10-K

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, 2019

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

Indicate 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 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 $10,713,311,150 based upon the June 28, 2019, closing price of $28.80 on the New York Stock Exchange.

There were 382,263,348 shares of Common Stock outstanding as of February 18, 2020.

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 19, 2020.

CONTENTS

		Page No.
Defined Terms		3
Part I
Item 1.	Business	6
Item 1A.	Risk Factors	9
Item 1B.	Unresolved Staff Comments	21
Item 2.	Properties	21
Item 3.	Legal Proceedings	21
Item 4.	Mine Safety Disclosures	21
Supplemental Item. Information about our Executive Officers		22
Part II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	23
Item 6.	Selected Financial Data	25
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	27
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	125
Item 9A.	Controls and Procedures	125
Item 9B.	Other Information	126
Part III
Item 10.	Directors, Executive Officers and Corporate Governance	128
Item 11.	Executive Compensation	128
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	128
Item 13.	Certain Relationships and Related Transactions, and Director Independence	128
Item 14.	Principal Accounting Fees and Services	128
Part IV
Item 15.	Exhibits, Financial Statement Schedules	129
Signatures		134

2

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
CPG (former subsidiary)	Columbia Pipeline Group, Inc.
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
AMRP	Accelerated Main Replacement Program
AMT	Alternative Minimum Tax
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)
DPA	Deferred prosecution agreement
DPU	Department of Public Utilities
DSIC	Distribution System Investment Charge
DSM	Demand Side Management
ECT	Environmental Cost Tracker
EERM	Environmental Expense Recovery Mechanism
ELG	Effluent Limitation Guidelines
EPA	United States Environmental Protection Agency
EPS	Earnings per share
FAC	Fuel adjustment clause
FASB	Financial Accounting Standards Board

3

DEFINED TERMS
FERC	Federal Energy Regulatory Commission
FMCA	Federally Mandated Cost Adjustment
GAAP	Generally Accepted Accounting Principles
GCA	Gas cost adjustment
GCR	Gas cost recovery
GHG	Greenhouse gas
GSEP	Gas System Enhancement Program
GWh	Gigawatt hours
IRIS	Infrastructure Replacement and Improvement Surcharge
IRP	Infrastructure Replacement Program
IRS	Internal Revenue Service
IURC	Indiana Utility Regulatory Commission
LDCs	Local distribution companies
LIBOR	London inter-bank offered rate
LIFO	Last-in, first-out
MA DOR	Massachusetts Department of Revenue
Massachusetts Business	All of the assets being sold to, and liabilities being 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
PISCC	Post-in-service carrying charges
PPA	Power Purchase Agreement
PSC	Public Service Commission
PTC	Production Tax Credits
PUC	Public Utility Commission
PUCO	Public Utilities Commission of Ohio
RCRA	Resource Conservation and Recovery Act
ROU	Right of use
SAB	Staff accounting bulletin
SAVE	Steps to Advance Virginia's Energy Plan
Separation	The separation of our natural gas pipeline, midstream and storage business from our natural gas and electric utility business accomplished through a pro rata distribution to holders of our outstanding common stock of all the outstanding shares of common stock of CPG. The separation was completed on July 1, 2015.
SEC	Securities and Exchange Commission

4

DEFINED TERMS
SMRP	Safety Modification and Replacement Program
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
U.S. Attorney's Office	U.S. Attorney's Office for the District of Massachusetts
VSCC	Virginia State Corporation Commission
WCE	Whiting Clean Energy

Note regarding forward-looking statements

This Annual Report on Form 10-K contains “forward-looking statements,” within the meaning of Section 27A of the Securities Act of 1933, as amended (the "Securities Act"), and Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). Investors and prospective investors should understand that many factors govern whether any forward-looking statement contained herein will be or can be realized. Any one of those factors could cause actual results to differ materially from those projected. These forward-looking statements include, but are not limited to, statements concerning our plans, strategies, objectives, expected performance, expenditures, recovery of expenditures through rates, stated on either a consolidated or segment basis, and any and all underlying assumptions and other statements that are other than statements of historical fact. 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 debt obligations; any changes to our credit rating or the credit rating of certain of our subsidiaries; our ability to execute our growth strategy; changes in general economic, capital and commodity market conditions; pension funding obligations; economic regulation and the impact of regulatory rate reviews; our ability to obtain expected financial or regulatory outcomes; our ability to adapt to, and manage costs related to, advances in technology; any changes in our assumptions regarding the financial implications of 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; the pending sale of the Columbia of Massachusetts business, including the terms and closing conditions under the Asset Purchase Agreement; potential incidents and other operating risks associated with our business; our ability to obtain sufficient insurance coverage and whether such coverage will protect us against significant losses; the outcome of legal and regulatory proceedings, investigations, incidents, claims and litigation; any damage to our reputation, including in connection with the Greater Lawrence Incident; compliance with applicable laws, regulations and tariffs; compliance with environmental laws and the costs of associated liabilities; fluctuations in demand from residential and commercial customers; economic conditions of certain industries; the success of NIPSCO's electric generation strategy; the price of energy commodities and related transportation costs; the reliability of customers and suppliers to fulfill their payment and contractual obligations; potential impairments of goodwill or definite-lived intangible assets; changes in taxation and accounting principles; the impact of an aging infrastructure; the impact of climate change; potential cyber-attacks; construction risks and natural gas costs and supply risks; extreme weather conditions; the attraction and retention of a qualified workforce; the ability of our subsidiaries to generate cash; our ability to manage new initiatives and organizational changes; the performance of third-party suppliers and service providers; changes in the method for determining LIBOR and the potential replacement of the LIBOR benchmark interest rate; and other matters set forth in Item 1A, “Risk Factors” of this report, many 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.

5

ITEM 1. BUSINESS

NISOURCE INC.

NiSource Inc. is 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 approximately 4.0 million customers in seven 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 is one of the nation’s largest natural gas distribution companies, as measured by number of customers. 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 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 (referred to herein as 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. Refer to Note 6, "Goodwill and Other Intangible Assets," Note 19-C. "Legal Proceedings," and E. "Other Matters," in the Notes to Consolidated Financial Statements for more information.

On February 26, 2020, NiSource and Columbia of Massachusetts (together with NiSource, “Seller”) entered into an Asset Purchase Agreement (the "Asset Purchase Agreement") with Eversource, a Massachusetts voluntary association. 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 business of storing, distributing or transporting natural gas to residential, commercial and industrial customers in Massachusetts, as conducted by Columbia of Massachusetts, and Eversource agreed to assume certain liabilities of Columbia of Massachusetts and its affiliates. The liabilities assumed by Eversource under the Asset Purchase Agreement do not include, among others, any liabilities arising out the Greater Lawrence Incident or 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 occurs prior to the closing in connection with the Massachusetts Business. The Asset Purchase Agreement provides for a purchase price of $1,100 million in cash, subject to adjustment based on Columbia of Massachusetts’ net working capital as of the closing. The closing of the transactions contemplated by the Asset Purchase Agreement is subject to Hart-Scott-Rodino Antitrust Improvements Act of 1976 and regulatory approvals, resolution of certain proceedings before governmental bodies and other conditions. For additional information, see Note 26, “Subsequent Event,” in 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 23, "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 3.5 million customers in seven states and operate approximately 60,000 miles of pipeline located in our service areas described below. Through our wholly-owned subsidiary NiSource Gas Distribution Group, Inc., we own six distribution subsidiaries that provide natural gas to approximately 2.7 million residential, commercial and industrial customers in Ohio, Pennsylvania, Virginia, Kentucky, Maryland and Massachusetts. Additionally, we distribute natural gas to approximately 839,000 customers in northern Indiana through our wholly-owned subsidiary NIPSCO.

Electric Operations

We generate, transmit and distribute electricity through our subsidiary NIPSCO to approximately 476,000 customers in 20 counties in the northern part of Indiana and engage in wholesale 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 Sugar Creek, a CCGT plant located in West Terre Haute, IN with generating capacity of 571 MW, three gas-fired generating units located at NIPSCO’s coal-fired electric generating stations with a generating capacity of 186 MW and 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 2,847 MW.

6

ITEM 1. BUSINESS

NISOURCE INC.

In May 2018, NIPSCO completed the retirement of two coal-burning units (Units 7 and 8) at Bailly Generating Station, located in Chesterton, IN. These units had a generating capacity of approximately 460 MW.

NIPSCO’s transmission system, with voltages from 69,000 to 765,000 volts, consists of 3,005 circuit miles. NIPSCO is interconnected with five neighboring electric utilities. During the year ended December 31, 2019, NIPSCO generated 62.4% and purchased 37.6% 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, FTR 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 our core, rate-regulated asset-based businesses with most of our operating income generated from the rate-regulated businesses. Our utilities continue to move forward on core infrastructure and environmental investment programs supported by complementary regulatory and customer initiatives across all seven states in which we operate. Our goal is to develop strategies that benefit all stakeholders as we address changing customer conservation patterns, develop more contemporary pricing structures, and embark on long-term investment programs. These strategies are intended to improve reliability and safety, enhance customer service and reduce emissions while generating sustainable returns.

In its 2018 Integrated Resource Plan submission to the IURC, NIPSCO laid out a plan to retire the R.M. Schahfer Generating Station (Units 14, 15, 17, and 18) by 2023 and Michigan City Generating Station (Unit 12) by 2028. These units represent 2,080 MW of generating capacity, equal to 72% of NIPSCO’s remaining capacity after the retirement of Bailly Units 7 and 8 in May of 2018. The current replacement plan includes renewable sources of energy, including wind, solar, and battery storage to be obtained through a combination of NIPSCO ownership and PPAs. Refer to Note 19-E, "Other Matters," in the Notes to Consolidated Financial Statements for further discussion of these plans.

Competition and Changes in the Regulatory Environment

The regulatory frameworks applicable to our operations, 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.

The Gas Distribution Operations companies have pursued non-traditional revenue sources within the evolving natural gas marketplace. These efforts include the sale of products and services upstream of the companies’ service territory, the sale of products and services in the companies’ service territories, and 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 company 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 company system. The incentive mechanisms give the Gas Distribution Operations companies 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. Residential usage for the year ended December 31, 2019 decreased primarily due to warmer weather in our operating area compared to the prior year. While historically 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 restructured its rate design through a base rate proceeding and has adopted a decoupled rate design which more closely links the recovery of fixed costs with fixed charges. Columbia of Massachusetts received regulatory approval of a decoupling mechanism which adjusts revenues to an approved benchmark level through a volumetric adjustment factor. Columbia of Maryland and Columbia of Virginia have regulatory approval for a revenue normalization adjustment for certain customer classes, a decoupling mechanism whereby monthly revenues that exceed or fall short of approved levels are reconciled in subsequent months. In a prior base rate proceeding, Columbia of Pennsylvania implemented a pilot residential weather normalization adjustment. Columbia of Maryland, Columbia of Virginia and Columbia of Kentucky have had approval for a weather normalization adjustment

7

ITEM 1. BUSINESS

NISOURCE INC.

for many years. In a prior gas base rate proceeding, NIPSCO implemented a higher fixed customer charge for residential and small customer classes moving toward full straight fixed variable rate design.

Natural Gas Competition.    Open access to natural gas supplies over interstate pipelines and the deregulation of the commodity price of gas has led to tremendous change in the energy markets. LDC customers and marketers can purchase gas directly from producers and marketers as an open, competitive market for gas supplies has emerged. This separation or “unbundling” of the transportation and other services offered by pipelines and LDCs allows customers to purchase the commodity independent of services provided by the pipelines and LDCs. The 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.

Gas Distribution Operations competes with investor-owned, municipal, and cooperative electric utilities throughout its service areas as well as other regulated and unregulated natural gas intra and interstate pipelines and 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. Natural gas competes with fuel oil and propane in the Massachusetts market mainly due to the installed base of fuel oil and propane-based heating which has comprised a declining percentage of the overall market over the last few years. However, fuel oil and propane are more viable in today’s oil market.

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 season, which is primarily from November through March, revenues from gas sales are more significant, and during the cooling season, which is primarily June through September, revenues from electric sales are more significant, than in other months.

Other Relevant Business Information

Our customer base is broadly diversified, with no single customer accounting for a significant portion of revenues.

As of December 31, 2019, we had 8,363 employees of whom 3,219 were subject to collective bargaining agreements. Collective bargaining agreements for 96 employees are set to expire within one year.

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.

8

ITEM 1A. RISK FACTORS

NISOURCE INC.

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.

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 $9,642.8 million outstanding as of December 31, 2019. 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 2018 and 2019, the impacts of the TCJA and the Greater Lawrence Incident. 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 the credit ratings of our or 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, 2019, the collateral requirement that would be required in the event of a downgrade below the ratings trigger levels would amount to approximately $72.1 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.

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. Our customer and regulatory initiatives may not achieve planned

9

ITEM 1A. RISK FACTORS

NISOURCE INC.

results. Utility infrastructure investments may not materialize, may cease to be achievable or economically viable and may not be successfully completed. Natural gas may cease to be viewed as an economically and environmentally attractive fuel. Certain groups and governmental entities may continue to oppose natural gas delivery and infrastructure investments because of perceived environmental impacts associated with the natural gas supply chain and end use. Energy conservation, energy efficiency, distributed generation, energy storage, policies favoring electric heat over gas heat and other factors may reduce demand for natural gas and energy. Any of these developments 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).

Adverse economic and market conditions or increases in interest rates could materially and adversely affect our results of operations, cash flows, financial condition and liquidity.

While the national economy is experiencing modest growth, we cannot predict how robust future growth will be or whether it will be sustained. Deteriorating or sluggish 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 revenue growth and increase operating costs. In addition, a rising interest rate environment may lead to higher borrowing costs, which may adversely impact reported earnings, cost of capital and capital holdings. Rising interest rates and negative market or company events may also result in a decrease in the price of our shares of common stock.

We rely on access to the capital markets to finance our liquidity and long-term capital requirements, including expenditures for our utility infrastructure and to comply with future regulatory requirements, to the extent not satisfied by the cash flow generated by our operations. We have historically relied on long-term debt and on the issuance of equity securities to fund a portion of our capital expenditures and repay outstanding debt, and on short-term borrowings to fund a portion of day-to-day business operations. Successful implementation of our long-term business strategies, including capital investment, is dependent upon our ability to access the capital and credit markets, including the banking and commercial paper markets, on competitive terms and rates. An economic downturn or uncertainty, market turmoil, changes in 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 and/or increased borrowing costs could reduce future net income and cash flows. Refer to Note 14, “Long-Term Debt,” in the Notes to Consolidated Financial Statements for information related to outstanding long-term debt and maturities of that debt.

If any of these risks or uncertainties limit our access to the credit and capital markets or significantly increase our cost of capital, 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.

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 11, "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 and other postretirement benefit plans. Additionally, changes in interest rates affect the liabilities under these benefit plans; as interest rates decrease, the liabilities increase, which could potentially increase funding requirements. Further, the funding requirements of the obligations related to these benefits plans may increase due to changes in governmental regulations and participant demographics, including increased numbers of retirements or changes in life expectancy assumptions. 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.

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The majority 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. In addition to our ongoing regulatory proceedings, the recovery of the Greater Lawrence pipeline replacement capital investment will be addressed in a future regulatory proceeding as discussed in Note 19, "Other Commitments and Contingencies - E. Other Matters” in the Notes to Consolidated Financial Statements.

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. 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.

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 is that generating power at central station power plants achieves economies of scale and produces power at a competitive cost. We continue to research, plan for, and implement new technologies that produce power or reduce power consumption. These technologies include renewable energy, distributed generation, energy storage, and energy efficiency. Advances in technology and changes in laws or regulations (including subsidization) are reducing the cost of these or other alternative methods of producing power to a level that is competitive with that of most central station power electric production or result in smaller-scale, more fuel efficient, and/or more cost-effective distributed generation. 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.

In addition, customers are increasingly expecting enhanced communications regarding their electric and natural gas services, which, in some cases, may involve 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.

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 as set forth in Note 6, "Goodwill and Other Intangible Assets," Note 19, "Other Commitments and Contingencies - C. Legal Proceedings," and “- E. Other Matters" in the Notes to Consolidated Financial Statements.

We are 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. We are cooperating with all inquiries and investigations. In addition, 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, as described further below.

As more information becomes known, management's estimates and assumptions regarding the costs and expenses to be incurred and the financial impact of the Greater Lawrence Incident may change. A change in management’s estimates or assumptions could result in an adjustment that would have a material impact on our financial condition, results of operations and cash flows during the period in which such change occurred.

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.

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We may also incur additional costs associated with the Greater Lawrence Incident, beyond the amount currently anticipated, including in connection with investigations by regulators 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 in the impacted area or we incur a material amount of other costs that we are unable to recover through rates or offset through operational or other cost savings, 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, rules, tariffs, or orders in connection with the Greater Lawrence Incident or in connection with the operations or maintenance of our natural gas system, and we are ordered to pay additional amounts in customer refunds, 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. Columbia of Massachusetts’ plea agreement with the U.S. Attorney’s Office is subject to approval by the United States District Court for the District of Massachusetts (the "Court"). If Columbia of Massachusetts’ guilty plea is not accepted by the Court or is withdrawn for any reason, the U.S. Attorney's Office may, at its sole option, render the DPA null and void. See Note 19, “Other Commitments and Contingencies - 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 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.

The closing of the sale of the Massachusetts Business is subject to receipt of clearance and approval from various governmental entities and other closing conditions that may not be satisfied or waived, and, in order to receive such clearance, consent or approval, governmental entities may impose conditions, terms, obligations or restrictions that Eversource is not obligated to accept in order to complete the transaction.

On February 26, 2020, NiSource, Columbia of Massachusetts and Eversource entered into the Asset Purchase Agreement providing for the sale of the Massachusetts Business to Eversource. The Asset Purchase Agreement provides for various closing conditions, including (a) the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, (b) the receipt of the approval of the Massachusetts DPU (the “MDPU Approval”) and (c) the final resolution or termination of all pending actions, claims and proceedings against Seller and its affiliates under the jurisdiction of the Massachusetts DPU and all future, actions, claims and proceedings against Seller and its affiliates relating to the Greater Lawrence Incident under the jurisdiction of the Massachusetts DPU.

The satisfaction of many of the closing conditions is beyond our control. We may not receive the required clearance and approvals for the transaction or the required resolution with the Massachusetts DPU, or we may not receive them in a timely manner. In addition, governmental entities could impose conditions, terms, obligations or restrictions as conditions for their approvals and as conditions to resolve certain proceedings, and these may include substantial payments by us. Moreover, Eversource is not required to agree to any conditions, terms, obligations or restrictions to obtain required clearance and approvals if such conditions, terms, obligations or restrictions would reasonably be expected to constitute a “burdensome condition” as defined in the Asset Purchase Agreement. There can be no assurance that regulators will not seek to impose conditions, terms, obligations or restrictions that would constitute burdensome conditions.

If the closing conditions are not satisfied or there is a substantial delay in obtaining the required clearance and approvals, or otherwise satisfying the closing conditions, the sale of the Massachusetts Business may not be completed, and we may lose some or all of the intended benefits of the sale.

