |  |  | 163.7 |
Total Other Assets | 3,509.6 |  |  | 3,663.5 |
Total Assets | $ | 22,040.5 |  |  | $ | 22,659.8 |

(1)Includes $175.6 million of net property, plant and equipment assets and $1.7 million of current assets of a consolidated VIE that may be used only to settle obligations of the consolidated VIE. Refer to Note 4 "Variable Interest Entity" for additional information.
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
N I S OURCE I NC.
CONSOLIDATED BALANCE SHEETS

(in millions, except share amounts) | December 31, 2020 |  | December 31, 2019
CAPITALIZATION AND LIABILITIES |  |  |
Capitalization |  |  |
Stockholders’ Equity |  |  |
Common stock - $0.01 par value, 600,000,000 shares authorized; 391,760,051 and 382,135,680 shares outstanding, respectively | $ | 3.9 |  |  | $ | 3.8 |
Preferred stock - $0.01 par value, 20,000,000 shares authorized; 440,000 shares outstanding | 880.0 |  |  | 880.0 |
Treasury stock | (99.9) |  |  | (99.9) |
Additional paid-in capital | 6,890.1 |  |  | 6,666.2 |
Retained deficit | (1,765.2) |  |  | (1,370.8) |
Accumulated other comprehensive loss | (156.7) |  |  | (92.6) |
Total NiSource Stockholders' Equity | 5,752.2 |  |  | 5,986.7 |
Noncontrolling interest in consolidated subsidiaries | 85.6 |  |  | — |
Total Stockholders’ Equity | 5,837.8 |  |  | 5,986.7 |
Long-term debt, excluding amounts due within one year | 9,219.8 |  |  | 7,856.2 |
Total Capitalization | 15,057.6 |  |  | 13,842.9 |
Current Liabilities |  |  |
Current portion of long-term debt | 23.3 |  |  | 13.4 |
Short-term borrowings | 503.0 |  |  | 1,773.2 |
Accounts payable | 589.0 |  |  | 666.0 |
Customer deposits and credits | 243.3 |  |  | 256.4 |
Taxes accrued | 244.1 |  |  | 231.6 |
Interest accrued | 104.7 |  |  | 99.4 |
Risk management liabilities | 78.2 |  |  | 12.6 |
Exchange gas payable | 48.5 |  |  | 59.7 |
Regulatory liabilities | 161.3 |  |  | 160.2 |
Accrued compensation and employee benefits | 141.8 |  |  | 156.3 |
Claims accrued | 28.6 |  |  | 165.4 |
Other accruals | 113.6 |  |  | 151.6 |
Total Current Liabilities | 2,279.4 |  |  | 3,745.8 |
Other Liabilities |  |  |
Risk management liabilities | 144.6 |  |  | 134.0 |
Deferred income taxes | 1,470.6 |  |  | 1,485.3 |
Accrued insurance liabilities | 84.8 |  |  | 81.5 |
Accrued liability for postretirement and postemployment benefits | 336.1 |  |  | 373.2 |
Regulatory liabilities | 1,904.2 |  |  | 2,352.0 |
Asset retirement obligations | 477.1 |  |  | 416.9 |
Other noncurrent liabilities | 286.1 |  |  | 228.2 |
Total Other Liabilities | 4,703.5 |  |  | 5,071.1 |
Commitments and Contingencies (Refer to Note 20, "Other Commitments and Contingencies") |  |  |
Total Capitalization and Liabilities | $ | 22,040.5 |  |  | $ | 22,659.8 |

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

Year Ended December 31, (in millions) | 2020 |  | 2019 |  | 2018
Operating Activities |  |  |  |  |
Net Income (Loss) | $ | (14.2) |  |  | $ | 383.1 |  |  | $ | (50.6) |
Adjustments to Reconcile Net Income (Loss) to Net Cash from Operating Activities: |  |  |  |  |
Loss on early extinguishment of debt | 243.5 |  |  | — |  |  | 45.5 |
Depreciation and amortization | 725.9 |  |  | 717.4 |  |  | 599.6 |
Deferred income taxes and investment tax credits | (29.0) |  |  | 118.2 |  |  | (188.2) |
Stock compensation expense and 401(k) profit sharing contribution | 17.4 |  |  | 25.9 |  |  | 28.6 |
Impairment of goodwill and intangible assets | — |  |  | 414.5 |  |  | — |
Loss (gain) on sale of assets | 409.8 |  |  | (0.6) |  |  | 1.3 |
Amortization of discount/premium on debt | 9.4 |  |  | 8.2 |  |  | 7.5 |
AFUDC equity | (9.9) |  |  | (8.0) |  |  | (14.2) |
Other adjustments | 0.2 |  |  | (0.3) |  |  | 0.4 |
Changes in Assets and Liabilities: |  |  |  |  |
Accounts receivable | (3.9) |  |  | 187.8 |  |  | (186.2) |
Inventories | (1.5) |  |  | (2.0) |  |  | 41.4 |
Accounts payable | (29.7) |  |  | (299.9) |  |  | 268.4 |
Customer deposits and credits | 10.0 |  |  | 16.9 |  |  | (25.4) |
Taxes accrued | 28.4 |  |  | 7.3 |  |  | 20.2 |
Interest accrued | 5.3 |  |  | 8.8 |  |  | (21.7) |
Exchange gas receivable/payable | (6.9) |  |  | 55.5 |  |  | (21.5) |
Other accruals | (218.8) |  |  | 105.3 |  |  | 43.5 |
Prepayments and other current assets | (5.9) |  |  | (33.6) |  |  | (14.5) |
Regulatory assets/liabilities | 70.8 |  |  | (85.6) |  |  | (53.2) |
Postretirement and postemployment benefits | (103.6) |  |  | (21.1) |  |  | 58.2 |
Deferred charges and other noncurrent assets | (15.0) |  |  | (76.1) |  |  | 3.8 |
Other noncurrent liabilities | 21.7 |  |  | 61.6 |  |  | (2.8) |
Net Cash Flows from Operating Activities | 1,104.0 |  |  | 1,583.3 |  |  | 540.1 |
Investing Activities |  |  |  |  |
Capital expenditures | (1,758.1) |  |  | (1,802.4) |  |  | (1,818.2) |
Cost of removal | (138.2) |  |  | (113.2) |  |  | (104.3) |
Proceeds from disposition of assets | 1,115.9 |  |  | 0.4 |  |  | 1.8 |
Purchases of available-for-sale securities | (144.7) |  |  | (140.4) |  |  | (90.0) |
Sales of available-for-sale securities | 131.4 |  |  | 132.1 |  |  | 82.3 |
Payment to renewable generation asset developer | (85.3) |  |  | — |  |  | — |
Other investing activities | (0.1) |  |  | 1.1 |  |  | 2.3 |
Net Cash Flows used for Investing Activities | (879.1) |  |  | (1,922.4) |  |  | (1,926.1) |
Financing Activities |  |  |  |  |
Proceeds from issuance of long-term debt | 2,974.0 |  |  | 750.0 |  |  | 350.0 |
Repayments of long-term debt and finance lease obligations | (1,622.0) |  |  | (51.6) |  |  | (1,046.1) |
Issuance of short-term debt (maturity > 90 days) | 1,350.0 |  |  | 600.0 |  |  | 950.0 |
Repayment of short-term debt (maturity > 90 days) | (2,200.0) |  |  | (700.0) |  |  | — |
Change in short-term borrowings, net (maturity ≤ 90 days) | (420.1) |  |  | (104.0) |  |  | (178.5) |
Issuance of common stock, net of issuance costs | 211.4 |  |  | 244.4 |  |  | 848.2 |
Issuance of preferred stock, net of issuance costs | — |  |  | — |  |  | 880.0 |
Equity costs, premiums and other debt related costs | (246.5) |  |  | (17.8) |  |  | (46.0) |
Acquisition of treasury stock | — |  |  | — |  |  | (4.0) |
Contributions from non-controlling interest, net of issuance costs | 82.2 |  |  | — |  |  | — |
Dividends paid - common stock | (321.6) |  |  | (298.5) |  |  | (273.3) |
Dividends paid - preferred stock | (55.1) |  |  | (56.1) |  |  | (11.6) |
Net Cash Flows from Financing Activities | (247.7) |  |  | 366.4 |  |  | 1,468.7 |
Change in cash, cash equivalents and restricted cash | (22.8) |  |  | 27.3 |  |  | 82.7 |
Cash, cash equivalents and restricted cash at beginning of period | 148.4 |  |  | 121.1 |  |  | 38.4 |
Cash, Cash Equivalents and Restricted Cash at End of Period | $ | 125.6 |  |  | $ | 148.4 |  |  | $ | 121.1 |

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

(in millions) | Common Stock |  | Preferred Stock(1) |  | Treasury Stock |  | Additional Paid-In Capital |  | Retained Deficit |  | Accumulated Other Comprehensive Loss |  | Noncontrolling Interest in Consolidated Subsidiaries |  | Total
Balance as of January 1, 2018 | $ | 3.4 |  |  | $ | — |  |  | $ | (95.9) |  |  | $ | 5,529.1 |  |  | $ | (1,073.1) |  |  | $ | (43.4) |  |  | $ | — |  |  | $ | 4,320.1 |
Comprehensive Loss: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
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 | — |  |  | — |  |  | — |  |  | — |  |  | 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 |
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 |

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

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

| Preferred |  | Common
(in thousands) | Shares |  | Shares |  | Treasury |  | Outstanding
Balance as of January 1, 2018 | — |  |  | 340,813 |  |  | (3,797) |  |  | 337,016 |
Treasury stock acquired | — |  |  | — |  |  | (166) |  |  | (166) |
Issued: |  |  |  |  |  |  |
Common stock - private placement | — |  |  | 24,964 |  |  | — |  |  | 24,964 |
Preferred stock | 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 |
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 |

(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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N I S OURCE I NC.
Notes to Consolidated Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
1. Nature of Operations and Summary of Significant Accounting Policies
A. Company Structure and Principles of Consolidation. We are an energy holding company incorporated in Delaware and headquartered in Merrillville, Indiana. Our subsidiaries are fully regulated natural gas and electric utility companies serving approximately 3.7 million customers in six states. We generate substantially all of our operating income through these rate-regulated businesses. The consolidated financial statements include the accounts of us, our majority-owned subsidiaries, and VIEs of which we are the primary beneficiary after the elimination of all intercompany accounts and transactions.
On February 26, 2020, NiSource and Columbia of Massachusetts entered into an Asset Purchase Agreement with Eversource (the "Asset Purchase Agreement"). On October 9, 2020, NiSource and Columbia of Massachusetts received net proceeds from the sale of approximately $1,113 million, which included, a $1,100 million purchase price, an estimate of Columbia of Massachusetts' net working capital, net of closing costs and a $56.0 million payment in lieu of penalties that NiSource agreed to make in full settlement of all of the pending and potential claims, lawsuits, investigations or proceedings settled by and released by a settlement agreement approved by the Massachusetts DPU. As of December 31, 2020, we have recorded a loss on the sale of $412.4 million based on asset and liability balances as of the close of the transaction on October 9, 2020, estimated net working capital and estimated transaction costs. This estimated pre-tax loss is presented as "Loss on sale of assets, net" on the Statements of Consolidated Income (Loss) and is subject to change based on the final net working capital determination.
The Massachusetts Business had the following pretax income (loss) for the twelve months ended December 31, 2020, 2019 and 2018:

|  | Twelve Months Ended December 31,
(in millions) |  | 2020 |  | 2019 |  | 2018 |
Pretax Income (Loss) |  | ($422.3) |  | $36.8 |  | ($835.6) |

We continue to monitor how the COVID-19 pandemic is affecting our workforce, customers, suppliers, operations, financial results and cash flow. See Note 3, "Revenue Recognition," Note 9, "Regulatory Matters," and Note 11, "Income Taxes," for information on the pandemic.
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 to satisfy requirements for the provision of various property, liability, workers compensation, and long-term disability insurance, which is classified as restricted cash on the Consolidated Balance Sheets and disclosed with cash and cash equivalents on the Statements of Consolidated Cash Flows.
D. Accounts Receivable and Unbilled Revenue. Accounts receivable on the Consolidated Balance Sheets includes both billed and unbilled amounts. Unbilled amounts of accounts receivable relate to a portion of a customer’s consumption of gas or electricity from the last cycle billing date through the last day of the month (balance sheet date). Factors taken into consideration when estimating unbilled revenue include historical usage, customer rates, weather and reasonable and supportable forecasts. Accounts receivable fluctuates from year to year depending in large part on weather impacts and price volatility. Our accounts receivable on the Consolidated Balance Sheets include unbilled revenue, less reserves, in the amounts of $338.3 million and $350.5 million as of December 31, 2020 and 2019, respectively. 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.
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” on the Consolidated Balance Sheets. Unrealized gains and losses, net of deferred income taxes, are recorded to accumulated other comprehensive income or loss. These
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N I S OURCE I NC.
Notes to Consolidated Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
investments are monitored for other than temporary declines in market value. Realized gains 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, 2020, 2019 or 2018. Refer to Note 18, "Fair Value," for additional information.
F. Basis of Accounting for Rate-Regulated Subsidiaries. Rate-regulated subsidiaries account for and report assets and liabilities consistent with the economic effect of the way in which regulators establish rates, if the rates established are designed to recover the costs of providing the regulated service and it is probable that such rates can be charged and collected. Certain expenses and credits subject to utility regulation or rate determination normally reflected in income are deferred on the Consolidated Balance Sheets and are later recognized in income as the related amounts are included in customer rates and recovered from or refunded to customers.
We continually evaluate whether or not our operations are within the scope of ASC 980 and rate regulations. As part of that analysis, we evaluate probability of recovery for our regulatory assets. In management’s opinion, our regulated subsidiaries will be subject to regulatory accounting for the foreseeable future. Refer to Note 9, "Regulatory Matters," for additional information.
G. Plant and Other Property and Related Depreciation and Maintenance. Property, plant and equipment (principally utility plant) is stated at cost. Our rate-regulated subsidiaries record depreciation using composite rates on a straight-line basis over the remaining service lives of the electric, gas and common properties, as approved by the appropriate regulators.
Non-utility property includes renewable generation assets owned by a joint venture of which we are the primary beneficiary and is generally depreciated on a straight-line basis over the life of the associated asset. Refer to Note 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 2.6% in 2020, 3.0% in 2019 and 3.5% in 2018.
Generally, our subsidiaries follow the practice of charging maintenance and repairs, including the cost of removal of minor items of property, to expense as incurred. When our subsidiaries retire regulated property, plant and equipment, original cost plus the cost of retirement, less salvage value, is charged to accumulated depreciation. However, when it becomes probable a regulated asset will be retired substantially in advance of its original expected useful life or is abandoned, the cost of the asset and the corresponding accumulated depreciation is recognized as a separate asset. If the asset is still in operation, the gross amounts are classified as "Non-Utility and Other " as described in Note 6, "Property, Plant and Equipment." If the asset is no longer operating but still subject to recovery, the net amount is classified in "Regulatory assets" on the Consolidated Balance Sheets. If we are able to recover a full return of and on investment, the carrying value of the asset is based on historical cost. If we are not able to recover a full return on investment, a loss on impairment is recognized to the extent the net book value of the asset exceeds the present value of future revenues discounted at the incremental borrowing rate.
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 "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 6, "Property, Plant and Equipment," for further information.
External and internal costs associated with computer software developed for internal use are capitalized. Capitalization of such costs commences upon the completion of the preliminary stage of each project. Once the installed software is ready for its intended use, such capitalized costs are amortized on a straight-line basis generally over a period of five years
External and internal up-front implementation costs associated with cloud computing arrangements that are service contracts are deferred on the Consolidated Balance Sheets. Once the installed software is ready for its intended use, such deferred costs are amortized on a straight-line basis to "Operation and maintenance," over the minimum term of the contract plus contractually-provided renewal periods that are reasonable expected to be exercised.
H. Goodwill and Other Intangible Assets. Substantially all of our goodwill relates to the excess of cost over the fair value of the net assets acquired in the Columbia acquisition on November 1, 2000. We test our goodwill for impairment annually as of May 1, or more frequently if events and circumstances indicate that goodwill might be impaired. Fair value of our reporting
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Notes to Consolidated Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
units is determined using a combination of income and market approaches. See Note 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, 2020 and 2019 Consolidated Balance Sheets and short-term debt is recorded in the amount of proceeds received from the transferees involved in the transactions. Refer to Note 19, "Transfers of Financial Assets," for further information.
J. Gas Cost and Fuel Adjustment Clause. Our regulated subsidiaries defer most differences between gas and fuel purchase costs and the recovery of such costs in revenues and adjust future billings for such deferrals on a basis consistent with applicable state-approved tariff provisions. These deferred balances are recorded as "Regulatory assets" or "Regulatory liabilities," as appropriate, on the Consolidated Balance Sheets. Refer to Note 9, "Regulatory Matters," for additional information.
K. Inventory. Both the LIFO inventory methodology and the weighted average cost methodology are used to value natural gas in storage, as approved by regulators for all of our regulated subsidiaries. Inventory valued using LIFO was $42.3 million and $47.2 million at December 31, 2020 and 2019, respectively. Based on the average cost of gas using the LIFO method, the estimated replacement cost of gas in storage was less than the stated LIFO cost by $19.6 million and $25.5 million at December 31, 2020 and 2019, respectively. Gas inventory valued using the weighted average cost methodology was $148.8 million at December 31, 2020 and $203.7 million at December 31, 2019.
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 not to net fair value amounts for any of our derivative instruments or the fair value amounts recognized for the right to receive cash collateral or obligation to pay cash collateral arising from those derivative instruments recognized at fair value, which are executed with the same counterparty under a master netting arrangement. See Note 10, "Risk Management Activities," for additional information.
N. Income Taxes and Investment Tax Credits. We record income taxes to recognize full interperiod tax allocations. Under the asset and liability method, deferred income taxes are provided for the tax consequences of temporary differences by applying enacted statutory tax rates applicable to future years to differences between the financial statement carrying amount and the tax basis of existing assets and liabilities. Investment tax credits associated with regulated operations are deferred and amortized as a reduction to income tax expense over the estimated useful lives of the related properties.
To the extent certain deferred income taxes of the regulated companies are recoverable or payable through future rates, regulatory assets and liabilities have been established. Regulatory assets for income taxes are primarily attributable to property-related tax timing differences for which deferred taxes had not been provided in the past, when regulators did not recognize such taxes as costs in the rate-making process. Regulatory liabilities for income taxes are primarily attributable to the regulated companies’ obligation to refund to ratepayers deferred income taxes provided at rates higher than the current Federal income tax rate. Such property-related amounts are credited to ratepayers using either the average rate assumption method or the reverse South Georgia method. Non property-related amounts are credited to ratepayers consistent with state utility commission direction.
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Notes to Consolidated Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
Pursuant to the Internal Revenue Code and relevant state taxing authorities, we and our subsidiaries file consolidated income tax returns for federal and certain state jurisdictions. We and our subsidiaries are parties to a tax sharing agreement. Income taxes recorded by each party represent amounts that would be owed had the party been separately subject to tax.
O. Environmental Expenditures. We accrue for costs associated with environmental remediation obligations, including expenditures related to asset retirement obligations and cost of removal, when the incurrence of such costs is probable and the amounts can be reasonably estimated, regardless of when the expenditures are actually made. The undiscounted estimated future expenditures are based on currently enacted laws and regulations, existing technology and estimated site-specific costs where assumptions may be made about the nature and extent of site contamination, the extent of cleanup efforts, costs of alternative cleanup methods and other variables. The liability is adjusted as further information is discovered or circumstances change. The accruals for estimated environmental expenditures are recorded on the Consolidated Balance Sheets in “Other accruals” for short-term portions of these liabilities and “Other noncurrent liabilities” for the respective long-term portions of these liabilities. Rate-regulated subsidiaries applying regulatory accounting establish regulatory assets on the Consolidated Balance Sheets to the extent that future recovery of environmental remediation costs is probable through the regulatory process. Refer to Note 8, "Asset Retirement Obligations," and Note 20, "Other Commitments and Contingencies," for further information.
P. Excise Taxes. As an agent for some state and local governments, we invoice and collect certain excise taxes levied by state and local governments on customers and record these amounts as liabilities payable to the applicable taxing jurisdiction. Such balances are presented within "Other accruals" on the Consolidated Balance Sheets. These types of taxes collected from customers, comprised largely of sales taxes, are presented on a net basis affecting neither revenues nor cost of sales. We account for excise taxes for which we are liable by recording a liability for the expected tax with a corresponding charge to “Other taxes” expense on the Statements of Consolidated Income (Loss).
Q. 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 20-E "Other Matters" for further information on accrued insurance liabilities related to the Greater Lawrence Incident.
2. Recent Accounting Pronouncements
Recently Issued Accounting Pronouncements
We are currently evaluating the impact of certain ASUs on our Consolidated Financial Statements or Notes to Consolidated Financial Statements, which are described below:

Standard | Description | Effective Date | Effect on the financial statements or other significant matters
ASU 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Statement | This pronouncement provides 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. | Upon issuance on March 12, 2020, and will apply though December 31, 2022. | We continue to evaluate the temporary expedients and options available under this guidance, and the effects of these pronouncements on our Consolidated Financial Statements and Notes to Consolidated Financial Statements. We are currently identifying and evaluating contracts that may be impacted. As of December 31, 2020, we have not applied any expedients and options available under this ASU.
ASU 2021-01, Reference Rate Reform (Topic 848): Scope

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

Standard | Description | Effective Date | Effect on the financial statements or other significant matters
ASU 2020-06, Debt with Conversion and Other Options (Subtopic 470-20) and Derivative and Hedging - Contracts in Entity's Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity's Own Equity | This pronouncement simplifies the accounting for certain financial instruments with characteristics of liabilities and 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 qualify for it" and "simplifies the diluted earnings per share (EPS) calculations in certain areas." | Annual period beginning after December 15, 2021. Early adoption is permitted for annual period beginning after December 15, 2020. | This pronouncement does not impact any securities we currently have on our balance sheet. We will continue to evaluate the effects of this pronouncement on our Consolidated Financial Statements and Notes to Consolidated Financial Statements as it pertains to any relevant future activity. We expect to adopt this ASU on its effective date.

Recently Adopted Accounting Pronouncements

Standard | Adoption
ASU 2019-04, Codification Improvements to Topic 326, Financial Instruments-Credit Losses, Topic 815, Derivatives and Hedging, and Topic 825, Financial Instruments | In June 2016, the FASB issued ASU 2016-13, Measurement of Credit Losses on Financial Instruments (ASC 326). ASC 326 revised the GAAP guidance on the impairment of most financial assets and certain other instruments that are not measured at fair value through net income. ASC 326 introduces the current expected credit loss (CECL) model that is based on expected losses for instruments measured at amortized cost rather than incurred losses. It also requires entities to record an allowance 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 debt securities will be recognized immediately in earnings, instead of over-time as they would under historic guidance. In 2019, the FASB issued ASU 2019-04, Codification Improvements to Topic 326, Financial Instruments-Credit Losses, Topic 815, Derivative and Hedging, and Topic 825, Financial Instruments. This pronouncement clarified and improved certain areas of guidance related to the recently issued standards on credit losses, hedging, and recognition and measurement. We adopted ASC 326 effective January 1, 2020, using a modified retrospective method. Adoption of this standard did not have material impact on our Consolidated Financial Statements. No adjustments were made to the January 1, 2020 opening balances as a result of this adoption. As required under the modified retrospective method of adoption, results for the reporting periods beginning after January 1, 2020 are presented under ASC 326, while prior period amounts are not adjusted. See Note 3, "Revenue Recognition," and Note 18, "Fair Value," for our discussion of the implementing these standards.
ASU 2016-13, Financial Instruments-Credit Losses (Topic 326)
ASU 2018-14, Compensation—Retirement Benefits—Defined Benefit Plans—General (Subtopic 715-20): Disclosure Framework—Changes to the Disclosure Requirements for Defined Benefit Plans | Issued in August 2018, the pronouncement modifies the disclosure requirements for defined benefit pension or 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 for fiscal years ending after December 15, 2020, and are applied on a retrospective basis to all periods presented. These disclosure requirements are reflected in the Note 12, "Pension and Postretirement Benefits."
ASU 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes | This pronouncement simplifies the accounting for income taxes by eliminating certain exceptions to the general principles in ASC 740, income taxes. It also improves consistency of application for other areas of the guidance by clarifying and amending existing guidance. We adopted the amendments of this pronouncement as of January 1, 2021 with no material impact to the Consolidated Financial Statements.

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Notes to Consolidated Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
3. Revenue Recognition
Customer Revenues. Substantially all of our revenues are tariff-based. Under ASC 606, the recipients of our utility service meet the definition of a customer, while the operating company tariffs represent an agreement that meets the definition of a contract, which creates enforceable rights and obligations. Customers in certain of our jurisdictions participate in programs that allow for a fixed payment each month regardless of usage. Payments received that exceed the value of gas or electricity actually delivered are recorded as a liability and presented in "Customer Deposits and Credits" on the Consolidated Balance Sheets. Amounts in this account are reduced and revenue is recorded when customer usage exceeds payments received.
We have identified our performance obligations created under tariff-based sales as 1) the commodity (natural gas or electricity, which includes generation and capacity) and 2) delivery. These commodities are sold and / or delivered to and generally consumed by customers simultaneously, leading to satisfaction of our performance obligations over time as gas or electricity is delivered to customers. Due to the at-will nature of utility customers, performance obligations are limited to the services requested and received to date. Once complete, we generally maintain no additional performance obligations.
Transaction prices for each performance obligation are generally prescribed by each operating company’s respective tariff. Rates include provisions to adjust billings for fluctuations in fuel and purchased power costs and cost of natural gas. Revenues are adjusted for differences between actual costs, subject to reconciliation, and the amounts billed in current rates. Under or over recovered revenues related to these cost recovery mechanisms are included in "Regulatory Assets" or "Regulatory Liabilities" on the Consolidated Balance Sheets and are recovered from or returned to customers through adjustments to tariff rates. As we provide and deliver service to customers, revenue is recognized based on the transaction price allocated to each performance obligation. Distribution revenues are generally considered daily or "at-will" contracts as customers may cancel their service at any time (subject to notification requirements), and revenue generally represents the amount we are entitled to bill customers.
In addition to tariff-based sales, our Gas Distribution Operations segment enters into balancing and exchange arrangements of natural gas as part of our operations and off-system sales programs. 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. We completed the sale of the Massachusetts Business on October 9, 2020. The Electric Operations segment provides electric service in 20 counties in the northern part of Indiana.
The table below reconciles 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, 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 24, "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.
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Notes to Consolidated Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

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 24, "Segments of Business," for discussion of intersegment revenues.