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.

The sale of the Massachusetts Business involves separation or carve-out activities and costs and possible disputes with Eversource. Following the sale, we may have continued financial liabilities with respect to the business conducted by Columbia of Massachusetts,

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as we will be required to retain responsibility for, and indemnify Eversource against, certain liabilities, including 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 occurs prior to the closing in connection with Columbia of 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.

If we do not realize the expected benefits of the sale of the Massachusetts Business, our consolidated financial condition, results of operations and cash flows could be negatively impacted. The sale of the Massachusetts Business may result in a dilutive impact to our future earnings if we are unable to offset the dilutive impact from the loss of revenue associated with the sale, which could have a material adverse effect on our results of operations and financial condition.

The failure to complete the transactions contemplated by the Asset Purchase Agreement within the expected time frame or at all could adversely affect our business, financial condition and results of operations and the price of our common stock.

If the sale of the Massachusetts Business is not completed by October 26, 2020 (subject to up to two automatic 45-day extensions under certain circumstances related to obtaining required regulatory approvals and resolution with the Massachusetts DPU), we or Eversource may choose not to proceed with the transaction. Completion of the transaction is subject to risks, including the risks that approval of the transaction by governmental entities will not be obtained or that certain other closing conditions will not be satisfied. A failure to complete the transaction may result in negative publicity and a negative impression of us in the investment community. Moreover, under the terms of the settlement with the U.S. Attorney’s Office, we will be obligated to use reasonable best efforts to sell Columbia of Massachusetts’ business, and there is no assurance that we will be able to sell such business to a third party on as favorable terms, if at all. The occurrence of any of these events, individually or in combination, could have a material adverse effect on our results of operations, financial condition or the trading price of our common stock.

Our gas distribution 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 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, damage to our infrastructure by third parties, 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, 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.

We may be unable to obtain insurance on acceptable terms or at all. Our liability insurance coverage did not provide protection against all significant losses as a result of the Greater Lawrence Incident and may not provide protection against all significant losses in the future.

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 of insurers. The 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. NiSource has been particularly affected by the current market conditions. 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 NiSource operations, and we expect that they will continue to increase as a result of 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 have exceeded the total amount of liability coverage available under our policies.

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Also, certain types of damages, expenses or claimed costs, such as fines and penalties, 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. For example, expenses related to the Greater Lawrence Incident that we are unable to recover from liability or property insurance have materially adversely affected and may continue to materially adversely affect our results of operations. For more information regarding our insurance programs in the context of the Greater Lawrence Incident, see Note 19, "Other Commitments and Contingencies - C. Legal Proceedings," and " - E. Other Matters" in the Notes to Consolidated Financial Statements.

The outcome of legal and regulatory proceedings, investigations, inquiries, claims and litigation related to our business operations, including those related to the Greater Lawrence Incident, 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 the Greater Lawrence Incident, the most significant of which are summarized in Note 19, “Other Commitments and Contingencies” in the Notes to Consolidated Financial Statements. Our insurance does not cover all costs and expenses that we have incurred and that we may incur in the future relating to the Greater Lawrence Incident, and may not fully cover other incidents that may 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. Certain matters in connection with the Greater Lawrence Incident have had or may have a material impact as described in Note 19, "Other Commitments and Contingencies" in the Notes to Consolidated Financial Statements. 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.

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

As a utility company, we are subject to adverse publicity focused on the reliability of our services, the speed with which we are able to respond effectively to electric outages, natural gas leaks or events and related accidents and similar interruptions caused by storm damage 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.

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

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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 and injunctions to remedy the failure or harm.

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 increased focus on both coal and natural gas in recent years. 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, priority pipeline replacement, energy efficiency, leak detection and repair, and other programs, and expect to further reduce GHG emissions through increased use of renewable energy, 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.

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.

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 it operates. In particular, sales to large industrial customers, such as those in the steel, oil refining, industrial gas and related industries, may be impacted by economic downturns and geographic or technological shifts in production or production methods. The U.S. manufacturing industry continues to adjust to changing market conditions including international competition, increasing costs, and fluctuating demand for its products.

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

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 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 sets forth a schedule to retire R.M. Schahfer Generating Station (Units 14, 15, 17, and 18) in 2023 and Michigan City Generating Station (Unit 12) in 2028. The current replacement plan includes renewable sources of energy, including wind, solar, and battery storage.

As part of this plan, NIPSCO has IURC approval for the Jordan Creek PPA for 400 MW, the Indiana Crossroads BTA for 300 MW and the Rosewater BTA for 100 MW. Each is a separate facility and all MW are nameplate capacity. NIPSCO has filed a notice with the IURC of its intention not to move forward with one of its approved PPAs due to the failure to meet a condition precedent in the agreement as a result of local zoning restrictions.

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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.

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 electric generating fleet is dependent on coal and natural gas for fuel, and our gas distribution operations purchase and resell much of the natural gas we deliver to our customers. These energy commodities are vulnerable to price fluctuations and fluctuations in associated transportation costs. From time to time, we have also used 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 providing service. 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.

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 could result in an increase in defaults by customers, suppliers and counterparties.

We have significant goodwill and definite-lived intangible assets. Impairments of goodwill and definite-lived intangible assets related to Columbia of Massachusetts have resulted in significant charges to earnings for the quarter and year ended December 31, 2019. Any future impairments of other 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.

We are required to record a charge in our financial statements for a period in which any impairment of our goodwill or definite-lived intangible assets is determined, negatively impacting our results of operations. In connection with the preparation of our financial statements for the year ended December 31, 2019, we conducted an impairment analysis for the goodwill and definite-lived intangible assets (franchise rights) related to Columbia of Massachusetts and concluded that such goodwill and franchise rights were impaired. As a result, we recorded an impairment charge of $204.8 million for such goodwill and an impairment charge of $209.7 million for such franchise rights at December 31, 2019. For additional information, see Note 6, “Goodwill and Other Intangible Assets,” in the Notes to Consolidated Financial Statements.

A significant charge in the future could impact the capitalization ratio covenant under certain financing agreements. We are subject to a financial covenant under our revolving credit facility and term loan agreement, which require us to maintain a debt to capitalization ratio that does not exceed 70%. A similar covenant in a 2005 private placement note purchase agreement requires us to maintain a debt to capitalization ratio that does not exceed 75%. As of December 31, 2019, the ratio was 61.7%.

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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, and deductions and credits. The outcome of regulatory proceedings regarding the extent to which the effect of a change in corporate tax rate will impact customers and the time period over which the impact will occur could significantly impact future earnings and cash flows. Separately, a challenge by a taxing authority, changes in taxing authorities’ administrative interpretations, decisions, policies and positions, our ability to utilize tax benefits such as carryforwards or tax credits, or a deviation from other tax-related assumptions may cause actual financial results to deviate from previous estimates.

Changes in accounting principles may adversely affect our financial results.

Future changes in accounting rules and associated changes in regulatory accounting may negatively impact the way we record revenues, expenses, assets and liabilities. These changes in accounting standards may adversely affect our financial condition and results of operations.

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 gas infrastructure assets. These risks can be driven by threats such as, but not limited to, internal corrosion, external corrosion and stress corrosion 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. Additionally, 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 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.

The impacts of climate change, natural disasters, acts of terrorism, accidents 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, cyber-attack (as further detailed below), accident 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. 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. There is also a concern that climate change may exacerbate the risks to physical infrastructure. Such risks include 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 costs that may be associated with its impacts have the potential to affect our business in many ways, including increasing the costs we incur in providing our products and services, impacting the demand for and consumption of our products and services (due to change in both costs and weather patterns), and affecting the economic health of the regions in which we operate.

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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 and inadvertent disclosure of sensitive information), the utility industry faces evolving and increasingly complex cybersecurity risks associated with protecting sensitive and confidential customer information, electric grid infrastructure, and natural gas infrastructure. Deployment of new business technologies represents a new and large-scale opportunity for attacks on our information systems and confidential customer 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 any cybersecurity-related litigation.

Our capital projects and programs subject us to construction risks and natural gas costs and supply risks, and require numerous 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.

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.

Sustained 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

18

ITEM 1A. RISK FACTORS

NISOURCE INC.

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.

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 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.

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.

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.

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 and term loan 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

19

ITEM 1A. RISK FACTORS

NISOURCE INC.

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. 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 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. SOFR may fail to gain market acceptance.

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.

20

ITEM 1B. UNRESOLVED STAFF COMMENTS

NISOURCE INC.

None.

ITEM 2. PROPERTIES

Discussed below are the principal properties held by us and our subsidiaries as of December 31, 2019.

Gas Distribution Operations

Refer to Item 1, "Business - Gas Distribution Operations" of this report for further information on Gas Distribution Operations properties.

Electric Operations

Refer to Item 1, "Business - Electric Operations" of this report for further information on Electric Operations properties.

Corporate and Other Operations

We own the Southlake Complex, our 325,000 square foot headquarters building located in Merrillville, Indiana.

Character of Ownership

Our principal properties and our subsidiaries principal properties are owned free from encumbrances, subject to minor exceptions, none of which are of such a nature as to impair substantially the usefulness of such properties. Many of our subsidiary offices in various communities served are occupied under leases. All properties are subject to routine liens for taxes, assessments and undetermined charges (if any) incidental to construction. It is our practice to regularly pay such amounts, as and when due, unless contested in good faith. In general, the electric lines, gas pipelines and related facilities are located on land not owned by us or our subsidiaries, but are covered by necessary consents of various governmental authorities or by appropriate rights obtained from owners of private property. We do not, however, generally have specific easements from the owners of the property adjacent to public highways over, upon or under which our electric lines and gas distribution pipelines are located. At the time each of the principal properties were purchased, a title search was made. In general, no examination of titles as to rights-of-way for electric lines, gas pipelines or related facilities was made, other than examination, in certain cases, to verify the grantors’ ownership and the lien status thereof.

ITEM 3. LEGAL PROCEEDINGS

For a description of our legal proceedings, see Note 19-C "Legal Proceedings" in the Notes to Consolidated Financial Statements.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

21

SUPPLEMENTAL ITEM. INFORMATION ABOUT OUR EXECUTIVE OFFICERS

NISOURCE INC.

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

Name	Age	Office(s) Held in Past 5 Years
Joseph Hamrock	56	President and Chief Executive Officer of NiSource since July 2015.
		Executive Vice President and Group Chief Executive Officer of NiSource from May 2012 to July 2015.
Donald E. Brown	48	Executive Vice President of NiSource since May 2015.
		Chief Financial Officer of NiSource since July 2015.
		Treasurer of NiSource from July 2015 to June 2016.
		Vice President and Chief Financial Officer of UGI Utilities, a division of UGI Corporation (gas and electric utility company) from 2010 to March 2015.
Peter T. Disser	51	Vice President, Internal Audit of NiSource since January 2019.
		Chief Operating Officer of NiSource from September 2018 to December 2018.
		Vice President, Audit of NiSource from November 2017 to September 2018.
		Vice President, Planning and Analysis of NiSource from June 2016 to November 2017.
		Vice President, Strategy and Planning of NiSource Corporate Services Company from July 2015 to May 2016.
		Chief Financial Officer of NIPSCO from 2012 to June 2015.
Carrie J. Hightman	62	Executive Vice President and Chief Legal Officer of NiSource since 2007.
Kenneth E. Keener	55	Senior Vice President and Chief Human Resources Officer of NiSource since August 2019.
		Vice President, Talent and Organizational Effectiveness of NiSource Corporate Services Company from June 2012 to July 2019.
Charles E. Shafer, II	50	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	58	Executive Vice President and President, NIPSCO of NiSource since July 2015.
		Senior Vice President and Chief Information Officer of NiSource from May 2014 to June 2015.
Suzanne K. Surface	55	Chief Services Officer of NiSource since January 2019.
		Vice President, Audit of NiSource from September 2018 to December 2018.
		Vice President, Transformation Office of NiSource from August 2018 to September 2018.
		Vice President, Corporate Services Customer Value of NiSource from November 2017 to August 2018.
		Vice President, Audit of NiSource from July 2015 to November 2017.
		Vice President, Regulatory Strategy and Support of NiSource Corporate Services Company from July 2009 to June 2015.
Pablo A. Vegas	46	Executive Vice President and President, Gas Utilities of NiSource since January 2019.
		Executive Vice President and 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.
		Executive Vice President and President, Columbia Gas Group from May 2016 to May 2017.
		President and Chief Operating Officer of American Electric Power Company of Ohio from May 2012 to May 2016.

22

PART II

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

NISOURCE INC.

NiSource’s common stock is listed and traded on the New York Stock Exchange under the symbol “NI.”

Holders of shares of NiSource’s common stock are entitled to receive dividends if and when declared by NiSource’s Board out of funds legally available, subject to the prior dividend rights of holders of our preferred stock or the depositary shares representing such preferred stock outstanding, and if full dividends have not been declared and paid on all outstanding shares of preferred stock in any dividend period, no dividend may be declared or paid or set aside for payment on our common stock. The policy of the Board has been to declare cash dividends on a quarterly basis payable on or about the 20th day of February, May, August, and November. At its January 31, 2020 meeting, the Board declared a quarterly common dividend of $0.21 per share, payable on February 20, 2020 to holders of record on February 11, 2020.

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 18, 2020, NiSource had 18,868 common stockholders of record and 382,263,348 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. On July 1, 2015, NiSource completed the Separation. Following the Separation, NiSource retained no ownership interest in CPG. The Separation is treated as a special dividend for purposes of calculating the total shareholder return, with the then-current market value of the distributed shares being deemed to have been reinvested on the Separation date in shares of NiSource common stock. A vertical line is included on the graph below to identify the periods before and after the Separation.

23

PART II

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

NISOURCE INC.

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, including the impact of the distribution of CPG common stock in the Separation.

24

ITEM 6. SELECTED FINANCIAL DATA

NISOURCE INC.

The selected data presented below as of and for the five years ended December 31, 2019, are derived from our Consolidated Financial Statements. The data should be read together with the Consolidated Financial Statements including the related notes thereto included in Item 8 of this Form 10-K.  

Year Ended December 31, (in millions except per share data)	2019		2018			2017		2016		2015
Statement of Income Data:
Total Operating Revenues	$	5,208.9	$	5,114.5		$	4,874.6	$	4,492.5	$	4,651.8
Net Income (Loss) Available to Common Shareholders	328.0		(65.6		)	128.5		331.5		198.6
Balance Sheet Data:
Total Assets	22,659.8		21,804.0			19,961.7		18,691.9		17,492.5
Capitalization
Stockholders’ equity	5,986.7		5,750.9			4,320.1		4,071.2		3,843.5
Long-term debt, excluding amounts due within one year	7,856.2		7,105.4			7,512.2		6,058.2		5,948.5
Total Capitalization	$	13,842.9	$	12,856.3		$	11,832.3	$	10,129.4	$	9,792.0
Per Share Data:
Basic Earnings (Loss) Per Share ($)	$	0.88	$	(0.18	)	$	0.39	$	1.02	$	0.63
Diluted Earnings (Loss) Per Share ($)	$	0.87	$	(0.18	)	$	0.39	$	1.01	$	0.63
Other Data:
Dividends declared per common share ($)	$	0.80	$	0.78		$	0.70	$	0.64	$	0.83
Common shares outstanding at the end of the year (in thousands)	382,136		372,363			337,016		323,160		319,110
Number of common stockholders	18,725		19,889			21,009		22,272		30,190
Dividends declared per Series A preferred share ($)	$	56.50	$	28.88		$	—	$	—	$	—
Dividends declared per Series B preferred share ($)	$	1,674.65	$	—		$	—	$	—	$	—
Capital expenditures	$	1,867.8	$	1,814.6		$	1,753.8	$	1,490.4	$	1,367.5
Number of employees	8,363		8,087			8,175		8,007		7,596

• During 2019, we recorded a loss of approximately $284 million for third-party claims and approximately $154 million for other incident-related expenses in connection with the Greater Lawrence Incident. Columbia of Massachusetts recorded $665 million for insurance recoveries through December 31, 2019. For additional information, see Note 19-C, "Legal Proceedings," and E, "Other Matters" in the Notes to Consolidated Financial Statements.

• During the fourth quarter of 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 6, “Goodwill and Other Intangible Assets,” in the Notes to Consolidated Financial Statements.

• During the third quarter of 2019, we closed our placement of $750.0 million of 2.95% senior unsecured notes maturing in 2029.

• During the second quarter of 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 and issued 400,000 shares of Series A preferred stock resulting in $400.0 million of gross proceeds or $393.9 million of net proceeds, after deducting commissions and sales expenses. Additionally, in the fourth quarter of 2018, we issued 20,000 shares of Series B preferred stock resulting in $500.0 million of gross proceeds or $486.1 million of net proceeds, after deducting commissions and sales expenses.

• During 2018, we recorded a loss of approximately $757 million for third-party claims and approximately $266 million for other incident-related expenses in connection with the Greater Lawrence Incident. Columbia of Massachusetts recorded $135 million for insurance recoveries through December 31, 2018. For additional information, see Note 19-C, "Legal Proceedings," and E, Other Matters." in the Notes to Consolidated Financial Statements.

• During the second quarter of 2018, we executed a tender offer for $209.0 million of outstanding notes consisting of a combination of our 6.80% notes due 2019, 5.45% notes due 2020 and 6.125% notes due 2022. During the third quarter of 2018, we redeemed $551.1 million of outstanding notes representing the remainder of our 6.80% notes due 2019, 5.45% notes due 2020 and 6.125% notes due 2022. In conjunction with our debt retired, we recorded a $45.5 million loss on early extinguishment of long-term debt primarily attributable to early redemption premiums.

25

ITEM 6. SELECTED FINANCIAL DATA

NISOURCE INC.

• The decrease in net income during 2017 was due primarily to increased tax expense as a result of the impact of adopting the provisions of the TCJA and a loss on early extinguishment of long-term debt, as discussed below.

• During the second quarter of 2017, we executed a tender offer for $990.7 million of outstanding notes consisting of a combination of our 6.40% notes due 2018, 6.80% notes due 2019, 5.45% notes due 2020, and 6.125% notes due 2022. In conjunction with the debt retired, we recorded a $111.5 million loss on early extinguishment of long-term debt, primarily attributable to early redemption premiums.

• Prior to the Separation, CPG closed the placement of $2,750.0 million in aggregate principal amount of senior notes. Using the proceeds from this offering, CPG made cash payments to us representing the settlement of inter-company borrowings and the payment of a one-time special dividend. In May 2015, using proceeds from the cash payments from CPG, we settled two bank term loans in the amount of $1,075.0 million and executed a tender offer for $750.0 million consisting of a combination of its 5.25% notes due 2017, 6.40% notes due 2018 and 4.45% notes due 2021. In conjunction with the debt retired, we recorded a $97.2 million loss on early extinguishment of long-term debt, primarily attributable to early redemption premiums.

26

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

NISOURCE INC.

Index	Page
Executive Summary	27
Summary of Consolidated Financial Results	29
Results and Discussion of Segment Operations	31
Gas Distribution Operations	32
Electric Operations	36
Liquidity and Capital Resources	40
Off Balance Sheet Arrangements	44
Market Risk Disclosures	44
Other Information	45

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 seven states. We generate substantially all of our operating income through these rate-regulated businesses which are summarized for financial reporting purposes into two primary reportable segments: Gas Distribution Operations and Electric Operations.

Refer to the “Business” section under Item 1 of this annual report and Note 23, "Segments of Business," in the Notes to Consolidated Financial Statements for further discussion of our regulated utility business segments.

Our goal is to develop strategies that benefit all stakeholders as we address changing customer conservation patterns, develops more contemporary pricing structures and embarks on long-term infrastructure investment and safety programs. These strategies are intended to improve reliability and safety, enhance customer services and reduce 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 discussion of Electric Supply within our Electric Operations Segment discussion for additional information on our long term electric generation strategy.

Greater Lawrence Incident: The Greater Lawrence Incident occurred on September 13, 2018. The following table summarizes expenses incurred and insurance recoveries recorded since the Greater Lawrence Incident. The amounts set forth in the table below do not include the capital cost of the pipeline replacement described below and as set forth in Note 19, "Other Commitments and Contingencies - E. Other Matters - Greater Lawrence Pipeline Replacement," in the Notes to Consolidated Financial Statements.

	Year Ended			Year Ended
(in millions)	December 31, 2018			December 31, 2019			Incident to Date
Third-party claims and government fines, penalties and settlements	$	757		$	284		$	1,041
Other incident-related costs	266			154			420
Total	1,023			438			1,461
Insurance recoveries recorded	(135		)	(665		)	(800		)
Loss (benefit) to income before income taxes	$	888		$	(227	)	$	661

Inclusive of the $1,041 million of third-party claims and fines, penalties and settlements associated with government investigations recorded incident to date, we estimate that total costs related to third-party claims and fines, penalties and settlements associated

27

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

NISOURCE INC.

with government investigations as set forth in Note 19, "Other Commitments and Contingencies - C. Legal Proceedings," will range from $1,041 million to $1,065 million, depending on the number, nature, final outcome and value of third-party claims and the final outcome of government investigations. These costs do not include costs of certain third-party claims and fines, penalties or settlements with government investigations that we are not able to estimate. We expect to incur a total of $450 million to $460 million in other incident-related costs, inclusive of the $420 million recorded incident to date, as set forth in Note 19, "Other Commitments and Contingencies - E. Other Matters - Greater Lawrence Incident Restoration."

The process for estimating costs associated with third-party claims and fines, penalties and settlements associated with government investigations 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, including additional information regarding ongoing investigations, 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 have collected the entire $800 million as of December 31, 2019. Expenses related to the incident have exceeded the total amount of insurance coverage available under our policies. The following table presents activity related to our Greater Lawrence Incident insurance recovery.

(in millions)	Insurance receivable(1)
Balance, December 31, 2018	$	130
Insurance recoveries recorded in first quarter of 2019	100
Cash collected from insurance recoveries in the first quarter of 2019	(108		)
Balance, March 31, 2019	122
Insurance recoveries recorded in the second quarter of 2019	435
Cash collected from insurance recoveries in the second quarter of 2019	(297		)
Balance, June 30, 2019	$	260
Insurance recoveries recorded in third quarter of 2019	—
Cash collected from insurance recoveries in the third quarter of 2019	(260		)
Balance, September 30, 2019	$	—
Insurance recoveries recorded in the fourth quarter of 2019	130
Cash collected from insurance recoveries in the fourth quarter of 2019	(130		)
Balance, December 31, 2019	$	—

⁽¹⁾$5 million of insurance recoveries were collected during 2018.

Since the Greater Lawrence Incident and through December 31, 2019, we have 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 full cost of 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. The recovery of any capital investment not reimbursed through insurance will be addressed in a future regulatory proceeding; a future regulatory proceeding is dependent on the outcome of the sale of the Massachusetts Business. The outcome of such a proceeding (if any) is uncertain. In accordance with ASC 980-360, if it becomes probable that a portion of the pipeline replacement cost will not be recoverable through customer rates and an amount can be reasonably estimated, we will reduce our regulated plant balance for the amount of the probable disallowance and record an associated charge to earnings. This could result in a material adverse effect on our financial condition, results of operations and cash flows. Additionally, if a rate order is received allowing recovery of the investment with no or reduced return on investment, a loss on disallowance may be required.

Refer to Note 19, "Other Commitments and Contingencies - C. Legal Proceedings" and " - 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.

28

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

NISOURCE INC.

Additionally, as discussed in Note 6, "Goodwill and Other Intangible Assets," in the Notes to Consolidated Financial Statements, we assessed the totality of several factors that developed during the fourth quarter related to the Greater Lawrence Incident and concluded that it was more likely than not that the fair value of the Columbia of Massachusetts reporting unit was below its carrying value. As a result, a new impairment analysis was required for our Columbia of Massachusetts reporting unit. The 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. We assessed the same fourth quarter circumstances in reviewing the Columbia of Massachusetts franchise rights intangible assets. These factors led us to conclude that it was more likely than not that the fair value of the franchise rights was below its carrying amount. As a result, we performed a year-end impairment test and determined that the fair value of the franchise rights was zero. Therefore, we wrote off the entire franchise rights book value, which resulted in an impairment charge totaling $209.7 million.

Columbia of Massachusetts Asset Sale: On February 26, 2020, NiSource and Columbia of Massachusetts entered into the Asset Purchase Agreement with Eversource. 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 the Massachusetts Business for a purchase price of $1,100 million, subject to adjustment. For additional information, see Note 26, “Subsequent Event,” in the Notes to Consolidated Financial Statements.

Summary of Consolidated Financial Results

Our operations are affected by the cost of sales. Cost of sales for the Gas Distribution Operations segment is principally comprised of the cost of natural gas used while providing transportation and distribution services to customers. Cost of sales for the Electric Operations segment is comprised of the cost of coal, related handling costs, natural gas purchased for the internal generation of electricity at NIPSCO and the cost of power purchased from third-party generators of electricity.

The majority of the cost of sales are tracked costs that are passed through directly to the customer resulting in an equal and offsetting amount reflected in operating revenues. As a result, we believe net revenues, a non-GAAP financial measure defined as operating revenues less cost of sales (excluding depreciation and amortization), provides management and investors a useful measure to analyze profitability. The presentation of net revenues herein is intended to provide supplemental information for investors regarding operating performance. Net revenues do not intend to represent operating income, the most comparable GAAP measure, as an indicator of operating performance and is not necessarily comparable to similarly titled measures reported by other companies.

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

NISOURCE INC.

For the years ended December 31, 2019, 2018 and 2017, operating income and a reconciliation of net revenues to the most directly comparable GAAP measure, operating income, was as follows:

Year Ended December 31, (in millions)	2019		2018		2017		2019 vs. 2018		2018 vs. 2017
Operating Income	$	890.7	$	124.7	$	921.2	$	766.0	$	(796.5	)

Year Ended December 31, (in millions, except per share amounts)	2019			2018			2017			2019 vs. 2018			2018 vs. 2017
Operating Revenues	$	5,208.9		$	5,114.5		$	4,874.6		$	94.4		$	239.9
Cost of sales (excluding depreciation and amortization)	1,534.8			1,761.3			1,518.7			(226.5		)	242.6
Total Net Revenues	3,674.1			3,353.2			3,355.9			320.9			(2.7		)
Other Operating Expenses	2,783.4			3,228.5			2,434.7			(445.1		)	793.8
Operating Income	890.7			124.7			921.2			766.0			(796.5		)
Total Other Deductions, Net	(384.1		)	(355.3		)	(478.2		)	(28.8		)	122.9
Income Taxes	123.5			(180.0		)	314.5			303.5			(494.5		)
Net Income (Loss)	383.1			(50.6		)	128.5			433.7			(179.1		)
Preferred dividends	(55.1		)	(15.0		)	—			(40.1		)	(15.0		)
Net Income (Loss) Available to Common Shareholders	328.0			(65.6		)	128.5			393.6			(194.1		)
Basic Earnings (Loss) Per Share	$	0.88		$	(0.18	)	$	0.39		$	1.06		$	(0.57	)
Basic Average Common Shares Outstanding	374.6			356.5			329.4			18.1			27.1

On a consolidated basis, we reported net income available to common shareholders of $328.0 million or $0.88 per basic share for the twelve months ended December 31, 2019 compared to a loss to common shareholders of $65.6 million or $0.18 per basic share for the same period in 2018. The increase in net income available to common shareholders during 2019 was primarily due to lower operating expenses related to the Greater Lawrence Incident, insurance recoveries recorded related to the Greater Lawrence Incident, and new rates from base rate proceedings and infrastructure replacement programs. These increases were partially offset by non-cash impairments of goodwill and other intangible assets in 2019 related to Columbia of Massachusetts (see Note 6, "Goodwill and Other Intangible Assets," in the Notes to Consolidated Financial Statements for additional information), higher income taxes (see "Income Taxes" below), higher depreciation expense due to regulatory outcomes at NIPSCO and Columbia of Ohio, and additional dilution in 2019 resulting from preferred stock dividend commitments.

Operating Income

For the twelve months ended December 31, 2019, we reported operating income of $890.7 million compared to $124.7 million for the same period in 2018. The increased operating income was primarily due to decreased operating expenses related to the Greater Lawrence Incident, insurance recoveries recorded related to the Greater Lawrence Incident, and new rates from base rate proceedings and infrastructure replacement programs. These increases were partially offset by non-cash impairments of goodwill and other intangible assets in 2019 related to Columbia of Massachusetts (see Note 6, "Goodwill and Other Intangible Asset," in the Notes to Consolidated Financial Statements for additional information), and increased depreciation due to the regulatory outcome of NIPSCO's gas rate case and an increase in amortization of depreciation previously deferred as a regulatory asset resulting from Columbia of Ohio's CEP.

Other Deductions, Net

Other deductions, net reduced income by $384.1 million in 2019 compared to a reduction in income of $355.3 million in 2018. This change is primarily due to lower actuarial investment returns on pension and other postretirement benefit assets of $34.6 million, and an increase in interest expense of $25.6 million driven by decreased regulatory deferrals from Columbia of Ohio's CEP. These unfavorable variances were partially offset by charitable contributions of $20.7 million in 2018 related to the Greater Lawrence Incident.

Income Taxes

The increase in income tax expense from 2018 to 2019 is primarily attributable to higher pre-tax income resulting from the items discussed above in "Operating Income" and "Other Deductions, Net," true-ups to tax expense in 2018 to reflect regulatory outcomes associated with excess deferred income taxes, and higher income tax expense in 2019 related to the non-deductible, non-cash impairment of goodwill, fines and penalties.

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

NISOURCE INC.

Refer to “Liquidity and Capital Resources” below and Note 10, "Income Taxes," in the Notes to Consolidated Financial Statements for additional information on income taxes and the change in the effective tax rate.

Capital Investment

In 2019, we invested approximately $1.9 billion in capital expenditures across the gas and electric utilities. These expenditures were primarily aimed at furthering the safety and reliability of our gas distribution system, and maintaining our existing electric generation fleet.

We continue to execute on an estimated $30 billion in total projected long-term regulated utility infrastructure investments and expect to invest approximately $1.8 to $1.9 billion in capital during 2020 as we continue to focus on growth, safety and modernization projects across our operating area.

Liquidity

A primary focus of ours is to ensure the availability of adequate financing to fund our ongoing safety and infrastructure investment programs which typically involves the issuance of debt and/or equity. In addition, expenses related to the Greater Lawrence Incident have exceeded the total amount of insurance coverage available under our policies. During 2020, we plan to pursue alternatives to cover this shortfall, including long-term financing and potential proceeds from the sale of the Massachusetts Business. For additional information, see Note 26, "Subsequent Event," in the Notes to Consolidated Financial Statements.

Through income generated from operating activities, amounts available under our short-term revolving credit facility, commercial paper program, accounts receivable securitization facilities, term loan borrowings, long-term debt agreements, our ability to access the capital markets and the potential sale of the Massachusetts Business, we believe there is adequate capital available to fund our operating activities and capital expenditures and the effects of the Greater Lawrence Incident in 2020 and beyond. At December 31, 2019 and 2018, we had approximately $1,409.1 million and $974.6 million, respectively, of net liquidity available, consisting of cash and available capacity under credit facilities.

These factors and other impacts to the financial results are discussed in more detail within the following discussions of “Results and Discussion of Segment Operations” and “Liquidity and Capital Resources.”

Regulatory Developments

In 2019, 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. Refer to Note 8, “Regulatory Matters” and Note 19-E, "Other Matters," in the Notes to Consolidated Financial Statements for a complete discussion of key regulatory developments that transpired during 2019.

RESULTS AND DISCUSSION OF SEGMENT OPERATIONS

Presentation of Segment Information

Our operations are divided into two primary reportable segments: Gas Distribution Operations and Electric Operations.

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

NISOURCE INC.

Gas Distribution Operations

For the years ended December 31, 2019, 2018 and 2017, operating income (loss) and a reconciliation of net revenues to the most directly comparable GAAP measure, operating income (loss), was as follows:

Year Ended December 31, (in millions)	2019		2018			2017		2019 vs. 2018		2018 vs. 2017
Operating Income (Loss)	$	675.4	$	(254.1	)	$	550.1	$	929.5	$	(804.2	)

Year Ended December 31, (in millions)	2019			2018			2017			2019 vs. 2018			2018 vs. 2017
Net Revenues
Operating revenues	$	3,522.8		$	3,419.5		$	3,102.1		$	103.3		$	317.4
Less: Cost of sales (excluding depreciation and amortization)	1,067.6			1,259.3			1,005.0			(191.7		)	254.3
Net Revenues	2,455.2			2,160.2			2,097.1			295.0			63.1
Operating Expenses
Operation and maintenance	935.7			1,908.1			1,090.8			(972.4		)	817.3
Depreciation and amortization	403.2			301.0			269.3			102.2			31.7
Impairment of other intangible assets	209.7			—			—			209.7			—
Loss on sale of fixed assets and impairments, net	0.1			0.2			2.8			(0.1		)	(2.6		)
Other taxes	231.1			205.0			184.1			26.1			20.9
Total Operating Expenses	1,779.8			2,414.3			1,547.0			(634.5		)	867.3
Operating Income (Loss)	$	675.4		$	(254.1	)	$	550.1		$	929.5		$	(804.2	)
Revenues
Residential	$	2,317.2		$	2,248.3		$	2,029.4		$	68.9		$	218.9
Commercial	775.1			753.7			669.4			21.4			84.3
Industrial	245.8			228.6			217.5			17.2			11.1
Off-System	77.7			92.4			111.8			(14.7		)	(19.4		)
Other	107.0			96.5			74.0			10.5			22.5
Total	$	3,522.8		$	3,419.5		$	3,102.1		$	103.3		$	317.4
Sales and Transportation (MMDth)
Residential	274.9			280.3			247.1			(5.4		)	33.2
Commercial	189.6			187.6			169.3			2.0			18.3
Industrial	542.5			555.7			517.5			(13.2		)	38.2
Off-System	32.9			30.0			39.0			2.9			(9.0		)
Other	0.3			—			0.3			0.3			(0.3		)
Total	1,040.2			1,053.6			973.2			(13.4		)	80.4
Heating Degree Days	5,375			5,562			4,927			(187		)	635
Normal Heating Degree Days	5,452			5,610			5,610			(158		)	—
% Warmer than Normal	(1		)%	(1		)%	(12		)%
Gas Distribution Customers
Residential	3,221,178			3,194,662			3,168,516			26,516			26,146
Commercial	282,778			281,517			280,362			1,261			1,155
Industrial	5,982			5,833			6,228			149			(395		)
Other	3			3			4			—			(1		)
Total	3,509,941			3,482,015			3,455,110			27,926			26,905

32

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

NISOURCE INC.

Gas Distribution Operations (continued)

Comparability of line item operating results may be impacted by regulatory, tax and depreciation trackers (other than those for cost of sales) that allow for the recovery in rates of certain costs. Therefore, increases in these tracked operating expenses are generally offset by increases in net revenues and have essentially no impact on net income.

2019 vs. 2018 Operating Income

For 2019, Gas Distribution Operations reported operating income of $675.4 million, an increase in income of $929.5 million from the comparable 2018 period.

Net revenues for 2019 were $2,455.2 million, an increase of $295.0 million from the same period in 2018. The change in net 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.

• Higher revenues of $14.5 million resulting from an update in the weather-related normal heating degree day methodology (see further detail below), 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.

Operating expenses were $634.5 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.

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 regulatory 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 net 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.

• Higher insurance expense of $9.1 million primarily driven by increased premiums.

2018 vs. 2017 Operating Income

For 2018, Gas Distribution Operations reported an operating loss of $254.1 million, a decrease in income of $804.2 million from the comparable 2017 period.

Net revenues for 2018 were $2,160.2 million, an increase of $63.1 million from the same period in 2017. The change in net revenues was primarily driven by:

• New rates from infrastructure replacement programs and base rate proceedings of $99.6 million.

• Higher revenues from the effects of colder weather in 2018 of $37.5 million.

• The effects of customer growth and increased usage of $17.4 million.

• Higher regulatory, tax and depreciation trackers, which are offset in operating expense, of $16.0 million.

Partially offset by:

• A revenue reserve of $85.0 million in 2018 resulting from the probable future refund of certain collections from customers as a result of the lower income tax rate from the TCJA.

• Decreased rates from implementation of regulatory outcomes related to the TCJA of $24.7 million.

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

NISOURCE INC.

Gas Distribution Operations (continued)

Operating expenses were $867.3 million higher in 2018 compared to 2017. This change was primarily driven by:

• Expenses related to third-party claims and other costs for the Greater Lawrence Incident of $864.4 million, net of insurance recoveries recorded.

• Increased depreciation of $29.6 million due to regulatory outcomes of NIPSCO's gas rate case and higher capital expenditures placed in service.

• Higher regulatory, tax and depreciation trackers, which are offset in net revenues, of $16.0 million.

• Increased property taxes of $11.0 million due to higher capital expenditures placed in service and the impact of regulatory-driven property tax deferrals.

Partially offset by:

• Decreased outside services of $33.2 million primarily due to IT service provider transition and other strategic initiative costs in 2017, lower ongoing IT costs and a temporary shift of resources to the Greater Lawrence Incident restoration.

• Lower employee and administrative expenses of $30.2 million driven by reduced incentive compensation and a temporary shift of resources to the Greater Lawrence Incident restoration.

Weather

In general, we calculate the weather-related revenue variance based on changing customer demand driven by weather variance from normal heating degree days. 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 net revenues.

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 net 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.

Weather in the Gas Distribution Operations service territories for 2018 was about 1% warmer than normal and about 13% colder than 2017, increasing net revenues $37.5 million for the year ended December 31, 2018 compared to 2017.

Throughput

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.

Total volumes sold and transported for the year ended December 31, 2018 were 1,053.6 MMDth, compared to 973.2 MMDth for 2017. This increase is primarily attributable to colder weather experienced in 2018 compared to 2017.

Economic Conditions

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 net revenues 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.