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 24, "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 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. The opening and closing balances of customer receivables for the years ended December 31, 2020 and 2019 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.
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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)(1) |  | Customer Accounts Receivable, Unbilled (less reserve) |
Balance as of December 31, 2019 | $ | 466.6 |  |  | $ | 346.6 |  |
Balance as of December 31, 2020 | 400.0 |  |  | 327.2 |  |
Decrease | $ | (66.6) |  |  | $ | (19.4) |  |

(1)Customer billed receivables decreased due to decreased natural gas costs and warmer weather in 2020 compared to 2019.
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, 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. In connection with the COVID-19 pandemic, certain state regulatory commissions instituted regulatory moratoriums that impacted our ability to pursue our standard credit risk mitigation practices. Following the issuance of these moratoriums, certain of our regulated operations have been authorized to recognize a regulatory asset for bad debt costs above levels currently in rates. We have reinstated our common credit mitigation practices where moratoriums have expired (see Note 9, "Regulatory Matters," for additional information on regulatory moratoriums and regulatory assets). It is probable that substantially all of the consideration to which we are entitled from customers will be collected upon satisfaction of performance obligations.
Allowance for Credit Losses. We adopted ASC 326 effective January 1, 2020. See "Recently Adopted Accounting Pronouncements" in Note 2, "Recent Accounting Pronouncements," for more information about ASC 326.
Each of our business segments pool their customer accounts receivables based on similar risk characteristics, such as customer type, geography, payment terms, and related macro-economic risks. Expected credit loss exposure is evaluated separately for each of our accounts receivable pools. Expected credit losses are established using a model that considers historical collections experience, current information, and reasonable and supportable forecasts. Relevant and reliable internal and external inputs used in the model include, but are not limited to, energy consumption trends, revenue projections, actual charge-offs data, recoveries data, shut-off orders executed data, and final bill data. We continuously evaluate available reasonable and supportable information relevant to assessing collectibility of current and future receivables. We evaluate creditworthiness of specific customers periodically or when required by 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; these include, but are not limited to, creditworthiness of overall population in service territories, adverse conditions impacting an industry sector, and current economic conditions.
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Notes to Consolidated Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
At each reporting period, we record expected credit losses using an allowance for credit losses account. When deemed to be uncollectible, customer accounts are written-off. A rollforward of our allowance for credit losses for the year ended December 31, 2020 are presented in the table below:

Year Ended December 31, 2020 (in millions) | Gas Distribution Operations |  | Electric Operations |  | Corporate and Other |  | Total
Beginning balance(1) | 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 |
Ending balance of the allowance for credit losses | 41.8 |  |  | 9.7 |  |  | 0.8 |  |  | 52.3 |
(1)Total beginning balance differs from that presented in the Consolidated Balance Sheets as it excludes Columbia of Massachusetts. Columbia of Massachusetts' customer receivables and related allowance for credit losses were included in the sale of the Massachusetts Business that occurred on October 9, 2020.

As of December 31, 2020, we have also evaluated the adequacy of our allowance for credit losses in light of the suspension of shut-offs for nonpayment due to the COVID-19 pandemic that remain in effect for certain jurisdictions, as well as the economic downturn. Our evaluation included an analysis of customer payment trends in 2020, economic conditions, receivables aging, considerations of past economic downturns and the associated allowance for credit losses and customer account write-offs. In addition, we considered benefits available under governmental COVID-19 relief programs, the impact of unemployment benefits initiatives, and flexible payment plans being offered to customers affected by or experiencing hardship as a result of the pandemic, which could help to mitigate the potential for increasing customer account delinquencies. Based upon this evaluation, we have concluded that the allowance for credit losses as of December 31, 2020 adequately reflected the collection risk and net realizable value for our receivables. We will continue to monitor changing circumstances and will adjust our allowance for credit losses as additional information becomes available.
4. Variable Interest Entities
A VIE is an entity in which the controlling interest is determined through means other than a majority voting interest. The primary beneficiary of a VIE is the business enterprise which has the power to direct the activities of the VIE that most significantly impact the VIE’s economic performance. Also, the primary beneficiary either absorbs a significant amount of the VIE’s losses or has the right to receive benefits that could be significant to the VIE. We consider these qualitative elements in determining whether we are the primary beneficiary of a VIE, and we consolidate those VIEs for which we are determined to be the primary beneficiary.
Rosewater (a joint venture) owns and operates 102 MW of nameplate capacity wind generation assets. Members of the joint venture are NIPSCO (who is the managing member) and a tax equity partner. Earnings, tax attributes and cash flows are allocated to both NIPSCO and the tax equity partner in varying percentages by category and over the life of the partnership. Once the tax equity partner has earned their negotiated rate of return and we have reached the agreed upon contractual date, NIPSCO has the option to purchase at fair market value from the tax equity partner the remaining interest in the aforementioned joint venture. NIPSCO has an obligation to purchase, through a PPA at established market rates, 100% of the electricity generated by Rosewater.
As the managing member of Rosewater, we control decisions that are significant to its ongoing operations and economic results. Therefore, we have concluded that we are the primary beneficiary of Rosewater and have consolidated Rosewater even though we own less than 100% of the total equity membership interest.
We have determined that the use of HLBV accounting is reasonable and appropriate in order to attribute income and loss to the noncontrolling interest held by the tax equity partner. HLBV accounting was selected as the allocation of Rosewater's economic results to members differ from the members' relative ownership percentages. Using the HLBV method, our earnings are calculated based on how the partnership would distribute its cash if it were to hypothetically sell all of its assets for their carrying amounts and liquidate at each reporting period. Under HLBV, we calculate the liquidation value allocable to each partner at the beginning and end of each period based on the contractual terms of the related entity's operating agreement and adjust our income for the period to reflect the change our associated book value.
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Notes to Consolidated Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
In December 2020, in exchange for their respective membership interests in Rosewater, NIPSCO contributed $0.7 million in cash, and the tax equity partner contributed $86.1 million in cash, the first of two contractual cash contributions for each partner, per the equity capital contribution agreement. NIPSCO's remaining economic interest was acquired by assuming an obligation of $69.7 million to the developer, which comes due in 2023 and is included in "Other noncurrent liabilities" in the Consolidated Balance Sheets. From the contributed funds, Rosewater paid $85.3 million to the developer of the wind generation assets. 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. Once asset construction is complete, NIPSCO and the tax equity partner will each make a second cash contribution of $0.1 million and $7.5 million, respectively, and NIPSCO will assume an additional obligation to the developer of $6.0 million, totaling contributions of $170.1 million for both partners. We did not provide any financial or other support during the year that was not previously contractually required, nor do we expect to provide such support in the future.
At December 31, 2020, $156.4 million in net assets (as detailed in the table below) related to Rosewater and the non-controlling interest attributable to the unrelated tax equity partner of $85.6 million were included in the Consolidated Balance Sheets. For the year ended December 31, 2020 $3.4 million was allocated to the tax equity partner and is included in "Net income attributable to non-controlling interest" on the Statements of Consolidated Income (Loss).
At December 31, 2020, our consolidated balance sheet included the following assets and liabilities associated with Rosewater:

(in millions) |
Net Property, Plant and Equipment | $ | 175.6 |
Current assets | 1.7
Total assets(1) | $ | 177.3 |
Current liabilities | $ | 15.3 |
Asset retirement obligations | 5.5
Other noncurrent liabilities | 0.1
Total liabilities | $ | 20.9 |

(1)The assets of Rosewater represent assets of a consolidated VIE that can be used only to settle obligations of the consolidated VIE.
5. Earnings Per Share
Basic EPS is computed by dividing net income attributable to common shareholders by the weighted-average number of shares of common stock outstanding for the period. The weighted-average shares outstanding for diluted EPS includes the incremental effects of the various long-term incentive compensation plans and forward agreements when the impact of such plans and agreements would be dilutive. The calculation of diluted earnings per share for the years ended December 31, 2020 and December 31, 2018 does not include any dilutive potential common shares as we had a net loss on the Statements of Consolidated Income (Loss) for these periods, and any incremental shares would have had an anti-dilutive impact on EPS. The computation of diluted average common shares is as follows:

Year Ended December 31, (in thousands) | 2020 |  | 2019 |  | 2018
Denominator |  |  |  |  |
Basic average common shares outstanding | 384,347 |  |  | 374,650 |  |  | 356,491 |
Dilutive potential common shares: |  |  |  |  |
Shares contingently issuable under employee stock plans | — |  |  | 929 |  |  | — |
Shares restricted under employee stock plans | — |  |  | 154 |  |  | — |
Forward agreements | — |  |  | 253 |  |  | — |
Diluted Average Common Shares | 384,347 |  |  | 375,986 |  |  | 356,491 |

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

At December 31, (in millions) | 2020 |  | 2019
Property, Plant and Equipment |  |  |
Gas Distribution Utility(1) | $ | 14,010.2 |  |  | $ | 14,989.7 |
Electric Utility(1) | 6,478.0 |  |  | 8,902.3 |
Corporate | 197.3 |  |  | 153.3 |
Construction Work in Process | 572.6 |  |  | 457.3 |
Renewable Generation Assets(2) | 175.7 |  |  | — |
Non-Utility and Other(3) | 2,746.1 |  |  | 39.3 |
Total Property, Plant and Equipment | $ | 24,179.9 |  |  | $ | 24,541.9 |
Accumulated Depreciation and Amortization |  |  |
Gas Distribution Utility(1) | $ | (3,292.9) |  |  | $ | (3,556.0) |
Electric Utility(1) | (2,305.0) |  |  | (3,973.8) |
Corporate | (109.3) |  |  | (79.5) |
Renewable Generation Assets(2) | (0.1) |  |  | — |
Non-Utility and Other(3) | (1,853.1) |  |  | (20.4) |
Total Accumulated Depreciation and Amortization | $ | (7,560.4) |  |  | $ | (7,629.7) |
Net Property, Plant and Equipment | $ | 16,619.5 |  |  | $ | 16,912.2 |

(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 Rosewater Wind Generation LLC, a joint venture between NIPSCO and unrelated tax equity partner, 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, 2020 includes net book value of $903.8 million related to R.M. Schahfer Generating Station, which was reclassified from Electric Utility in the second quarter of 2020. Depreciation expense for the remaining net book value continues to be recorded at the composite depreciation rate approved by the IURC. See Note 20-E, "Other Matters," for additional information.
The weighted average depreciation provisions for utility plant, as a percentage of the original cost, for the periods ended December 31, 2020, 2019 and 2018 were as follows:

| 2020 |  | 2019 |  | 2018
Electric Operations(1) | 3.4 | % |  | 2.8 | % |  | 2.9 | %
Gas Distribution Operations | 2.3 | % |  | 2.5 | % |  | 2.2 | %

(1)Increased rate beginning in 2020 primarily attributable to higher depreciation rates from the recent rate case proceeding.
We recognized depreciation expense of $655.6 million, $612.2 million and $503.4 million for the years ended 2020, 2019 and 2018, respectively.
Amortization of Software Costs. We amortized $56.7 million, $55.5 million and $54.1 million in 2020, 2019 and 2018, respectively, related to software costs. Our unamortized software balance was $136.4 million and $169.6 million at December 31, 2020 and 2019, respectively.
Amortization of Cloud Computing Costs. We amortized $3.4 million, $1.6 million and $0.1 million in 2020, 2019 and 2018, respectively, related to cloud computing costs. Our unamortized cloud computing balance was $12.7 million and $14.2 million at December 31, 2020 and 2019, respectively.
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Notes to Consolidated Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
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 goodwill balance allocated by segment as of December 31, 2020 and 2019:

(in millions) | 2020 |  | 2019
Gas Distribution Operations | $ | 1,485.9 |  |  | $ | 1,485.9 |
Electric Operations | — |  |  | — |
Corporate and Other | — |  |  | — |
Total | $ | 1,485.9 |  |  | $ | 1,485.9 |

For our annual goodwill impairment analysis performed as of May 1, 2020, we completed a quantitative ("step 1") fair value measurement of our reporting units. Fair value of this reporting unit was determined based on a weighting of income and market approaches. The income approach calculated discounted cash flows using updated cash flow projections, discount rates and return on equity assumptions. The market approach applied a combination of comparable company multiples and comparable transactions and used the most recent cash flow projections. The test indicated that the fair value of each of the reporting units that are allocated goodwill exceeded their carrying values, indicating that no impairment was necessary.
Columbia of Massachusetts was not considered to be a reporting unit for May 1, 2020 fair value measurement as the goodwill balance had been reduced to zero 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 for our Columbia of Massachusetts reporting unit. The fair value of the Columbia of Massachusetts reporting unit was determined in the same manner as described above for our remaining reporting units. The 2019 year-end impairment analysis indicated that the fair value of the Columbia of Massachusetts reporting unit was below its carrying value. As a result, we reduced the Columbia of Massachusetts reporting unit goodwill balance to zero and recognized a goodwill impairment charge totaling $204.8 million, which is non-deductible for tax purposes.
Intangible and Other Long-Lived Assets Impairment. We review our definite-lived intangible assets, along with other long-lived assets (utility plant), for impairment when events or changes in circumstances indicate the assets' fair value might be below their carrying amount. Prior to December 31, 2019, our intangible assets, apart from goodwill, 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.
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 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 recorded in the Gas Distribution Operations segment during the year ended December 31, 2019.
As of December 31, 2020 and 2019, the carrying amount of the franchise rights was zero. We recorded zero amortization expense in 2020 and $11.0 million in 2019 and 2018 related to our franchise rights intangible asset.
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, certain costs to retire pipeline, removal costs for certain underground storage tanks, removal of certain pipelines known to contain PCB contamination, closure costs for certain sites including ash ponds, solid waste management units and a landfill, as well as some other nominal asset retirement obligations. We also have an obligation associated with the decommissioning of our two hydro facilities located in Indiana. These hydro facilities have an indeterminate life, and as such, no asset retirement obligation has been recorded.
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Notes to Consolidated Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
Changes in our liability for asset retirement obligations for the years 2020 and 2019 are presented in the table below:

(in millions) | 2020 |  | 2019 |
Beginning Balance | $ | 416.9 |  |  | $ | 352.0 |  |
Accretion recorded as a regulatory asset/liability | 17.3 |  |  | 15.7 |  |
Additions | 5.5 |  |  | — |  |
Settlements | (13.9) |  |  | (5.4) |  |
Change in estimated cash flows | 86.0 |  | (1) | 54.6 |  | (2)
Other | (16.2) |  | (3) | — |  |
Ending Balance | $ | 495.6 |  |  | $ | 416.9 |  |

(1)The change in estimated cash flows for 2020 is primarily attributed to revisions to the estimated costs associated with refining the CCR compliance plan, changes in estimated costs for electric generating stations and the changes in estimated costs for retirement of gas mains. See Note 20-D. "Environmental Matters" for additional information on CCRs.
(2)The change in estimated cash flows for 2019 is primarily attributed to changes in estimated costs and settlement timing for electric generating stations and the changes in estimated costs for retirement of gas mains.
(3)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.
9. Regulatory Matters
Regulatory Assets and Liabilities
We follow the accounting and reporting requirements of ASC Topic 980, which provides that regulated entities account for and report assets and liabilities consistent with the economic effect of regulatory rate-making procedures when the rates established are designed to recover the costs of providing the regulated service and it is probable that such rates will be charged and collected from customers. Certain expenses and credits subject to utility regulation or rate determination normally reflected in income or expense are deferred on the balance sheet and are recognized in the income statement as the related amounts are included in customer rates and recovered from or refunded to customers. We assess the probability of collection for all of our regulatory assets each period.
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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) | 2020 |  | 2019
Regulatory Assets |  |  |
Unrecognized pension and other postretirement benefit costs (see Note 12) | $ | 583.3 |  |  | $ | 739.1 |
Deferred pension and other postretirement benefit costs (see Note 12) | 72.4 |  |  | 91.3 |
Environmental costs (see Note 20-D) | 56.6 |  |  | 73.4 |
Regulatory effects of accounting for income taxes (see Note 1-N and Note 11) | 194.5 |  |  | 234.0 |
Under-recovered gas and fuel costs (see Note 1-J) | 8.0 |  |  | 3.9 |
Depreciation | 192.6 |  |  | 210.7 |
Post-in-service carrying charges | 228.6 |  |  | 219.8 |
Safety activity costs | 146.0 |  |  | 118.6 |
DSM programs | 37.8 |  |  | 50.1 |
Bailly Generating Station | 204.7 |  |  | 221.8 |
Losses on Commodity Price Risk Programs (See Note 10) | 54.7 |  |  | 76.4 |
Deferred Property Taxes | 62.9 |  |  | 60.3 |
Other | 88.4 |  |  | 140.2 |
Total Regulatory Assets | $ | 1,930.5 |  |  | $ | 2,239.6 |
Less: Current Portion | 135.7 |  |  | 225.7 |
Total Noncurrent Regulatory Assets | $ | 1,794.8 |  |  | $ | 2,013.9 |

Regulatory liabilities were comprised of the following items:

At December 31, (in millions) | 2020 |  | 2019
Regulatory Liabilities |  |  |
Over-recovered gas and fuel costs (see Note 1-J) | $ | 47.8 |  |  | $ | 42.6 |
Cost of removal (see Note 8) | 775.2 |  |  | 1,047.5 |
Regulatory effects of accounting for income taxes (see Note 1-N and Note 11) | 1,105.1 |  |  | 1,307.0 |
Deferred pension and other postretirement benefit costs (see Note 12) | 69.5 |  |  | 64.7 |
Other | 67.9 |  |  | 50.4 |
Total Regulatory Liabilities | $ | 2,065.5 |  |  | $ | 2,512.2 |
Less: Current Portion | 161.3 |  |  | 160.2 |
Total Noncurrent Regulatory Liabilities | $ | 1,904.2 |  |  | $ | 2,352.0 |

Regulatory assets, including under-recovered gas and fuel costs and depreciation, of approximately $1,260.6 million and $1,524.3 million as of December 31, 2020 and 2019, respectively, are not earning a return on investment. These costs are recovered over a remaining life, the longest of which is 41 years.
Assets:
Unrecognized pension and other postretirement benefit costs. Represents the deferred other comprehensive income or loss of the actuarial gains or losses and the prior service costs or credits that arise during the period but that are not immediately recognized as components of net periodic benefit costs by certain subsidiaries that will ultimately be recovered through base rates.
Deferred pension and other postretirement benefit costs. Primarily relates to the difference between defined benefit plan expense recorded by certain subsidiaries due to regulatory orders and the corresponding expense that would otherwise be recorded in accordance with GAAP. The majority of these amounts are driven by Columbia of Ohio. The timeframe for the recovery of these costs will be addressed in the next base rate case, and the costs are expected to be collected through future base rates, revenue riders or tracking mechanisms.
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Notes to Consolidated Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
Environmental costs. Includes certain recoverable costs related to gas plant sites, disposal sites or other sites onto which material may have migrated, the recovery of which is to be addressed in future base rates, billing riders or tracking mechanisms of certain of our subsidiaries.
Regulatory effects of accounting for income taxes. Represents the deferral and under collection of deferred taxes in the rate making process.
Under-recovered gas and fuel costs. Represents the difference between the costs of gas and fuel and the recovery of such costs in revenue and is used to adjust future billings for such deferrals on a basis consistent with applicable state-approved tariff provisions. Recovery of these costs is achieved through tracking mechanisms.
Depreciation. Represents differences between depreciation expense incurred on a GAAP basis and that prescribed through regulatory order. The majority of this balance is driven by Columbia of Ohio's IRP and CEP deferrals. Recovery of these amounts is approved annually through the related riders.
Post-in-service carrying charges. Represents deferred debt-based carrying charges incurred on certain assets placed into service but not yet included in customer rates. The majority of this balance is driven by Columbia of Ohio's IRP and CEP deferrals.
Safety activity costs. Represents the difference between costs incurred by certain of our subsidiaries in eligible safety programs in compliance with PHMSA regulations in excess of those being recovered in rates.
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. Represents the net book value of Units 7 and 8 of Bailly Generating Station that was retired during 2018. These amounts are currently being amortized at a rate consistent with their inclusion in customer rates.
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.
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.
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 collected through depreciation rates for future costs to be incurred.
Regulatory effects of accounting for income taxes. Represents amounts owed to customers for deferred taxes collected at a higher rate than the current statutory rates and liabilities associated with accelerated tax deductions owed to customers. Balance includes excess deferred taxes recorded upon implementation of the TCJA in December 2017, net of amounts amortized through 2020.
Deferred pension and other postretirement benefit costs. Primarily represents cash contributions in excess of postretirement benefit expense that is deferred by certain subsidiaries.
COVID-19 Regulatory Filings
In response to the COVID-19 pandemic, we have engaged, or have received directives from, the regulatory commissions in the states in which we operate, as described below.
Columbia of Ohio filed a Deferral Application and a Transition Plan with the PUCO on May 29, 2020. The Deferral Application requested approval to record a regulatory asset for pandemic incremental costs, foregone revenue from late payment fees, and bad debt expense from certain classes of customers. An order approving the Deferral Application was received on July 15, 2020. The Transition Plan requested the resumption of activities that were suspended in March 2020,
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Notes to Consolidated Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
including resumption of disconnects due to non-payment and billing of late payment fees beginning with the August 2020 billing cycle. The PUCO approved the Transition Plan on June 17, 2020. As of December 31, 2020, $2.0 million of incremental pandemic-related costs were deferred to a regulatory asset.
NIPSCO received a COVID-19 pandemic order from the IURC on June 29, 2020. This order extended the disconnection moratorium and the suspension of collection of late payment fees, deposits and reconnection fees through August 14, 2020. The order requires utilities to offer payment arrangements of at least six months and requires NIPSCO to provide the IURC with information about NIPSCO’s communications with delinquent customers. On August 12, 2020, the IURC issued an order affirming the expiration of the disconnect moratorium after August 14, 2020, while requiring that six month payment plans be offered to all customers and extending the suspension for collection of late payment fees, deposits, and reconnection fees through October 12, 2020 for residential customers only. On October 7, 2020 the Office of Utility Consumer Counselor ("OUCC") filed a motion for the IURC to extend these temporary consumer protections for an additional 60 days. On October 27, the IURC issued a docket entry denying the OUCC's motion. The June 29, 2020 order also authorized NIPSCO to create a regulatory asset for pandemic-related incremental bad debt expense as well as the costs to implement the requirements of the order. As of December 31, 2020, $9.2 million of incremental bad debt expense and costs to implement the requirements of the order were deferred to a regulatory asset.
Columbia of Pennsylvania received a secretarial letter issued by the Pennsylvania PUC on May 13, 2020 authorizing Pennsylvania utilities to create a regulatory asset for incremental bad debt expense incurred since March 13, 2020, above levels currently in rates. While Columbia of Pennsylvania is not authorized to defer any other incremental costs, it is required to track extraordinary non-recurring costs, and any offsetting benefits received, in connection with the COVID-19 pandemic. On October 13, 2020, the Pennsylvania PUC entered an order modifying its March 13, 2020 emergency order that had established a moratorium on utility service terminations. As modified, the moratorium still applies to residential customers with incomes at or below 300% of the federal poverty income guidelines (“protected customers”). For all other customers, the moratorium was lifted on November 9, 2020, but utilities must comply with several notice requirements beyond those already in place in Pennsylvania in order to proceed with service terminations. For residential customers who are subject to termination under the revised moratorium, as of December 1, 2020, the standard winter service moratorium will be in effect until April 1, 2021, which will render service termination for delinquent accounts impractical during that period. Additionally, the October 13, 2020 order authorizes utilities to create a regulatory asset for any incremental expenses incurred above those embedded in rates resulting from the directives contained in the Order. As of December 31, 2020, $5.4 million of incremental bad debt expense was deferred to a regulatory asset.
On March 16, 2020, the VSCC ordered a moratorium on service disconnections for unpaid bills due to the effects of the COVID-19 pandemic. The order also suspended late payment fees, required utilities to offer payment plans of up to 12 months, and required utilities to provide certain information about customer accounts receivables to the VSCC. Columbia of Virginia received an order from the VSCC on April 29, 2020 authorizing Columbia of Virginia to create a regulatory asset for incremental bad debt expense, suspended late payment fees, reconnection costs, carrying costs and other incremental prudently incurred costs related to the pandemic. The VSCC moratorium expired on October 6, 2020; however, the directives requiring utilities to offer payment plans of up to 12 months and suspending service disconnections or charging of late payment fees to customers that are current on such payment plans remain in effect. On November 18, 2020, legislation was enacted that extended the moratorium on residential service disconnections and late payment fees until the Governor determines that the economic and public health conditions have improved such that the prohibition does not need to be in place, or until at least 60 days after such declared state of emergency ends, whichever is sooner. Recovery of any regulatory asset will be addressed in future base rate proceedings and is subject to an earnings test review.
On August 31, 2020, the Maryland PSC issued an emergency order that extended the Governor's order prohibiting residential service terminations through October 1, 2020. The emergency order also requires Maryland utilities that proceed with residential service terminations after that date to provide at least 45 days notice prior to terminating service; to offer structured payment plans to applicable residential customers with a minimum of 12 months to repay, or 24 months for certified low income customers; the requirement or collection of down payments or deposits as a condition of beginning a payment plan by any residential customer; and cannot refuse to negotiate or deny a payment plan to a residential customer due to such customer's failure to meet the terms and conditions of an alternate payment plan during the past 18 months. Columbia of Maryland received an order issued by the Maryland PSC on April 9, 2020, authorizing Maryland utilities to create a regulatory asset for incremental COVID-19 pandemic-related 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
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Notes to Consolidated Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
received in connection with the pandemic. As of December 31, 2020, Columbia of Maryland has deferred $0.7 million of incremental bad debt expense and pandemic-related costs to a regulatory asset.
Columbia of Kentucky received an order from the Kentucky PSC on September 21, 2020 lifting the disconnection moratorium for all customers, effective October 20, 2020. The September 21, 2020 order also lifted the suspension of late payment and reconnection fees for non-residential customers as of October 20, 2020. For residential customers, the moratorium on late payment and reconnection fees is extended to December 31, 2020 and tracking of lost revenue is required. Residential customers with accumulated arrearages for service provided on or after March 16, 2020 through October 1, 2020 will be notified and placed on a default payment plan of equal installments for nine months beginning with the November 2020 billing cycle. Residential customers on a payment plan that default shall be offered another payment plan. Carrying charges may be applied to all arrearages arising during the default payment plan period at a rate no greater than the utility’s long-term debt rate. The Kentucky PSC order allows Columbia of Kentucky to create a regulatory asset for carrying charges on all arrearages arising during the default payment plan period. As of December 31, 2020, an immaterial amount of carrying charges were deferred to a regulatory asset.
10. Risk Management Activities
We are exposed to certain risks related to our ongoing business operations; namely commodity price risk and interest rate risk. We recognize that the prudent and selective use of derivatives may help to lower our cost of debt capital, manage interest rate exposure and limit volatility in the price of natural gas.
Risk management assets and liabilities on our derivatives are presented on the Consolidated Balance Sheets as shown below:

December 31, (in millions) | 2020 |  | 2019
Risk Management Assets - Current(1) |  |  |
Interest rate risk programs | $ | — |  |  | $ | — |
Commodity price risk programs | 10.4 |  |  | 0.6 |
Total | $ | 10.4 |  |  | $ | 0.6 |
Risk Management Assets - Noncurrent(2) |  |  |
Interest rate risk programs | $ | — |  |  | $ | — |
Commodity price risk programs | 2.8 |  |  | 3.8 |
Total | $ | 2.8 |  |  | $ | 3.8 |
Risk Management Liabilities - Current |  |  |
Interest rate risk programs | $ | 70.9 |  |  | $ | — |
Commodity price risk programs | 7.3 |  |  | 12.6 |
Total | $ | 78.2 |  |  | $ | 12.6 |
Risk Management Liabilities - Noncurrent |  |  |
Interest rate risk programs | $ | 99.5 |  |  | $ | 76.2 |
Commodity price risk programs | 45.1 |  |  | 57.8 |
Total | $ | 144.6 |  |  | $ | 134.0 |

(1)Presented in "Prepayments and other" on the Consolidated Balance Sheets.
(2)Presented in "Deferred charges and other" on the Consolidated Balance Sheets.
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Notes to Consolidated Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
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.
NIPSCO 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 10 years and is limited to 20% of NIPSCO’s average annual GCA purchase volume. Gains and losses on these derivative contracts are deferred as regulatory liabilities or assets and are remitted to or collected from customers through NIPSCO’s quarterly GCA mechanism. These instruments are not designated as accounting hedges.
Interest Rate Risk Management
As of December 31, 2020, 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 forecasted debt issuances, which are expected to take place by the end of 2024. These interest rate swaps are designated as cash flow hedges. The gains and losses related to these swaps are recorded to AOCI and will be recognized in "Interest expense, net" concurrently with the recognition of interest expense on the associated debt, once issued. 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" in the Statements of Consolidated Income (Loss) as it became probable the forecasted borrowing transactions would no longer occur.
There were no amounts excluded from effectiveness testing for derivatives in cash flow hedging relationships at December 31, 2020, 2019 and 2018.
Our derivative instruments measured at fair value as of December 31, 2020 and 2019 do not contain any credit-risk-related contingent features.
11. Income Taxes
Income Tax Expense. The components of income tax expense (benefit) were as follows:

Year Ended December 31, (in millions) | 2020 |  | 2019 |  | 2018
Income Taxes |  |  |  |  |
Current |  |  |  |  |
Federal | $ | 0.2 |  |  | $ | — |  |  | $ | — |
State | 11.7 |  |  | 5.2 |  |  | 8.2 |
Total Current | 11.9 |  |  | 5.2 |  |  | 8.2 |
Deferred |  |  |  |  |
Federal | (0.4) |  |  | 110.7 |  |  | (209.4) |
State | (27.4) |  |  | 9.0 |  |  | 22.2 |
Total Deferred | (27.8) |  |  | 119.7 |  |  | (187.2) |
Deferred Investment Credits | (1.2) |  |  | (1.4) |  |  | (1.0) |
Income Taxes | $ | (17.1) |  |  | $ | 123.5 |  |  | $ | (180.0) |

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Notes to Consolidated Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
Statutory Rate Reconciliation. The following table represents a reconciliation of income tax expense at the statutory federal income tax rate to the actual income tax expense from continuing operations:

Year Ended December 31, (in millions) | 2020 |  | 2019 |  | 2018
Book income (loss) before income taxes | $ | (31.3) |  |  |  |  | $ | 506.6 |  |  |  |  | $ | (230.6) |  |  |
Tax expense (benefit) at statutory federal income tax rate | (6.6) |  |  | 21.0 | % |  | 106.5 |  |  | 21.0 | % |  | (48.4) |  |  | 21.0 | %
Increases (reductions) in taxes resulting from: |  |  |  |  |  |  |  |  |  |  |
State income taxes, net of federal income tax benefit | (11.7) |  |  | 37.4 |  |  | 10.1 |  |  | 2.0 |  |  | 24.7 |  |  | (10.7) |
Amortization of regulatory liabilities | (38.4) |  |  | 122.7 |  |  | (29.4) |  |  | (5.8) |  |  | (29.3) |  |  | 12.7 |
Goodwill impairment | — |  |  | — |  |  | 43.0 |  |  | 8.5 |  |  | — |  |  | — |
Fines and penalties | 11.8 |  |  | (37.7) |  |  | 11.5 |  |  | 2.3 |  |  | 0.2 |  |  | (0.1) |
Charitable contribution carryover | — |  |  | — |  |  | (2.5) |  |  | (0.5) |  |  | — |  |  | — |
State regulatory proceedings | — |  |  | — |  |  | (9.5) |  |  | (1.9) |  |  | (127.8) |  |  | 55.4 |
Employee stock ownership plan dividends and other compensation | (1.3) |  |  | 4.2 |  |  | (2.0) |  |  | (0.4) |  |  | (2.2) |  |  | 1.0 |
Deferred taxes on TCJA regulatory liability divested | 23.3 |  |  | (74.5) |  |  | — |  |  | — |  |  | — |  |  | — |
Tax accrual adjustments | 8.9 |  |  | (28.4) |  |  | — |  |  | — |  |  | — |  |  | — |
Federal tax credits | (2.5) |  |  | 8.0 |  |  | — |  |  | — |  |  | — |  |  | — |
Other adjustments | (0.6) |  |  | 1.9 |  |  | (4.2) |  |  | (0.8) |  |  | 2.8 |  |  | (1.2) |
Income Taxes | $ | (17.1) |  |  | 54.6 | % |  | $ | 123.5 |  |  | 24.4 | % |  | $ | (180.0) |  |  | 78.1 | %

The effective income tax rates were 54.6%, 24.4% and 78.1% in 2020, 2019 and 2018, respectively. The difference in tax expense year-over-year has a relative impact on the effective tax rate proportional to pretax income or loss. The 30.2% increase in effective tax rate in 2020 versus 2019 was primarily the result of lower pre-tax income, state jurisdictional mix of pre-tax loss in 2020 tax effected at statutory tax rates and increased amortization of excess deferred federal income taxes in 2020 compared to 2019. These items were offset by increased deferred tax expense recognized on the sale of Columbia of Massachusetts' regulatory liability, established due to TCJA in 2017, that would have otherwise been recognized over the amortization period, non-deductible penalties as described in Note 1, "Company Structure and Principles of Consolidation" and non-cash impairment of goodwill related to Columbia of Massachusetts in 2019 (see Note 7, "Goodwill and Other Intangible Assets" for additional information), and one-time tax accrual adjustments.
The 53.7% decrease in effective tax rate in 2019 versus 2018 was primarily the result of not having significant income tax decreases resulting from state regulatory proceedings as in 2018. Additionally, there was an increase in the effective tax rate related to the non-cash impairment of goodwill in 2019 related to Columbia of Massachusetts (see Note 7, "Goodwill and Other Intangible Assets" for additional information) and non-deductible fines and penalties related to the Greater Lawrence Incident (see Note 20, "Legal Proceedings" for additional information). The rate is also impacted by the relative impact of permanent differences on higher pre-tax income.
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Notes to Consolidated Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
Net Deferred Income Tax Liability Components. Deferred income taxes result from temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities. The principal components of our net deferred tax liability were as follows:

At December 31, (in millions) | 2020 |  | 2019
Deferred tax liabilities |  |  |
Accelerated depreciation and other property differences | $ | 2,339.3 |  |  | $ | 2,516.9 |
Other regulatory assets | 331.8 |  |  | 381.5 |
Total Deferred Tax Liabilities | 2,671.1 |  |  | 2,898.4 |
Deferred tax assets |  |  |
Other regulatory liabilities and deferred investment tax credits (including TCJA) | 287.8 |  |  | 336.1 |
Pension and other postretirement/postemployment benefits | 118.1 |  |  | 152.1 |
Net operating loss carryforward and AMT credit carryforward | 602.1 |  |  | 765.9 |
Environmental liabilities | 22.6 |  |  | 25.4 |
Other accrued liabilities | 41.5 |  |  | 35.3 |
Other, net | 128.4 |  |  | 98.3 |
Total Deferred Tax Assets | 1,200.5 |  |  | 1,413.1 |
Net Deferred Tax Liabilities | $ | 1,470.6 |  |  | $ | 1,485.3 |

At December 31, 2020, we have federal net operating loss carryforwards of $520.8 million. The federal net operating loss carryforwards are available to offset taxable income and will begin to expire in 2037. In addition, we have $7.8 million in charitable contribution carryforwards to offset future taxable income, which begin to expire in 2023. We believe it is more likely than not that we will realize the benefit from the federal net operating loss carryforwards.
We also have $81.4 million (net) of state net operating loss carryforwards. Depending on the jurisdiction in which the state net operating loss was generated, the carryforwards will begin to expire in 2028.
We believe it is more likely than not that a portion of the benefit from certain state NOL carryforwards will not be realized. In recognition of this risk, we have provided a valuation allowance of $6.4 million (net) on the deferred tax assets related to sale of Massachusetts Business assets (see Note 1, "Company Structure and Principles of Consolidation" for additional information) reflected in the state net operating loss carryforward presented above.
Unrecognized Tax Benefits. A reconciliation of the beginning and ending amounts of unrecognized tax benefits is as follows:

Reconciliation of Unrecognized Tax Benefits (in millions) | 2020 |  | 2019 |  | 2018
Unrecognized Tax Benefits - Opening Balance | $ | 23.2 |  |  | $ | 1.2 |  |  | $ | 1.4 |
Gross decreases - tax positions in prior period | (1.5) |  |  | (0.6) |  |  | (0.4) |
Gross increases - current period tax positions | — |  |  | 22.6 |  |  | 0.2 |
Unrecognized Tax Benefits - Ending Balance | $ | 21.7 |  |  | $ | 23.2 |  |  | $ | 1.2 |
Offset for net operating loss carryforwards | (21.7) |  |  | (22.6) |  |  | — |
Balance - Less Net Operating Loss Carryforwards | $ | — |  |  | $ | 0.6 |  |  | $ | 1.2 |

In 2020, we resolved prior unrecognized tax benefits of $1.5 million.
We present accrued interest on unrecognized tax benefits, accrued interest on other income tax liabilities and tax penalties in "Income Taxes" on our Statements of Consolidated Income (Loss). Interest expense recorded on unrecognized tax benefits and other income tax liabilities was immaterial for all periods presented. There were no accruals for penalties recorded in the Statements of Consolidated Income (Loss) for the years ended December 31, 2020, 2019 and 2018, and there were no balances for accrued penalties recorded on the Consolidated Balance Sheets as of December 31, 2020 and 2019.
We are subject to income taxation in the United States and various state jurisdictions, primarily Indiana, Pennsylvania, Kentucky, Massachusetts, Maryland and Virginia.
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Notes to Consolidated Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
We participate in the IRS CAP, which provides the opportunity to resolve tax matters with the IRS before filing each year's consolidated federal income tax return. As of December 31, 2020, tax years through 2019 have been audited and are effectively closed to further assessment. The audit of tax year 2020 under the CAP program is expected to be completed in 2021.
The statute of limitations in each of the state jurisdictions in which we operate remains open until the years are settled for federal income tax purposes, at which time amended state income tax returns reflecting all federal income tax adjustments are filed. As of December 31, 2020, there were no state income tax audits in progress that would have a material impact on the consolidated financial statements.
12. Pension and Other Postretirement Benefits
We provide defined contribution plans and noncontributory defined benefit retirement plans that cover certain of our employees. Benefits under the defined benefit retirement plans reflect the employees’ compensation, years of service and age at retirement. Additionally, we provide health care and life insurance benefits for certain retired employees. The majority of employees may become eligible for these benefits if they reach retirement age while working for us. The expected cost of such benefits is accrued during the employees’ years of service. Current rates of rate-regulated companies include postretirement benefit costs, including amortization of the regulatory assets that arose prior to inclusion of these costs in rates. For most plans, cash contributions are remitted to grantor trusts.
Our Pension and Other Postretirement Benefit Plans’ Asset Management. The Board has delegated oversight of the pension and other postretirement benefit plans’ assets to an Administrative & Investment Management Committee (“the Committee”). The Committee has adopted investment policy statements for the pension and other postretirement benefit plans’ assets. For the pension plans, we employ a liability-driven investing strategy. A total return approach is utilized for the other postretirement benefit plans’ assets. A mix of diversified investments are used to maximize the long-term return of plan assets and hedge the liabilities at a prudent level of risk. The investment portfolio includes U.S. and non-U.S. equities, real estate, long-term and intermediate-term fixed income and alternative investments. Risk tolerance is established through careful consideration of plan liabilities, funded status, and asset class volatility. Investment risk is measured and monitored on an ongoing basis through quarterly investment portfolio reviews, annual liability measurements, and periodic asset/liability studies.
In determining the expected long-term rate of return on plan assets, historical markets are studied, relationships between equities and fixed income are analyzed and current market factors, such as inflation and interest rates are evaluated with consideration of diversification and rebalancing. Our expected long-term rate of return on assets is based on assumptions regarding target asset allocations and corresponding long-term capital market assumptions for each asset class. The pension plans’ investment policy calls for a gradual reduction in the allocation of return-seeking assets (equities, real estate and private equity) and a corresponding increase in the allocation of liability-hedging assets (fixed income) as the funded status of the plans’ increase.
As of December 31, 2020, the asset mix and acceptable minimum and maximum ranges established by the policy for the pension and other postretirement benefit plans are as follows:
Asset Mix Policy of Funds:

| Defined Benefit Pension Plan |  | Postretirement Benefit Plan
Asset Category | Minimum |  | Maximum |  | Minimum |  | Maximum
Domestic Equities | 12% |  | 32% |  | 0% |  | 55%
International Equities | 6% |  | 16% |  | 0% |  | 25%
Fixed Income | 59% |  | 71% |  | 20% |  | 100%
Real Estate | 0% |  | 7% |  | 0% |  | 0%
Private Equity | 0% |  | 5% |  | 0% |  | 0%
Short-Term Investments | 0% |  | 10% |  | 0% |  | 10%

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Notes to Consolidated Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
As of December 31, 2019, the asset mix and acceptable minimum and maximum ranges established by the policy for the pension and other postretirement benefit plans were as follows:
Asset Mix Policy of Funds:

| Defined Benefit Pension Plan |  | Postretirement Benefit Plan
Asset Category | Minimum |  | Maximum |  | Minimum |  | Maximum
Domestic Equities | 12% |  | 32% |  | 0% |  | 55%
International Equities | 6% |  | 16% |  | 0% |  | 25%
Fixed Income | 59% |  | 71% |  | 20% |  | 100%
Real Estate | 0% |  | 7% |  | 0% |  | 0%
Private Equity | 0% |  | 5% |  | 0% |  | 0%
Short-Term Investments | 0% |  | 10% |  | 0% |  | 10%

Pension Plan and Postretirement Plan Asset Mix at December 31, 2020 and December 31, 2019:

| Defined Benefit Pension Assets |  | 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, 2019 |  | Postretirement Benefit Plan Assets |  | December 31, 2019
Asset Class (in millions) | Asset Value |  | % of Total Assets |  | Asset Value |  | % of Total Assets
Domestic Equities | $ | 446.4 |  |  | 21.5 | % |  | $ | 93.8 |  |  | 35.9 | %
International Equities | 205.0 |  |  | 9.9 | % |  | 40.7 |  |  | 15.6 | %
Fixed Income | 1,337.2 |  |  | 64.2 | % |  | 119.5 |  |  | 45.7 | %
Real Estate | 53.9 |  |  | 2.6 | % |  | — |  |  | — |
Cash/Other | 38.4 |  |  | 1.8 | % |  | 7.4 |  |  | 2.8 | %
Total | $ | 2,080.9 |  |  | 100.0 | % |  | $ | 261.4 |  |  | 100.0 | %

The categorization of investments into the asset classes in the tables above are based on definitions established by our Benefits Committee.
Fair Value Measurements. The following table sets forth, by level within the fair value hierarchy, the pension and other postretirement benefits investment assets at fair value as of December 31, 2020 and 2019. Assets are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. There were no investment assets in the pension and other postretirement benefits trusts classified within Level 3 for the years ended December 31, 2020 and 2019.
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Notes to Consolidated Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
Valuation Techniques Used to Determine Fair Value:
Level 1 Measurements
Most common and preferred stocks are traded in active markets on national and international securities exchanges and are valued at closing prices on the last business day of each period presented. Cash is stated at cost which approximates fair value, with the exception of cash held in foreign currencies which fluctuates with changes in the exchange rates. Short-term bills and notes are priced based on quoted market values.
Level 2 Measurements
Most U.S. Government Agency obligations, mortgage/asset-backed securities, and corporate fixed income securities are generally valued by benchmarking model-derived prices to quoted market prices and trade data for identical or comparable securities. To the extent that quoted prices are not available, fair value is determined based on a valuation model that includes inputs such as interest rate yield curves and credit spreads. Securities traded in markets that are not considered active are valued based on quoted market prices, broker or dealer quotations, or alternative pricing sources with reasonable levels of price transparency. Other fixed income includes futures and options which are priced on bid valuation or settlement pricing.
Level 3 Measurements
Investments with unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets and liabilities are classified as level 3 investments.
Not Classified
Commingled funds, private equity limited partnerships and real estate partnerships hold underlying investments that have prices derived from quoted prices in active markets and are not classified within the fair value hierarchy. Instead, these assets are measured at estimated fair value using the net asset value per share of the investments. Commingled funds' underlying assets are principally marketable equity and fixed income securities. Units held in commingled funds are valued at the unit value as reported by the investment managers. Private equity and real estate funds invest in natural resources, commercial real estate and distressed real estate. The fair value of these investments is determined by reference to the funds’ underlying assets.
For the year ended December 31, 2020, there were no significant changes to valuation techniques to determine the fair value of our pension and other postretirement benefits' assets.
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Notes to Consolidated Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
Fair Value Measurements at December 31, 2020:

(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 |  |  | $ | — |

(1)This class includes limited partnerships/fund of funds that invest in a diverse portfolio of private equity strategies, including buy-outs, venture capital, growth capital, special situations and secondary markets, primarily inside the United States.
(2)This class includes limited partnerships/fund of funds that invest in diverse portfolio of private equity strategies, including buy-outs, venture capital, growth capital, special situations and secondary markets, primarily outside the United States.
(3)This class of investments is measured at fair value using the net asset value per share and has not been classified in the fair value hierarchy.
(4)This class represents pending trades with brokers.
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Notes to Consolidated Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
The table below sets forth a summary of unfunded commitments, redemption frequency and redemption notice periods for certain investments that are measured at fair value using the net asset value per share for the year ended December 31, 2020:

(in millions) | Fair Value |  |  |  | Redemption Frequency |  | Redemption Notice Period
Commingled Funds |  |  |  |  |  |  |
Short-term money markets | $ | 86.4 |  |  |  |  | Daily |  | 1 day
U.S. equities | 293.7 |  |  |  |  | Daily |  | 1-5 days
International equities | 200.9 |  |  |  |  | Monthly |  | 10-30 days
Fixed income | 337.6 |  |  |  |  | Daily |  | 3 days
Total | $ | 918.6 |  |  |  |  |  |  |

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Notes to Consolidated Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
Fair Value Measurements at December 31, 2019:

(in millions) | December 31, 2019 |  | 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 | $ | 6.7 |  |  | $ | 6.7 |  |  | $ | — |  |  | $ | — |
Fixed income securities |  |  |  |  |  |  |
Government | 319.6 |  |  | — |  |  | 319.6 |  |  | — |
Corporate | 651.8 |  |  | — |  |  | 651.8 |  |  | — |
Mutual Funds |  |  |  |  |  |  |
U.S. multi-strategy | 140.5 |  |  | 140.5 |  |  | — |  |  | — |
International equities | 56.9 |  |  | 56.9 |  |  | — |  |  | — |
Private equity limited partnerships(3) |  |  |  |  |  |  |
U.S. multi-strategy(1) | 14.0 |  |  | — |  |  | — |  |  | — |
International multi-strategy(2) | 8.5 |  |  | — |  |  | — |  |  | — |
Distressed opportunities | 0.5 |  |  | — |  |  | — |  |  | — |
Real Estate | 53.9 |  |  | — |  |  | — |  |  | — |
Commingled funds(3) |  |  |  |  |  |  |
Short-term money markets | 14.8 |  |  | — |  |  | — |  |  | — |
U.S. equities | 305.9 |  |  | — |  |  | — |  |  | — |
International equities | 148.1 |  |  | — |  |  | — |  |  | — |
Fixed income | 351.8 |  |  | — |  |  | — |  |  | — |
Pension plan assets subtotal | 2,073.0 |  |  | 204.1 |  |  | 971.4 |  |  | — |
Other postretirement benefit plan assets: |  |  |  |  |  |  |
Mutual funds |  |  |  |  |  |  |
U.S. multi-strategy | 81.7 |  |  | 81.7 |  |  | — |  |  | — |
International equities | 20.6 |  |  | 20.6 |  |  | — |  |  | — |
Fixed income | 119.2 |  |  | 119.2 |  |  | — |  |  | — |
Commingled funds(3) |  |  |  |  |  |  |
Short-term money markets | 7.7 |  |  | — |  |  | — |  |  | — |
U.S. equities | 12.1 |  |  | — |  |  | — |  |  | — |
International equities | 20.1 |  |  | — |  |  | — |  |  | — |
Other postretirement benefit plan assets subtotal | 261.4 |  |  | 221.5 |  |  | — |  |  | — |
Due to brokers, net(4) | (2.8) |  |  | — |  |  | (2.8) |  |  | — |
Accrued income/dividends | 10.7 |  |  | 10.7 |  |  | — |  |  | — |
Total pension and other postretirement benefit plan assets | $ | 2,342.3 |  |  | $ | 436.3 |  |  | $ | 968.6 |  |  | $ | — |

(1)This class includes limited partnerships/fund of funds that invest in a diverse portfolio of private equity strategies, including buy-outs, venture capital, growth capital, special situations and secondary markets, primarily inside the United States.
(2)This class includes limited partnerships/fund of funds that invest in diverse portfolio of private equity strategies, including buy-outs, venture capital, growth capital, special situations and secondary markets, primarily outside the United States.
(3)This class of investments is measured at fair value using the net asset value per share and has not been classified in the fair value hierarchy.
(4)This class represents pending trades with brokers.
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Notes to Consolidated Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
The table below sets forth a summary of changes in the fair value of the Plan’s Level 3 assets for the year ended December 31, 2019:

| Balance at January 1, 2019 |  |  |  |  |  |  |  | Transfers out (Level 3)(1) |  | Balance at December 31, 2019
Private equity limited partnerships |  |  |  |  |  |  |  |  |  |  |
U.S. multi-strategy | 18.5 |  |  |  |  |  |  |  |  | (18.5) |  |  | — |
International multi-strategy | 12.5 |  |  |  |  |  |  |  |  | (12.5) |  |  | — |
Distress opportunities | 2.4 |  |  |  |  |  |  |  |  | (2.4) |  |  | — |
Real estate | 52.7 |  |  |  |  |  |  |  |  | (52.7) |  |  | — |
Total | $ | 86.1 |  |  |  |  |  |  |  |  | $ | (86.1) |  |  | $ | — |

(1)Level 3 assets from 2018 were reclassified in the 2019 presentation and included within the fair value hierarchy table as of December 31, 2019 as "Not Classified" investments for which fair value is measured using net asset value per share, consistent with the definitions described above.
The table below sets forth a summary of unfunded commitments, redemption frequency and redemption notice periods for certain investments that are measured at fair value using the net asset value per share for the year ended December 31, 2019:

(in millions) | Fair Value |  |  |  | Redemption Frequency |  | Redemption Notice Period
Commingled Funds |  |  |  |  |  |  |
Short-term money markets | $ | 22.5 |  |  |  |  | Daily |  | 1 day
U.S. equities | 318.0 |  |  |  |  | Monthly |  | 3 days
International equities | 168.2 |  |  |  |  | Monthly |  | 10-30 days
Fixed income | 351.8 |  |  |  |  | Daily |  | 3 days
Total | $ | 860.5 |  |  |  |  |  |  |

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

| Pension Benefits |  | Other Postretirement Benefits
(in millions) | 2020 |  | 2019 |  | 2020 |  | 2019
Change in projected benefit obligation(1) |  |  |  |  |  |  |
Benefit obligation at beginning of year | $ | 2,130.5 |  |  | $ | 1,981.3 |  |  | $ | 576.5 |  |  | $ | 492.5 |
Service cost | 32.0 |  |  | 29.2 |  |  | 6.6 |  |  | 5.1 |
Interest cost | 51.6 |  |  | 72.3 |  |  | 15.4 |  |  | 19.2 |
Plan participants’ contributions | — |  |  | — |  |  | 4.1 |  |  | 4.8 |
Plan amendments | — |  |  | — |  |  | — |  |  | 5.1 |
Actuarial loss(2) | 140.1 |  |  | 204.3 |  |  | 24.8 |  |  | 88.8 |
Benefits paid | (174.5) |  |  | (156.6) |  |  | (37.0) |  |  | (39.5) |
Estimated benefits paid by incurred subsidy | — |  |  | — |  |  | 0.4 |  |  | 0.5 |
Spinoff to Eversource | (121.3) |  |  | — |  |  | — |  |  | — |
Projected benefit obligation at end of year | $ | 2,058.4 |  |  | $ | 2,130.5 |  |  | $ | 590.8 |  |  | $ | 576.5 |
Change in plan assets |  |  |  |  |  |  |
Fair value of plan assets at beginning of year | $ | 2,080.9 |  |  | $ | 1,867.7 |  |  | $ | 261.4 |  |  | $ | 216.3 |
Actual return on plan assets | 329.9 |  |  | 366.8 |  |  | 36.3 |  |  | 56.9 |
Employer contributions | 2.9 |  |  | 2.9 |  |  | 21.6 |  |  | 23.0 |
Plan participants’ contributions | — |  |  | — |  |  | 4.1 |  |  | 4.7 |
Benefits paid | (174.6) |  |  | (156.5) |  |  | (37.0) |  |  | (39.5) |
Spinoff to Eversource | (121.4) |  |  | — |  |  | — |  |  | — |
Fair value of plan assets at end of year | $ | 2,117.7 |  |  | $ | 2,080.9 |  |  | $ | 286.4 |  |  | $ | 261.4 |
Funded Status at end of year | $ | 59.3 |  |  | $ | (49.6) |  |  | $ | (304.4) |  |  | $ | (315.1) |
Amounts recognized in the statement of financial position consist of: |  |  |  |  |  |  |
Noncurrent assets | 91.4 |  |  | 8.2 |  |  | — |  |  | — |
Current liabilities | (2.9) |  |  | (3.0) |  |  | (0.9) |  |  | (0.8) |
Noncurrent liabilities | (29.2) |  |  | (54.8) |  |  | (303.5) |  |  | (314.3) |
Net amount recognized at end of year(3) | $ | 59.3 |  |  | $ | (49.6) |  |  | $ | (304.4) |  |  | $ | (315.1) |
Amounts recognized in accumulated other comprehensive income or regulatory asset/liability(4) |  |  |  |  |  |  |
Unrecognized prior service credit | $ | 0.3 |  |  | $ | 3.0 |  |  | $ | (10.1) |  |  | $ | (10.7) |
Unrecognized actuarial loss | 497.2 |  |  | 652.8 |  |  | 116.4 |  |  | 118.4 |
Net amount recognized at end of year | $ | 497.5 |  |  | $ | 655.8 |  |  | $ | 106.3 |  |  | $ | 107.7 |

(1)The change in benefit obligation for Pension Benefits represents the change in Projected Benefit Obligation while the change in benefit obligation for Other Postretirement Benefits represents the change in accumulated postretirement benefit obligation.
(2)The pension actuarial loss was primarily driven by the decrease in the discount rate, offset by the change in mortality assumptions. The other postretirement benefits loss was also primarily driven by a decrease in discount rates, offset by favorable claims experienced and a change in the mortality assumptions.
(3)We recognize our Consolidated Balance Sheets underfunded and overfunded status of our various defined benefit postretirement plans, measured as the difference between the fair value of the plan assets and the benefit obligation.
(3)We determined that for certain rate-regulated subsidiaries the future recovery of pension and other postretirement benefits costs is probable. These rate-regulated subsidiaries recorded regulatory assets and liabilities of $583.3 million and zero, respectively, as of December 31, 2020, and $739.1 million and $0.1 million, respectively, as of December 31, 2019 that would otherwise have been recorded to accumulated other comprehensive loss.
Our accumulated benefit obligation for our pension plans was $2,036.8 million and $2,111.5 million as of December 31, 2020 and 2019, respectively. The accumulated benefit obligation at each date is the actuarial present value of benefits attributed by the pension benefit formula to employee service rendered prior to that date and based on current and past compensation levels. The accumulated benefit obligation differs from the projected benefit obligation disclosed in the table above in that it includes no assumptions about future compensation levels.
We are required to reflect the funded status of our pension and postretirement benefit plans on the Consolidated Balance Sheet. The funded status of the plans is measured as the difference between the plan assets' fair value and the projected benefit
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obligation. We present the noncurrent aggregate of all underfunded plans within "Accrued liability for postretirement and postemployment benefits." The portion of the amount by which the actuarial present value of benefits included in the projected benefit obligation exceeds the fair value of plan assets, payable in the next 12 months, is reflected in "Accrued compensation and other benefits." We present the aggregate of all overfunded plans within "Deferred charges and other."
Information for pension plans with a projected benefit obligation in excess of plan assets:

| December 31,
| 2020(1) |  | 2019
Accumulated Benefit Obligation | $ | 32.1 |  |  | $ | 1,473.9 |
Funded Status |  |  |
Projected Benefit Obligation | 32.1 |  |  | 1,492.9 |
Fair Value of Plan Assets | — |  |  | 1,435.1 |
Funded Status of Underfunded Pension Plans at End of Year | $ | (32.1) |  |  | $ | (57.8) |

(1)As of December 31, 2020, only our nonqualified plans were underfunded. These plans have no assets as they are not funded until benefits are paid.
Information for pension plans with plan assets in excess of the projected benefit obligation:

| December 31,
| 2020 |  | 2019
Accumulated Benefit Obligation | $ | 2,004.7 |  |  | $ | 637.6 |
Funded Status |  |  |
Projected Benefit Obligation | 2,026.3 |  |  | 637.6 |
Fair Value of Plan Assets | 2,117.7 |  |  | 645.8 |
Funded Status of Overfunded Pension Plans at End of Year | $ | 91.4 |  |  | $ | 8.2 |

Our pension plans were overfunded, in aggregate, by $59.3 million at December 31, 2020 compared to being underfunded by $49.6 million at December 31, 2019. The improvement in the funded status was due primarily to favorable asset returns offset by a decrease in discount rates. We contributed $2.9 million to our pension plans in both 2020 and 2019.
Our other postretirement benefit plans were underfunded by $304.4 million at December 31, 2020 compared to being underfunded by $315.1 million at December 31, 2019. The change in funded status was primarily due to favorable asset returns offset by a decrease in discount rates. We contributed $21.6 million and $23.0 million to our other postretirement benefit plans in 2020 and 2019, respectively.
In 2020 and 2019, some of our qualified pension plans paid lump sum payouts in excess of the respective plan's service cost plus interest cost, thereby meeting the requirement for settlement accounting. We recorded settlement charges of $10.5 million and $9.5 million in 2020 and 2019, respectively. Net periodic pension benefit cost for 2020 was decreased by $1.4 million as a result of the interim remeasurement.
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
The following table provides the key assumptions that were used to calculate the pension and other postretirement benefits obligations for our various plans as of December 31:

| Pension Benefits |  | Other Postretirement Benefits
| 2020 |  | 2019 |  | 2020 |  | 2019
Weighted-average assumptions to Determine Benefit Obligation |  |  |  |  |  |  |
Discount Rate | 2.38 | % |  | 3.12 | % |  | 2.49 | % |  | 3.21 | %
Rate of Compensation Increases | 4.00 | % |  | 4.00 | % |  | — |  |  | — |
Interest Crediting Rates | 4.00 | % |  | 4.00 | % |  | — |  |  | — |
Health Care Trend Rates |  |  |  |  |  |  |
Trend for Next Year | — |  |  | — |  |  | 6.69 | % |  | 6.68 | %
Ultimate Trend | — |  |  | — |  |  | 4.50 | % |  | 4.50 | %
Year Ultimate Trend Reached | — |  |  | — |  |  | 2029 |  | 2028

We expect to make contributions of approximately $2.9 million to our pension plans and approximately $21.8 million to our postretirement medical and life plans in 2021.
The following table provides benefits expected to be paid in each of the next five fiscal years, and in the aggregate for the five fiscal years thereafter. The expected benefits are estimated based on the same assumptions used to measure our benefit obligation at the end of the year and include benefits attributable to the estimated future service of employees:

(in millions) | Pension Benefits |  | Other Postretirement Benefits |  | Federal Subsidy Receipts
Year(s) |  |  |  |  |
2021 | $ | 218.8 |  |  | $ | 38.4 |  |  | $ | 0.4 |
2022 | 154.5 |  |  | 37.8 |  |  | 0.4 |
2023 | 149.2 |  |  | 37.3 |  |  | 0.4 |
2024 | 145.9 |  |  | 37.0 |  |  | 0.4 |
2025 | 141.3 |  |  | 36.6 |  |  | 0.3 |
2026-2030 | 621.9 |  |  | 172.1 |  |  | 1.2 |

The following table provides the components of the plans’ actuarially determined net periodic benefits cost for each of the three years ended December 31, 2020, 2019 and 2018:

| Pension Benefits |  | Other Postretirement Benefits
(in millions) | 2020 |  | 2019 |  | 2018 |  | 2020 |  | 2019 |  | 2018
Components of Net Periodic Benefit Cost(1) |  |  |  |  |  |  |  |  |  |  |
Service cost | $ | 32.0 |  |  | $ | 29.2 |  |  | $ | 31.3 |  |  | $ | 6.6 |  |  | $ | 5.1 |  |  | $ | 5.0 |
Interest cost | 51.6 |  |  | 72.3 |  |  | 67.1 |  |  | 15.4 |  |  | 19.2 |  |  | 17.6 |
Expected return on assets | (111.6) |  |  | (108.8) |  |  | (142.3) |  |  | (14.4) |  |  | (13.1) |  |  | (14.9) |
Amortization of prior service cost (credit) | 0.7 |  |  | 0.2 |  |  | (0.4) |  |  | (2.1) |  |  | (3.2) |  |  | (4.0) |
Recognized actuarial loss | 33.8 |  |  | 45.2 |  |  | 40.6 |  |  | 4.9 |  |  | 2.0 |  |  | 3.8 |
Settlement/curtailment loss | 10.5 |  |  | 9.5 |  |  | 18.5 |  |  | 1.5 |  |  | — |  |  | — |
Total Net Periodic Benefits Cost | $ | 17.0 |  |  | $ | 47.6 |  |  | $ | 14.8 |  |  | $ | 11.9 |  |  | $ | 10.0 |  |  | $ | 7.5 |

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

| Pension Benefits |  | Other Postretirement Benefits
| 2020 |  | 2019 |  | 2018 |  | 2020 |  | 2019 |  | 2018
Weighted-average Assumptions to Determine Net Periodic Benefit Cost |  |  |  |  |  |  |  |  |  |  |
Discount rate - service cost | 3.39 | % |  | 4.48 | % |  | 3.79 | % |  | 3.52 | % |  | 4.59 | % |  | 3.89 | %
Discount rate - interest cost | 2.65 | % |  | 3.84 | % |  | 3.15 | % |  | 2.76 | % |  | 3.94 | % |  | 3.27 | %
Expected Long-Term Rate of Return on Plan Assets | 5.70 | % |  | 6.10 | % |  | 7.00 | % |  | 5.67 | % |  | 5.83 | % |  | 5.80 | %
Rate of Compensation Increases | 4.00 | % |  | 4.00 | % |  | 4.00 | % |  | — |  |  | — |  |  | — |
Interest Crediting Rates | 4.00 | % |  | 4.00 | % |  | 4.00 | % |  | — |  |  | — |  |  | — |

We assumed a 5.70% and 5.67% rate of return on pension and other postretirement plan assets, respectively, for our calculation of 2020 pension benefits cost. These rates were primarily based on asset mix and historical rates of return and were adjusted in 2020 due to anticipated changes in asset allocation and projected market returns.
The following table provides other changes in plan assets and projected benefit obligations recognized in other comprehensive income or regulatory asset or liability:

| Pension Benefits |  | Other Postretirement Benefits
(in millions) | 2020 |  | 2019 |  | 2020 |  | 2019
Other Changes in Plan Assets and Projected Benefit Obligations Recognized in Other Comprehensive Income or Regulatory Asset or Liability |  |  |  |  |  |  |
Net prior service cost | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | 5.1 |
Net actuarial loss (gain) | (78.2) |  |  | (53.8) |  |  | 2.9 |  |  | 45.1 |
Settlements/curtailments | (10.5) |  |  | (9.5) |  |  | (1.5) |  |  | — |
Less: amortization of prior service cost | (0.7) |  |  | (0.2) |  |  | 2.1 |  |  | 3.2 |
Less: amortization of net actuarial loss | (33.8) |  |  | (45.2) |  |  | (4.9) |  |  | (2.0) |
Less: gain attributable to spinoff to Eversource | (33.1) |  |  | — |  |  | — |  |  | — |
Less: prior service cost attributable to spinoff to Eversource | (2.0) |  |  | — |  |  | — |  |  | — |
Total Recognized in Other Comprehensive Income or Regulatory Asset or Liability | $ | (158.3) |  |  | $ | (108.7) |  |  | $ | (1.4) |  |  | $ | 51.4 |
Amount Recognized in Net Periodic Benefits Cost and Other Comprehensive Income or Regulatory Asset or Liability | $ | (141.3) |  |  | $ | (61.1) |  |  | $ | 10.5 |  |  | $ | 61.4 |

13. Equity
Holders of shares of our common stock are entitled to receive dividends when, as and if declared by the Board out of funds legally available. The policy of the Board has been to declare cash dividends on a quarterly basis payable on or about the 20th day of February, May, August and November. We have certain debt covenants which could potentially limit the amount of dividends the Company could pay in order to maintain compliance with these covenants. Refer to Note 15, "Long-Term Debt," for more information. As of December 31, 2020, these covenants did not restrict the amount of dividends that were available to be paid.
Dividends paid to preferred shareholders vary based on the series of preferred stock owned. Additional information is provided below. Holders of our shares of common stock are subject to the prior dividend rights of holders of our preferred stock or the
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depositary shares representing such preferred stock outstanding, and if full dividends have not been declared and paid on all outstanding shares of preferred stock in any dividend period, no dividend may be declared or paid or set aside for payment on our common stock.
Common and preferred stock activity for 2020, 2019 and 2018 is described further below.
ATM Program and Forward Sale Agreements. On May 3, 2017, we entered into four separate equity distribution agreements, pursuant to which we were able to sell up to an aggregate of $500.0 million of our common stock.
On November 13, 2017, under the ATM program, we executed a forward agreement, which allowed us to issue a fixed number of shares at a price to be settled in the future. On November 6, 2018, the forward agreement was settled for $26.43 per share, resulting in $167.7 million of net proceeds. The equity distribution agreements entered into on May 3, 2017 expired December 31, 2018.
On November 1, 2018, we entered into five separate equity distribution agreements pursuant to which we were able to sell up to an aggregate of $500.0 million of our common stock. Four of these agreements were then amended on August 1, 2019 and one was terminated, pursuant to which we may sell, from time to time, up to an aggregate of $434.4 million of our common stock.
On December 6, 2018, under the ATM program, we executed a forward agreement, which allowed us to issue a fixed number of shares at a price to be settled in the future. From December 6, 2018 to December 10, 2018, 4,708,098 shares were borrowed from third parties and sold by the dealer at a weighted average price of $26.55 per share. On November 21, 2019, the forward agreement was settled for $26.01 per share, resulting in $122.5 million of net proceeds.
On August 12, 2019, under the ATM program, we executed a forward agreement, which allowed us to issue a fixed number of shares at a price to be settled in the future. From August 12, 2019 to September 13, 2019, 3,714,400 shares were borrowed from third parties and sold by the dealer at a weighted average price of $29.26 per share. On December 11, 2019, the forward agreement was settled for $28.83 per share, resulting in $107.1 million of net proceeds.
On August 6, 2020, under the ATM program, we executed a forward agreement, which allowed us to issue a fixed number of shares at a price to be settled in the future. From August 7, 2020 to September 3, 2020, 2,809,029 shares were borrowed from third parties and sold by the dealer at a weighted average price of $23.25 per share. On December 15, 2020, the forward agreement was settled for $22.77 per share, resulting in $64.0 million of net proceeds.
On September 4, 2020, under the ATM program, we executed a separate forward agreement, which allowed us to issue a fixed number of shares at a price to be settled in the future. From September 4, 2020 to September 16, 2020, 1,452,102 shares were borrowed from third parties and sold by the dealer at a weighted average price of $22.28 per share. On December 15, 2020, the forward agreement was settled for $21.82 per share, resulting in $31.7 million of net proceeds.
The equity distribution agreements entered into on November 1, 2018 and amended on August 1, 2019 expired December 31, 2020.
The following table summarizes our activity under the ATM program:

Year Ending December 31, | 2020 |  | 2019 |  | 2018
Number of shares issued | 8,459,430 |  |  | 8,422,498 |  |  | 8,883,014 |
Average price per share | $ | 23.60 |  |  | $ | 27.75 |  |  | $ | 26.85 |
Proceeds, net of fees (in millions) | $ | 196.5 |  |  | $ | 229.1 |  |  | $ | 232.5 |

Private Placement of Common Stock. On May 4, 2018, we completed the sale of 24,964,163 shares of $0.01 par value common stock at a price of $24.28 per share in a private placement to selected institutional and accredited investors. The private placement resulted in $606.0 million of gross proceeds or $599.6 million of net proceeds, after deducting commissions and sale expenses. The common stock issued in connection with the private placement was registered on Form S-1, filed with the SEC on May 11, 2018.
Preferred Stock. On June 11, 2018, we completed the sale of 400,000 shares of 5.650% Series A Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Stock (the "Series A Preferred Stock") at a price of $1,000 per share. The transaction resulted in $400.0 million of gross proceeds or $393.9 million of net proceeds, after deducting commissions and sale expenses. The Series A Preferred Stock was issued in a private placement pursuant to SEC Rule 144A. On December 13, 2018, we filed a
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registration statement with the SEC enabling holders to exchange their unregistered shares of Series A Preferred Stock for publicly registered shares with substantially identical terms.
Dividends on the Series A Preferred Stock accrue and are cumulative from the date the shares of Series A Preferred Stock were originally issued to, but not including, June 15, 2023 at a rate of 5.650% per annum of the $1,000 liquidation preference per share. On and after June 15, 2023, dividends on the Series A Preferred Stock will accumulate for each five year period at a percentage of the $1,000 liquidation preference equal to the five-year U.S. Treasury Rate plus (i) in respect of each five year period commencing on or after June 15, 2023 but before June 15, 2043, a spread of 2.843% (the “Initial Margin”), and (ii) in respect of each five year period commencing on or after June 15, 2043, the Initial Margin plus 1.000%. The Series A Preferred Stock may be redeemed by us at our option on June 15, 2023, or on each date falling on the fifth anniversary thereafter, or in connection with a ratings event (as defined in the Certificate of Designation of the Series A Preferred Stock).
As of December 31, 2020 and 2019, Series A Preferred Stock had $1.0 million of cumulative preferred dividends in arrears, or $2.51 per share.
Holders of Series A Preferred Stock generally have no voting rights, except for limited voting rights with respect to (i) potential amendments to our certificate of incorporation that would have a material adverse effect on the existing preferences, rights, powers or duties of the Series A Preferred Stock, (ii) the creation or issuance of any security ranking on a parity with the Series A Preferred Stock if the cumulative dividends payable on then outstanding Series A Preferred Stock are in arrears, or (iii) the creation or issuance of any security ranking senior to the Series A Preferred Stock. The Series A Preferred Stock does not have a stated maturity and is not subject to mandatory redemption or any sinking fund. The Series A Preferred Stock will remain outstanding indefinitely unless repurchased or redeemed by us. Any such redemption would be effected only out of funds legally available for such purposes and will be subject to compliance with the provisions of our outstanding indebtedness.
On December 5, 2018, we completed the sale of 20,000,000 depositary shares with an aggregate liquidation preference of $500,000,000 under the Company’s registration statement on Form S-3. Each depositary share represents 1/1,000th ownership interest in a share of our 6.500% Series B Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Stock, liquidation preference $25,000 per share (equivalent to $25 per depositary share) (the “Series B Preferred Stock"). The transaction resulted in $500.0 million of gross proceeds or $486.1 million of net proceeds, after deducting commissions and sale expenses.
Dividends on the Series B Preferred Stock accrue and are cumulative from the date the shares of Series B Preferred Stock were originally issued to, but not including, March 15, 2024 at a rate of 6.500% per annum of the $25,000 liquidation preference per share. On and after March 15, 2024, dividends on the Series B Preferred Stock will accumulate for each five year period at a percentage of the $25,000 liquidation preference equal to the five-year U.S. Treasury Rate plus (i) in respect of each five year period commencing on or after March 15, 2024 but before March 15, 2044, a spread of 3.632% (the “Initial Margin”), and (ii) in respect of each five year period commencing on or after March 15, 2044, the Initial Margin plus 1.000%. The Series B Preferred Stock may be redeemed by us at our option on March 15, 2024, or on each date falling on the fifth anniversary thereafter, or in connection with a ratings event (as defined in the Certificate of Designation of the Series B Preferred Stock).
As of December 31, 2020 and 2019, Series B Preferred Stock had $1.4 million of cumulative preferred dividends in arrears, or $72.23 per share.
In addition, we issued 20,000 shares of “Series B-1 Preferred Stock”, par value $0.01 per share, (“Series B-1 Preferred Stock”), as a distribution with respect to the Series B Preferred Stock. As a result, each of the depositary shares issued on December 5, 2018 now represents a 1/1,000th ownership interest in a share of Series B Preferred Stock and a 1/1,000th ownership interest in a share of Series B-1 Preferred Stock. We issued the Series B-1 Preferred Stock to enhance the voting rights of the Series B Preferred Stock to comply with the minimum voting rights policy of the New York Stock Exchange. The Series B-1 Preferred Stock is paired with the Series B Preferred Stock and may not be transferred, redeemed or repurchased except in connection with the simultaneous transfer, redemption or repurchase of a like number of shares of the underlying Series B Preferred Stock.
Holders of Series B Preferred Stock generally have no voting rights, except for limited voting rights with respect to (i) potential amendments to our certificate of incorporation that would have a material adverse effect on the existing preferences, rights, powers or duties of the Series B Preferred Stock, (ii) the creation or issuance of any security ranking on a parity with the Series B Preferred Stock if the cumulative dividends payable on then outstanding Series B Preferred Stock are in arrears, or (iii) the creation or issuance of any security ranking senior to the Series B Preferred Stock. In addition, if and whenever dividends on any shares of Series B Preferred Stock shall not have been declared and paid for at least six dividend periods, whether or not consecutive, the number of directors then constituting our Board of Directors shall automatically be increased by two until all
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accumulated and unpaid dividends on the Series B Preferred Stock shall have been paid in full, and the holders of Series B-1 Preferred Stock, voting as a class together with the holders of any outstanding securities ranking on a parity with the Series B-1 Preferred Stock and having like voting rights that are exercisable at the time and entitled to vote thereon, shall be entitled to elect the two additional directors. The Series B Preferred Stock does not have a stated maturity and is not subject to mandatory redemption or any sinking fund. The Series B Preferred Stock will remain outstanding indefinitely unless repurchased or redeemed by us. Any such redemption would be effected only out of funds legally available for such purposes and will be subject to compliance with the provisions of our outstanding indebtedness.
The following table summarizes preferred stock by outstanding series of shares:

|  |  | Year ended December 31, | December 31, |  | December 31,
|  |  | 2020 | 2019 | 2018 | 2020 |  | 2019
(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 |  | $ | 28.88 |  | $ | 393.9 |  |  | $ | 393.9 |
6.500% Series B | $ | 25,000.00 |  | 20,000 |  | $ | 1,625.00 |  | $ | 1,674.65 |  | $ | — |  | $ | 486.1 |  |  | $ | 486.1 |

Noncontrolling Interest in Consolidated Subsidiaries. In December 2020, NIPSCO and a tax equity partner completed their initial cash contributions into the Rosewater joint venture. 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. The tax equity partner's contributions, net of these allocations, is represented as a noncontrolling interest within total equity on the Consolidated Balance Sheets. Refer to Note 4, "Variable Interest Entities," for more information.
14. Share-Based Compensation
Prior to May 19, 2020 we issued share-based compensation to employees and non-employee directors under the NiSource Inc. 2010 Omnibus Plan ("2010 Omnibus Plan"), which was most recently approved by stockholders at the Annual Meeting of Stockholders held on May 12, 2015. The 2010 Omnibus Plan provided for awards to employees and non-employee directors of incentive and nonqualified stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance units, cash-based awards and other stock-based awards and superseded the Director Stock Incentive Plan (“Director Plan”) with respect to grants made after the effective date of the 2010 Omnibus Plan.
The stockholders approved and adopted the NiSource Inc. 2020 Omnibus Incentive Plan ("2020 Omnibus Plan") at the Annual Meeting of Stockholders held on May 19, 2020. The 2020 Omnibus Plan provides for awards to employees and non-employee directors of incentive and nonqualified stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance units, cash-based awards and other stock-based awards and supersedes the 2010 Omnibus Plan with respect to grants made after the effective date of the 2020 Omnibus Plan.
The 2020 Omnibus Plan provides that the number of shares of common stock of NiSource available for awards is 10,000,000 plus the number of shares subject to outstanding awards that expire or terminate for any reason that were granted under the 2020 Omnibus Plan, the 2010 Omnibus Plan or any other equity plan under which awards were outstanding as of May 19, 2020. At December 31, 2020, there were 10,007,832 shares available for future awards under the 2020 Omnibus Plan.
We recognized stock-based employee compensation expense of $13.5 million, $16.3 million and $15.2 million, during 2020, 2019 and 2018, respectively, as well as related tax benefits of $3.3 million, $4.0 million and $3.7 million, respectively. We recognized related excess tax expense from the distribution of vested share-based employee compensation of $0.4 million in 2020 and excess tax benefits of $0.8 million and $1.0 million in 2019 and 2018, respectively.
As of December 31, 2020, the total remaining unrecognized compensation cost related to non-vested awards amounted to $19.1 million, which will be amortized over the weighted-average remaining requisite service period of 1.9 years.
Restricted Stock Units and Restricted Stock. We granted 235,100, 166,031, and 158,689 restricted stock units and shares of restricted stock to employees, subject to service conditions in 2020, 2019, and 2018, respectively. The total grant date fair value of the restricted stock units and shares of restricted stock during 2020, 2019, and 2018, respectively, was $6.1 million, $4.1 million, and $3.5 million based on the average market price of our common stock at the date of each grant less the present value of any dividends not received during the vesting period, which will be expensed over the vesting period which is generally three
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years. As of December 31, 2020, 223,724, 135,170, and 119,333 non-vested restricted stock units and shares of restricted stock granted in 2020, 2019, and 2018, respectively.
If an employee terminates employment before the service conditions lapse under the 2018, 2019 or 2020 awards due to (1) retirement or disability (as defined in the award agreement), or (2) death, the service conditions will lapse on the date of such termination with respect to a pro rata portion of the restricted stock units and shares of restricted stock based upon the percentage of the service period satisfied between the grant date and the date of the termination of employment. In the event of a change in control (as defined in the award agreement), all unvested shares of restricted stock and restricted stock units awarded will immediately vest upon termination of employment occurring in connection with a change in control. Termination due to any other reason will result in all unvested shares of restricted stock and restricted stock units awarded being forfeited effective on the employee’s date of termination.
A summary of our restricted stock unit award transactions for the year ended December 31, 2020 is as follows:

(shares) | Restricted Stock Units |  | Weighted Average Award Date Fair Value Per Unit ($)
Non-vested at December 31, 2019 | 302,606 |  |  | 23.49 |
Granted | 235,100 |  |  | 25.77 |
Forfeited | (38,220) |  |  | 24.18 |
Vested | (21,259) |  |  | 24.68 |
Non-vested at December 31, 2020 | 478,227 |  |  | 24.51 |

Employee Performance Shares. We granted 528,729 and 552,389 performance shares subject to service, performance and market-based vesting conditions in 2020 and 2019, respectively. We awarded 514,338 performance shares subject to similar service, performance and market conditions in 2018. The performance conditions are based on the achievement of one non-GAAP financial measure, relative total shareholder return and additional operational measures as outlined below.
The financial measure is cumulative net operating earnings per share ("NOEPS"), which we define as income from continuing operations adjusted for certain items. The number of cumulative NOEPS shares determined using this measure shall be increased or decreased based on our relative total shareholder return, a market-based vesting condition, which we define as the annualized growth in dividends and share price of a share of our common stock (calculated using a 20 trading day average of our closing price over the performance period, approximately) compared to the total shareholder return of a predetermined peer group of companies. A relative shareholder return result within the first quartile will result in an increase to the NOEPS shares of 25%, while a relative shareholder return result within the fourth quartile will result in a decrease of 25%. A Monte Carlo analysis was used to value the portion of these awards dependent on the market-based vesting condition. The grant date fair value of the NOEPS shares is based on the average market price of our common stock at the date of each grant less the present value of dividends not received during the vesting period, which will be expensed over the requisite service period of three years. See table below for further details on these awards.
If a threshold level of cumulative NOEPS financial performance is achieved, additional operational measures, which we refer to as the customer value framework and which consists of equally weighted areas of focus, apply. Each area of focus represents an equal portion of the customer value framework shares, and the targets for all areas of focus must be met for the customer value framework shares to vest at 100%. The grant date fair value of the customer value framework shares is based on the average market price of our common stock on the grant date of each award less the present value of dividends not received during the vesting period, which will be expensed over the requisite service period of three years for those customer value framework shares that are granted. See table below for further details on these awards.
For the 2020 awards, the customer value framework consists of four equally weighted areas of focus including safety, customer satisfaction, culture and environmental, each representing 25% of the customer value framework shares. For the 2019 and 2018 awards, the customer value framework consists of five equally weighted areas of focus including financial and all those noted for the 2020 awards, each representing 20% of the customer value framework shares.
For the 2018 awards, individual payout percentages for these shares may range from 0%-200% as determined by the compensation committee in its sole discretion. Due to this discretion, these shares are not considered to be granted under ASC
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
718. The service inception date fair value of the awards is based on the closing market price of our common stock on the service inception date of each award. This value will be reassessed at each reporting period to be based on our closing market price of our common stock at the reporting period date with adjustments to expense recorded as appropriate.
The following table presents details of the performance awards described above.