34

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

NISOURCE INC.

Gas Distribution Operations (continued)

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 19-C. "Legal Proceedings," and 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. For additional information, see Note 26, “Subsequent Event,” in the Notes to Consolidated Financial Statements.

35

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

NISOURCE INC.

Electric Operations

For the years ended December 31, 2019, 2018 and 2017, operating income and a reconciliation of net revenues to the most directly comparable GAAP measure, operating income, was as follows:

Year Ended December 31, (in millions)	2019		2018		2017		2019 vs. 2018		2018 vs. 2017
Operating Income	$	406.8	$	386.1	$	367.4	$	20.7	$	18.7

Year Ended December 31, (in millions)	2019			2018			2017			2019 vs. 2018			2018 vs. 2017
Net Revenues
Operating revenues	$	1,699.2		$	1,708.2		$	1,786.5		$	(9.0	)	$	(78.3	)
Less: Cost of sales (excluding depreciation and amortization)	467.3			502.1			513.9			(34.8		)	(11.8		)
Net Revenues	1,231.9			1,206.1			1,272.6			25.8			(66.5		)
Operating Expenses
Operation and maintenance	495.0			500.0			565.6			(5.0		)	(65.6		)
Depreciation and amortization	277.3			262.9			277.8			14.4			(14.9		)
Loss (gain) on sale of fixed assets and impairments, net	(0.1		)	—			1.9			(0.1		)	(1.9		)
Other taxes	52.9			57.1			59.9			(4.2		)	(2.8		)
Total Operating Expenses	825.1			820.0			905.2			5.1			(85.2		)
Operating Income	$	406.8		$	386.1		$	367.4		$	20.7		$	18.7
Revenues
Residential	$	481.6		$	494.7		$	476.9		$	(13.1	)	$	17.8
Commercial	486.7			492.6			501.2			(5.9		)	(8.6		)
Industrial	608.4			614.4			698.1			(6.0		)	(83.7		)
Wholesale	11.7			15.7			11.6			(4.0		)	4.1
Other	110.8			90.8			98.7			20.0			(7.9		)
Total	$	1,699.2		$	1,708.2		$	1,786.5		$	(9.0	)	$	(78.3	)
Sales (Gigawatt Hours)
Residential	3,369.5			3,535.2			3,301.7			(165.7		)	233.5
Commercial	3,760.3			3,844.6			3,793.5			(84.3		)	51.1
Industrial	8,466.1			8,829.5			9,469.7			(363.4		)	(640.2		)
Wholesale	8.2			114.3			32.5			(106.1		)	81.8
Other	117.2			124.4			128.2			(7.2		)	(3.8		)
Total	15,721.3			16,448.0			16,725.6			(726.7		)	(277.6		)
Cooling Degree Days	962			1,180			837			(218		)	343
Normal Cooling Degree Days	803			806			806			(3		)	—
% Warmer than Normal	20		%	46		%	4		%
Electric Customers
Residential	415,534			412,267			409,401			3,267			2,866
Commercial	57,058			56,605			56,134			453			471
Industrial	2,256			2,284			2,305			(28		)	(21		)
Wholesale	726			735			739			(9		)	(4		)
Other	2			2			2			—			—
Total	475,576			471,893			468,581			3,683			3,312

36

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

NISOURCE INC.

Electric Operations (continued)

Comparability of line item operating results may be impacted by regulatory and depreciation trackers (other than those for cost of sales) that allow for the recovery in rates of certain costs. Therefore, increases in these tracked operating expenses are offset by increases in net revenues and have essentially no impact on net income.

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.

Net revenues for 2019 were $1,231.9 million, an increase of $25.8 million from the same period in 2018. The change in net revenues was primarily driven 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.

Partially offset by:

• Lower revenues from the effects of cooler weather of $15.1 million.

• Decreased residential, commercial and industrial usage of $10.8 million.

Operating expenses were $5.1 million higher in 2019 than 2018. This change was primarily driven by:

• Higher regulatory and depreciation trackers, which are offset in net revenues, of $8.4 million.

• Increased depreciation of $8.7 million due to higher capital expenditures placed in service.

Partially offset by:

• 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.

2018 vs. 2017 Operating Income

For 2018, Electric Operations reported operating income of $386.1 million, an increase of $18.7 million from the comparable 2017 period.

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

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

• Decreased rates from implementation of regulatory outcomes related to the TCJA of $32.9 million.

• Decreased industrial usage of $17.1 million.

• A revenue reserve of $16.2 million in 2018 resulting from the probable future refund of certain collections from customers as a result of the lower income tax rate from the TCJA .

• Increased fuel handling costs of $7.3 million.

Partially offset by:

• The effects of warmer weather of $25.2 million.

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

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

• Lower regulatory and depreciation trackers, which are offset in net revenues, of $35.6 million.

• Lower outside service costs of $32.1 million and lower material and supplies costs of $10.2 million primarily related to the retirement of Bailly Generating Station Units 7 and 8 on May 31, 2018.

• Decreased employee and administrative costs of $18.4 million.

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

NISOURCE INC.

Electric Operations (continued)

Partially offset by:

• Increased depreciation of $10.0 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 net revenues.

Weather in the Electric Operations’ territories for 2019 was 20% warmer than normal and 18% cooler than the same period in 2018, decreasing net revenues $15.1 million for the year ended December 31, 2019 compared to 2018.

Weather in the Electric Operations’ territories for 2018 was 46% warmer than normal and 41% warmer than the same period in 2017, increasing net revenues $25.2 million for the year ended December 31, 2018 compared to 2017.

Sales

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.

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

BP Products North America. On March 29, 2018, WCE, which is currently owned by BP p.l.c ("BP") and BP Products North America, which operates the BP Refinery, filed a petition at the IURC asking that the combined operations of WCE and BP be treated as a single premise, and the WCE generation be dedicated primarily to BP Refinery operations beginning in May 2019 as WCE has self-certified as a qualifying facility at FERC. BP Refinery planned to continue to purchase electric service from NIPSCO at a reduced demand level beginning May 2019; however, a settlement agreement was filed on November 2, 2018 agreeing that BP and WCE would not move forward with construction of a private transmission line to serve BP until conclusion of NIPSCO's pending electric rate case. The IURC approved the settlement agreement as filed on February 20, 2019. On December 4, 2019, the IURC issued an order in the electric rate case approving the implementation of a new industrial service structure. This resolved the issues included in BP’s original petition. Refer to Note 8, "Regulatory Matters," in the Notes to Consolidated Financial Statements for additional information.

Economic Conditions

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 net 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.

NIPSCO's performance remains closely linked to the performance of the steel industry. NIPSCO’s MWh sales to steel-related industries accounted for approximately 51.5% and 49.7% of the total industrial MWh sales for the years ended December 31, 2019 and 2018, respectively.

Electric Supply

NIPSCO 2018 Integrated Resource Plan. Multiple factors, but primarily economic ones, including low natural gas prices, advancing cost effective renewable technology and increasing capital and operating costs associated with existing coal plants, have led NIPSCO to conclude in its October 2018 Integrated Resource Plan submission that NIPSCO’s current fleet of coal generation facilities will be retired earlier than previous Integrated Resource Plan’s had indicated.

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

NISOURCE INC.

Electric Operations (continued)

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

The current replacement plan includes renewable sources of energy, including wind, solar, and battery storage to be obtained through a combination of NIPSCO ownership and PPAs. Refer to Note 19-E, "Other Matters," in the Notes to Consolidated Financial Statements for further discussion.

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

NISOURCE INC.

Liquidity and Capital Resources

Greater Lawrence Incident: As discussed in the "Executive Summary" and in Note 19, “Other Commitments and Contingencies” in the Notes to Consolidated Financial Statements, we have recorded and paid costs associated with the Greater Lawrence Incident and have invested capital to replace the entire affected 45-mile cast iron and bare steel pipeline system that delivers gas to the impacted area. As discussed in the "Executive Summary," Note 19 referenced earlier in this paragraph, and Part I, Item 1A “Risk Factors,” we may incur additional expenses and liabilities in excess of our recorded liabilities and estimated additional costs associated with the Greater Lawrence Incident. Since the Greater Lawrence Incident and through December 31, 2019, we have collected $800 million from insurance providers; however, total costs related to the incident have exceeded the total amount of insurance coverage available under our policies. To date, this excess has primarily been funded through short-term borrowings. During 2020, we plan to pursue alternatives to these short-term borrowings, which include long-term financing and potential proceeds from the sale of the Massachusetts Business. For additional information, see Note 26, “Subsequent Event,” in the Notes to Consolidated Financial Statements.

Operating Activities

Net cash from operating activities for the year ended December 31, 2019 was $1,583.3 million, an increase of $1,043.2 million from 2018. This increase was driven primarily by the receipt of $795 million of insurance recoveries in 2019 related to the Greater Lawrence Incident and approximately $220 million lower cash spend for the Greater Lawrence Incident in 2019. Refer to Note 19, "Other Commitments and Contingencies" in the Notes to Consolidated Financial Statements for further information related to the Greater Lawrence Incident.

Pension and Other Postretirement Plan Funding. In 2019, we contributed $2.9 million to our pension plans and $23.0 million to our other postretirement benefit plans. In 2018, we contributed $2.9 million to our pension plans and $21.0 million to our other postretirement benefit plans. Given the current funded status of the pension plans, and barring unforeseen market volatility that may negatively impact the valuation of our plan assets, we do not believe additional material contributions to our pension plans will be required for the foreseeable future.

Income Taxes. Rates for our regulated customers include provisions for the collection of U.S. federal income taxes. The reduction in the U.S. federal corporate income tax rate as a result of the TCJA led to a decrease in the amount billed to customers through rates, ultimately resulting in lower cash collections from operating activities. In addition, we are required to pass back to customers “excess deferred taxes” which represent amounts collected from customers in the past to cover deferred tax liabilities which, as a result of the passage of the TCJA, are now less than the originally billed amounts. Approximately $1.5 billion of excess deferred taxes was recorded as a regulatory liability as of December 31, 2017 as a result of implementing the TCJA. The majority of this balance related to temporary book-to-tax differences on utility property protected by IRS normalization rules; this portion of the excess deferred taxes balance will be passed back to customers over the remaining average useful life of the associated property as required by the TCJA. The remainder of the excess deferred tax balance is passed back over periods determined by our state utility commissions. The pass back of excess deferred taxes has been approved in all our jurisdictions. As of December 31, 2019, we have approximately $1.3 billion of remaining regulatory liabilities associated with excess deferred taxes.

As of December 31, 2019, we have a deferred tax asset of $657.1 million related to a federal NOL carryforward, of which $406.1 million relates to years prior to the implementation of the TCJA. As a result of being in an NOL position, we were not required to make any cash payments for federal income tax purposes during the three years ended December 31, 2019. The carryforward periods for pre-TCJA tax benefits expire in various tax years from 2028 to 2037; however, we expect to fully utilize the carryforward benefit prior to its expiration. According to the TCJA, utilization of NOL carryforwards generated after December 31, 2017 do not expire but are limited to 80% of current year taxable income. Accordingly, we may be required to make cash payments for federal income taxes in future years despite having NOL carryforwards in excess of current taxes payable.

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

NISOURCE INC.

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. The table below reflects capital expenditures and certain other investing activities by segment for 2019, 2018 and 2017. 

(in millions)	2019		2018(3)		2017
Gas Distribution Operations
System Growth and Tracker	$	1,006.1	$	897.5	$	909.2
Maintenance	374.3		417.8		216.4
Total Gas Distribution Operations	1,380.3		1,315.3		1,125.6
Electric Operations
System Growth and Tracker	279.5		346.0		435.3
Maintenance	189.4		153.3		157.1
Total Electric Operations	468.9		499.3		592.4
Corporate and Other Operations - Maintenance(1)	18.6		—		35.8
Total(2)	$	1,867.8	$	1,814.6	$	1,753.8

⁽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 2017 and 2019.

⁽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 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 2018, capital expenditures and certain other investing activities were $1,814.6 million, which was $60.8 million higher than the 2017 capital program. This increased spending is due in part to costs associated with the Greater Lawrence Incident pipeline replacement, gas transmission projects, environmental investments and system modernization projects across all seven states in our operating area.

For 2020, we project to invest approximately $1.8 to $1.9 billion in our capital program. This projected level of spend is consistent with 2019 spend levels and is expected to focus on growth, safety, and modernization projects across our operating area.

Financing Activities

Short-term Debt. Refer to Note 15, “Short-Term Borrowings,” in the Notes to Consolidated Financial Statements for information on short-term debt.

Long-term Debt. Refer to Note 14, “Long-Term Debt,” in the Notes to Consolidated Financial Statements for information on long-term debt.

Net Available Liquidity. As of December 31, 2019, an aggregate of $1,409.1 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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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)

NISOURCE INC.

The following table displays NiSource's liquidity position as of December 31, 2019 and 2018:

Year Ended December 31, (in millions)	2019		2018
Current Liquidity
Revolving Credit Facility	$	1,850.0	$	1,850.0
Accounts Receivable Program(1)	353.2		399.2
Less:
Commercial Paper	570.0		978.0
Accounts Receivable Program Utilized	353.2		399.2
Letters of Credit Outstanding Under Credit Facility	10.2		10.2
Add:
Cash and Cash Equivalents	139.3		112.8
Net Available Liquidity	$	1,409.1	$	974.6

⁽¹⁾Represents the lesser of the seasonal limit or maximum borrowings supportable by the underlying receivables.

Debt Covenants. We are subject to a financial covenant under our revolving credit facility and term loan agreement, which requires us to maintain a debt to capitalization ratio that does not exceed 70%. A similar covenant in a 2005 private placement note purchase agreement requires us to maintain a debt to capitalization ratio that does not exceed 75%. As of December 31, 2019, the ratio was 61.7%.

Sale of Trade Accounts Receivables. Refer to Note 18, “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, 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+	Negative	Baa2	Stable	BBB	Stable
NIPSCO	BBB+	Negative	Baa1	Stable	BBB	Stable
Columbia of Massachusetts	BBB+	Negative	Baa2	Stable	Not rated	Not rated
Commercial Paper	A-2	Negative	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, 2019, the collateral requirement that would be required in the event of a downgrade below the ratings trigger levels would amount to approximately $72.1 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, 2019, 382,135,680 shares of common stock and 440,000 shares of preferred stock were outstanding. For more information regarding our common and preferred stock, see Note 12, "Equity," in the Notes to Consolidated Financial Statements.

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

NISOURCE INC.

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, 2019 and their maturities were:

(in millions)	Total		2020		2021		2022		2023		2024		After
Long-term debt (1)	$	7,738.6	$	—	$	63.6	$	530.0	$	600.0	$	—	$	6,545.0
Interest payments on long-term debt	6,214.2		342.0		340.7		337.1		311.1		299.9		4,583.4
Finance leases(2)	325.9		27.2		27.3		26.8		23.1		19.9		201.6
Operating leases(3)	79.1		15.6		9.4		8.2		7.6		6.6		31.7
Energy commodity contracts(4)	95.9		65.5		30.4		—		—		—		—
Service obligations:
Pipeline service obligations	3,450.7		605.0		590.1		546.8		357.2		237.5		1,114.1
IT service obligations	153.2		63.6		49.4		38.0		1.1		1.1		—
Other service obligations(5)	59.8		45.8		14.0		—		—		—		—
Other liabilities	27.3		27.3		—		—		—		—		—
Total contractual obligations	$	18,144.7	$	1,192.0	$	1,124.9	$	1,486.9	$	1,300.1	$	565.0	$	12,475.8

⁽¹⁾ Long-term debt balance excludes unamortized issuance costs and discounts of $70.5 million.

⁽²⁾ Finance lease payments shown above are inclusive of interest totaling $108.3 million.

⁽³⁾ Operating lease payments shown above are inclusive of interest totaling $14.3 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. If we were to continue the fleet vehicle leases outstanding at December 31, 2019, payments would be $34.5 million in 2020, $28.3 million in 2021, $23.4 million in 2022, $19.9 million in 2023, $15.2 million in 2024 and $15.2 million thereafter.  

⁽⁴⁾In January 2020, NIPSCO signed new coal contract commitments of $14.4 million for 2020. These contracts are not included above.  

⁽⁵⁾In February 2020, NIPSCO signed a new railcar coal transportation contract commitment of $12.0 million for 2020. This contract is not included above.

Our calculated estimated interest payments for long-term debt is based on the stated coupon and payment dates. For 2020, we project that we will be required to make interest payments of approximately $368.2 million, which includes $342.0 million of interest payments related to our long-term debt outstanding as of December 31, 2019. At December 31, 2019, we had $1,773.2 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 2020. Plan contributions beyond 2020 are dependent upon a number of factors, including actual returns on plan assets, which cannot be reliably estimated at this time. In 2020, we expect to make contributions of approximately $3.0 million to our pension plans and approximately $24.0 million to our postretirement medical and life plans. Refer to Note 11, “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, payroll, sales and use, and various other taxes and expect to make tax payments of approximately $247.1 million in 2020, 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 10, "Income Taxes," in the Notes to Consolidated Financial Statements for more information.

Refer to Note 19-A, “Contractual Obligations,” in the Notes to Consolidated Financial Statements for further information.

In January 2019, NIPSCO executed two 20 year PPAs to purchase 100% of the output from renewable generation facilities at a fixed price per MWh. Payments under the PPAs will not begin until the associated generation facilities are constructed by the owner / seller which is currently scheduled to be complete by the end of 2020 for one facility. Payments that will be made under the agreements are not included in the table of contractual commitments above as there are no minimum payment obligations under the agreements. NIPSCO has filed a notice with the IURC of its intention not to move forward with one of its approved PPAs due to the failure to meet a condition precedent in the agreement as a result of local zoning restrictions. See Note 19-E, “Other Matters - NIPSCO 2018 Integrated Resource Plan,” in the Notes to Consolidated Financial Statements for additional information.

In January 2019, NIPSCO executed a BTA with a developer to construct a renewable generation facility with a nameplate capacity of approximately 100 MW; construction of the facility is expected to be completed by the end of 2020. In October 2019, NIPSCO

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

NISOURCE INC.

executed a BTA with a developer to construct an additional renewable generation facility with a nameplate capacity of approximately 300 MW; construction of this facility is expected to be completed by the end of 2021. Payments under these agreements are not included in the table of contractual commitments as NIPSCO's purchase requirement under these BTAs is dependent on satisfactory approval of the BTAs by the IURC, successful execution of agreements with a tax equity partner, and timely completion of construction. See Note 19-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 19, “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. Risk management for us is 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 9, "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, 2019 and 2018.

Interest Rate Risk

We are exposed to interest rate risk as a result of changes in interest rates on borrowings under our revolving credit agreement, commercial paper program, term loan agreement and accounts receivable programs, which have interest rates that are indexed to short-term market interest rates. Based upon average borrowings and debt obligations subject to fluctuations in short-term market interest rates, an increase (or decrease) in short-term interest rates of 100 basis points (1%) would have increased (or decreased) interest expense by $19.0 million and $13.3 million for 2019 and 2018, 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.

Refer to Note 9, "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, 2019 and 2018. 