Award Year | Service Conditions Lapse date | Performance Period | Award Conditions |  | Shares outstanding at 12/31/2020 (shares) | Grant Date Fair Value (in millions)
2020 | 02/28/23 | 01/01/2020- 12/31/2022 | Non-GAAP Financial Measure |  | 392,619 |  | $ | 11.7 |
Operational Measures |  | 90,604 |  | $ | 2.6 |
2019 | 02/28/22 | 01/01/2019- 12/31/2021 | Non-GAAP Financial Measure |  | 384,680 |  | $ | 11.7 |
Operational Measures |  | 88,769 |  | $ | 2.5 |
2018 | 02/26/21 | 01/01/2018- 12/31/2020 | Non-GAAP Financial Measure |  | 347,479 |  | $ | 9.2 |
Operational Measures(1) |  | 80,185 |  | $ | 2.4 |

(1) Grant date fair value amount represents the service inception date fair value of these awards as they are not yet granted.
A summary of our performance award transactions for the year ended December 31, 2020 is as follows:

(shares) | Performance Awards |  | Weighted Average Grant Date Fair Value Per Unit ($)(1)
Non-vested at December 31, 2019 | 1,503,251 |  |  | 22.74 |
Granted | 528,729 |  |  | 27.01 |
Forfeited | (118,716) |  |  | 25.63 |
Vested | (528,928) |  |  | 28.30 |
Non-vested at December 31, 2020 | 1,384,336 |  |  | 25.09 |

(1) 2018 performance shares awarded based on the customer value index are included at reporting date fair value as these awards have not been granted under ASC 718 as discussed above.
Non-employee Director Awards. As of May 19, 2020, awards to non-employee directors may be made only under the 2020 Omnibus Plan. Currently, restricted stock units are granted annually to non-employee directors, subject to a non-employee director’s election to defer receipt of such restricted stock unit award. The non-employee director’s annual award of restricted stock units vest on the first anniversary of the grant date subject to special pro-rata vesting rules in the event of retirement or disability (as defined in the award agreement), or death. The vested restricted stock units are payable as soon as practicable following vesting except as otherwise provided pursuant to the non-employee director’s deferral election. Certain restricted stock units remain outstanding from the 2010 Omnibus Plan and the Director Plan. All such awards are fully vested and shall be distributed to the directors upon their separation from the Board.
As of December 31, 2020, 210,273 restricted stock units are outstanding to non-employee directors under either the 2020 Omnibus Plan, the 2010 Omnibus Plan or the Director Plan. Of this amount, 67,806 restricted stock units are unvested and expected to vest.
401(k) Match, Profit Sharing and Company Contribution. We have a voluntary 401(k) savings plan covering eligible employees that allows for periodic discretionary matches as a percentage of each participant’s contributions payable in cash for nonunion employees and generally payable in shares of NiSource common stock for union employees, subject to collective bargaining. We also have a retirement savings plan that provides for discretionary profit sharing contributions similarly payable in cash or shares of NiSource common stock to eligible employees based on earnings results, and eligible employees hired after
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January 1, 2010 receive a non-elective company contribution of 3% of eligible pay similarly payable in cash or shares of NiSource common stock. For the years ended December 31, 2020, 2019 and 2018, we recognized 401(k) match, profit sharing and non-elective contribution expense of $37.8 million, $37.5 million and $37.6 million, respectively.
15. Long-Term Debt
Our long-term debt as of December 31, 2020 and 2019 is as follows:

Long-term debt type | Maturity as of December 31, 2020 | Weighted average interest rate (%) |  | Outstanding balance as of December 31, (in millions)
| 2020 |  | 2019
Senior notes: |  |  |  |  |  |
NiSource | December 2021 | 4.45 | % |  | — |  |  | 63.6 |
NiSource | November 2022 | 2.65 | % |  | — |  |  | 500.0 |
NiSource | February 2023 | 3.85 | % |  | — |  |  | 250.0 |
NiSource | June 2023 | 3.65 | % |  | — |  |  | 350.0 |
NiSource | August 2025 | 0.95 | % |  | 1,250.0 |  |  | — |
NiSource | November 2025 | 5.89 | % |  | — |  |  | 265.0 |
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 |  |  | — |
NiSource | February 2031 | 1.70 | % |  | 750.0 |  |  | — |
NiSource | December 2040 | 6.25 | % |  | 152.6 |  |  | 250.0 |
NiSource | June 2041 | 5.95 | % |  | 347.4 |  |  | 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 |  |  |  | $ | 9,003.0 |  |  | $ | 7,581.6 |
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(1) | December 2025 to February 2028 | 6.37 | % |  | 15.0 |  |  | 40.0 |
Total medium term notes |  |  |  | $ | 132.0 |  |  | $ | 157.0 |
Finance leases: |  |  |  |  |  |
NiSource Corporate Services | April 2022 to January 2025 | 2.19 | % |  | 49.4 |  |  | 22.3 |
NIPSCO | November 2028 | 1.79 | % |  | 16.0 |  |  | — |
Columbia of Ohio | October 2021 to March 2044 | 6.16 | % |  | 91.2 |  |  | 94.8 |
Columbia of Virginia | July 2029 to November 2039 | 6.30 | % |  | 18.4 |  |  | 19.1 |
Columbia of Kentucky | May 2027 | 3.79 | % |  | 0.3 |  |  | 0.3 |
Columbia of Pennsylvania | August 2027 to May 2035 | 5.65 | % |  | 19.7 |  |  | 20.7 |
Columbia of Massachusetts | N/A | — | % |  | — |  |  | 44.3 |
Total finance leases |  |  |  | 195.0 |  |  | 201.5 |
Unamortized issuance costs and discounts |  |  |  | $ | (86.9) |  |  | $ | (70.5) |
Total Long-Term Debt |  |  |  | $ | 9,243.1 |  |  | $ | 7,869.6 |

(1)Rate increased from 6.30% in 2019 to 6.37% in 2020 in connection with debt redemptions described below.
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Notes to Consolidated Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
Details of our 2020 long-term debt related activity are summarized below:
•On April 13, 2020, we completed the issuance and sale of $1.0 billion of 3.60% senior unsecured notes maturing in 2030, which resulted in approximately $987.8 million of net proceeds after deducting commissions and expenses.
•On August 18, 2020, we completed the issuance and sale of $1.25 billion of 0.95% senior unsecured notes maturing in 2025 and $750.0 million of 1.70% senior unsecured notes maturing in 2031, which resulted in approximately $1,980.4 million of net proceeds after deducting commissions and expenses.
•In August 2020, we executed tender offers for $969.3 million of outstanding notes consisting of a combination of our 4.45% notes due 2021, 2.65% notes due 2022, 3.85% notes due 2023, 3.65% notes due 2023, 6.25% notes due 2040, and 5.95% notes due 2041. In August and September 2020, we redeemed $609.3 million of outstanding notes representing the remainder of our 4.45% notes due 2021, 2.65% notes due 2022, 3.85% notes due 2023, and 3.65% notes due 2023 and all of our 5.89% notes due 2025. In conjunction with the debt retired, we recorded a $231.8 million loss on early extinguishment of long-term debt, primarily attributable to early redemption premiums.
•In September 2020, Columbia of Massachusetts redeemed $25.0 million of its outstanding 6.26% notes due 2028. In conjunction with the debt retired, Columbia of Massachusetts recorded an $11.7 million loss on early extinguishment of long-term debt, primarily attributable to early redemption premiums. Under the terms of the Asset Purchase Agreement, Columbia of Massachusetts’ net working capital at the closing of the sale of the Massachusetts Business was increased by 50% of the debt extinguishment costs, which was approximately $5.3 million.
Details of our 2019 long-term debt related activity are summarized below:
•On April 1, 2019, NIPSCO repaid $41.0 million of 5.85% pollution control bonds at maturity.
•On August 12, 2019, we completed the issuance and sale of $750.0 million of 2.95% senior unsecured notes maturing in 2029 which resulted in approximately $742.4 million of net proceeds after deducting commissions and expenses.
See Note 20-A, "Contractual Obligations," for the outstanding long-term debt maturities at December 31, 2020.
Unamortized debt expense, premium and discount on long-term debt applicable to outstanding bonds are being amortized over the life of such bonds.
We are subject to a financial covenant under our revolving credit facility which requires us to maintain a debt to capitalization ratio that does not exceed 70%. As of December 31, 2020, the ratio was 62.5%.
We are also subject to certain other non-financial covenants under the revolving credit facility. Such covenants include a limitation on the creation or existence of new liens on our assets, generally exempting liens on utility assets, purchase money security interests, preexisting security interests and an additional subset of assets equal to $150 million. An asset sale covenant generally restricts the sale, conveyance, lease, transfer or other disposition of our assets to those dispositions that are for a price not materially less than fair market of such assets, that would not materially impair our ability to perform obligations under the revolving credit facility, and that together with all other such dispositions, would not have a material adverse effect. The covenant also restricts dispositions to no more than 10% of our consolidated total assets on December 31, 2015. The revolving credit facility also includes a cross-default provision, which triggers an event of default under the credit facility in the event of an uncured payment default relating to any indebtedness of us or any of our subsidiaries in a principal amount of $50.0 million or more.
Our indentures generally do not contain any financial maintenance covenants. However, our indentures are generally subject to cross-default provisions ranging from uncured payment defaults of $5 million to $50 million, and limitations on the incurrence of liens on our assets, generally exempting liens on utility assets, purchase money security interests, preexisting security interests and an additional subset of assets capped at 10% of our consolidated net tangible assets.
16. Short-Term Borrowings
We generate short-term borrowings from our revolving credit facility, commercial paper program, accounts receivable transfer programs and now-settled term loan borrowings. Each of these borrowing sources is described further below.
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Notes to Consolidated Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
We maintain a revolving credit facility to fund ongoing working capital requirements, including the provision of liquidity support for our commercial paper program, provide for issuance of letters of credit and also for general corporate purposes. Our revolving credit facility has a program limit of $1.85 billion and is comprised of a syndicate of banks led by Barclays. On February 20, 2019, we extended the termination date of our revolving credit facility to February 20, 2024. At December 31, 2020 and 2019, we had no outstanding borrowings under this facility.
Our commercial paper program has a program limit of up to $1.5 billion with a dealer group comprised of Barclays, Citigroup, Credit Suisse and Wells Fargo. We had $503.0 million and $570.0 million of commercial paper outstanding as of December 31, 2020 and 2019, respectively.
Transfers of accounts receivable are accounted for as secured borrowings resulting in the recognition of short-term borrowings on the Consolidated Balance Sheets. We had no transfers as of December 31, 2020 and $353.2 million in transfers as of December 31, 2019, respectively. Refer to Note 19, "Transfers of Financial Assets," for additional information.
On April 1, 2020, we terminated and repaid in full our existing $850.0 million term loan agreement with a syndicate of banks led by MUFG Bank, Ltd. and entered into a new $850.0 million term loan agreement with a syndicate of banks led by KeyBank National Association. Any and all outstanding borrowings under the term loan agreement were due by March 31, 2021. Interest charged on borrowings depended on the variable rate structure we elected at the time of each borrowing. The available variable rate structures from which we could choose were defined in the term loan agreement. Under the agreement, we borrowed $850.0 million on April 1, 2020 with an interest rate of LIBOR plus 75 basis points. On October 14, 2020, we terminated and repaid in full our $850.0 million term loan agreement with proceeds from the sale of the Massachusetts Business.
Short-term borrowings were as follows:

At December 31, (in millions) | 2020 |  | 2019
Commercial Paper weighted-average interest rate of 0.27% and 2.03% at December 31, 2020 and 2019, respectively | $ | 503.0 |  |  | $ | 570.0 |
Accounts receivable securitization facility borrowings | — |  |  | 353.2 |
Term loan interest rate of 2.40% at December 31, 2019 | — |  |  | $ | 850.0 |
Total Short-Term Borrowings | $ | 503.0 |  |  | $ | 1,773.2 |

Other than for the term loan, revolving credit facility and certain commercial paper borrowings, cash flows related to the borrowings and repayments of the items listed above are presented net in the Statements of Consolidated Cash Flows as their maturities are less than 90 days.
17. Leases
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 are reported in accordance with ASC 840. 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, IT assets and railcars. Adoption of this standard resulted in the recording of additional lease liabilities and corresponding ROU assets of $57.0 million on our Consolidated Balance Sheets as of January 1, 2019. The standard had no material impact on our Statements of Consolidated Income (Loss) or our Statements of Consolidated Cash Flows.
Lease Descriptions. We are the lessee for substantially all of our leasing activity, which includes operating and finance leases for corporate and field offices, railcars, fleet vehicles and certain IT assets. Our corporate and field office leases have remaining lease terms between 1 and 23 years with options to renew the leases for up to 25 years. We lease railcars to transport coal to and from our electric generation facilities in Indiana. Our railcars are specifically identified in the lease agreements and have lease terms between 1 and 2 years with options to renew for 1 year. Our fleet vehicles include trucks, trailers and equipment that have been customized specifically for use in the utility industry. We lease fleet vehicles on 1 year terms, after which we have the option to extend on a month-to-month basis or terminate with written notice. ROU assets and liabilities on our Consolidated Balance Sheets do not include obligations for possible fleet vehicle lease renewals beyond the initial lease term. While we have the ability to renew these leases beyond the initial term, we are not reasonably certain (as that term is defined in ASC 842) to do
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
so. We lease the majority of our IT assets under 4 year lease terms. Ownership of leased IT assets is transferred to us at the end of the lease term.
We have not provided material residual value guarantees for our leases, nor do our leases contain material restrictions or covenants. Lease contracts containing renewal and termination options are mostly exercisable at our sole discretion. Certain of our real estate and railcar leases include renewal periods in the measurement of the lease obligation if we have deemed the renewals reasonably certain to be exercised.
With respect to service contracts involving the use of assets, if we have the right to direct the use of the asset and obtain substantially all economic benefits from the use of an asset, we account for the service contract as a lease. Unless specifically provided to us by the lessor, we utilize NiSource's collateralized incremental borrowing rate commensurate to the lease term as the discount rate for all of our leases.
Lease costs for the years ended December 31, 2020 and December 31, 2019 are presented in the table below. These costs include both amounts recognized in expense and amounts capitalized as part of the cost of another asset. Income statement presentation for these costs (when ultimately recognized on the income statement) is also included:

Year Ended December 31, (in millions) | Income Statement Classification | 2020 |  | 2019
Finance lease cost |  |  |  |
Amortization of right-of-use assets | Depreciation and amortization | $ | 23.4 |  |  | $ | 15.5 |
Interest on lease liabilities | Interest expense, net | 11.1 |  |  | 11.3 |
Total finance lease cost |  | 34.5 |  |  | 26.8 |
Operating lease cost | Operation and maintenance | 20.3 |  |  | 17.9 |
Short-term lease cost | Operation and maintenance | — |  |  | 1.0 |
Total lease cost |  | $ | 54.8 |  |  | $ | 45.7 |

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

At December 31, (in millions) | Balance Sheet Classification | 2020 |  | 2019
Assets |  |  |  |
Finance leases | Net Property, Plant and Equipment | $ | 176.8 |  |  | $ | 179.5 |
Operating leases | Deferred charges and other | 39.9 |  |  | 64.2
Total leased assets |  | 216.7 |  |  | 243.7
Liabilities |  |  |  |
Current |  |  |  |
Finance leases | Current portion of long-term debt | 23.3 |  |  | 13.4
Operating leases | Other accruals | 10.3 |  |  | 13.2
Noncurrent |  |  |  |
Finance leases | Long-term debt, excluding amounts due within one year | 171.7 |  |  | 188.1
Operating leases | Other noncurrent liabilities | 29.9 |  |  | 51.6
Total lease liabilities |  | $ | 235.2 |  |  | $ | 266.3 |

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
Other pertinent information related to leases was as follows:

Year Ended December 31, (in millions) | 2020 |  | 2019
Cash paid for amounts included in the measurement of lease liabilities |  |  |
Operating cash flows used for finance leases | $ | 11.1 |  |  | $ | 11.3 |
Operating cash flows used for operating leases | 20.2 |  |  | 17.9
Financing cash flows used for finance leases | 18.4 |  |  | 10.6
Right-of-use assets obtained in exchange for lease obligations |  |  |
Finance leases | 59.3 |  |  | 26.4
Operating leases | $ | 10.9 |  |  | $ | 13.4 |

| December 31, 2020 |  | December 31, 2019
Weighted-average remaining lease term (years) |  |  |
Finance leases | 11.2 |  | 14.8
Operating leases | 8.0 |  | 9.2
Weighted-average discount rate |  |  |
Finance leases | 5.1 | % |  | 5.9 | %
Operating leases | 4.0 | % |  | 4.3 | %

Maturities of our lease liabilities as of December 31, 2020 were as follows:

As of December 31, 2020, (in millions) | Total | Finance Leases | Operating Leases
2021 | $ | 44.4 |  | $ | 32.7 |  | $ | 11.7 |
2022 | 37.4 |  | 32.2 |  | 5.2 |
2023 | 33.5 |  | 28.8 |  | 4.7 |
2024 | 25.3 |  | 20.8 |  | 4.5 |
2025 | 19.8 |  | 16.1 |  | 3.7 |
Thereafter | 152.3 |  | 134.1 |  | 18.2 |
Total lease payments | 312.7 |  | 264.7 |  | 48.0 |
Less: Imputed interest | (77.5) |  | (69.7) |  | (7.8) |
Total | 235.2 |  | 195.0 |  | 40.2 |
Reported as of December 31, 2020 |  |  |
Short-term lease liabilities | 33.6 |  | 23.3 |  | 10.3 |
Long-term lease liabilities | 201.6 |  | 171.7 |  | 29.9 |
Total lease liabilities | $ | 235.2 |  | $ | 195.0 |  | $ | 40.2 |

There were no leases signed but not yet commenced as of December 31, 2020.
Disclosures Related to Periods Prior to Adoption of ASC 842. We lease assets in several areas of our operations including fleet vehicles and equipment, rail cars for coal delivery and certain operations centers. Payments made in connection with operating leases were $49.1 million in 2018, and were primarily charged to operation and maintenance expense as incurred.
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Notes to Consolidated Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
18. Fair Value
A.Fair Value Measurements
Recurring Fair Value Measurements. The following tables present financial assets and liabilities measured and recorded at fair value on our Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of December 31, 2020 and December 31, 2019:

Recurring Fair Value Measurements December 31, 2020 (in millions) | Quoted Prices in Active Markets for Identical Assets (Level 1) |  | Significant Other Observable Inputs (Level 2) |  | Significant Unobservable Inputs (Level 3) |  | Balance as of December 31, 2020
Assets |  |  |  |  |  |  |
Risk management assets | $ | — |  |  | $ | 13.2 |  |  | $ | — |  |  | $ | 13.2 |
Available-for-sale securities | — |  |  | 170.9 |  |  | — |  |  | 170.9 |
Total | $ | — |  |  | $ | 184.1 |  |  | $ | — |  |  | $ | 184.1 |
Liabilities |  |  |  |  |  |  |
Risk management liabilities | $ | — |  |  | $ | 222.8 |  |  | $ | — |  |  | $ | 222.8 |
Total | $ | — |  |  | $ | 222.8 |  |  | $ | — |  |  | $ | 222.8 |

Recurring Fair Value Measurements December 31, 2019 (in millions) | Quoted Prices in Active Markets for Identical Assets (Level 1) |  | Significant Other Observable Inputs (Level 2) |  | Significant Unobservable Inputs (Level 3) |  | Balance as of December 31, 2019
Assets |  |  |  |  |  |  |
Risk management assets | $ | — |  |  | $ | 4.4 |  |  | $ | — |  |  | $ | 4.4 |
Available-for-sale securities | — |  |  | 154.2 |  |  | — |  |  | 154.2 |
Total | $ | — |  |  | $ | 158.6 |  |  | $ | — |  |  | $ | 158.6 |
Liabilities |  |  |  |  |  |  |
Risk management liabilities | $ | — |  |  | $ | 146.6 |  |  | $ | — |  |  | $ | 146.6 |
Total | $ | — |  |  | $ | 146.6 |  |  | $ | — |  |  | $ | 146.6 |

Risk Management Assets and Liabilities. Risk management assets and liabilities include interest rate swaps, exchange-traded NYMEX futures and NYMEX options and non-exchange-based forward purchase contracts. When utilized, exchange-traded derivative contracts are based on unadjusted quoted prices in active markets and are classified within Level 1. These financial assets and liabilities are secured with cash on deposit with the exchange; therefore, nonperformance risk has not been incorporated into these valuations. Certain non-exchange-traded derivatives are valued using broker or over-the-counter, on-line exchanges. In such cases, these non-exchange-traded derivatives are classified within Level 2. Non-exchange-based derivative instruments include swaps, forwards, and options. In certain instances, these instruments may utilize models to measure fair value. We use a similar model to value similar instruments. Valuation models utilize various inputs that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, other observable inputs for the asset or liability and market-corroborated inputs, (i.e., inputs derived principally from or corroborated by observable market data by correlation or other means). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized within Level 2. Certain derivatives trade in less active markets with a lower availability of pricing information and models may be utilized in the valuation. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized within Level 3. Credit risk is considered in the fair value calculation of derivative instruments that are not exchange-traded. Credit exposures are adjusted to reflect collateral agreements that reduce exposures. As of December 31, 2020 and 2019, there were no material transfers between fair
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value hierarchies. Additionally, there were no changes in the method or significant assumptions used to estimate the fair value of our financial instruments.
Credit risk is considered in the fair value calculation of each of our forward-starting interest rate swaps, as described in Note 10, "Risk Management Activities." As they are based on observable data and valuations of similar instruments, the hedges are categorized within Level 2 of the fair value hierarchy. There was no exchange of premium at the initial date of the swaps, and we can settle the contracts at any time.
NIPSCO has entered into long-term forward natural gas purchase instruments to lock in a fixed price for its natural gas customers. We value these contracts using a pricing model that incorporates market-based information when available, as these instruments trade less frequently and are classified within Level 2 of the fair value hierarchy. For additional information see Note 10, “Risk Management Activities.”
Available-for-Sale Debt Securities. Available-for-sale debt securities are investments pledged as collateral for trust accounts related to our wholly-owned insurance company. We value U.S. Treasury, corporate debt and mortgage-backed securities using a matrix pricing model that incorporates market-based information. These securities trade less frequently and are classified within Level 2.
We adopted ASC 326 effective January 1, 2020. See "Recently Adopted Accounting Pronouncements" in Note 2, "Recent Accounting Pronouncements," for more information about ASC 326. Upon adoption of ASC 326, our available-for-sale debt securities impairments are recognized periodically using an allowance approach instead of an 'other than temporary' impairment model. At each reporting date, we utilize a quantitative and qualitative review process to assess the impairment of available-for-sale debt securities at the individual security level. For securities in a loss position, we evaluate our intent to sell or whether it is more-likely-than-not that we will be required to sell the security prior to the recovery of its amortized cost. If either criteria is met, the loss is recognized in earnings immediately, with the offsetting entry to the carrying value of the security. If both criteria are not met, we perform an analysis to determine whether the unrealized loss is related to credit factors. The analysis focuses on a variety of factors that include, but are not limited to, downgrade on ratings of the security, defaults in the current reporting period or projected defaults in the future, the security's yield spread over treasuries, and other relevant market data. If the unrealized loss is not related to credit factors, it is included in other comprehensive income. If the unrealized loss is related to credit factors, the loss is recognized as credit loss expense in earnings during the period, with an offsetting entry to the allowance for credit losses. The amount of the credit loss recorded to the allowance account is limited by the amount at which security's fair value is less than its amortized cost basis. If the credit losses in the allowance for credit losses are deemed uncollectible, the allowance on the uncollectible portion will be charged off, with an offsetting entry to the carrying value of the security. Subsequent improvements to the estimated credit losses of available-for-sale debt securities will be recognized immediately in earnings instead of over-time as they would under historic guidance. During the year ended December 31, 2020, we recorded $0.5 million as an allowance for credit losses on available-for-sale debt securities as a result of the analysis described above. Continuous credit monitoring and portfolio credit balancing mitigates our risk of credit losses on our available-for-sale debt securities.
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The amortized cost, gross unrealized gains and losses, allowance for credit losses, and fair value of available-for-sale securities at December 31, 2020 and 2019 were:

December 31, 2020 (in millions) | Amortized Cost |  | Gross Unrealized Gains |  | Gross Unrealized Losses(1) |  | Allowance for Credit Losses |  | Fair Value
Available-for-sale debt securities |  |  |  |  |  |  |  |  |
U.S. Treasury debt securities | $ | 33.7 |  |  | $ | 0.3 |  |  | $ | — |  |  | $ | — |  |  | $ | 34.0 |
Corporate/Other debt securities | 130.2 |  |  | 7.7 |  |  | (0.5) |  |  | (0.5) |  |  | 136.9 |
Total | $ | 163.9 |  |  | $ | 8.0 |  |  | $ | (0.5) |  |  | $ | (0.5) |  |  | $ | 170.9 |
December 31, 2019 (in millions) | Amortized Cost |  | Gross Unrealized Gains |  | Gross Unrealized Losses(2) |  | Allowance for Credit Losses |  | Fair Value
Available-for-sale debt securities |  |  |  |  |  |  |  |  |
U.S. Treasury debt securities | $ | 31.4 |  |  | $ | 0.1 |  |  | $ | (0.1) |  |  | $ | — |  |  | $ | 31.4 |
Corporate/Other debt securities | 118.7 |  |  | 4.2 |  |  | (0.1) |  |  | — |  |  | 122.8 |
Total | $ | 150.1 |  |  | $ | 4.3 |  |  | $ | (0.2) |  |  | $ | — |  |  | $ | 154.2 |

(1) Fair value of U.S. Treasury debt securities and Corporate/Other debt securities in an unrealized loss position without an allowance for credit losses is $0 and $13.2 million, respectively, at December 31, 2020.
(2) Fair value of U.S. Treasury debt securities and Corporate/Other debt securities in an unrealized loss position without an allowance for credit losses is $17.2 million and $12.2 million, respectively, at December 31, 2019.
Realized gains and losses on available-for-sale securities were immaterial for the year-ended December 31, 2020 and 2019.
The cost of maturities sold is based upon specific identification. At December 31, 2020, approximately $4.9 million of U.S. Treasury debt securities and approximately $4.3 million of Corporate/Other debt securities have maturities of less than a year.
There are no material items in the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis for the years ended December 31, 2020 and 2019.
Non-recurring Fair Value Measurements. We measure the fair value of certain assets on a non-recurring basis, typically annually or when events or changes in circumstances indicate that the carrying amount of the assets may not be recoverable. These assets include goodwill and other intangible assets.
The sale of the Massachusetts Business occurred on October 9, 2020, and the assets and liabilities of the Massachusetts Business were measured at fair value, less costs to sell. Our estimated total pre-tax loss for the year ended December 31, 2020 is $412.4 million.
At December 31, 2019, we recorded an impairment charge of $204.8 million for goodwill and an impairment charge of $209.7 million for franchise rights, in each case related to Columbia of Massachusetts. For additional information, see Note 7, “Goodwill and Other Intangible Assets.”
B. Other Fair Value Disclosures for Financial Instruments. The carrying amount of cash and cash equivalents, restricted cash, notes receivable, customer deposits and short-term borrowings is a reasonable estimate of fair value due to their liquid or short-term nature. Our long-term borrowings are recorded at historical amounts.
The following method and assumptions were used to estimate the fair value of each class of financial instruments.
Long-term debt. The fair value of outstanding long-term debt is estimated based on the quoted market prices for the same or similar securities. Certain premium costs associated with the early settlement of long-term debt are not taken into consideration in determining fair value. These fair value measurements are classified within Level 2 of the fair value hierarchy. For the years ended December 31, 2020 and 2019, there was no change in the method or significant assumptions used to estimate the fair value of long-term debt.
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The carrying amount and estimated fair values of these financial instruments were as follows:

At December 31, (in millions) | Carrying Amount 2020 |  | Estimated Fair Value 2020 |  | Carrying Amount 2019 |  | Estimated Fair Value 2019
Long-term debt (including current portion) | $ | 9,243.1 |  |  | $ | 11,034.2 |  |  | $ | 7,869.6 |  |  | $ | 8,764.4 |

19. Transfers of Financial Assets
Columbia of Ohio, NIPSCO and Columbia of Pennsylvania each maintain a receivables agreement whereby they transfer their customer accounts receivables to third party financial institutions through wholly-owned and consolidated special purpose entities. The three agreements expire between May 2021 and October 2021 and may be further extended if mutually agreed to by the parties thereto.
All receivables transferred to third parties are valued at face value, which approximates fair value due to their short-term nature. The amount of the undivided percentage ownership interest in the accounts receivables transferred is determined in part by required loss reserves under the agreements.
Transfers of accounts receivable are accounted for as secured borrowings resulting in the recognition of short-term borrowings on the Consolidated Balance Sheets. As of December 31, 2020, the maximum amount of debt that could be recognized related to our accounts receivable programs is $380.0 million.
The following table reflects the gross receivables balance and net receivables transferred as well as short-term borrowings related to the securitization transactions as of December 31, 2020 and 2019:

At December 31, (in millions) | 2020 |  | 2019
Gross receivables | $ | 607.7 |  |  | $ | 569.1 |
Less: receivables not transferred | 607.7 |  |  | 215.9 |
Net receivables transferred | $ | — |  |  | $ | 353.2 |
Short-term debt due to asset securitization | $ | — |  |  | $ | 353.2 |

During 2020 and 2019, $353.2 million and $46.0 million, respectively, was recorded as cash flows used for financing activities related to the change in short-term borrowings due to securitization transactions. Fees associated with the securitization transactions were $2.6 million for the years ended December 31, 2020, 2019 and 2018. Columbia of Ohio, NIPSCO and Columbia of Pennsylvania remain responsible for collecting on the receivables securitized, and the receivables cannot be transferred to another party.
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20. Other Commitments and Contingencies
A. Contractual Obligations. We have certain contractual obligations requiring payments at specified periods. The obligations include long-term debt, lease obligations, energy commodity contracts and obligations for various services including pipeline capacity and outsourcing of IT services. The total contractual obligations in existence at December 31, 2020 and their maturities were:

(in millions) | Total |  | 2021 |  | 2022 |  | 2023 |  | 2024 |  | 2025 |  | After
Long-term debt (1) | $ | 9,135.0 |  |  | $ | — |  |  | $ | 30.0 |  |  | $ | — |  |  | $ | — |  |  | $ | 1,260.0 |  |  | $ | 7,845.0 |
Interest payments on long-term debt | 6,046.3 |  |  | 336.3 |  |  | 335.7 |  |  | 334.1 |  |  | 334.1 |  |  | 334.1 |  |  | 4,372.0 |
Finance leases(2) | 264.7 |  |  | 32.7 |  |  | 32.2 |  |  | 28.8 |  |  | 20.8 |  |  | 16.1 |  |  | 134.1 |
Operating leases(3) | 48.0 |  |  | 11.7 |  |  | 5.2 |  |  | 4.7 |  |  | 4.5 |  |  | 3.7 |  |  | 18.2 |
Energy commodity contracts | 42.1 |  |  | 42.1 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Service obligations: |  |  |  |  |  |  |  |  |  |  |  |  |
Pipeline service obligations(4) | 1,495.6 |  |  | 468.7 |  |  | 422.5 |  |  | 256.0 |  |  | 150.5 |  |  | 56.2 |  |  | 141.7 |
IT service obligations | 240.3 |  |  | 74.9 |  |  | 74.0 |  |  | 38.1 |  |  | 30.5 |  |  | 22.8 |  |  | — |
Other service obligations(5) | 12.6 |  |  | 12.6 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Other liabilities(6) | 116.9 |  |  | 26.0 |  |  | 0.8 |  |  | 90.1 |  |  | — |  |  | — |  |  | — |
Total contractual obligations | $ | 17,401.5 |  |  | $ | 1,005.0 |  |  | $ | 900.4 |  |  | $ | 751.8 |  |  | $ | 540.4 |  |  | $ | 1,692.9 |  |  | $ | 12,511.0 |

(1) Long-term debt balance excludes unamortized issuance costs and discounts of $86.9 million.
(2) Finance lease payments shown above are inclusive of interest totaling $69.7 million.
(3) Operating lease payments shown above are inclusive of interest totaling $7.8 million. Operating lease balances do not include obligations for possible fleet vehicle lease renewals beyond the initial lease term. While we have the ability to renew these leases beyond the initial term, we are not reasonably certain (as that term is defined in ASC 842) to do so as they are renewed month-to-month after the first year. If we were to continue the fleet vehicle leases outstanding at December 31, 2020, payments would be $30.0 million in 2021, $27.7 million in 2022, $24.9 million in 2023, $22.0 million in 2024, $19.0 million in 2025 and $21.5 million thereafter.
(4)In February 2021, the demand rate increased for our pipeline service obligations, resulting in a total increase of $638.6 million in addition to our future pipeline service obligations shown above.
(5)On February 9, 2021, a rail transportation contract for the transportation of coal was fully executed between NIPSCO and a counterparty, replacing the prior agreement. The minimum coal tonnage shipment commitment for 2021 was eliminated under the new agreement, reducing our contractual obligation for 2021 by $12.1 million.
(6)Other liabilities shown above are inclusive of the Rosewater Developer payment due in 2023.
Purchase and Service Obligations. We have entered into various purchase and service agreements whereby we are contractually obligated to make certain minimum payments in future periods. Our purchase obligations are for the purchase of physical quantities of natural gas, electricity and coal. Our service agreements encompass a broad range of business support and maintenance functions which are generally described below.
Our subsidiaries have entered into various energy commodity contracts to purchase physical quantities of natural gas, electricity and coal. These amounts represent the minimum quantity of these commodities we are obligated to purchase at both fixed and variable prices. To the extent contractual purchase prices are variable, obligations disclosed in the table above are valued at market prices as of December 31, 2020.
NIPSCO has power purchase arrangements representing a total of 500 MW of wind power, with contracts expiring between between 2024 and 2040. No minimum quantities are specified within these agreements due to the variability of electricity generation from wind, so no amounts related to these contracts are included in the table above. Upon early termination of one of these agreements by NIPSCO for any reason (other than material breach by the counterparties), NIPSCO may be required to pay a termination charge that could be material depending on the events giving rise to termination and the timing of the termination.
We have pipeline service agreements that provide for pipeline capacity, transportation and storage services. These agreements, which have expiration dates ranging from 2021 to 2038, require us to pay fixed monthly charges.
NIPSCO has contracts with three major rail operators providing for coal transportation services for which there are certain minimum payments. These service contracts extend for various periods through 2021.
We have executed agreements with multiple IT service providers. The agreements extend for various periods through 2025.
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B. Guarantees and Indemnities. We and certain subsidiaries enter into various agreements providing financial or performance assurance to third parties on behalf of certain subsidiaries as part of normal business. Such agreements include guarantees and stand-by letters of credit. These agreements are entered into primarily to support or enhance the creditworthiness otherwise attributed to a subsidiary on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish the subsidiaries’ intended commercial purposes. At December 31, 2020 and 2019, we had issued stand-by letters of credit of $15.2 million and $10.2 million , respectively, for the benefit of third parties.
We have provided guarantees related to our future performance under BTAs for our renewable generation projects. At December 31, 2020, our guarantees for the Rosewater and Indiana Crossroads BTAs totaled $40.7 million. The amount of each guaranty will decrease upon the substantial completion of the construction of the facilities. See “- E. Other Matters - NIPSCO 2018 Integrated Resource Plan,” below for more information.
C. Legal Proceedings. On September 13, 2018, a series of fires and explosions occurred in Lawrence, Andover and North Andover, Massachusetts related to the delivery of natural gas by Columbia of Massachusetts (the "Greater Lawrence Incident"). The Greater Lawrence Incident resulted in one fatality and a number of injuries, damaged multiple homes and businesses, and caused the temporary evacuation of significant portions of each municipality. The Massachusetts Governor’s Office declared a state of emergency, authorizing the Massachusetts DPU to order another utility company to coordinate the restoration of utility services in Lawrence, Andover and North Andover. The incident resulted in the interruption of gas for approximately 7,500 gas meters, the majority of which served residences and approximately 700 of which served businesses, and the interruption of other utility service more broadly in the area. Columbia of Massachusetts has replaced the cast iron and bare steel gas pipeline system in the affected area and restored service to nearly all of the gas meters. See “- E. Other Matters - Greater Lawrence Pipeline Replacement” below for more information. On September 1, 2020, the Massachusetts Governor terminated the state of emergency declared following the Greater Lawrence Incident.
We have been subject to state and federal inquiries and investigations by government authorities and regulatory agencies regarding the Greater Lawrence Incident, including the Massachusetts DPU and the Massachusetts Attorney General's Office. On February 26, 2020, the Company and Columbia of Massachusetts entered into agreements with the U.S. Attorney’s Office for the District of Massachusetts to resolve the U.S. Attorney’s Office’s investigation relating to the Greater Lawrence Incident, as described below. The Company and Columbia of Massachusetts entered into an agreement with the Massachusetts Attorney General’s Office (among other parties) to resolve the Massachusetts DPU and the Massachusetts Attorney General’s Office investigations, that was approved by the Massachusetts DPU on October 7, 2020 as part of the sale of the Massachusetts Business to Eversource.
NTSB Investigation. As previously disclosed, the NTSB concluded its investigation into the Greater Lawrence Incident. On November 24, 2020, the NTSB closed NiSource’s one remaining open safety recommendation.
U.S. Department of Justice Investigation. On February 26, 2020, the Company and Columbia of Massachusetts entered into agreements with the U.S. Attorney’s Office to resolve the U.S. Attorney’s Office’s investigation relating to the Greater Lawrence Incident. Columbia of Massachusetts agreed to plead guilty in the United States District Court for the District of Massachusetts (the “Court”) to violating the Natural Gas Pipeline Safety Act (the “Plea Agreement”), and the Company entered into a Deferred Prosecution Agreement (the “DPA”).
On March 9, 2020, Columbia of Massachusetts entered its guilty plea pursuant to the Plea Agreement, which the Court accepted. Subsequently, Columbia of Massachusetts and the U.S. Attorney’s Office modified the Plea Agreement. On June 23, 2020, the Court sentenced Columbia of Massachusetts in accordance with the terms of the modified Plea Agreement. Under the modified Plea Agreement, Columbia of Massachusetts is subject to the following terms, among others: (i) a criminal fine in the amount of $53,030,116, which has been paid; (ii) a three year probationary period that will terminate early upon a sale of Columbia of Massachusetts or a sale of its gas distribution business to a qualified third-party buyer consistent with certain requirements, but in no event before the end of the one-year mandatory period of probation; (iii) compliance with each of the NTSB recommendations stemming from the Greater Lawrence Incident; and (iv) employment of an in-house monitor until the end of the term of probation or until the sale of Columbia of Massachusetts or its gas distribution business, whichever is earlier. On October 13, 2020, the Court, upon agreement of the U.S. Attorney's Office and Columbia Gas of Massachusetts, modified the terms of probation by ending the term of the in-house monitor.
Under the DPA, the U.S. Attorney’s Office agreed to defer prosecution of the Company in connection with the Greater Lawrence Incident for a three-year period (which three-year period may be extended for twelve (12) months upon the U.S.
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Attorney’s Office’s determination of a breach of the DPA) subject to certain obligations of the Company, including, but not limited to, the following: (i) the Company will use reasonable best efforts to sell Columbia of Massachusetts or Columbia of Massachusetts’ gas distribution business to a qualified third-party buyer consistent with certain requirements, and, upon the completion of any such sale, the Company will cease and desist any and all gas pipeline and distribution activities in the District of Massachusetts; (ii) the Company will forfeit and pay, within 30 days of the later of the sale becoming final or the date on which post-closing adjustments to the purchase price are finally determined in accordance with the agreement to sell Columbia of Massachusetts or its gas distribution business, a fine equal to the total amount of the profit or gain, if any, from any sale of Columbia of Massachusetts or its gas distribution business, with the amount of profit or gain determined as provided in the DPA; and (iii) the Company agrees as to each of the Company’s subsidiaries involved in the distribution of gas through pipeline facilities in Massachusetts, Indiana, Ohio, Pennsylvania, Maryland, Kentucky and Virginia to implement and adhere to each of the recommendations from the NTSB stemming from the Greater Lawrence Incident. Pursuant to the DPA, if the Company complies with all of its obligations under the DPA, including, but not limited to those identified above, the U.S. Attorney’s Office will not file any criminal charges against the Company related to the Greater Lawrence Incident. If Columbia of Massachusetts withdraws its plea for any reason, if the Court rejects any aspect of the Plea Agreement, or if Columbia of Massachusetts should fail to perform an obligation under the Plea Agreement prior to the sale of Columbia of Massachusetts or its gas distribution business, the U.S. Attorney's Office may, at its sole option, render the DPA null and void. The sale of the Massachusetts Business was completed on October 9, 2020. The Company was not required to forfeit or pay any funds because the Company did not realize a profit or gain from the sale as provided in the DPA.
U.S. Federal Government Activity. 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 O&M 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 leak detection and repair programs that meet safety needs and consider the environment, require the use of advance leak detection practices and technologies, and require operators to be able to locate and categorize all leaks that are hazardous to human safety or the environment, or that can become hazardous. Natural gas companies, including the Company, may see increased costs depending on how PHMSA implements the new mandates resulting from the PIPES Act.
Private Actions. Various lawsuits, including several purported class action lawsuits, have been filed by various affected residents or businesses in Massachusetts state courts against the Company and/or Columbia of Massachusetts in connection with the Greater Lawrence Incident.
On July 26, 2019, the Company, Columbia of Massachusetts and NiSource Corporate Services Company, a subsidiary of the Company, entered into a term sheet with the class action plaintiffs under which they agreed to settle the class action claims in connection with the Greater Lawrence Incident. Columbia of Massachusetts agreed to pay $143 million into a settlement fund to compensate the settlement class and the settlement class agreed to release Columbia of Massachusetts and affiliates from all claims arising out of or related to the Greater Lawrence Incident. The following claims are not covered under the proposed settlement because they are not part of the consolidated class action: (1) physical bodily injury and wrongful death; (2) insurance subrogation, whether equitable, contractual or otherwise; and (3) claims arising out of appliances that are subject to the Massachusetts DPU orders. Emotional distress and similar claims are covered under the proposed settlement unless they are secondary to a physical bodily injury. The settlement class is defined under the term sheet as all persons and businesses in the three municipalities of Lawrence, Andover and North Andover, Massachusetts, subject to certain limited exceptions. The motion for preliminary approval and the settlement documents were filed on September 25, 2019. The preliminary approval court hearing was held on October 7, 2019 and the court issued an order granting preliminary approval of the settlement on October 11, 2019. The Court granted final approval of the settlement on March 12, 2020.
With respect to claims not included in the consolidated class action, many of the asserted wrongful death and bodily injury claims have settled, and we continue to discuss potential settlements with remaining claimants. The outcomes and impacts of such private actions are uncertain at this time.
Shareholder Derivative Lawsuit. On April 28, 2020, a shareholder derivative lawsuit was filed by the City of Detroit Police and Fire Retirement System in the United States District Court for the District of Delaware against certain of our current and former directors, alleging breaches of fiduciary duty with respect to the pipeline safety management systems relating to the distribution of natural gas prior to the Greater Lawrence Incident and also including claims related to our proxy statement
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disclosures regarding our safety systems. The remedies sought include damages for the alleged breaches of fiduciary duty, corporate governance reforms, and restitution of any unjust enrichment. The defendants have filed a motion to dismiss the lawsuit. The motion to dismiss is fully briefed. On January 5, 2021, the judge set the defendants’ motion to dismiss for oral argument on March 2, 2021. Because of the preliminary nature of this lawsuit, we are not able to estimate a loss or range of loss, if any, that may be incurred in connection with this matter at this time.
Financial Impact. Since the Greater Lawrence Incident, we have recorded expenses of approximately $1,036 million for third-party claims and fines, penalties and settlements associated with government investigations. We estimate that total costs related to third-party claims and fines, penalties and settlements associated with government investigations resulting from the incident will range from $1,036 million to $1,050 million, depending on the number, nature, final outcome and value of third-party claims. With regard to third-party claims, these costs include, but are not limited to, personal injury and property damage claims, damage to infrastructure, business interruption claims, and mutual aid payments to other utilities assisting with the restoration effort. These costs do not include costs of certain third-party claims and fines, penalties or settlements associated with government investigations that we are not able to estimate. These costs also do not include non-claims related and government investigation-related legal expenses resulting from the incident, the capital cost of the pipeline replacement and the payment in lieu of penalties, which are set forth in " - D. Other Matters - Greater Lawrence Incident Restoration," "- Greater Lawrence Incident Pipeline Replacement," and Note 1-A, "Company Structure and Principles of Consolidation," respectively.
The process for estimating costs associated with third-party claims relating to the Greater Lawrence Incident requires management to exercise significant judgment based on a number of assumptions and subjective factors. As more information becomes known, management’s estimates and assumptions regarding the financial impact of the Greater Lawrence Incident may change.
The aggregate amount of third-party liability insurance coverage available for losses arising from the Greater Lawrence Incident is $800 million. We collected the entire $800 million as of December 31, 2019. Total expenses related to the incident have exceeded the total amount of insurance coverage available under our policies. Refer to "- E. Other Matters - Greater Lawrence Incident Restoration," below for a summary of third-party claims-related expense activity and associated insurance recoveries recorded since the Greater Lawrence Incident.
We are also party to certain other claims, regulatory and legal proceedings arising in the ordinary course of business in each state in which we have operations, none of which is deemed to be individually material at this time.
Due to the inherent uncertainty of litigation, there can be no assurance that the resolution of any particular claim, proceeding or investigation related to the Greater Lawrence Incident or otherwise would not have a material adverse effect on our results of operations, financial position or liquidity. Certain matters in connection with the Greater Lawrence Incident have had or may have a material impact as described above. If one or more of such additional or other matters were decided against us, the effects could be material to our results of operations in the period in which we would be required to record or adjust the related liability and could also be material to our cash flows in the periods that we would be required to pay such liability.
D. Environmental Matters. Our operations are subject to environmental statutes and regulations related to air quality, water quality, hazardous waste and solid waste. We believe we are, in all material respects, in compliance with the environmental regulations currently applicable to our operations.
It is management's continued intent to address environmental issues in cooperation with regulatory authorities in such a manner as to achieve mutually acceptable compliance plans. However, there can be no assurance that fines and penalties will not be incurred. Management expects a significant portion of environmental assessment, improvement and remediation costs to be recoverable through rates for certain of our companies.
As of December 31, 2020 and 2019, we had recorded a liability of $92.6 million and $104.4 million, respectively, to cover environmental remediation at various sites. The current portion of this liability is included in "Other Accruals" in the Consolidated Balance Sheets. The noncurrent portion is included in "Other noncurrent liabilities." We recognize costs associated with environmental remediation obligations when the incurrence of such costs is probable and the amounts can be reasonably estimated. The original estimates for remediation activities may differ materially from the amount ultimately expended. The actual future expenditures depend on many factors, including currently enacted laws and regulations, the nature and extent of impact and the method of remediation. These expenditures are not currently estimable at some sites. We periodically adjust our liability as information is collected and estimates become more refined.
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Notes to Consolidated Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
Electric Operations' compliance estimates disclosed below are reflective of NIPSCO's Integrated Resource Plan submitted to the IURC on October 31, 2018. See section " - E. Other Matters - NIPSCO 2018 Integrated Resource Plan," below for additional information.
Air
Future legislative and regulatory programs could significantly limit allowed GHG emissions or impose a cost or tax on GHG emissions. Additionally, rules that require further GHG reductions or impose additional requirements for natural gas facilities could impose additional costs. NiSource will carefully monitor all GHG reduction proposals and regulations.
ACE Rule. 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. NIPSCO will continue to monitor this matter.
Waste
CERCLA. Our subsidiaries are potentially responsible parties at waste disposal sites under the CERCLA (commonly known as Superfund) and similar state laws. Under CERCLA, each potentially responsible party can be held jointly, severally and strictly liable for the remediation costs as the EPA, or state, can allow the parties to pay for remedial action or perform remedial action themselves and request reimbursement from the potentially responsible parties. Our affiliates have retained CERCLA environmental liabilities, including remediation liabilities, associated with certain current and former operations. These liabilities are not material to the Consolidated Financial Statements.
MGP. A program has been instituted to identify and investigate former MGP sites where Gas Distribution Operations subsidiaries or predecessors may have liability. The program has identified 54 such sites where liability is probable. Remedial actions at many of these sites are being overseen by state or federal environmental agencies through consent agreements or voluntary remediation agreements.
We utilize a probabilistic model to estimate our future remediation costs related to MGP sites. The model was prepared with the assistance of a third party and incorporates our experience and general industry experience with remediating MGP sites. We complete an annual refresh of the model in the second quarter of each fiscal year. No material changes to the estimated future remediation costs were noted as a result of the refresh completed as of June 30, 2020. Our total estimated liability related to the facilities subject to remediation was $85.0 million and $102.2 million at December 31, 2020 and 2019, respectively. The liability represents our best estimate of the probable cost to remediate the facilities. We believe that it is reasonably possible that remediation costs could vary by as much as $20 million in addition to the costs noted above. Remediation costs are estimated based on the best available information, applicable remediation standards at the balance sheet date, and experience with similar facilities.
CCRs. On April 17, 2015, the EPA issued a final rule for regulation of CCRs. The rule regulates CCRs under the RCRA Subtitle D, which determines them to be nonhazardous. The rule is implemented in phases and requires increased groundwater monitoring, reporting, recordkeeping and posting of related information to the Internet. The rule also establishes requirements related to CCR management and disposal. The rule will allow NIPSCO to continue its byproduct beneficial use program.
To comply with the rule, NIPSCO completed capital expenditures in 2019 to modify its infrastructure and manage CCRs. The CCR rule also resulted in revisions to previously recorded legal obligations associated with the retirement of certain NIPSCO facilities. The actual asset retirement costs related to the CCR rule may vary substantially from the estimates used to record the increased asset retirement obligation due to the uncertainty about the requirements that will be established by environmental authorities, compliance strategies that will be used and the preliminary nature of available data used to estimate costs. As allowed by the rule, NIPSCO will continue to collect data over time to determine the specific compliance solutions and associated costs and, as a result, the actual costs may vary. NIPSCO will also continue to work with EPA and the Indiana Department of Environmental Management to obtain administrative approvals associated with the CCR rule. In the event that the approvals are not obtained, future operations could be impacted. We believe the possibility of such an outcome is remote.
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Notes to Consolidated Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
E. Other Matters.
NIPSCO 2018 Integrated Resource Plan. NIPSCO concluded 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 Plans 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 the R.M. Schahfer Generating Station by mid-2023 and the Michigan City Generating Station by the end of 2028. These units represent 2,080 MW of generating capacity, equal to 72% of NIPSCO’s remaining generating capacity and 100% of NIPSCO's remaining coal-fired generating capacity. NIPSCO will refresh its 2018 Integrated Resource Plan in 2021.
In the second quarter of 2020, the MISO approved NIPSCO's plan to retire the R.M. Schahfer Generating Station in 2023. In accordance with ASC 980-360, the net book value of certain plant and equipment for the R.M. Schahfer Generating Station was reclassified as "Non-Utility and Other" as described in Note 6, "Property, Plant and Equipment." The December 2019, NIPSCO electric rate case order included approval to create a regulatory asset upon the retirement of the R.M. Schahfer Generating Station. The order allows for the recovery of and on the net book value of the station by the end of 2032. Refer to Note 6, "Property, Plant and Equipment" for further information.
In connection with the MISO's approval of NIPSCO's planned retirement of the R.M. Schahfer Generating Station, we recorded $4.6 million of plant retirement-related charges in the second quarter of 2020. These charges are presented within "Operation and maintenance" and were comprised of write downs of certain capital projects that have been cancelled and materials and supplies inventory balances deemed obsolete due to the planned retirement. As more information becomes available, the retirement date of the R.M. Schahfer Generating Station will be finalized, and additional plant retirement-related charges may be incurred. In February 2021, NIPSCO decided to submit modified Attachment Y Notices to MISO requesting accelerated retirement of two of the four coal fired units at R.M. Schahfer Generating Station. The two units are now expected to be retired by the end of 2021, with the remaining two units still scheduled to be retired in 2023. At retirement, the net book value of the retired units will be reclassified from "Non-Utility and Other property", to current and long-term “Regulatory Assets,” as described above.
In connection with the planned retirement of the Schahfer Generating Station and the Michigan City Generating Station, the current capacity replacement plan includes lower-cost, reliable, cleaner energy resources to be obtained through a combination of NIPSCO ownership and PPAs. To this effect, NIPSCO has entered into a number of agreements with counterparties.
NIPSCO has executed several PPAs to purchase 100% of the output from renewable generation facilities at a fixed price per MWh. Each facility supplying the energy will have an associated nameplate capacity, and payments under the PPAs will not begin until the associated generation facility is constructed by the owner/seller. NIPSCO has also executed several BTAs with developers to construct renewable generation facilities. NIPSCO's purchase requirement under the BTAs is dependent on satisfactory approval of the BTA by the IURC, successful execution of an agreement with a tax equity partner and timely completion of construction. NIPSCO and the tax equity partner are obligated to make cash contributions to the partnership at the date construction is substantially complete. Once the tax equity partner has earned their negotiated rate of return and we have reached the agreed upon contractual date, NIPSCO has the option to purchase at fair market value from the tax equity partner the remaining interest in the aforementioned joint venture.
Greater Lawrence Incident Restoration. In addition to the amounts estimated for third-party claims and fines, penalties and settlements associated with government investigations described above, we have recorded expenses for other incident-related costs. Such costs include certain consulting costs, legal costs, vendor costs, claims center costs, labor and related expenses incurred in connection with the incident, and insurance-related loss surcharges. These amounts do not include the capital cost of the pipeline replacement, which is set forth below.
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Notes to Consolidated Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
The following table summarizes expenses incurred and insurance recoveries recorded since the Greater Lawrence Incident. This activity is presented within "Operation and maintenance" and "Other, net" in our Statements of Consolidated Income (Loss).

| Total Costs Incurred through |  |  | Year Ended |
(in millions) | December 31, 2019 |  |  | December 31, 2020 | Incident to Date
Third-party claims and government fines, penalties and settlements | $ | 1,041 |  |  |  | $ | (5) |  | $ | 1,036 |
Other incident-related costs | 420 |  |  |  | 22 |  | 442 |
Total | 1,461 |  |  |  | 17 |  | 1,478 |
Insurance recoveries recorded | (800) |  |  |  | — |  | (800) |
Total costs incurred | $ | 661 |  |  |  | $ | 17 |  | $ | 678 |

As discussed in "- C. Legal Proceedings," the aggregate amount of third-party liability insurance coverage available for losses arising from the Greater Lawrence Incident is $800 million. While we collected the entire $800 million, expenses related to the incident exceeded the total amount of insurance coverage available under our policies.
The following table summarizes the total estimated incident-related expenses.

(in millions) | Current Total Estimated Amount
Third-party claims and government fines, penalties and settlements | $1,036 - $1,050
Other incident-related costs | $445 - $450

Greater Lawrence Pipeline Replacement. In connection with the Greater Lawrence Incident, Columbia of Massachusetts, in cooperation with the Massachusetts Governor’s office, replaced the entire affected pipeline system. We invested approximately $258 million of capital spend for the pipeline replacement; this work was completed in 2019. We maintain property insurance for gas pipelines and other applicable property. Columbia of Massachusetts has filed a proof of loss with its property insurer for the pipeline replacement. In January 2020, we filed a lawsuit against the property insurer, seeking payment of our property claim. We are currently unable to predict the timing or amount of any insurance recovery under the property policy. Refer to Note 1-A, "Company Structure and Principles of Consolidation," for more information.
State Income Taxes Related to Greater Lawrence Incident Expenses. As of December 31, 2018, expenses related to the Greater Lawrence Incident were $1,023 million. In the fourth quarter of 2019, we filed an application for Alternative Apportionment with the MA DOR to request an allocable approach to these expenses for purposes of Massachusetts state income taxes, which, if approved, would result in a state deferred tax asset of approximately $50 million, net. The MA DOR issued a denial during the first quarter of 2020. We filed an application for abatement in the second quarter of 2020, resulting in a hearing with the MA DOR during the fourth quarter of 2020. We believe it is reasonably possible that an alternative method will be proposed by the MA DOR during the first half of 2021.
Voluntary Separation Program. On August 5, 2020, we commenced a voluntary separation program for certain employees. Expense for the voluntary separation program was predominantly recognized in the third quarter of 2020, when the employees accepted the offer, absent a retention period. For employees that have a retention period, expense will be recognized over the remaining service period. Employee acceptance under the voluntary separation program was determined by management based on facts and circumstances of the benefits being offered. The total severance expense for employees who were accepted under the voluntary separation program offered in August 2020 is approximately $38 million, which will be recognized over the remaining service period of the applicable employees. A rollforward of the voluntary separation program accrual for the year ended December 31, 2020 is presented below:

(in millions) | Balance as of January 1, 2020 | Changes Attributable to Costs Incurred(1) | Costs Paid | Adjustments | Balance as of December 31, 2020(2)
Voluntary Separation Program | $ | — |  | 33.5 | $ | (21.2) |  | (1.2) |  | $ | 11.1 |

(1)This activity is presented within "Operation and maintenance" in our Statements of Consolidated Income (Loss).
(2)This activity is presented within "Accrued compensation and employee benefits" in our Consolidated Balance Sheets.
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Notes to Consolidated Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
21. Accumulated Other Comprehensive Loss
The following table displays the activity of Accumulated Other Comprehensive Loss, net of tax:

(in millions) | Gains and Losses on Securities(1) |  | Gains and Losses on Cash Flow Hedges(1) |  | Pension and OPEB Items(1) |  | Accumulated Other Comprehensive Loss(1)
Balance as of January 1, 2018 | $ | 0.2 |  |  | $ | (29.4) |  |  | $ | (14.2) |  |  | $ | (43.4) |
Other comprehensive income (loss) before reclassifications | (3.0) |  |  | 55.8 |  |  | (4.4) |  |  | 48.4 |
Amounts reclassified from accumulated other comprehensive loss | 0.4 |  |  | (33.1) |  |  | — |  |  | (32.7) |
Net current-period other comprehensive income (loss) | (2.6) |  |  | 22.7 |  |  | (4.4) |  |  | 15.7 |
Reclassification due to adoption of ASU 2018-02 | — |  |  | (6.3) |  |  | (3.2) |  |  | (9.5) |
Balance as of December 31, 2018 | $ | (2.4) |  |  | $ | (13.0) |  |  | $ | (21.8) |  |  | $ | (37.2) |
Other comprehensive income (loss) before reclassifications | 6.1 |  |  | (64.3) |  |  | 2.3 |  |  | (55.9) |
Amounts reclassified from accumulated other comprehensive loss | (0.4) |  |  | 0.1 |  |  | 0.8 |  |  | 0.5 |
Net current-period other comprehensive income (loss) | 5.7 |  |  | (64.2) |  |  | 3.1 |  |  | (55.4) |
Balance as of December 31, 2019 | $ | 3.3 |  |  | $ | (77.2) |  |  | $ | (18.7) |  |  | $ | (92.6) |
Other comprehensive income (loss) before reclassifications | 3.3 |  |  | (70.8) |  |  | 2.9 |  |  | (64.6) |
Amounts reclassified from accumulated other comprehensive loss | (0.6) |  |  | 0.1 |  |  | 1.0 |  |  | 0.5 |
Net current-period other comprehensive income (loss) | 2.7 |  |  | (70.7) |  |  | 3.9 |  |  | (64.1) |
Balance as of December 31, 2020 | $ | 6.0 |  |  | $ | (147.9) |  |  | $ | (14.8) |  |  | $ | (156.7) |

(1)All amounts are net of tax. Amounts in parentheses indicate debits.
22. Other, Net

Year Ended December 31, (in millions) | 2020 |  | 2019 |  | 2018
Interest income | $ | 5.5 |  |  | $ | 7.7 |  |  | $ | 6.6 |
AFUDC equity | 9.9 |  |  | 8.0 |  |  | 14.2 |
Charitable contributions(1) | (1.5) |  |  | (5.1) |  |  | (45.3) |
Pension and other postretirement non-service cost(2) | 9.3 |  |  | (16.5) |  |  | 18.0 |
Sale of emission reduction credits | 4.6 |  |  | — |  |  | — |
Interest rate swap settlement gain(3) | — |  |  | — |  |  | 46.2 |
Miscellaneous | 4.3 |  |  | 0.7 |  |  | 3.8 |
Total Other, net | $ | 32.1 |  |  | $ | (5.2) |  |  | $ | 43.5 |

(1) 2018 charitable contributions include $20.7 million related to the Greater Lawrence Incident and $20.0 million of discretionary contributions made to the NiSource Charitable Foundation. See Note 20, "Other Commitments and Contingencies" for additional information on the Greater Lawrence Incident.
(2) See Note 12, "Pension and Other Postretirement Benefits" for additional information.
(3) See Note 10, "Risk Management Activities" for additional information.
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Notes to Consolidated Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
23. Interest Expense, Net

Year Ended December 31, (in millions) | 2020 |  | 2019 |  | 2018
Interest on long-term debt | $ | 354.2 |  |  | $ | 327.7 |  |  | $ | 342.2 |
Interest on short-term borrowings | 14.7 |  |  | 50.8 |  |  | 31.8 |
Debt discount/cost amortization | 9.1 |  |  | 8.3 |  |  | 7.7 |
Accounts receivable securitization fees | 2.6 |  |  | 2.6 |  |  | 2.6 |
Allowance for borrowed funds used and interest capitalized during construction | (7.0) |  |  | (7.5) |  |  | (9.1) |
Debt-based post-in-service carrying charges | (14.6) |  |  | (18.7) |  |  | (35.0) |
Other | 11.7 |  |  | 15.7 |  |  | 13.1 |
Total Interest Expense, net | $ | 370.7 |  |  | $ | 378.9 |  |  | $ | 353.3 |

24. Segments of Business
At December 31, 2020, our operations are divided into two primary reportable segments, the Gas Distribution Operations and the Electric Operations segment. The remainder of our operations, which are not significant enough on a stand-alone basis to warrant treatment as an operating segment, are presented as "Corporate and Other" and primarily are comprised of interest expense on holding company debt, and unallocated corporate costs and activities. Refer to Note 3, "Revenue Recognition," for additional information on our segments and their sources of revenues. The following table provides information about our reportable segments. We use operating income as our primary measurement for each of the reported segments and make decisions on finance, dividends and taxes at the corporate level on a consolidated basis. Segment revenues include intersegment sales to affiliated subsidiaries, which are eliminated in consolidation. Affiliated sales are recognized on the basis of prevailing market, regulated prices or at levels provided for under contractual agreements. Operating income is derived from revenues and expenses directly associated with each segment.

Year Ended December 31, (in millions) | 2020 |  | 2019 |  | 2018
Operating Revenues |  |  |  |  |
Gas Distribution Operations |  |  |  |  |
Unaffiliated | $ | 3,128.1 |  |  | $ | 3,509.7 |  |  | $ | 3,406.4 |
Intersegment | 12.1 |  |  | 13.1 |  |  | 13.1 |
Total | 3,140.2 |  |  | 3,522.8 |  |  | 3,419.5 |
Electric Operations |  |  |  |  |
Unaffiliated | 1,535.9 |  |  | 1,698.4 |  |  | 1,707.4 |
Intersegment | 0.7 |  |  | 0.8 |  |  | 0.8 |
Total | 1,536.6 |  |  | 1,699.2 |  |  | 1,708.2 |
Corporate and Other |  |  |  |  |
Unaffiliated | 17.7 |  |  | 0.8 |  |  | 0.7 |
Intersegment | 449.8 |  |  | 468.1 |  |  | 517.6 |
Total | 467.5 |  |  | 468.9 |  |  | 518.3 |
Eliminations | (462.6) |  |  | (482.0) |  |  | (531.5) |
Consolidated Operating Revenues | $ | 4,681.7 |  |  | $ | 5,208.9 |  |  | $ | 5,114.5 |

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

Year Ended December 31, (in millions) | 2020 |  | 2019 |  | 2018
Operating Income (Loss) |  |  |  |  |
Gas Distribution Operations(1) | $ | 199.1 |  |  | $ | 675.4 |  |  | $ | (254.1) |
Electric Operations | 348.8 |  |  | 406.8 |  |  | 386.1 |
Corporate and Other(2) | 2.9 |  |  | (191.5) |  |  | (7.3) |
Consolidated Operating Income | $ | 550.8 |  |  | $ | 890.7 |  |  | $ | 124.7 |
Depreciation and Amortization |  |  |  |  |
Gas Distribution Operations | $ | 363.1 |  |  | $ | 403.2 |  |  | $ | 301.0 |
Electric Operations | 321.3 |  |  | 277.3 |  |  | 262.9 |
Corporate and Other | 41.5 |  |  | 36.9 |  |  | 35.7 |
Consolidated Depreciation and Amortization | $ | 725.9 |  |  | $ | 717.4 |  |  | $ | 599.6 |
Assets |  |  |  |  |
Gas Distribution Operations | $ | 13,433.0 |  |  | $ | 14,224.5 |  |  | $ | 13,527.0 |
Electric Operations | 6,443.1 |  |  | 6,027.6 |  |  | 5,735.2 |
Corporate and Other | 2,164.4 |  |  | 2,407.7 |  |  | 2,541.8 |
Consolidated Assets | $ | 22,040.5 |  |  | $ | 22,659.8 |  |  | $ | 21,804.0 |
Capital Expenditures(3) |  |  |  |  |
Gas Distribution Operations | $ | 1,266.9 |  |  | $ | 1,380.3 |  |  | $ | 1,315.3 |
Electric Operations | 422.8 |  |  | 468.9 |  |  | 499.3 |
Corporate and Other | 31.1 |  |  | 18.6 |  |  | — |
Consolidated Capital Expenditures | $ | 1,720.8 |  |  | $ | 1,867.8 |  |  | $ | 1,814.6 |

(1)In 2020, Gas Distribution Operations reflects the loss of $412.4 million on the sale of the Massachusetts Business. For additional information, see Note 1, "Nature of Operations and Summary of Significant Accounting Policies".
(2)In 2019, Corporate and Other reflects an impairment charge of $204.8 million for goodwill related to Columbia of Massachusetts. For additional information, see Note 7, "Goodwill and Other Intangible Assets."
(3)Amounts differ from those presented on the Statements of Consolidated Cash Flows primarily due to the inclusion of capital expenditures in current liabilities, the capitalized portion of the Corporate Incentive Plan payout, and AFUDC Equity.
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Notes to Consolidated Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
25. Quarterly Financial Data (Unaudited)
Quarterly financial data does not always reveal the trend of our business operations due to nonrecurring items and seasonal weather patterns, which affect earnings and related components of revenue and operating income.

(in millions, except per share data) | First Quarter(1) |  | Second Quarter(2) |  | Third Quarter(3) |  | Fourth Quarter(4)
2020 |  |  |  |  |  |  |
Operating Revenues | $ | 1,605.5 |  |  | $ | 962.7 |  |  | $ | 902.5 |  |  | $ | 1,211.0 |
Operating Income | 148.2 |  |  | 91.7 |  |  | 92.8 |  |  | 218.1 |
Net Income (Loss) | 75.6 |  |  | (4.7) |  |  | (172.9) |  |  | 87.8 |
Net income attributable to noncontrolling interest | — |  |  | — |  |  | — |  |  | 3.4 |
Net Income (Loss) attributable to NiSource | 75.6 |  |  | (4.7) |  |  | (172.9) |  |  | 84.4 |
Preferred Dividends | (13.8) |  |  | (13.8) |  |  | (13.8) |  |  | (13.7) |
Net Income (Loss) Available to Common Shareholders | 61.8 |  |  | (18.5) |  |  | (186.7) |  |  | 70.7 |
Earnings (Loss) Per Share |  |  |  |  |  |  |
Basic Earnings (Loss) Per Share | $ | 0.16 |  |  | $ | (0.05) |  |  | $ | (0.49) |  |  | $ | 0.18 |
Diluted Earnings (Loss) Per Share | $ | 0.16 |  |  | $ | (0.05) |  |  | $ | (0.49) |  |  | $ | 0.18 |
2019 |  |  |  |  |  |  |
Operating Revenues | $ | 1,869.8 |  |  | $ | 1,010.4 |  |  | $ | 931.5 |  |  | $ | 1,397.2 |
Operating Income (Loss) | 374.2 |  |  | 463.5 |  |  | 91.0 |  |  | (38.0) |
Net Income (Loss) | 218.9 |  |  | 296.9 |  |  | 6.6 |  |  | (139.3) |
Preferred Dividends | (13.8) |  |  | (13.8) |  |  | (13.8) |  |  | (13.7) |
Net Income (Loss) Available to Common Shareholders | 205.1 |  |  | 283.1 |  |  | (7.2) |  |  | (153.0) |
Earnings (Loss) Per Share |  |  |  |  |  |  |
Basic Earnings (Loss) Per Share | $ | 0.55 |  |  | $ | 0.76 |  |  | $ | (0.02) |  |  | $ | (0.41) |
Diluted Earnings (Loss) Per Share | $ | 0.55 |  |  | $ | 0.75 |  |  | $ | (0.02) |  |  | $ | (0.41) |

(1) Net income for the first quarter of 2020 was impacted by $280.2 million loss on sale of the Massachusetts Business. Net income for the first quarter of 2019 was impacted by $108.0 million in insurance recoveries (pretax) related to the Greater Lawrence Incident. See Note 1, "Company Structure and Principles of Consolidation" and Note 20-E, "Other Matters" for additional information.
(2) Net income for the second quarter of 2020 was impacted by an additional $84.4 million loss on sale of the Massachusetts Business. Net income for the second quarter of 2019 was impacted by $297.0 million in insurance recoveries (pretax) related to the Greater Lawrence Incident. See Note 1, "Company Structure and Principles of Consolidation" and Note 20-E, "Other Matters" for additional information.
(3) Net loss for the third quarter of 2020 was impacted by $243.4 million loss on early extinguishments of long-term debt. See Note 15, "Long-Term Debt" for additional information.
(4) Net loss for the fourth quarter of 2019 was impacted by an impairment charge of $204.8 million for goodwill and an impairment charge of $209.7 million for franchise rights, in each case related to Columbia of Massachusetts. For additional information, see Note 7, "Goodwill and Other Intangible Assets."
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Notes to Consolidated Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
26. Supplemental Cash Flow Information
The following table provides additional information regarding our Consolidated Statements of Cash Flows for the years ended December 31, 2020, 2019 and 2018:

Year Ended December 31, (in millions) | 2020 |  | 2019 |  | 2018
Supplemental Disclosures of Cash Flow Information |  |  |  |  |
Non-cash transactions: |  |  |  |  |
Capital expenditures included in current liabilities | $ | 170.4 |  |  | $ | 223.6 |  |  | $ | 152.0 |
Assets acquired under a finance lease | 59.3 |  |  | 26.4 |  |  | 54.6 |
Assets acquired under an operating lease | 10.9 |  |  | 13.4 |  |  | — |
Reclassification of other property to regulatory assets(1) | — |  |  | — |  |  | 245.3 |
Assets recorded for asset retirement obligations(2) | 91.5 |  |  | 54.6 |  |  | 78.1 |
Obligation to developer at formation of joint venture(3) | 69.7 |  |  | — |  |  | — |
Schedule of interest and income taxes paid: |  |  |  |  |
Cash paid for interest, net of interest capitalized amounts | $ | 349.0 |  |  | $ | 349.7 |  |  | $ | 354.2 |
Cash paid for income taxes, net of refunds(4) | (1.0) |  |  | 10.8 |  |  | 3.3 |

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

Twelve months ended December 31, 2020
|  |  | Additions |  |  |  |  |
($ in millions) | Balance Jan. 1, 2020 |  | Charged to Costs and Expenses |  | Charged to Other Account (1) |  |  | Deductions for Purposes for which Reserves were Created |  | Balance Dec. 31, 2020
Reserves Deducted in Consolidated Balance Sheet from Assets to Which They Apply: |  |  |  |  |  |  |  |  |  |
Reserve for accounts receivable | $ | 19.2 |  |  | $ | 31.6 |  |  | $ | 33.0 |  |  |  | $ | 31.5 |  |  | $ | 52.3 |
Reserve for other investments | 3.0 |  |  | — |  |  | — |  |  |  | 3.0 |  |  | — |
Twelve months ended December 31, 2019
|  |  | Additions |  |  |  |  |
($ in millions) | Balance Jan. 1, 2019 |  | Charged to Costs and Expenses |  | Charged to Other Account (1) |  |  | Deductions for Purposes for which Reserves were Created |  | Balance Dec. 31, 2019
Reserves Deducted in Consolidated Balance Sheet from Assets to Which They Apply: |  |  |  |  |  |  |  |  |  |
Reserve for accounts receivable | $ | 21.1 |  |  | $ | 21.6 |  |  | $ | 41.3 |  |  |  | $ | 64.8 |  |  | $ | 19.2 |
Reserve for other investments | 3.0 |  |  | — |  |  | — |  |  |  | — |  |  | 3.0 |
Twelve months ended December 31, 2018
|  |  | Additions |  |  |  |  |
($ in millions) | Balance Jan. 1, 2018 |  | Charged to Costs and Expenses |  | Charged to Other Account (1) |  |  | Deductions for Purposes for which Reserves were Created |  | Balance Dec. 31, 2018
Reserves Deducted in Consolidated Balance Sheet from Assets to Which They Apply: |  |  |  |  |  |  |  |  |  |
Reserve for accounts receivable | $ | 18.3 |  |  | $ | 20.2 |  |  | $ | 43.7 |  |  |  | $ | 61.1 |  |  | $ | 21.1 |
Reserve for other investments | 3.0 |  |  | — |  |  | — |  |  |  | — |  |  | 3.0 |

(1) Charged to Other Accounts reflects the deferral of bad debt expense to a regulatory asset.
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N I S OURCE I NC.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
Our chief executive officer and chief financial officer are responsible for evaluating the effectiveness of disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)). Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by the Company in reports that are filed or submitted under the Exchange Act are accumulated and communicated to management, including our chief executive officer and chief financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon that evaluation, our chief executive officer and chief financial officer concluded that, as of the end of the period covered by this report, disclosure controls and procedures were effective to provide reasonable assurance that financial information was processed, recorded and reported accurately.
Management’s Annual Report on Internal Control over Financial Reporting
Our management, including our chief executive officer and chief financial officer, are responsible for establishing and maintaining internal control over financial reporting, as such term is defined under Rule 13a-15(f) or Rule 15d-15(f) promulgated under the Exchange Act. However, management would note that a control system can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Our management has adopted the 2013 framework set forth in the Committee of Sponsoring Organizations of the Treadway Commission report, Internal Control - Integrated Framework, the most commonly used and understood framework for evaluating internal control over financial reporting, as its framework for evaluating the reliability and effectiveness of internal control over financial reporting. During 2020, we conducted an evaluation of our internal control over financial reporting. Based on this evaluation, management concluded that our internal control over financial reporting was effective as of the end of the period covered by this annual report.
Deloitte & Touche LLP, our independent registered public accounting firm, issued an attestation report on our internal controls over financial reporting which is included herein.
Changes in Internal Controls
There have been no changes in our internal control over financial reporting during the most recently completed quarter covered by this report that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
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ITEM 9A. CONTROLS AND PROCEDURES
N I S OURCE I NC.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the shareholders and the Board of Directors of NiSource Inc.
Opinion on Internal Control over Financial Reporting
We have audited the internal control over financial reporting of NiSource Inc. and subsidiaries (the “Company”) as of December 31, 2020, 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, 2020, based on criteria established in Internal Control — Integrated Framework (2013) issued by COSO.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as of and for the year ended December 31, 2020, of the Company and our report dated February 17, 2021, 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 17, 2021
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ITEM 9B. OTHER INFORMATION
N I S OURCE I NC.
Not applicable.
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PART III
N I S OURCE I NC.
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Except for the information required by this item with respect to our executive officers included at the end of Part I of this report on Form 10-K, the information required by this Item 10 is incorporated herein by reference to the discussion in "Proposal 1 Election of Directors," "Corporate Governance," and "Delinquent Section 16(a) Reports"" of the Proxy Statement for the Annual Meeting of Stockholders to be held on May 25, 2021.
ITEM 11. EXECUTIVE COMPENSATION
The information required by this Item 11 is incorporated herein by reference to the discussion in "Corporate Governance - Compensation Committee Interlocks and Insider Participation," "Director Compensation," "Executive Compensation," and "Executive Compensation - Compensation Committee Report," of the Proxy Statement for the Annual Meeting of Stockholders to be held on May 25, 2021.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The information required by this Item 12 is incorporated herein by reference to the discussion in "Security Ownership of Certain Beneficial Owners and Management" and "Equity Compensation Plan Information" of the Proxy Statement for the Annual Meeting of Stockholders to be held on May 25, 2021.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
The information required by this Item 13 is incorporated herein by reference to the discussion in "Corporate Governance - Policies and Procedures with Respect to Transactions with Related Persons" and "Corporate Governance - Director Independence" of the Proxy Statement for the Annual Meeting of Stockholders to be held on May 25, 2021.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
The information required by this Item 14 is incorporated herein by reference to the discussion in "Independent Registered Public Accounting Firm Fees" of the Proxy Statement for the Annual Meeting of Stockholders to be held on May 25, 2021.
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PART IV
N I S OURCE I NC.
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
Financial Statements and Financial Statement Schedules
The following financial statements and financial statement schedules filed as a part of the Annual Report on Form 10-K are included in Item 8, "Financial Statements and Supplementary Data."

| Page
Report of Independent Registered Public Accounting Firm | 51
Statements of Consolidated Income (Loss) | 53
Statements of Consolidated Comprehensive Income (Loss) | 54
Consolidated Balance Sheets | 55
Statements of Consolidated Cash Flows | 57
Statements of Consolidated Stockholders’ Equity | 58
Notes to Consolidated Financial Statements | 60
Schedule II | 117

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

EXHIBIT NUMBER | DESCRIPTION OF ITEM
(1.1) | Form of Equity Distribution Agreement (incorporated by reference to Exhibit 1.1 to the NiSource Inc. Form 8-K filed on November 1, 2018).
(1.2) | Form of Master Forward Sale Confirmation (incorporated by reference to Exhibit 1.2 to the NiSource Inc. Form 8-K filed on November 1, 2018).
(2.1) | Separation and Distribution Agreement, dated as of June 30, 2015, by and between NiSource Inc. and Columbia Pipeline Group, Inc. (incorporated by reference to Exhibit 2.1 to the NiSource Inc. Form 8-K filed on July 2, 2015).
(2.2) | Asset Purchase Agreement, dated as of February 26, 2020, by and among NiSource Inc., Bay State Gas Company d/b/a Columbia Gas of Massachusetts and Eversource Energy (incorporated by reference to Exhibit 2.1 of the NiSource Inc. Form 8-K filed on February 27, 2020).***
(3.1) | Amended and Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 to the Registrant’s Form 10-Q, filed with the Commission on August 3, 2015).
(3.2) | Certificate of Amendment of Amended and Restated Certificate of Incorporation of NiSource dated May 7, 2019 (incorporated by reference to Exhibit 3.1 of the NiSource Inc. Form 8-K filed on May 8, 2019).
(3.3) | Bylaws of NiSource Inc., as amended and restated through January 26, 2018 (incorporated by reference to Exhibit 3.1 to the NiSource Inc. Form 8-K filed on January 26, 2018).
(3.4) | Certificate of Designations of 5.65% Series A Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Stock (incorporated by reference to Exhibit 3.1 of the NiSource Inc. Form 8-K filed on June 12, 2018).
(3.5) | Form of Certificate of Designations of 6.50% Series B Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Stock (incorporated by reference to Exhibit 3.1 of the NiSource Inc. Form 8-K filed on November 29, 2018).
(3.6) | Certificate of Designations of 6.50% Series B Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Stock (incorporated by reference to Exhibit 3.1 of the NiSource Inc. Form 8-K filed on December 6, 2018).