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

NISOURCE INC.

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.

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 $2,239.6 million and $2,512.2 million at December 31, 2019, and $2,237.5 million and $2,660.0 million at December 31, 2018, respectively. For additional information, refer to Note 8, “Regulatory Matters,” in the Notes to Consolidated Financial Statements.

In the event that regulation significantly changes the opportunity for us to recover our costs in the future, all or a portion of our regulated operations may no longer meet the criteria for the application of ASC Topic 980, Regulated Operations. In such event, a write-down of all or a portion of our existing regulatory assets and liabilities could result. If transition cost recovery is approved by the appropriate regulatory bodies that would meet the requirements under GAAP for continued accounting as regulatory assets and liabilities during such recovery period, the regulatory assets and liabilities would be reported at the recoverable amounts. If we were unable to continue to apply the provisions of ASC Topic 980, Regulated Operations, we would be required to apply the provisions of ASC Topic 980-20, Discontinuation of Rate-Regulated Accounting. In management’s opinion, our regulated subsidiaries will be subject to ASC Topic 980, Regulated Operations for the foreseeable future.

Certain of the regulatory assets reflected on our Consolidated Balance Sheets require specific regulatory action in order to be included in future service rates. Although recovery of these amounts is not guaranteed, we believe that these costs meet the requirements for deferral as regulatory assets. Regulatory assets requiring specific regulatory action amounted to $307.2 million at December 31, 2019. If we determine that the amounts included as regulatory assets were not recoverable, a charge to income would immediately be required to the extent of the unrecoverable amounts.

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 8, "Regulatory Matters," and Note 10, "Income Taxes," in the Notes to Consolidated Financial Statements.

As discussed in Note 19-E, "Other Matters - Greater Lawrence Pipeline Replacement," since the Greater Lawrence Incident and through December 31, 2019, we have invested approximately $258 million of capital spend for the pipeline replacement in the affected communities; 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 full cost of the pipeline replacement. In January 2020, we filed a lawsuit against the property insurer, seeking payment of our property claim. We are currently unable

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

NISOURCE INC.

to predict the timing or amount of any insurance recovery under the property policy. The recovery of any capital investment not reimbursed through insurance will be addressed in a future regulatory proceeding; a future regulatory proceeding is dependent on the outcome of the sale of the Massachusetts Business. The outcome of such a proceeding (if any) is uncertain. In accordance with ASC 980-360, if it becomes probable that a portion of the pipeline replacement cost will not be recoverable through customer rates and an amount can be reasonably estimated, we will reduce our regulated plant balance for the amount of the probable disallowance and record an associated charge to earnings. This could result in a material adverse effect to our financial condition, results of operations and cash flows. Additionally, if a rate order is received allowing recovery of the investment with no or reduced return on investment, a loss on disallowance may be required.

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 2020 net periodic benefit cost, we selected an expected pre-tax long-term rate of return of 5.70% and 5.67% for our pension and other postretirement benefit plan assets, respectively.

We estimate the assumed health care cost trend rate, which is used in determining our other postretirement benefit net expense, based upon our actual health care cost experience, the effects of recently enacted legislation, third-party actuarial surveys and general economic conditions.

We use the Society of Actuaries’ most recently published mortality data in developing a best estimate of mortality as part of the calculation of the pension and other postretirement benefit obligations.

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

NISOURCE INC.

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

	Impact on December 31, 2019 Projected Benefit Obligation Increase/(Decrease)
Change in Assumptions (in millions)	Pension Benefits			Other Postretirement Benefits
+50 basis points change in discount rate	$	(89.9	)	$	(29.0	)
-50 basis points change in discount rate	97.7			31.8
+50 basis points change in health care trend rates				15.0
-50 basis points change in health care trend rates				(13.1		)
	Impact on 2019 Expense Increase/(Decrease)(1)
Change in Assumptions (in millions)	Pension Benefits			Other Postretirement Benefits
+50 basis points change in discount rate	$	(1.8	)	$	0.3
-50 basis points change in discount rate	1.9			0.7
+50 basis points change in expected long-term rate of return on plan assets	(8.9		)	(1.2		)
-50 basis points change in expected long-term rate of return on plan assets	8.9			1.2
+50 basis points change in health care trend rates				0.6
-50 basis points change in health care trend rates				(0.5		)

⁽¹⁾Before labor capitalization and regulatory deferrals.

In January 2017, we changed the method used to estimate the service and interest components of net periodic benefit cost for pension and other postretirement benefits. This change, compared to the previous method, resulted in a decrease in the actuarially-determined service and interest cost components. Historically, we estimated service and interest cost utilizing a single weighted-average discount rate derived from the yield curve used to measure the benefit obligation at the beginning of the period. For fiscal 2017 and beyond, we now utilize a full yield curve approach to estimate these components by applying the specific spot rates along the yield curve used in the determination of the benefit obligation to the relevant projected cash flows. For further discussion of our pension and other postretirement benefits, see Note 11, “Pension and Other Postretirement Benefits,” in the Notes to Consolidated Financial Statements.

Goodwill and Intangible Assets. We have seven goodwill reporting units, comprised of the seven state operating companies within the Gas Distribution Operations reportable segment. Our goodwill assets at December 31, 2019 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, 2019. A qualitative ("step 0") test was completed on May 1, 2019 for all reporting units other than our Columbia of Massachusetts reporting unit. In the Step 0 analysis, we assessed various assumptions, events and circumstances that would have affected the estimated fair value of the applicable reporting units as compared to their baseline May 1, 2016 “step 1” fair value measurement. The results of this assessment indicated that it is not more likely than not that these reporting units fair values are less than their reporting unit carrying values; therefore, no “step 1” analysis was required.

The results of our Columbia of Massachusetts reporting unit were negatively impacted by the Greater Lawrence Incident (see Note 19-C, "Legal Proceedings," in the Notes to Consolidated Financial Statements). As a result, we completed a quantitative "step 1" analysis for the May 1, 2019 goodwill analysis for this reporting unit. Consistent with our historical impairment testing of goodwill, fair value of this reporting unit 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

47

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

NISOURCE INC.

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 the Columbia of Massachusetts reporting unit exceeds its carrying value. As a result, no impairment charge was recorded as of the May 1, 2019 test date.

Although our annual impairment test is performed during the second quarter, we continue to monitor changes in circumstances that may indicate that it is more likely than not that the fair value of our reporting units is less than the reporting unit carrying value. During the fourth quarter of 2019, in connection with the preparation of the year-end financial statements, we assessed matters related to Columbia of Massachusetts. While there was no single determinative event or factor, the consideration in totality of several factors that developed during the fourth quarter of 2019 led us to conclude that it was more likely than not that the fair value of the Columbia of Massachusetts reporting unit was below its carrying value. These factors included: (i) increased Massachusetts DPU regulatory enforcement activity related to Columbia of Massachusetts during the fourth quarter, including (a) an order imposing work restrictions on Columbia of Massachusetts, impacting Columbia of Massachusetts' infrastructure replacement program, (b) two orders opening public investigations into Columbia of Massachusetts related to the Greater Lawrence Incident and restoration efforts following the incident, and (c) an order defining the scope of the Massachusetts DPU's investigation into the preparation and response of Columbia of Massachusetts related to the incident; (ii) increased uncertainty as to the ability of Columbia of Massachusetts to execute its growth strategy, including utility infrastructure investments, and to obtain timely regulatory outcomes with reasonable rates of return; (iii) further damage to Columbia of Massachusetts' reputation as a result of concerns related to service lines abandoned during the restoration work following the Greater Lawrence Incident and the gas release event in Lawrence, Massachusetts on September 27, 2019; and (iv) a potential sale of the Massachusetts Business. See Note 19, "Other Commitments and Contingencies - C. Legal Proceedings," in the Notes to Consolidated Financial Statements for more information regarding Massachusetts DPU regulatory enforcement activity and Note 26, "Subsequent Event," in the Notes to Consolidated Financial Statements for more information regarding the potential sale of the Massachusetts Business.

As a result, a new impairment analysis was required for our Columbia of Massachusetts reporting unit. This analysis used a weighted average of income and market approaches for calculating fair value. 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 updated cash flow projections. While certain assumptions, such as market multiples, remained unchanged in the year-end test, our cash flow projections, return on equity and rate case timing assumptions were all unfavorably updated at year-end compared to the May 1, 2019 test. The effects of these unfavorable developments were greater than the favorable change in weighted average cost of capital between the two tests. The 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.

Our intangible assets, apart from goodwill, consist 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. We review our definite-lived intangible assets for impairment when events or changes in circumstances indicate its fair value might be below its carrying amount.

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 the franchise rights was below its carrying amount. These factors were the same fourth quarter circumstances outlined in the goodwill impairment discussion above. As a result, we performed a year-end impairment test in which we compared the book value of Columbia of Massachusetts to its undiscounted future cash flow and estimated fair value. With this analysis, we determined that the fair value of the franchise rights was zero. Therefore, we wrote off the entire franchise rights book value, which resulted in an impairment charge totaling $209.7 million. See Note 6, "Goodwill and Other Intangible Assets," in the Notes to Consolidated Financial Statements for more information.

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.

Recently Issued Accounting Pronouncements

Refer to Note 2, "Recent Accounting Pronouncements," in the Notes to Consolidated Financial Statements.

48

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

NISOURCE INC.

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.”

49

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

NISOURCE INC.

Index	Page
Report of Independent Registered Public Accounting Firm	51
Statements of Consolidated Income (Loss)	54
Statements of Consolidated Comprehensive Income (Loss)	55
Consolidated Balance Sheets	56
Statements of Consolidated Cash Flows	58
Statements of Consolidated Stockholders' Equity	59
Notes to Consolidated Financial Statements	61
1. Nature of Operations and Summary of Significant Accounting Policies	61
2. Recent Accounting Pronouncements	64
3. Revenue Recognition	65
4. Earnings Per Share	68
5. Property, Plant and Equipment	69
6. Goodwill and Other Intangible Assets	69
7. Asset Retirement Obligations	71
8. Regulatory Matters	71
9. Risk Management Activities	79
10. Income Taxes	81
11. Pension and Other Postretirement Benefits	83
12. Equity	95
13. Share-Based Compensation	98
14. Long-Term Debt	101
15. Short-Term Borrowings	102
16. Leases	103
17. Fair Value	106
18. Transfers of Financial Assets	109
19. Other Commitments and Contingencies	110
20. Accumulated Other Comprehensive Loss	119
21. Other, Net	119
22. Interest Expense, Net	120
23. Segments of Business	120
24. Quarterly Financial Data (Unaudited)	122
25. Supplemental Cash Flow Information	122
26. Subsequent Event	123
Schedule II	124

50

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

NISOURCE INC.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the stockholders 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, 2019 and 2018, 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, 2019, 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, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2019, 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 27, 2020, expressed an unqualified opinion on the Company's internal control over financial reporting.

Basis for Opinion

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

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

Critical Audit Matters

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

Impact of Rate Regulation on the Financial Statements - Refer to Notes 1, 8, 19, and 26 to the financial statements

Critical Audit Matter Description

Certain subsidiaries of NiSource Inc. are fully regulated natural gas and electric utility companies serving customers in seven 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.

Through December 31, 2019, the Company invested approximately $258 million of capital spend for the Greater Lawrence Incident pipeline replacement. As of December 31, 2019, the Company determined that a disallowance of the Greater Lawrence Incident pipeline replacement capital expenditures was not probable. On February 26, 2020, the Company and its wholly-owned subsidiary, Columbia of Massachusetts (CMA), agreed to sell substantially all of CMA's utility property, plant, and equipment (including the

51

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

NISOURCE INC.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Greater Lawrence Incident pipeline replacement assets) with other specified assets and liabilities, to a third party. The Company estimates that the total pre-tax loss resulting from this sale will be approximately $360 million, based on December 31, 2019 asset and liability balances and estimated transaction costs.

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, (2) the likelihood of refund of amounts previously collected from customers, and (3) the probability of recovery of amounts capitalized related to the Greater Lawrence Incident pipeline replacement. 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 regulatory 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, including the Greater Lawrence Incident pipeline replacement; 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 regulatory commissions, regulatory statutes, interpretations, 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 precedence of regulatory commissions’ treatment of similar costs under similar circumstances. We evaluated the external information and compared it to management’s recorded regulatory asset and liability balances for completeness.

• For regulatory matters in process, including those that could impact the Greater Lawrence Incident pipeline replacement, we inspected the Company’s filings with regulatory commissions and the filings with regulatory commissions by intervenors 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. We inspected minutes of meetings of the board of directors and regulatory orders and other filings with regulatory 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.

• We evaluated the impact of the February 26, 2020 sale transaction on the carrying value of the Company’s utility property, plant, and equipment as of December 31, 2019.

Impairment of the Franchise Rights Intangible Asset & the Columbia of Massachusetts Reporting Unit Goodwill  - Refer to Note 6 to the financial statements

Critical Audit Matter Description

The Company assessed the changes in circumstances that occurred during the fourth quarter to determine whether it was more likely than not that the fair values of the long-lived assets (including the franchise rights intangible asset) and goodwill of Columbia of Massachusetts (CMA), a wholly-owned subsidiary of the Company, were below their carrying amount. The totality of several factors led to the Company concluding that it was more likely than not that the fair value of the CMA reporting unit and the value of CMA’s long-lived assets were below their carrying values. These factors included: (1) increased Massachusetts Department of Public Utilities (DPU) regulatory enforcement activity related to CMA, including (i) an order imposing work restrictions on CMA, (ii) two orders opening public investigations into CMA related to the Greater Lawrence Incident and restoration efforts following the incident, and (iii) an order defining the scope of the DPU’s investigation into the preparation and response of CMA related to the incident; (2) increased uncertainty as to the ability of CMA to execute its growth strategy, including utility infrastructure

52

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

NISOURCE INC.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

investments, and CMA’s ability to obtain timely regulatory outcomes with reasonable rates of return; (3) further damage to CMA’s reputation; and (4) the potential sale of the Company's business in Massachusetts.

The Company performed a long-lived asset impairment test as of December 31, 2019 in which it compared the book value of the CMA asset group to its undiscounted future cash flows and determined that the carrying value of the asset group was not recoverable. The Company estimated the fair value of the CMA 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 loss was allocated to reduce the recorded franchise rights intangible asset to its fair value of zero, which resulted in an impairment charge totaling $209.7 million for the year ended December 31, 2019. The Company also performed a goodwill impairment test for the CMA reporting unit as of December 31, 2019. As part of this test, the Company estimated CMA’s fair value based on a weighting of income and market approaches. This impairment analysis indicated that the fair value of the CMA reporting unit was below its carrying value and, as a result, the Company recognized a goodwill impairment charge totaling $204.8 million.

We identified the impairment of the franchise rights intangible asset and the CMA reporting unit goodwill as a critical audit matter as there was a high degree of auditor judgment and subjectivity in applying procedures relating to the allocation of impairment to CMA’s long-lived assets and the fair value measurement of the reporting unit. This was driven by significant management judgment when determining fair value, including (1) the weightings of the fair value approaches, (2) the future cash flows used in the impairment tests, and (3) other inputs used in the valuation including comparable company multiples, discount rates, and return on equity. In addition, the audit effort involved the use of fair value specialists to assist in performing audit procedures over these assumptions and evaluating the audit evidence obtained.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the impairment of CMA’s franchise rights intangible asset and CMA reporting unit goodwill included the following, among others:

• We tested the effectiveness of management’s controls over the impairments, including (1) validation of the assumptions included in the impairment analysis for both the franchise rights intangible asset and goodwill, (2) the evaluation of the methodology used in determining the magnitude of impairment charges as of December 31, 2019, and (3) the verification of the completeness and accuracy of the journal entry made to record the impairments and the related disclosures.

• We evaluated the inputs used in the franchise rights intangible asset and goodwill impairment tests, including cash flow projections, scenario analysis, discount rates, return on equity assumptions, and comparable company multiples.

• We compared the undiscounted cash flows used in the franchise rights intangible asset impairment test to the carrying value of the asset group to evaluate whether an impairment existed at December 31, 2019.

• With the assistance of our fair value specialists, we evaluated the reasonableness of the calculated amount of fair value of the franchise rights intangible asset.

• We evaluated the allocation of impairment to the franchise rights intangible asset.

• We evaluated the relative weightings of the income and market approaches used to estimate fair value for the purposes of the goodwill impairment test.

• We evaluated the reasonableness of the fair value calculated under the combination of income and market approaches by comparing it to the fair value used in the May 1, 2019 goodwill impairment test.

• We evaluated the Company’s disclosures related to the impairment charges.

/s/ DELOITTE & TOUCHE LLP

Columbus, Ohio

February 27, 2020

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

53

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

NISOURCE INC.

STATEMENTS OF CONSOLIDATED INCOME (LOSS)

Year Ended December 31, (in millions, except per share amounts)	2019			2018			2017
Operating Revenues
Customer revenues	$	5,053.4		$	4,991.1		$	4,730.2
Other revenues	155.5			123.4			144.4
Total Operating Revenues	5,208.9			5,114.5			4,874.6
Operating Expenses
Cost of sales (excluding depreciation and amortization)	1,534.8			1,761.3			1,518.7
Operation and maintenance	1,354.7			2,352.9			1,601.7
Depreciation and amortization	717.4			599.6			570.3
Impairment of goodwill and other intangible assets	414.5			—			—
Loss on sale of fixed assets and impairments, net	—			1.2			5.5
Other taxes	296.8			274.8			257.2
Total Operating Expenses	4,318.2			4,989.8			3,953.4
Operating Income	890.7			124.7			921.2
Other Income (Deductions)
Interest expense, net	(378.9		)	(353.3		)	(353.2		)
Other, net	(5.2		)	43.5			(13.5		)
Loss on early extinguishment of long-term debt	—			(45.5		)	(111.5		)
Total Other Deductions, Net	(384.1		)	(355.3		)	(478.2		)
Income (Loss) before Income Taxes	506.6			(230.6		)	443.0
Income Taxes	123.5			(180.0		)	314.5
Net Income (Loss)	383.1			(50.6		)	128.5
Preferred dividends	(55.1		)	(15.0		)	—
Net Income (Loss) Available to Common Shareholders	328.0			(65.6		)	128.5
Earnings (Loss) Per Share
Basic Earnings (Loss) Per Share	$	0.88		$	(0.18	)	$	0.39
Diluted Earnings (Loss) Per Share	$	0.87		$	(0.18	)	$	0.39
Basic Average Common Shares Outstanding	374.6			356.5			329.4
Diluted Average Common Shares	376.0			356.5			330.8

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

54

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

NISOURCE INC.

STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME (LOSS)

Year Ended December 31, (in millions, net of taxes)	2019			2018			2017
Net Income (Loss)	$	383.1		$	(50.6	)	$	128.5
Other comprehensive income (loss):
Net unrealized gain (loss) on available-for-sale securities(1)	5.7			(2.6		)	0.8
Net unrealized gain (loss) on cash flow hedges(2)	(64.2		)	22.7			(22.5		)
Unrecognized pension and OPEB benefit (costs)(3)	3.1			(4.4		)	3.4
Total other comprehensive income (loss)	(55.4		)	15.7			(18.3		)
Total Comprehensive Income (Loss)	$	327.7		$	(34.9	)	$	110.2

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

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

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

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

55

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

NISOURCE INC.

CONSOLIDATED BALANCE SHEETS

(in millions)	December 31, 2019			December 31, 2018
ASSETS
Property, Plant and Equipment
Utility plant	$	24,502.6		$	22,780.8
Accumulated depreciation and amortization	(7,609.3		)	(7,257.9		)
Net utility plant	16,893.3			15,522.9
Other property, at cost, less accumulated depreciation	18.9			19.6
Net Property, Plant and Equipment	16,912.2			15,542.5
Investments and Other Assets
Unconsolidated affiliates	1.3			2.1
Other investments	228.9			204.0
Total Investments and Other Assets	230.2			206.1
Current Assets
Cash and cash equivalents	139.3			112.8
Restricted cash	9.1			8.3
Accounts receivable (less reserve of $19.2 and $21.1, respectively)	856.9			1,058.5
Gas inventory	250.9			286.8
Materials and supplies, at average cost	120.2			101.0
Electric production fuel, at average cost	53.6			34.7
Exchange gas receivable	48.5			88.4
Regulatory assets	225.7			235.4
Prepayments and other	149.7			129.5
Total Current Assets	1,853.9			2,055.4
Other Assets
Regulatory assets	2,013.9			2,002.1
Goodwill	1,485.9			1,690.7
Intangible assets, net	—			220.7
Deferred charges and other	163.7			86.5
Total Other Assets	3,663.5			4,000.0
Total Assets	$	22,659.8		$	21,804.0

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

56

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

NISOURCE INC.

CONSOLIDATED BALANCE SHEETS

(in millions, except share amounts)	December 31, 2019			December 31, 2018
CAPITALIZATION AND LIABILITIES
Capitalization
Stockholders’ Equity
Common stock - $0.01 par value, 600,000,000 shares authorized; 382,135,680 and 372,363,656 shares outstanding, respectively	$	3.8		$	3.8
Preferred stock - $0.01 par value, 20,000,000 shares authorized; 440,000 and 420,000 shares outstanding, respectively	880.0			880.0
Treasury stock	(99.9		)	(99.9		)
Additional paid-in capital	6,666.2			6,403.5
Retained deficit	(1,370.8		)	(1,399.3		)
Accumulated other comprehensive loss	(92.6		)	(37.2		)
Total Stockholders’ Equity	5,986.7			5,750.9
Long-term debt, excluding amounts due within one year	7,856.2			7,105.4
Total Capitalization	13,842.9			12,856.3
Current Liabilities
Current portion of long-term debt	13.4			50.0
Short-term borrowings	1,773.2			1,977.2
Accounts payable	666.0			883.8
Customer deposits and credits	256.4			238.9
Taxes accrued	231.6			222.7
Interest accrued	99.4			90.7
Exchange gas payable	59.7			85.5
Regulatory liabilities	160.2			140.9
Legal and environmental	20.1			18.9
Accrued compensation and employee benefits	156.3			149.7
Claims accrued	165.4			114.7
Other accruals	144.1			63.8
Total Current Liabilities	3,745.8			4,036.8
Other Liabilities
Risk management liabilities	134.0			46.7
Deferred income taxes	1,485.3			1,330.5
Deferred investment tax credits	9.7			11.2
Accrued insurance liabilities	81.5			84.4
Accrued liability for postretirement and postemployment benefits	373.2			389.1
Regulatory liabilities	2,352.0			2,519.1
Asset retirement obligations	416.9			352.0
Other noncurrent liabilities	218.5			177.9
Total Other Liabilities	5,071.1			4,910.9
Commitments and Contingencies (Refer to Note 19, "Other Commitments and Contingencies")	—			—
Total Capitalization and Liabilities	$	22,659.8		$	21,804.0

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

57

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

NISOURCE INC.

STATEMENTS OF CONSOLIDATED CASH FLOWS

Year Ended December 31, (in millions)	2019			2018			2017
Operating Activities
Net Income (Loss)	$	383.1		$	(50.6	)	$	128.5
Adjustments to Reconcile Net Income (Loss) to Net Cash from Operating Activities:
Loss on early extinguishment of debt	—			45.5			111.5
Depreciation and amortization	717.4			599.6			570.3
Deferred income taxes and investment tax credits	118.2			(188.2		)	306.7
Stock compensation expense and 401(k) profit sharing contribution	25.9			28.6			40.1
Impairment of goodwill and other intangible assets	414.5			—			—
Amortization of discount/premium on debt	8.2			7.5			7.4
AFUDC equity	(8.0		)	(14.2		)	(12.6		)
Other adjustments	(0.9		)	1.7			6.6
Changes in Assets and Liabilities:
Accounts receivable	187.8			(186.2		)	(52.3		)
Inventories	(2.0		)	41.4			19.0
Accounts payable	(299.9		)	268.4			49.0
Customer deposits and credits	16.9			(25.4		)	(2.5		)
Taxes accrued	7.3			20.2			10.2
Interest accrued	8.8			(21.7		)	(33.9		)
Exchange gas receivable/payable	55.5			(21.5		)	(64.5		)
Other accruals	105.3			43.5			31.8
Prepayments and other current assets	(33.6		)	(14.5		)	(13.3		)
Regulatory assets/liabilities	(85.6		)	(53.2		)	57.5
Postretirement and postemployment benefits	(21.1		)	58.2			(380.9		)
Deferred charges and other noncurrent assets	(76.1		)	3.8			(2.0		)
Other noncurrent liabilities	61.6			(2.8		)	(34.4		)
Net Cash Flows from Operating Activities	1,583.3			540.1			742.2
Investing Activities
Capital expenditures	(1,802.4		)	(1,818.2		)	(1,695.8		)
Cost of removal	(113.2		)	(104.3		)	(109.0		)
Purchases of available-for-sale securities	(140.4		)	(90.0		)	(168.4		)
Sales of available-for-sale securities	132.1			82.3			163.1
Other investing activities	1.5			4.1			1.6
Net Cash Flows used for Investing Activities	(1,922.4		)	(1,926.1		)	(1,808.5		)
Financing Activities
Issuance of long-term debt	750.0			350.0			3,250.0
Repayments of long-term debt and finance lease obligations	(51.6		)	(1,046.1		)	(1,855.0		)
Issuance of short-term debt (maturity > 90 days)	600.0			950.0			—
Repayment of short-term debt (maturity > 90 days)	(700.0		)	—			—
Change in short-term borrowings, net (maturity ≤ 90 days)	(104.0		)	(178.5		)	(282.4		)
Issuance of common stock, net of issuance costs	244.4			848.2			336.7
Issuance of preferred stock, net of issuance costs	—			880.0			—
Equity costs, premiums and other debt related costs	(17.8		)	(46.0		)	(144.3		)
Acquisition of treasury stock	—			(4.0		)	(7.2		)
Dividends paid - common stock	(298.5		)	(273.3		)	(229.1		)
Dividends paid - preferred stock	(56.1		)	(11.6		)	—
Net Cash Flows from Financing Activities	366.4			1,468.7			1,068.7
Change in cash, cash equivalents and restricted cash	27.3			82.7			2.4
Cash, cash equivalents and restricted cash at beginning of period	121.1			38.4			36.0
Cash, Cash Equivalents and Restricted Cash at End of Period	$	148.4		$	121.1		$	38.4

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

58

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

NISOURCE INC.

STATEMENTS OF CONSOLIDATED STOCKHOLDERS’ EQUITY

(in millions)	Common Stock		Preferred Stock(1)		Treasury Stock			Additional Paid-In Capital		Retained Deficit			Accumulated Other Comprehensive Loss			Total
Balance as of January 1, 2017	$	3.3	$	—	$	(88.7	)	$	5,153.9	$	(972.2	)	$	(25.1	)	$	4,071.2
Comprehensive Income:
Net Income	—		—		—			—		128.5			—			128.5
Other comprehensive loss, net of tax	—		—		—			—		—			(18.3		)	(18.3		)
Common stock dividends ($0.70 per share)	—		—		—			—		(229.4		)	—			(229.4		)
Treasury stock acquired	—		—		(7.2		)	—		—			—			(7.2		)
Stock issuances:
Employee stock purchase plan	—		—		—			5.0		—			—			5.0
Long-term incentive plan	—		—		—			14.9		—			—			14.9
401(k) and profit sharing	—		—		—			34.3		—			—			34.3
Dividend reinvestment plan	—		—		—			6.4		—			—			6.4
ATM Program	0.1		—		—			314.6		—			—			314.7
Balance as of December 31, 2017	$	3.4	$	—	$	(95.9	)	$	5,529.1	$	(1,073.1	)	$	(43.4	)	$	4,320.1
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 12)	—		—		—			—		(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

⁽¹⁾Series A and Series B shares have an aggregate liquidation preference of $400M and $500M, respectively. See Note 12, "Equity" for additional information.

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

59

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

NISOURCE INC.

STATEMENTS OF CONSOLIDATED STOCKHOLDERS’ EQUITY

	Preferred	Common
(in thousands)	Shares	Shares	Treasury		Outstanding
Balance as of January 1, 2017	—	326,664	(3,504	)	323,160
Treasury stock acquired	—	—	(293	)	(293	)
Issued:
Employee stock purchase plan	—	207	—		207
Long-term incentive plan	—	351	—		351
401(k) and profit sharing plan	—	1,396	—		1,396
Dividend reinvestment plan	—	264	—		264
ATM program	—	11,931	—		11,931
Balance as of December 31, 2017	—	340,813	(3,797	)	337,016
Treasury stock acquired	—	—	(166	)	(166	)
Issued:
Common stock - private placement	—	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

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

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

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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 4.0 million customers in seven states. We generate substantially all of our operating income through these rate-regulated businesses. The consolidated financial statements include the accounts of us and our majority-owned subsidiaries after the elimination of all intercompany accounts and transactions.

On February 26, 2020, NiSource and Columbia of Massachusetts entered into the Asset Purchase Agreement with Eversource, a Massachusetts voluntary association. 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 business of storing, distributing or transporting natural gas to residential, commercial and industrial customers in Massachusetts, as conducted by Columbia of Massachusetts, and Eversource agreed to assume certain liabilities of Columbia of Massachusetts and its affiliates. For additional information, see Note 26, “Subsequent Event.”

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 and weather. 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 $350.5 million and $324.2 million as of December 31, 2019 and 2018, 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 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, 2019, 2018 or 2017. Refer to Note 17, "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.

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 regulatory accounting. In such an event, a write-down of all or a portion of our existing regulatory assets and liabilities could result. If transition cost recovery was approved by the appropriate regulatory bodies that would meet the requirements under GAAP for continued accounting as regulatory assets and liabilities during such recovery period, the regulatory assets and liabilities would be reported at the recoverable amounts. If unable to continue to apply

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Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

the provisions of regulatory accounting, we would be required to apply the provisions of ASC 980-20, Discontinuation of Rate-Regulated Accounting. In management’s opinion, our regulated subsidiaries will be subject to regulatory accounting for the foreseeable future. Refer to Note 8, "Regulatory Matters," for additional information.

G.       Plant and Other Property and Related Depreciation and Maintenance.    Property, plant and equipment (principally utility plant) is stated at cost. The 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 is generally depreciated on a straight-line basis over the life of the associated asset. Refer to Note 5, "Property, Plant and Equipment," for additional information related to depreciation expense.

For rate-regulated companies, AFUDC is capitalized on all classes of property except organization costs, land, autos, office equipment, tools and other general property purchases. The allowance is applied to construction costs for that period of time between the date of the expenditure and the date on which such project is placed in service. Our pre-tax rate for AFUDC was 3.0% in 2019, 3.5% in 2018 and 4.0% in 2017.

Generally, our subsidiaries follow the practice of charging maintenance and repairs, including the cost of removal of minor items of property, to expense as incurred. When our subsidiaries retire regulated property, plant and equipment, original cost plus the cost of retirement, less salvage value, is charged to accumulated depreciation. However, when it becomes probable a regulated asset will be retired substantially in advance of its original expected useful life or is abandoned, the cost of the asset and the corresponding accumulated depreciation is recognized as a separate asset. If the asset is still in operation, the net amount is classified as "Other property, at cost, less accumulated depreciation" on the Consolidated Balance Sheets. If the asset is no longer operating, the net amount is classified in "Regulatory assets" on the Consolidated Balance Sheets. If we are able to recover a full return of and on investment, the carrying value of the asset is based on historical cost. If we are not able to recover a full return on investment, a loss on impairment is recognized to the extent the net book value of the asset exceeds the present value of future revenues discounted at the incremental borrowing rate.

When our subsidiaries sell entire regulated operating units, or retire or sell nonregulated properties, the original cost and accumulated depreciation and amortization balances are removed from "Property, Plant and Equipment" on the Consolidated Balance Sheets. Any gain or loss is recorded in earnings, unless otherwise required by the applicable regulatory body. Refer to Note 5, "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, except for certain significant enterprise-wide technology investments which are amortized over a ten-year period.

External and internal up-front implementation costs associated with cloud computing arrangements that are service contracts are deferred on the Consolidated Balance Sheets. Once the installed software is ready for its intended use, such deferred costs are amortized on a straight-line basis to "Operation and maintenance," over the minimum term of the contract plus contractually-provided renewal periods that are reasonable expected to be exercised -- generally up to a maximum of five years.

H.        Goodwill and Other Intangible Assets.    Substantially all of our goodwill relates to the excess of cost over the fair value of the net assets acquired in the Columbia acquisition on November 1, 2000. We test our goodwill for impairment annually as of May 1, or more frequently if events and circumstances indicate that goodwill might be impaired. Fair value of our reporting units is determined using a combination of income and market approaches.

We had other intangible assets consisting primarily of franchise rights apart from goodwill that were identified as part of the purchase price allocations associated with the acquisition of Columbia of Massachusetts, which were being amortized on a straight-line basis over forty years from the date of acquisition.

During the fourth quarter of 2019, we impaired goodwill and intangible assets related to Columbia of Massachusetts. See Note 6, "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, 2019 and 2018 Consolidated Balance Sheets and short-term debt is recorded

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Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

in the amount of proceeds received from the transferees involved in the transactions. Refer to Note 18, "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 8, "Regulatory Matters," for additional information.

K.        Inventory.    Both the LIFO inventory methodology and the weighted average cost methodology are used to value natural gas in storage, as approved by regulators for all of our regulated subsidiaries. Inventory valued using LIFO was $47.2 million and $47.5 million at December 31, 2019 and 2018, 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 $25.5 million and $12.2 million at December 31, 2019 and 2018, respectively. Gas inventory valued using the weighted average cost methodology was $203.7 million at December 31, 2019 and $239.3 million at December 31, 2018.

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 9, "Risk Management Activities," for additional information.

N.        Income Taxes and Investment Tax Credits.    We record income taxes to recognize full interperiod tax allocations. Under the asset and liability method, deferred income taxes are provided for the tax consequences of temporary differences by applying enacted statutory tax rates applicable to future years to differences between the financial statement carrying amount and the tax basis of existing assets and liabilities. Investment tax credits associated with regulated operations are deferred and amortized as a reduction to income tax expense over the estimated useful lives of the related properties.

To the extent certain deferred income taxes of the regulated companies are recoverable or payable through future rates, regulatory assets and liabilities have been established. Regulatory assets for income taxes are primarily attributable to property-related tax timing differences for which deferred taxes had not been provided in the past, when regulators did not recognize such taxes as costs in the rate-making process. Regulatory liabilities for income taxes are primarily attributable to the regulated companies’ obligation to refund to ratepayers deferred income taxes provided at rates higher than the current Federal income tax rate. Such property-related amounts are credited to ratepayers using either the average rate assumption method or the reverse South Georgia method. Non property-related amounts are credited to ratepayers consistent with state utility commission direction.

Pursuant to the Internal Revenue Code and relevant state taxing authorities, we and our subsidiaries file consolidated income tax returns for federal and certain state jurisdictions. We and our subsidiaries are parties to a tax sharing agreement. Income taxes recorded by each party represent amounts that would be owed had the party been separately subject to tax.

O.       Environmental Expenditures.    We accrue for costs associated with environmental remediation obligations 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

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NISOURCE INC.

Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

cleanup efforts, costs of alternative cleanup methods and other variables. The liability is adjusted as further information is discovered or circumstances change. The accruals for estimated environmental expenditures are recorded on the Consolidated Balance Sheets in “Legal and environmental” 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 19, "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 19-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 2018-14, Compensation—Retirement Benefits—Defined Benefit Plans—General (Subtopic 715-20): Disclosure Framework—Changes to the Disclosure Requirements for Defined Benefit Plans	The pronouncement modifies the disclosure requirements for defined benefit pension 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 and must be applied on a retrospective basis to all periods presented.	Annual periods ending after December 15, 2020. Early adoption is permitted.	We are currently evaluating the effects of this pronouncement on our Notes to Consolidated Financial Statements. We expect to adopt this ASU on its effective date.
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.	Annual periods beginning after December 15, 2020. Early adoption is permitted.	We are currently evaluating the effects of this pronouncement on our Consolidated Financial Statements and Notes to Consolidated Financial Statements. We tentatively expect to adopt this ASU on its effective date.

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Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

Recently Adopted Accounting Pronouncements

Standard	Adoption
ASU 2019-01, Leases (Topic 842): Codification Improvements	See Note 16, "Leases," for our discussion of the effects of implementing these standards.
ASU 2018-11, Leases (Topic 842): Targeted Improvements
ASU 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842
ASU 2016-02, Leases (Topic 842)
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 that revised the guidance on the impairment of most financial assets and certain other instruments that are not measured at fair value through net income. This ASU replaces the current "incurred loss" model with an "expected loss" model for instruments measured at amortized cost. It also requires entities to record allowances for available-for-sale securities rather than impair the carrying amount of the securities. Subsequent improvements to the estimated credit losses of available-for-sale securities will be recognized immediately in earnings instead of over time as they are under historic guidance. We adopted this ASU effective January 1, 2020, using a modified retrospective method. Adoption of this standard did not have a material impact on our Consolidated Financial Statements. No material adjustments were made to January 1, 2020 opening balances as a result of adoption. For our investments that are classified as available for sale debt securities, we will recognize impairment using an allowance approach instead of an 'other than temporary' impairment (OTTI) model. Since we do not have amounts previously recognized in other comprehensive income related to previous OTTI charges, provisions of this ASU are adopted prospectively. In regards to our recorded balances of trade receivables that fall within the scope of this ASU, the ASU did not result in any significant modifications to our policies related to recognizing an allowance on our trade receivables. Based on shared risk characteristics, we segregate our trade receivables into separate pools. We will apply separate models to calculate reserves for uncollectible receivables, as well as consider factors other than time to determine whether a credit loss exists. ASC 326 also prescribes additional presentation and disclosure requirements. For reporting periods beginning after January 1, 2020, we will include additional disclosures in our Notes to Consolidated Financial Statements based on qualitative and quantitative assessment of materiality.
ASU 2016-13,  Financial Instruments-Credit Losses (Topic 326)

3.     Revenue Recognition

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

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Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

The table below provides results for the years ended December 31, 2019 and 2018 as if it had been prepared under historic accounting guidance. We included operating revenue information for the year ended December 31, 2017 for comparability.