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(3.7) | Certificate of Designations of Series B-1 Preferred Stock (incorporated by reference to Exhibit 3.1 to the NiSource Inc. Form 8-K filed on December 27, 2018).
(4.1) | Indenture, dated as of March 1, 1988, by and between Northern Indiana Public Service Company ("NIPSCO") and Manufacturers Hanover Trust Company, as Trustee (incorporated by reference to Exhibit 4 to the NIPSCO Registration Statement (Registration No. 33-44193)).
(4.2) | First Supplemental Indenture, dated as of December 1, 1991, by and between Northern Indiana Public Service Company and Manufacturers Hanover Trust Company, as Trustee (incorporated by reference to Exhibit 4.1 to the NIPSCO Registration Statement (Registration No. 33-63870)).
(4.3) | Indenture Agreement, dated as of February 14, 1997, by and between NIPSCO Industries, Inc., NIPSCO Capital Markets, Inc. and Chase Manhattan Bank as trustee (incorporated by reference to Exhibit 4.1 to the NIPSCO Industries, Inc. Registration Statement (Registration No. 333-22347)).
(4.4) | Second Supplemental Indenture, dated as of November 1, 2000, by and among NiSource Capital Markets, Inc., NiSource Inc., New NiSource Inc., and The Chase Manhattan Bank, as trustee (incorporated by reference to Exhibit 4.45 to the NiSource Inc. Form 10-K for the period ended December 31, 2000).
(4.5) | Indenture, dated November 14, 2000, among NiSource Finance Corp., NiSource Inc., as guarantor, and The Chase Manhattan Bank, as Trustee (incorporated by reference to Exhibit 4.1 to the NiSource Inc. Form S-3, dated November 17, 2000 (Registration No. 333-49330)).
(4.6) | Form of 3.490% Notes due 2027 (incorporated by reference to Exhibit 4.1 to the NiSource Inc. Form 8-K filed on May 17, 2017).
(4.7) | Form of 4.375% Notes due 2047 (incorporated by reference to Exhibit 4.2 to the NiSource Inc. Form 8-K filed on May 17, 2017).
(4.8) | Form of 3.950% Notes due 2048 (incorporated by reference to Exhibit 4.1 to the NiSource Inc. Form 8-K filed on September 8, 2017).
(4.9) | Form of 2.650% Notes due 2022 (incorporated by reference to Exhibit 4.1 to the NiSource Inc. Form 8-K filed on November 14, 2017).
(4.10) | Second Supplemental Indenture, dated as of November 30, 2017, between NiSource Inc. and The Bank of New York Mellon, as trustee (incorporated by reference to Exhibit 4.4 to Post-Effective Amendment No. 1 to Form S-3 filed November 30, 2017 (Registration No. 333-214360)).
(4.11) | Third Supplemental Indenture, dated as of November 30, 2017, between NiSource Inc. and The Bank of New York Mellon, as trustee (incorporated by reference to Exhibit 4.2 to the NiSource Inc. Form 8-K filed on December 1, 2017).
(4.12) | Second Supplemental Indenture, dated as of February 12, 2018, between Northern Indiana Public Service Company and The Bank of New York Mellon, solely as successor trustee under the Indenture dated as of March 1, 1988 between the Company and Manufacturers Hanover Trust Company, as original trustee. (incorporated by reference to Exhibit 4.1 to the NiSource Inc. Form 10-Q filed on May 2, 2018).
(4.13) | Third Supplemental Indenture, dated as of June 11, 2018, by and between NiSource Inc. and The Bank of New York Mellon, as trustee (including form of 3.650% Notes due 2023) (incorporated by reference to Exhibit 4.1 of the NiSource Inc. Form 8-K filed on June 12, 2018).
(4.14) | Deposit Agreement, dated as of December 5, 2018, among NiSource, Inc., Computershare Inc. and Computershare Trust Company, N.A., acting jointly as depositary, and the holders from time to time of the depositary receipts described therein (incorporated by reference to Exhibit 4.1 of the NiSource Inc. Form 8-K filed on December 6, 2018).
(4.15) | Form of Depositary Receipt (incorporated by reference to Exhibit 4.1 of the NiSource Inc. Form 8-K filed on December 6, 2018).
(4.16) | Amended and Restated Deposit Agreement, dated as of December 27, 2018, among NiSource, Inc., Computershare Inc. and Computershare Trust Company, N.A., acting jointly as depositary, and the holders from time to time of the depositary receipts described therein (incorporated by reference to Exhibit 4.1 to the NiSource Inc. Form 8-K filed on December 27, 2018).
(4.17) | Form of Depositary Receipt (incorporated by reference to Exhibit 4.1 to the NiSource Inc. Form 8-K filed on December 27, 2018).

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(4.18) | Form of 2.950% Notes due 2029 (incorporated by reference to Exhibit 4.1 to NiSource Inc. Form 8-K filed on August 12, 2019).
(4.19) | Amended and Restated NiSource Inc. Employee Stock Purchase Plan (incorporated by reference to Exhibit C to the Registrant’s Definitive Proxy Statement on Schedule 14A, filed with the Commission on April 1, 2019).
(4.20) | Description of NiSource Inc.’s Securities Registered Under Section 12 of the Exchange Act. (incorporated by reference to Exhibit 4.20 of the NiSource Form 10-K filed on February 28, 2020)
(4.21) | Form of 3.600% Notes due 2030 (incorporated by reference to Exhibit 4.1 to the NiSource Inc. Form 8-K filed on April 8, 2020).
(4.22) | Form of 0.950% Notes due 2025 (incorporated by reference to Exhibit 4.1 to the NiSource Inc. Form 8-K filed on August 18, 2020).
(4.23) | Form of 1.700% Notes due 2031(incorporated by reference to Exhibit 4.2 to the NiSource Inc. Form 8-K filed on August 18, 2020).
(10.1) | 2010 Omnibus Incentive Plan (incorporated by reference to Exhibit B to the NiSource Inc. Definitive Proxy Statement to Stockholders for the Annual Meeting held on May 11, 2010, filed on April 2, 2010).*
(10.2) | First Amendment to the 2010 Omnibus Incentive Plan (incorporated by reference to Exhibit 10.2 to the NiSource Inc. Form 10-K filed on February 18, 2014.)*
(10.3) | 2010 Omnibus Incentive Plan (incorporated by reference to Exhibit C to the NiSource Inc. Definitive Proxy Statement to Stockholders for the Annual Meeting held on May 12, 2015, filed on April 7, 2015).*
(10.4) | Second Amendment to the NiSource Inc. 2010 Omnibus Incentive Plan (incorporated by reference to Exhibit 10.1 to the NiSource Inc. Form 8-K filed October 23, 2015.)*
(10.5) | Form of Amended and Restated 2013 Performance Share Agreement effective on implementation of the spin-off on July 1, 2015, (under the 2010 Omnibus Incentive Plan)(incorporated by reference to Exhibit 10.1 to the NiSource Inc. Form 10-Q filed on November 3, 2015).*
(10.6) | Form of Amended and Restated 2014 Performance Share Agreement effective on the implementation of the spin-off on July 1, 2015, (under the 2010 Omnibus Incentive Plan)(incorporated by reference to Exhibit 10.2 to the NiSource Inc. Form 10-Q filed on November 3, 2015).*
(10.7) | Form of Amendment to Restricted Stock Unit Award Agreement related to Vested but Unpaid NiSource Restricted Stock Unit Awards for Nonemployee Directors of NiSource entered into as of July 13, 2015 (incorporated by reference to Exhibit 10.3 to the NiSource Inc. Form 10-Q filed on November 3, 2015).*
(10.8) | NiSource Inc. Nonemployee Director Retirement Plan, as amended and restated effective May 13, 2008 (incorporated by reference to Exhibit 10.2 to the NiSource Inc. Form 10-K filed on February 27, 2009).*
(10.9) | Supplemental Life Insurance Plan effective January 1, 1991, as amended, (incorporated by reference to Exhibit 2 to the NIPSCO Industries, Inc. Form 8-K filed on March 25, 1992).*
(10.10) | Revised Form of Change in Control and Termination Agreement (incorporated by reference to Exhibit 10.2 to the NiSource Inc. Form 8-K filed on October 23, 2015.)*
(10.11) | Form of Restricted Stock Agreement under the 2010 Omnibus Incentive Plan (incorporated by reference to Exhibit 10.18 to the NiSource Inc. Form 10-K filed on February 28, 2011).*
(10.12) | Form of Restricted Stock Unit Award Agreement for Non-employee directors under the Non-employee Director Stock Incentive Plan (incorporated by reference to Exhibit 10.19 to the NiSource Inc. Form 10-K filed on February 28, 2011).*
(10.13) | Form of Restricted Stock Unit Award Agreement for Nonemployee Directors under the 2010 Omnibus Incentive Plan (incorporated by reference to Exhibit 10.1 to NiSource Inc. Form 10-Q filed on August 2, 2011).*
(10.14) | Form of Restricted Stock Unit Award Agreement under the 2010 Omnibus Incentive Plan (incorporated by reference to Exhibit 10.17 to the NiSource Inc. Form 10-K filed on February 22, 2017).*
(10.15) | Form of Restricted Stock Unit Award Agreement for Nonemployee Directors under the 2010 Omnibus Incentive Plan (incorporated by reference to Exhibit 10.18 to the NiSource Inc. Form 10-K filed on February 22, 2017). *

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(10.16) | Amended and Restated NiSource Inc. Executive Deferred Compensation Plan effective November 1, 2012 (incorporated by reference to Exhibit 10.21 to the NiSource Inc. Form 10-K filed on February 19, 2013).*
(10.17) | NiSource Inc. Executive Severance Policy, as amended and restated, effective January 1, 2015 (incorporated by reference to Exhibit 10.21 to the NiSource Inc. Form 10-K filed on February 18, 2015).*
(10.18) | Note Purchase Agreement, dated as of August 23, 2005, by and among NiSource Finance Corp., as issuer, NiSource Inc., as guarantor, and the purchasers named therein (incorporated by reference to Exhibit 10.1 to the NiSource Inc. Current Report on Form 8-K filed on August 26, 2005).
(10.19) | Amendment No. 1, dated as of November 10, 2008, to the Note Purchase Agreement by and among NiSource Finance Corp., as issuer, NiSource Inc., as guarantor, and the purchasers whose names appear on the signature page thereto (incorporated by reference to Exhibit 10.30 to the NiSource Inc. Form 10-K filed on February 27, 2009).
(10.20) | Letter Agreement, dated as of March 17, 2015, by and between NiSource Inc. and Donald Brown. (incorporated by reference Exhibit 10.1 to the NiSource Inc. Form 10-Q filed on April 30, 2015).*
(10.21) | Letter Agreement, dated as of February 23, 2016, by and between NiSource Inc. and Pablo A. Vegas. (incorporated by reference Exhibit 10.29 to the NiSource Inc. Form 10-K filed on February 22, 2017).*
(10.22) | Employee Matters Agreement, dated as of June 30, 2015, by and between NiSource Inc. and Columbia Pipeline Group, Inc. (incorporated by reference to Exhibit 10.2 of the NiSource Inc. Form 8-K filed on July 2, 2015).
(10.23) | Form of Change in Control and Termination Agreement (incorporated by reference to Exhibit 10.1 to the NiSource Inc. Form 10-Q filed on August 2, 2017).*
(10.24) | Form of Performance Share Award Agreement under the 2010 Omnibus Incentive Plan (incorporated by reference to Exhibit 10.33 to the NiSource Form 10-K filed on February 20, 2018).*
(10.25) | Form of Restricted Stock Unit Award Agreement under the 2010 Omnibus Incentive Plan (incorporated by reference to Exhibit 10.34 to the NiSource Form 10-K filed on February 20, 2018).*
(10.26) | Common Stock Subscription Agreement, dated as of May 2, 2018, by and among NiSource Inc. and the purchasers named therein (incorporated by reference to Exhibit 10.1 of the NiSource Inc. Form 8-K filed on May 2, 2018).
(10.27) | Registration Rights Agreement, dated as of May 2, 2018, by and among NiSource Inc. and the purchasers named therein (incorporated by reference to Exhibit 10.2 of the NiSource Inc. Form 8-K filed on May 2, 2018).
(10.28) | Purchase Agreement, dated as of June 6, 2018, by and among NiSource Inc. and Credit Suisse Securities (USA) LLC, J.P. Morgan Securities LLC, Morgan Stanley & Co. LLC and MUFG Securities Americas Inc., as representatives, relating to the 5.650% Series A Preferred Stock (incorporated by reference to Exhibit 10.1 of the NiSource Inc. Form 8-K filed on June 12, 2018).
(10.29) | Purchase Agreement, dated as of June 6, 2018, by and among NiSource Inc. and Credit Suisse Securities (USA) LLC, J.P. Morgan Securities LLC, Morgan Stanley & Co. LLC and MUFG Securities Americas Inc., as representatives, relating to the 3.650% Notes due 2023 (incorporated by reference to Exhibit 10.2 of the NiSource Inc. Form 8-K filed on June 12, 2018).
(10.30) | Registration Rights Agreement, dated as of June 11, 2018, by and among NiSource Inc. and Credit Suisse Securities (USA) LLC, J.P. Morgan Securities LLC, Morgan Stanley & Co. LLC and MUFG Securities Americas Inc., as representatives, relating to the 5.650% Series A Preferred Stock (incorporated by reference to Exhibit 10.3 of the NiSource Inc. Form 8-K filed on June 12, 2018).
(10.31) | Registration Rights Agreement, dated as of June 11, 2018, by and among NiSource Inc. and Credit Suisse Securities (USA) LLC, J.P. Morgan Securities LLC, Morgan Stanley & Co. LLC and MUFG Securities Americas Inc., as representatives, relating to the 3.650% Notes due 2023 (incorporated by reference to Exhibit 10.4 of the NiSource Inc. Form 8-K filed on June 12, 2018).
(10.32) | Form of 2019 Performance Share Award Agreement under the 2010 Omnibus Incentive Plan. (incorporated by reference to Exhibit 10.45 of the NiSource Inc. Form 10-K filed on February 20, 2019).*

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(10.33) | Fifth Amended and Restated Revolving Credit Agreement, dated as of February 20, 2019, among NiSource Inc., as Borrower, the Lenders party thereto, Barclays Bank PLC, as Administrative Agent, Citibank, N.A. and MUFG Bank, Ltd., as Co-Syndication Agents, Credit Suisse AG, Cayman Islands Branch, JPMorgan Chase Bank, N.A. and Wells Fargo Bank, National Association, as Co-Documentation Agents, and Barclays Bank PLC, Citibank, N.A., MUFG Bank, Ltd., Credit Suisse Loan Funding LLC, JPMorgan Chase Bank, N.A. and Wells Fargo Securities, LLC, as Joint Lead Arrangers and Joint Bookrunners (incorporated by reference to Exhibit 10.1 of the NiSource Inc. Form 8-K filed on February 20, 2019).
(10.34) | Amended and Restated NiSource Inc. Employee Stock Purchase Plan adopted as of February 1, 2019 (incorporated by reference to Exhibit C to the NiSource Inc. Definitive Proxy Statement to Stockholders for the Annual Meeting to be held on May 7, 2019, filed on April 1, 2019).
(10.35) | Form of Performance Share Award Agreement (incorporated by reference to Exhibit 10.39 of the NiSource Form 10-K filed on February 28, 2020).*
(10.36) | Form of Restricted Stock Unit Award Agreement (incorporated by reference to Exhibit 10.40 of the NiSource Form 10-K filed on February 28, 2020). *
(10.37) | Form of Cash-Based Award Agreement (incorporated by reference to Exhibit 10.41 of the NiSource Form 10-K filed on February 28, 2020). *
(10.38) | Columbia Gas of Massachusetts Plea Agreement dated February 26, 2020 (incorporated by reference to Exhibit 10.2 of the NiSource Inc. Form 8-K filed on February 27, 2020).
(10.39) | NiSource Deferred Prosecution Agreement dated February 26, 2020 (incorporated by reference to Exhibit 10.1 of the NiSource Inc. Form 8-K filed on February 27, 2020).
(10.40) | Term Loan Agreement, dated as of April 1, 2020, among NiSource Inc., as Borrower, the lenders party thereto, and KeyBank National Association, as Administrative Agent, and KeyBank National Association, PNC Bank, National Association and U.S. Bank National Association, as Joint Lead Arrangers and Joint Bookrunners (incorporated by reference to Exhibit 10.1 of the NiSource Inc. Form 8-K filed on April 1, 2020).
(10.41) | 2020 Omnibus Incentive Plan (incorporated by reference to Exhibit A to the NiSource Inc. Definitive Proxy Statement to Stockholders for the Annual Meeting held on May 19, 2020, filed on April 13, 2020).*
(10.42) | Settlement Agreement, dated July 2, 2020, by and among Bay State Gas Company d/b/a Columbia Gas of Massachusetts, NiSource Inc., Eversource Gas Company of Massachusetts, Eversource Energy, the Massachusetts Attorney General’s Office, the Massachusetts Department of Energy Resources the Low-Income Weatherization and Fuel Assistance Program Network (incorporated by reference to Exhibit 10.1 of the NiSource Inc. Form 8-K filed on July 6, 2020).
(10.43) | Form of Restricted Stock Unit Award Agreement for Nonemployee Directors under the 2020 Omnibus Incentive Plan (incorporated by reference to Exhibit 10.2 of the NiSource Inc. Form 10-Q filed on August 5, 2020).*
(10.44) | Addendum to Plea Agreement filed on or about June 21, 2020 in the United States District Court for the District of Massachusetts (incorporated by reference to Exhibit 10.4 of the NiSource Inc. Form 10-Q filed on August 5, 2020).
(10.45) | Letter Agreement by and among NiSource Inc., Bay State Gas Company d/b/a Columbia Gas of Massachusetts and Eversource Energy Relating to Asset Purchase Agreement, dated October 9, 2020 (incorporated by reference to Exhibit 10.3 to the NiSource Inc. Form 10-Q filed on November 2, 2020).***
(10.46) | NiSource Inc. Supplemental Executive Retirement Plan, as amended and restated effective November 1, 2020 (incorporated by reference to Exhibit 10.4 to the NiSource Inc. Form 10-Q filed on November 2, 2020).*
(10.47) | Pension Restoration Plan for NiSource Inc. and Affiliates, as amended and restated effective November 1, 2020 (incorporated by reference to Exhibit 10.5 to the NiSource Inc. Form 10-Q filed on November 2, 2020).
(10.48) | Savings Restoration Plan for NiSource Inc. and Affiliates, as amended and restated effective November 1, 2020 (incorporated by reference to Exhibit 10.6 to the NiSource Inc. Form 10-Q filed on November 2, 2020).*
(10.49) | NiSource Inc. Executive Severance Policy, as amended and restated effective October 19, 2020 (incorporated by reference to Exhibit 10.7 to the NiSource Inc. Form 10-Q filed on November 2, 2020).*
(10.50) | NiSource Next Voluntary Separation Program, effective as of August 5, 2020 (incorporated by reference to Exhibit 10.8 to the NiSource Inc. Form 10-Q filed on November 2, 2020).*

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(10.51) | Letter Agreement dated October 19, 2020 by and between NiSource Inc. and Carrie Hightman (incorporated by reference to Exhibit 10.9 to the NiSource Inc. Form 10-Q filed on November 2, 2020).*
(10.52) | Amendment to Settlement Agreement by and among Bay State Gas Company d/b/a Columbia Gas of Massachusetts, NiSource Inc., Eversource Gas Company of Massachusetts, Eversource Energy, the Massachusetts Attorney General’s Office, the Massachusetts Department of Energy Resources and the Low-Income Weatherization and Fuel Assistance Program Network, dated September 29, 2020 (incorporated by reference to Exhibit 10.2 to the NiSource Inc. Form 10-Q filed on November 2, 2020).
(10.53) | Form of Restricted Stock Unit Award Agreement.* **
(10.54) | Form of Performance Share Unit Award Agreement.* **
(10.55) | Form of Special Performance Share Unit Award Agreement.* **
(21) | List of Subsidiaries.**
(23) | Consent of Deloitte & Touche LLP.**
(31.1) | Certification of Chief Executive Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.**
(31.2) | Certification of Chief Financial Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.**
(32.1) | Certification of Chief Executive Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith).**
(32.2) | Certification of Chief Financial Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith).**
(101.INS) | Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document. **
(101.SCH) | Inline XBRL Schema Document.**
(101.CAL) | Inline XBRL Calculation Linkbase Document.**
(101.LAB) | Inline XBRL Labels Linkbase Document.**
(101.PRE) | Inline XBRL Presentation Linkbase Document.**
(101.DEF) | Inline XBRL Definition Linkbase Document.**
(104) | Cover page Interactive Data File (formatted as inline XBRL, and contained in Exhibit 101.)

* | Management contract or compensatory plan or arrangement of NiSource Inc.

** | Exhibit filed herewith.

*** | Schedules and exhibits have been omitted pursuant to Item 601(b)(2) of Regulation S-K. NiSource agrees to furnish supplementally a copy of any omitted schedules or exhibits to the SEC upon request.

References made to NIPSCO filings can be found at Commission File Number 001-04125. References made to NiSource Inc. filings made prior to November 1, 2000 can be found at Commission File Number 001-09779.
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ITEM 16. FORM 10-K SUMMARY
None
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, hereunto duly authorized.

|  | NiSource Inc.
|  | (Registrant)
Date: February 17, 2021 | By: | /s/ JOSEPH HAMROCK
|  | Joseph Hamrock
|  | President, Chief Executive Officer and Director
|  | (Principal Executive Officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

|  | /s/ | JOSEPH HAMROCK |  | President, Chief | Date: February 17, 2021
|  |  | Joseph Hamrock |  | Executive Officer and Director (Principal Executive Officer) |
|  | /s/ | DONALD E. BROWN |  | Executive Vice President and | Date: February 17, 2021
|  |  | Donald E. Brown |  | Chief Financial Officer (Principal Financial Officer) |
|  | /s/ | GUNNAR J. GODE |  | Vice President and | Date: February 17, 2021
|  |  | Gunnar J. Gode |  | Chief Accounting Officer (Principal Accounting Officer) |
|  | /s/ | KEVIN T. KABAT |  | Chairman of the Board | Date: February 17, 2021
|  |  | Kevin T. Kabat |  |  |
|  | /s/ | PETER A. ALTABEF |  | Director | Date: February 17, 2021
|  |  | Peter A. Altabef |  |  |
|  | /s/ | THEODORE H. BUNTING, JR. |  | Director | Date: February 17, 2021
|  |  | Theodore H. Bunting, Jr. |  |  |
|  | /s/ | ERIC L. BUTLER |  | Director | Date: February 17, 2021
|  |  | Eric L. Butler |  |  |
|  | /s/ | ARISTIDES S. CANDRIS |  | Director | Date: February 17, 2021
|  |  | Aristides S. Candris |  |  |
|  | /s/ | WAYNE S. DEVEYDT |  | Director | Date: February 17, 2021
|  |  | Wayne S. DeVeydt |  |  |
|  | /s/ | DEBORAH A. HENRETTA |  | Director | Date: February 17, 2021
|  |  | Deborah A. Henretta |  |  |
|  | /s/ | DEBORAH A.P. HERSMAN |  | Director | Date: February 17, 2021
|  |  | Deborah A. P. Hersman |  |  |
|  | /s/ | MICHAEL E. JESANIS |  | Director | Date: February 17, 2021
|  |  | Michael E. Jesanis |  |  |
|  | /s/ | CAROLYN Y. WOO |  | Director | Date: February 17, 2021
|  |  | Carolyn Y. Woo |  |  |
|  | /s/ | LLOYD M. YATES |  | Director | Date: February 17, 2021
|  |  | Lloyd M. Yates |  |  |

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