Year Ended December 31, (in millions)	2019		2018		2017
Operating Revenues
Gas Distribution	$	2,336.1	$	2,348.4	$	2,063.2
Gas Transportation	1,171.3		1,055.2		1,021.5
Electric	1,698.5		1,707.4		1,785.5
Other	3.0		3.5		4.4
Total Operating Revenues	$	5,208.9	$	5,114.5	$	4,874.6

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

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

Customers in certain of our jurisdictions participate in programs that allow for a fixed payment each month regardless of usage. Payments received that exceed the value of gas or electricity actually delivered are recorded as a liability and presented in "Customer Deposits and Credits" on the Consolidated Balance Sheets. Amounts in this account are reduced and revenue is recorded when customer usage begins to exceed 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. In general, revenue recognized from tariff-based sales is equivalent to the value of natural gas or electricity supplied and billed each period, in addition to an estimate for deliveries completed during the period but not yet billed to the customer.

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,

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Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

Kentucky, Maryland, Indiana and Massachusetts. 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, 2019 (in millions)	Gas Distribution Operations		Electric Operations		Corporate and Other		Total
Customer Revenues(1)
Residential	$	2,309.0	$	481.6	$	—	$	2,790.6
Commercial	771.3		486.6		—		1,257.9
Industrial	245.2		607.7		—		852.9
Off-system	77.7		—		—		77.7
Miscellaneous	52.0		21.5		0.8		74.3
Total Customer Revenues	$	3,455.2	$	1,597.4	$	0.8	$	5,053.4
Other Revenues	54.5		101.0		—		155.5
Total Operating Revenues	$	3,509.7	$	1,698.4	$	0.8	$	5,208.9

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

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

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, 2019 and 2018 are presented in the table below. We had no significant contract assets or liabilities during the period. Additionally, we have not incurred any significant costs to obtain or fulfill contracts.

(in millions)	Customer Accounts Receivable, Billed (less reserve)(1)			Customer Accounts Receivable, Unbilled (less reserve)
Balance as of December 31, 2018	$	540.5		$	349.1
Balance as of December 31, 2019	466.6			346.6
Decrease	$	(73.9	)	$	(2.5	)

⁽¹⁾ Customer billed receivables decreased due to decreased natural gas costs and warmer weather in 2019 compared to 2018.

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.

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Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

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 programs that allow for the adjustment of billings and revenue for certain broad, external factors, or for additional billings if the entity achieves certain objectives, such as a specified reduction of costs. We maintain a 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.

4.    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 year ended 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 that period, and any incremental shares would have had an anti-dilutive impact on EPS. The calculation of diluted earnings per share for the year ended December 31, 2017 excludes the impact of forward agreements, which had an anti-dilutive effect for that period. The computation of diluted average common shares is as follows:

Year Ended December 31, (in thousands)	2019	2018	2017
Denominator
Basic average common shares outstanding	374,650	356,491	329,388
Dilutive potential common shares:
Shares contingently issuable under employee stock plans	929	—	547
Shares restricted under stock plans	154	—	821
Forward agreements	253	—	—
Diluted Average Common Shares	375,986	356,491	330,756

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Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

5.    Property, Plant and Equipment

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

At December 31, (in millions)	2019			2018
Property, Plant and Equipment
Gas Distribution Utility(1)	$	14,989.7		$	13,776.0
Electric Utility(1)	8,902.3			8,374.2
Corporate	153.3			155.8
Construction Work in Process	457.3			474.8
Non-Utility and Other	39.3			38.7
Total Property, Plant and Equipment	$	24,541.9		$	22,819.5
Accumulated Depreciation and Amortization
Gas Distribution Utility(1)	$	(3,556.0	)	$	(3,373.8	)
Electric Utility(1)	(3,973.8		)	(3,809.5		)
Corporate	(79.5		)	(74.6		)
Non-Utility and Other	(20.4		)	(19.1		)
Total Accumulated Depreciation and Amortization	$	(7,629.7	)	$	(7,277.0	)
Net Property, Plant and Equipment	$	16,912.2		$	15,542.5

⁽¹⁾NIPSCO’s common utility plant and associated accumulated depreciation and amortization are allocated between Gas Distribution Utility and Electric Utility Property, Plant and Equipment.

The weighted average depreciation provisions for utility plant, as a percentage of the original cost, for the periods ended December 31, 2019, 2018 and 2017 were as follows:

	2019		2018		2017
Electric Operations(1)	2.8	%	2.9	%	3.4	%
Gas Distribution Operations	2.5	%	2.2	%	2.1	%

⁽¹⁾Lower depreciation rate beginning in 2018 due to reduced EERM-related depreciation expense and higher depreciable base from transmission assets being placed into service in 2018.

We recognized depreciation expense of $612.2 million, $503.4 million and $501.5 million for the years ended 2019, 2018 and 2017, respectively.

Amortization of Software Costs. We amortized $55.5 million, $54.1 million and $44.0 million in 2019, 2018 and 2017, respectively, related to software costs. Our unamortized software balance was $169.6 million and $159.5 million at December 31, 2019 and 2018, respectively.

Amortization of Cloud Computing Costs. We amortized $1.6 million and $0.1 million in 2019 and 2018, respectively, related to cloud computing costs. Our unamortized cloud computing balance was $14.2 million and $4.9 million at December 31, 2019 and 2018, respectively.

6.    Goodwill and Other Intangible Assets

Intangible and Other Long-Lived Assets Impairment. Our intangible assets, apart from goodwill, consist 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. 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.

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. While there was no single determinative event or factor, the consideration in totality of several factors that developed during the fourth quarter of 2019 led us to conclude that it was more likely than not that the fair value of the Columbia of Massachusetts reporting unit and the value of its long-lived assets was below

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Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

its carrying value. These factors included: (i) increased Massachusetts DPU regulatory enforcement activity related to Columbia of Massachusetts during the fourth quarter, including (a) an order imposing work restrictions on Columbia of Massachusetts, impacting Columbia of Massachusetts' infrastructure replacement program, (b) two orders opening public investigations into Columbia of Massachusetts related to the Greater Lawrence Incident and restoration efforts following the incident, and (c) an order defining the scope of the Massachusetts DPU's investigation into the preparation and response of Columbia of Massachusetts related to the incident; (ii) increased uncertainty as to the ability of Columbia of Massachusetts to execute its growth strategy, including utility infrastructure investments, and to obtain timely regulatory outcomes with reasonable rates of return; (iii) further damage to Columbia of Massachusetts' reputation as a result of concerns related to service lines abandoned during the restoration work following the Greater Lawrence Incident and the gas release event in Lawrence, Massachusetts on September 27, 2019; and (iv) the potential sale of the Massachusetts Business. See Note 19, "Other Commitments and Contingencies - C. Legal Proceedings" for more information regarding Massachusetts DPU regulatory enforcement activity. See Note 26, "Subsequent Event" for more information on the potential sale of the Massachusetts Business.

As a result, we performed a year-end impairment test of the 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. This 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.

We also considered if any regulatory assets or ROU assets were probable of disallowance and determined no disallowances were probable. All of Columbia of Massachusetts' regulatory assets represent incurred costs probable of recovery.

As of December 31, 2019 and 2018, the carrying amount of the franchise rights was $0.0 million and $220.7 million (net of accumulated amortization of $221.5 million), respectively. We recorded amortization expense of $11.0 million in 2019, 2018 and 2017 related to our franchise rights intangible asset.

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, 2019 and 2018:

(in millions)	2019		2018
Gas Distribution Operations	$	1,485.9	$	1,690.7
Electric Operations	—		—
Corporate and Other	—		—
Total	$	1,485.9	$	1,690.7

For our annual goodwill impairment analysis performed as of May 1, 2019, we completed a qualitative "step 0" analysis for all reporting units other than our Columbia of Massachusetts reporting unit. In the step 0 analysis, we assessed various assumptions, events and circumstances that would have affected the estimated fair value of the applicable reporting units as compared to their baseline May 1, 2016 "step 1" fair value measurement. The results of this assessment indicated that it was not more likely than not that the fair values of these reporting units were less than their respective carrying values, accordingly, no "step 1" analysis was required.

The results of our Columbia of Massachusetts reporting unit were negatively impacted by the Greater Lawrence Incident (see Note 19-C, "Legal Proceedings"). As a result, we completed a quantitative "step 1" analysis for the May 1, 2019 goodwill analysis for this reporting unit. This analysis considered the progress Columbia of Massachusetts had made with its restoration efforts related to the Greater Lawrence Incident, including the replacement of previously repaired equipment and the settlement agreement with the three impacted municipalities, as well as the ability for Columbia of Massachusetts to sustain its infrastructure replacement growth strategy through GSEP and timely rate cases with reasonable rates of return. Consistent with our historical impairment testing of goodwill, fair value of the Columbia of Massachusetts reporting unit 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. These approaches also incorporate the latest available cash flow projections reflecting the estimated ongoing impacts of the Greater Lawrence Incident on Columbia of Massachusetts’ operations. The discount rates were derived using peer company

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Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

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 the Columbia of Massachusetts reporting unit exceeds its carrying value. As a result, no impairment charge was recorded as of the May 1, 2019 test date.

Although our annual impairment test is performed during the second quarter, we continue to monitor changes in circumstances that may indicate that it is more likely than not that the fair value of our reporting units is less than the reporting unit carrying value. During the fourth quarter of 2019, in connection with the preparation of the year-end financial statements, we assessed the matters related to Columbia of Massachusetts. These factors were the same fourth quarter circumstances outlined in the intangible and other long-lived assets impairment above.

As a result, a new impairment analysis was required for our Columbia of Massachusetts reporting unit. Consistent with the May 1, 2019 test, 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 updated cash flow projections. While certain assumptions, such as market multiples, remained unchanged in the year-end test, our cash flow projections, return on equity and rate case assumptions were all unfavorably updated at year-end compared to the May 1, 2019 test. The effects of these unfavorable developments were greater than the favorable change in weighted average cost of capital between the two tests. The 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.

7.    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 a significant obligation associated with the decommissioning of our two hydro facilities located in Indiana. These hydro facilities have an indeterminate life, and as such, no asset retirement obligation has been recorded.

Changes in our liability for asset retirement obligations for the years 2019 and 2018 are presented in the table below:

(in millions)	2019				2018
Beginning Balance	$	352.0			$	268.7
Accretion recorded as a regulatory asset/liability	15.7				11.1
Additions	—				63.3			(2)
Settlements	(5.4		)		(5.9		)
Change in estimated cash flows	54.6			(1)	14.8			(2)
Ending Balance	$	416.9			$	352.0

⁽¹⁾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.

⁽²⁾In 2018, $59.8 million of additions and $17.7 million of the change in estimated cash flows are attributed to costs associated with refining the CCR compliance plan. See Note 19-D, "Environmental Matters," for additional information on CCRs.

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.

8.    Regulatory Matters

Regulatory Assets and Liabilities

We follow the accounting and reporting requirements of ASC Topic 980, which provides that regulated entities account for and report assets and liabilities consistent with the economic effect of regulatory rate-making procedures if the rates established are

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Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

designed to recover the costs of providing the regulated service and it is probable that such rates can 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.

Regulatory assets were comprised of the following items: 

At December 31, (in millions)	2019		2018
Regulatory Assets
Unrecognized pension and other postretirement benefit costs (see Note 11)	$	739.1	$	798.3
Deferred pension and other postretirement benefit costs (see Note 11)	91.3		74.1
Environmental costs (see Note 19-D)	73.4		61.5
Regulatory effects of accounting for income taxes (see Note 1-N and Note 10)	234.0		233.1
Under-recovered gas and fuel costs (see Note 1-J)	3.9		34.7
Depreciation	210.7		209.6
Post-in-service carrying charges	219.8		206.6
Safety activity costs	118.6		91.7
DSM programs	50.1		45.5
Bailly Generating Station	221.8		244.3
Other	276.9		238.1
Total Regulatory Assets	$	2,239.6	$	2,237.5

Regulatory liabilities were comprised of the following items: 

At December 31, (in millions)	2019		2018
Regulatory Liabilities
Over-recovered gas and fuel costs (see Note 1-J)	$	42.6	$	32.0
Cost of removal (see Note 7)	1,047.5		1,076.0
Regulatory effects of accounting for income taxes (see Note 1-N and Note 10)	1,307.0		1,428.3
Deferred pension and other postretirement benefit costs (see Note 11)	64.7		62.7
Other	50.4		61.0
Total Regulatory Liabilities	$	2,512.2	$	2,660.0

Regulatory assets, including under-recovered gas and fuel cost, of approximately $1,524.3 million as of December 31, 2019 are not earning a return on investment. These costs are recovered over a remaining life of up to 41 years. Regulatory assets of approximately $1,932.4 million include expenses that are recovered as components of the cost of service and are covered by regulatory orders. Regulatory assets of approximately $307.2 million at December 31, 2019, require specific rate action.

Assets:

Unrecognized pension and other postretirement benefit costs. In 2007, we adopted certain updates of ASC 715 which required, among other things, the recognition in other comprehensive income or loss of the actuarial gains or losses and the prior service costs or credits that arise during the period but that are not immediately recognized as components of net periodic benefit costs. Certain subsidiaries defer these gains or losses as a regulatory asset in accordance with regulatory orders or as a result of regulatory precedent, to be recovered through base rates.

Deferred pension and other postretirement benefit costs. Primarily relates to the difference between postretirement expense recorded by certain subsidiaries due to regulatory orders and the postretirement expense recorded in accordance with GAAP. These costs are expected to be collected through future base rates, revenue riders or tracking mechanisms.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

Environmental costs. Includes certain recoverable costs of investigating, testing, remediating and other costs related to gas plant sites, disposal sites or other sites onto which material may have migrated. Certain of our companies defer the costs as a regulatory asset in accordance with regulatory orders, to be recovered in future base rates, billing riders or tracking mechanisms.

Regulatory effects of accounting for income taxes. Represents the deferral and under collection of deferred taxes in the rate making process. In prior years, we have lowered customer rates in certain jurisdictions for the benefits of accelerated tax deductions. Amounts are expensed for financial reporting purposes as we recover deferred taxes in the rate making process.

Under-recovered gas and fuel costs. Represents the difference between the costs of gas and fuel and the recovery of such costs in revenue and is used to adjust future billings for such deferrals on a basis consistent with applicable state-approved tariff provisions. Recovery of these costs is achieved through tracking mechanisms.

Depreciation. Represents differences between depreciation expense incurred on a GAAP basis and that prescribed through regulatory order. Significant components of this balance include:

• Columbia of Ohio depreciation rates. Prior to 2005, the PUCO-approved depreciation rates for rate-making had been lower than those which would have been utilized if Columbia of Ohio were not subject to regulation resulting in the creation of a regulatory asset. In 2005, the PUCO authorized Columbia of Ohio to revise its depreciation accrual rates for the period beginning January 1, 2005. The revised depreciation rates are higher than those which would have been utilized if Columbia of Ohio were not subject to regulation allowing for amortization of the previously created regulatory asset. The amount of depreciation that would have been recorded from 2005 through 2019 had Columbia of Ohio not been subject to rate regulation is a cumulative $923.5 million, $103.8 million less than that reflected in rates. The resulting regulatory asset balance was $27.9 million and $39.5 million as of December 31, 2019 and 2018, respectively.

• Columbia of Ohio IRP and CEP. Columbia of Ohio also has PUCO approval to defer depreciation and debt-based post-in-service carrying charges (see "Post-in-service carrying charges" below) associated with its IRP and CEP. As of December 31, 2019, depreciation of $31.9 million and $77.2 million was deferred for the respective programs. Depreciation deferral balances for the respective programs as of December 31, 2018 were $29.1 million and $76.0 million. Recovery of the depreciation is approved annually through the IRP and CEP riders. The equivalent of annual depreciation expense, based on the average life of the related assets, is included in the calculation of the IRP and CEP riders approved by the PUCO and billed to customers. Deferred depreciation expense is recognized as the IRP and CEP riders are billed to customers.

• NIPSCO ECRM. NIPSCO obtained approval from the IURC to recover certain environmental related costs including operation and maintenance and depreciation expense once the environmental facilities become operational. The ECRM deferred charges represent expenses that will be recovered from customers through an annual ECRM Cost Tracker (ECT) which authorizes the collection of deferred balances over a six month period. Depreciation of $15.2 million and $14.4 million was deferred to a regulatory asset as of December 31, 2019 and 2018, respectively. This regulatory asset was included in electric base rates, which was approved by the IURC on December 4, 2019.

• NIPSCO TDSIC. NIPSCO obtained approval from the IURC to recover costs for certain system modernization projects outside of a base rate proceeding. Eighty percent of the related costs, including depreciation, property taxes, and debt and equity based carrying charges (see "Post-in-service carrying charges" below) are recovered through a semi-annual recovery mechanism. Recovery of these costs will continue through the TDSIC tracker until such assets are included in rate base through a gas or electric base rate case, respectively. The remaining twenty percent of the costs are deferred until the next base rate case. As of December 31, 2019 and 2018, depreciation of $22.0 million and $16.5 million, respectively, was deferred as a regulatory asset.

Post-in-service carrying charges. Represents deferred debt-based carrying charges incurred on certain assets placed into service but not yet included in customer rates. This balance includes:

• Columbia of Ohio IRP and CEP. See description of IRP and CEP programs above under the heading "Depreciation." As of December 31, 2019 and 2018, Columbia of Ohio had deferred PISCC of $206.4 million and $197.1 million, respectively.

• NIPSCO TDSIC. See description of TDSIC program above under the heading "Depreciation." Deferral of equity-based carrying charges for the TDSIC program is allowed; however, such amounts are not reflected in regulatory asset balances for financial reporting as equity-based returns do not meet the definition of incurred costs under ASC 980. As of December 31, 2019 and 2018, NIPSCO had deferred PISCC of $13.4 million and $9.5 million, respectively.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

Safety activity costs. Represents the difference between costs incurred in eligible safety programs in excess of those being recovered in rates. The eligible cost deferrals represent necessary business expenses incurred in compliance with PHMSA regulations and are targeted to enhance the safety of the pipeline systems. Certain subsidiaries defer the excess costs as a regulatory asset in accordance with regulatory orders and recovery of these costs will be addressed in future base rate proceedings.

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

Bailly Generating Station. 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.

 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 that have been, and continue to be, included in depreciation rates and collected in customer rates of the rate-regulated subsidiaries 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 that are established during the rate making process. Balance includes excess deferred taxes recorded upon implementation of the TCJA in December 2017, net of amounts amortized through 2019.

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

Cost Recovery and Trackers

Comparability of our line item operating results is impacted by regulatory trackers that allow for the recovery in rates of certain costs such as those described below. Increases in the expenses that are the subject of trackers generally result in a corresponding increase in operating revenues and, therefore, have essentially no impact on total operating income results.

Certain costs of our operating companies are significant, recurring in nature and generally outside the control of the operating companies. Some states allow the recovery of such costs through cost tracking mechanisms. Such tracking mechanisms allow for abbreviated regulatory proceedings in order for the operating companies to implement charges and recover appropriate costs. Tracking mechanisms allow for more timely recovery of such costs as compared with more traditional cost recovery mechanisms. Examples of such mechanisms include GCR adjustment mechanisms, tax riders, bad debt recovery mechanisms, electric energy efficiency programs, MISO non-fuel costs and revenues, resource capacity charges, federally mandated costs and environmental-related costs.

A portion of the Gas Distribution revenue is related to the recovery of gas costs, the review and recovery of which occurs through standard regulatory proceedings. All states in our operating area require periodic review of actual gas procurement activity to determine prudence and to permit the recovery of prudently incurred costs related to the supply of gas for customers. Our distribution companies have historically been found prudent in the procurement of gas supplies to serve customers.

A portion of the Electric Operations revenue is related to the recovery of fuel costs to generate power and the fuel costs related to purchased power. These costs are recovered through a FAC, a quarterly regulatory proceeding in Indiana.

Infrastructure Replacement and Federally-Mandated Compliance Programs

All of our operating utility companies have completed rate proceedings involving infrastructure replacement or enhancement, and have embarked upon initiatives to replace significant portions of their operating systems that are nearing the end of their useful lives. Each company's approach to cost recovery is unique, given the different laws, regulations and precedent that exist in each jurisdiction.

Columbia of Ohio, IRP - On December 3, 2008, the PUCO issued an order which established Columbia of Ohio’s IRP. Pursuant to that order, the IRP provides for recovery of costs resulting from: (1) the maintenance, repair and replacement of customer-owned service lines that have been determined by Columbia of Ohio to present an existing or probable hazard to persons and property;

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(2) Columbia of Ohio’s replacement of cast iron, wrought iron, unprotected coated steel and bare steel pipe and associated company and customer-owned metallic service lines; (3) the replacement of customer-owned natural gas risers identified by the PUCO as prone to failure; and (4) the installation of AMR devices on all residential and commercial meters served by Columbia of Ohio. Recoverable costs include a return on investment, depreciation and property taxes, offset by specified cost savings. Columbia of Ohio’s five-year IRP plan renewal was last approved on January 31, 2018 for the years 2018-2022.

Columbia of Ohio, CEP - On October 3, 2011, Columbia of Ohio filed an application for approval to establish the CEP that would provide for the deferral of PISCC on those assets placed into service, but not reflected in rates as plant in service, and the deferral of depreciation expense and property taxes directly attributable to the CEP assets for the period October 1, 2011 through December 31, 2012. Capital expenditures covered under this program included those placed into service that were not part of Columbia of Ohio's IRP. CEP was approved by the PUCO on August 29, 2012. Under this program, the PUCO’s approval provided for the deferral of related PISCC, depreciation and property taxes up to the point where the deferred amount, if included in rates, would exceed $1.50 per month impact on the Small General Service class of customers, subject to the PUCO’s determination of the prudence and reasonableness of investments covered under this program in a future regulatory proceeding. Subsequently, on October 3, 2013, the PUCO modified and approved Columbia of Ohio’s application to continue its CEP deferrals in 2013 and succeeding years, subject to the determination of the prudence, reasonableness and magnitude of the deferrals and capital expenditures in a future cost recovery proceeding. On December 1, 2017, Columbia of Ohio filed an application in which it requested authority to implement a rider to begin recovering plant and associated deferrals related to its CEP. On October 25, 2018, a joint stipulation and recommendation was filed to recover CEP investments and deferrals through December 31, 2017, with annual adjustments for capital investments made in subsequent years. Additionally, the signatory parties to the stipulation agreed to a reduction in rates to adjust for the impacts of the Tax Cut Jobs Act and for a base rate case filing to be made by Columbia of Ohio no later than June 30, 2021. On November 28, 2018 the PUCO issued an order unanimously approving the settlement, without modification.

NIPSCO Gas and Electric, TDSIC - On April 30, 2013, the Indiana Governor signed Senate Enrolled Act 560, known as the TDSIC statute, into law. Among other provisions, the TDSIC statute provides for cost recovery outside of a base rate proceeding for new or replacement electric and gas transmission, distribution, and storage projects that a public utility undertakes for the purposes of safety, reliability, system modernization or economic development. Provisions of the TDSIC statute require that, among other things, requests for recovery include a seven-year plan of eligible investments. Once the plan is approved by the IURC, eighty percent of eligible costs can be recovered using a periodic rate adjustment mechanism, known as the TDSIC mechanism. Recoverable costs include a return on the investment, including AFUDC, PISCC, depreciation and property taxes. The remaining twenty percent of recoverable costs are deferred for future recovery in NIPSCO's next general rate case. This rate adjustment mechanism is typically filed semi-annually and has a cap at an annual increase of two percent of total retail revenues. During the 2019 Legislative session, the Indiana General Assembly amended the TDSIC statute in House Enrolled Act 1470 that was signed into law by the Governor on April 24, 2019. The revisions that became effective on July 1, 2019 permit flexibility in TDSIC Plans between five and seven years in length, permits the IURC to authorize multi-unit projects that do not include specific locations or an exact number of inspections, repairs, or replacements and projects involving advanced technology investments to support the modernization of transmission, distribution, or storage systems. The amendments also authorize termination of TDSIC Plans prior to their expiration and provide that the projects associated with the terminated plan will continue to receive TDSIC treatment until an Order is issued in the utility’s next general rate case, and provide for the ability to seek approval of a new TDSIC Plan. The amended statute also provides that the two percent revenue cap applies to the aggregate of approved TDSIC Plans and requires that the utility file a base rate case at some point during the term of each TDSIC plan. On December 31, 2019, NIPSCO Gas filed a new 6-year TDSIC for the periods 2020 through 2025.

NIPSCO Electric, ECRM - NIPSCO has approval from the IURC to recover certain environmental related costs through an ECT (environmental cost tracker). Under the ECT, NIPSCO is permitted to recover (1) AFUDC and a return on the capital investment expended by NIPSCO to implement environmental compliance plan projects and (2) related operation and maintenance and depreciation expenses once the environmental facilities become operational. All deferred costs associated with ECRM were included in electric rate base and approved by the IURC on December 4, 2019.

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

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

federally mandated costs of the approved compliance project by more than twenty-five percent shall require specific justification by NIPSCO and specific approval by the IURC before being authorized in the next general rate case.

Columbia of Massachusetts, GSEP - On July 7, 2014, the Governor of Massachusetts signed into law Chapter 149 of the Acts of 2014, an Act Relative to Natural Gas Leaks (“the Act”). Adopted into the Massachusetts Utility Provisions, G.L. c. 164, § 145, the Act authorizes natural gas distribution companies to file a GSEP for capital investments made on or after January 1, 2015, that are not included in the company’s current rate base as determined in the most recent base rate case, with the Massachusetts DPU to (1) address the replacement or improvement of existing aging natural gas pipeline infrastructure to improve public safety or infrastructure reliability, and (2) reduce the lost and unaccounted for natural gas through a reduction in natural gas system leaks. In addition, the Act provides that the Massachusetts DPU may, after review of the plan, allow the proposed estimated costs of the plan into rates as of May 1 of the subsequent year. Recoverable costs include a return on investment, depreciation and property taxes, offset by identified operations and maintenance cost savings. Beginning with the 2019 GSEP, rates are subject to a capped annual revenue increase of three percent of total annual firm delivery revenues, plus imputed gas revenues for sales and transportation customers, calculated as the product of (1) the historical average cost of gas per therm, and (2) the average weather normalized sales, for the period beginning with 2013 and ending with the most recent year that actual data is available at the time of the October GSEP Plan filing, per the Massachusetts DPU order in Columbia of Massachusetts' 2019 GSEP. Prior to the 2019 GSEP, the annual revenue increase was capped at one and a half percent. At the end of each 12-month period, in May of the subsequent year, Columbia of Massachusetts must file a reconciliation of the amount collected and actual costs. Any over-collection or under-collection balance is passed back to, or recovered from, customers through the surcharge over a 12-month period beginning in November. On October 31, 2019, the Massachusetts DPU issued an order on Columbia of Massachusetts' GSEP reconciliation proceeding finding that, due to pending investigations of the Greater Lawrence Incident and other operational matters, the Massachusetts DPU could not, at this time, make a finding of prudence with respect to the Columbia of Massachusetts' 2018 GSEP investments and deferred the decision on the prudency of the 2018 GSEP investments in the annual GSEP and GSEP reconciliation filings until the investigations by the DPU are complete. The DPU added that its inability to make a finding of prudence did not constitute a finding of imprudence. Once new base rates are established under a base rate proceeding, the GSEP factor is re-set to remove the capital investment and associated revenue reflected in the base rates. Columbia of Massachusetts' current five year GSEP plan for the periods 2019-2023 was approved April 30, 2019.

Columbia of Pennsylvania, DSIC - On February 14, 2012, the Governor of Pennsylvania signed into law Act 11 of 2012, which provided a DSIC mechanism for certain utilities to recover costs related to repair, replacement or improvement of eligible distribution property that has not previously been reflected in rates or rate base. Through a DSIC, a utility may recover the fixed costs of eligible infrastructure incurred during the three months ended one month prior to the effective date of the charge, thereby reducing the historical regulatory lag associated with cost recovery through the traditional rate-making process. On March 14, 2013, the Pennsylvania PUC approved Columbia of Pennsylvania’s petition to implement a DSIC as of April 1, 2013. Accordingly, Columbia of Pennsylvania is authorized to recover the cost of eligible plant associated with repair, replacement or improvement that was not previously reflected in rate base and has been placed in service during the applicable three-month period. After the initial charge is established, the DSIC is updated quarterly to recover the cost of further plant additions and cannot exceed five percent of distribution revenues. Recoverable costs include a return on investment, exclusive of accumulated deferred income taxes from the calculation of rate base, and depreciation. Once new base rates are established under a base rate proceeding, the DSIC is set to zero. Additionally, the DSIC rate is also reset to zero if, in any quarter, the data reflected in the Columbia of Pennsylvania's most recent quarterly financial earnings report show that the utility will earn an overall rate of return that would exceed the allowable rate of return used to calculate its fixed costs under the DSIC mechanism. A utility is exempt from filing a quarterly financial earnings report when a base rate proceeding is pending before the Pennsylvania PUC.

Columbia of Virginia, SAVE - On March 11, 2010, the Virginia Governor signed legislation into law that allows natural gas utilities to implement programs to replace qualifying infrastructure on an expedited basis and provides for timely cost recovery. Known as the SAVE Act, the law allows natural gas utilities to file programs with the VSCC providing a timeline and estimated costs for replacing eligible infrastructure. Eligible infrastructure replacement projects are those that (1) enhance safety or reliability by reducing system integrity risks associated with customer outages, corrosion, equipment failures, material failures, or natural forces; (2) do not increase revenues by directly connecting the infrastructure replacement to new customers; (3) reduce or have the potential to reduce greenhouse gas emissions; (4) are not included in the natural gas utility’s rate base in its most recent rate case; and (5) are commenced on or after January 1, 2010. The SAVE Act provides for recovery of costs associated with the eligible infrastructure through a rate rider. Recoverable costs include a return on investment, depreciation and property taxes. Columbia of Virginia’s current five year SAVE plan was approved by the VSCC in 2016 and amended in 2017 for the years 2016 through 2020 and amended in 2019 for calendar year 2020.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

Columbia of Kentucky, SMRP (formerly AMRP) - On October 26, 2009, the Kentucky PSC approved a mechanism for recovering the costs of Columbia of Kentucky’s AMRP not previously reflected in rate base through an annual fixed monthly rate rider filed in October. In its 2013 rate case, Columbia of Kentucky was allowed to base the AMRP rider on the expected annual cost of service. Recoverable costs include a return on investment, depreciation and property taxes, offset by specific cost savings. At the end of each 12-month period, Columbia of Kentucky must file a reconciliation of the amount collected and actual costs. Any over-collection or under-collection balance is passed back to, or recovered from, customers through the surcharge over a 12-month period beginning in June of the subsequent year. Once new base rates are established under a base rate proceeding, the AMRP rider is set to zero. On July 29, 2019, CKY filed its SMRP to clarify approval of low pressure project spend and expand its AMRP to include for recovery of system safety investments, including low pressure project spend. On November 7, 2019, the Commission approved Columbia of Kentucky's request to amend and expand its annual AMRP to become the SMRP.

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

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Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

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	Filed	Status	Rates Effective
Columbia of Ohio	IRP - 2019(1)	$	18.2		$	199.6	1/18-12/18	February 28, 2019	Approved April 24, 2019	May 2019
Columbia of Ohio	CEP - 2018	$	74.5		$	659.9	1/11-12/17	December 1, 2017	Approved November 28, 2018	December 2018
Columbia of Ohio	CEP - 2019	$	15.0		$	121.7	1/18-12/18	February 28, 2019	Approved August 28, 2019	September 2019
NIPSCO - Gas	TDSIC 9(1)(2)	$	(10.6	)	$	54.4	1/18-6/18	August 28, 2018	Approved December 27, 2018	January 2019
NIPSCO - Gas	TDSIC 10(3)	$	1.6		$	12.4	7/18-4/19	June 25, 2019	Approved October 16, 2019	November 2019
NIPSCO - Gas	TDSIC 11(4)	$	(1.7	)	$	38.7	5/19-12/19	February 25, 2020	Order Expected June 2020	July 2020
NIPSCO - Gas	FMCA 1(5)	$	9.9		$	1.5	11/17-9/18	November 30, 2018	Approved March 27, 2019	April 2019
NIPSCO - Gas	FMCA 2(5)	$	(3.5	)	$	1.8	10/18-3/19	May 29, 2019	Approved September 25, 2019	October 2019
NIPSCO - Gas	FMCA 3(5)	$	0.3		$	43.0	4/19-9/19	November 26, 2019	Order Expected March 2020	April 2020
Columbia of Massachusetts	GSEP - 2019(6)	$	9.6		$	36.0	1/19-12/19	October 31, 2018	Approved April 30, 2019	May 2019
Columbia of Massachusetts	GSEP - 2020(6)(7)	$	2.4		$	75.0	1/20-12/20	October 31, 2019	Order Expected April 2020	May 2020
Columbia of Virginia	SAVE - 2019	$	2.4		$	36.0	1/19-12/19	August 17, 2018	Approved October 26, 2018	January 2019
Columbia of Virginia	SAVE - 2020	$	3.8		$	50.0	1/20-12/20	August 15, 2019	Approved December 6, 2019	January 2020
Columbia of Kentucky	AMRP - 2019	$	3.6		$	30.1	1/19-12/19	October 15, 2018	Approved December 5, 2018	January 2019
Columbia of Kentucky	SMRP - 2020	$	4.2		$	40.4	1/20-12/20	October 15, 2019	Approved December 20, 2019	January 2020
Columbia of Maryland	STRIDE - 2019	$	1.2		$	19.7	1/19-12/19	November 1, 2018	Approved December 12, 2018	January 2019
Columbia of Maryland	STRIDE - 2020	$	1.3		$	15.0	1/20-12/20	January 29, 2020	Approved February 19, 2020	February 2020
NIPSCO - Electric	TDSIC - 5(1)	$	15.9		$	58.8	6/18-11/18	January 29, 2019	Approved June 12, 2019	June 2019
NIPSCO - Electric	TDSIC - 6	$	28.1		$	131.1	12/18-6/19	August 21, 2019	Approved December 18, 2019	January 2020
NIPSCO - Electric	FMCA - 11(5)	$	0.9		$	22.4	9/18-2/19	April 17, 2019	Approved July 29, 2019	August 2019
NIPSCO - Electric	FMCA - 12(5)	$	1.6		$	4.7	3/19-8/19	October 18, 2019	Approved January 29, 2020	February 2020

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

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

⁽³⁾Incremental capital and revenue are net of amounts included in the step 2 rates.

⁽⁴⁾Incremental revenue is net of amounts included in the step 2 rates and reflects a more typical filing period.

⁽⁵⁾Incremental revenue is inclusive of tracker eligible operations and maintenance expense.

⁽⁶⁾Due to an order from the Massachusetts DPU on October 3, 2019 imposing work restrictions on Columbia of Massachusetts, Columbia of Massachusetts did not meet the approved projected 2019 GSEP spend of $64 million and associated incremental revenue of $10.7 million. In the 2020 GSEP, Columbia of Massachusetts reduced the projected capital spend for calendar year 2019 to $36 million and the associated incremental revenue in 2019 GSEP to $9.6 million.

⁽⁷⁾Incremental capital investment is anticipated to be lower than $75 million in 2020 due to the Massachusetts DPU imposed work restrictions.

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Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

Rate Case Actions

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

(in millions)
Company	Requested Incremental Revenue		Approved Incremental Revenue			Filed	Status	Rates Effective
NIPSCO - Gas(1)	$	138.1	$	105.6		September 27, 2017	Approved September 19, 2018	October 2018
Columbia of Virginia(2)	$	14.2	$	1.3		August 28, 2018	Approved June 12, 2019	February 2019
NIPSCO - Electric(3)	$	21.4	$	(53.5	)	October 31, 2018	Approved December 4, 2019	January 2020
Columbia of Maryland	$	2.5	$	(0.1	)	May 22, 2019	Approved December 18, 2019	December 2019

⁽¹⁾Rates were implemented in three steps, with implementation of step 1 rates effective October 1, 2018. Step 2 rates were effective on March 1, 2019, and step 3 rates were effective on January 1, 2020. The step 3 increase was approved based on actual information and revised from $107.3 million to $105.6 million. The IURC’s order also dismissed NIPSCO from phase 2 of the IURC’s TCJA investigation.

⁽²⁾Rates, as originally filed, were implemented in February 2019 on an interim basis, subject to refund. The final approved rates, which replaced interim rates, were implemented in July 2019.

⁽³⁾An order was received on December 4, 2019, which included the resolution of outstanding TCJA impacts to rates. Incremental revenues decreased due to a reduction in fuel costs associated with the new industrial service structure. Rates will be implemented in two steps, with implementation of step 1 rates effective January 2, 2020 and step 2 rates effective March 2, 2020.

Additional Regulatory Matters

NIPSCO Electric. On March 29, 2018, WCE, which is currently owned by BP p.l.c ("BP") and BP Products North America, which operates the BP Refinery, filed a petition at the IURC asking that the combined operations of WCE and BP be treated as a single premise, and the WCE generation be dedicated primarily to BP Refinery operations beginning in May 2019 as WCE has self-certified as a qualifying facility at FERC. BP Refinery planned to continue to purchase electric service from NIPSCO at a reduced demand level beginning in May 2019; however, a settlement agreement was filed on November 2, 2018 agreeing that BP and WCE would not move forward with construction of a private transmission line to serve BP until conclusion of NIPSCO’s pending electric rate case. The IURC approved the settlement agreement as filed on February 20, 2019. On December 4, 2019, the IURC issued an order in the electric rate case approving the implementation of a new industrial service structure. This resolved the issues included in BP’s original petition.

The December 4, 2019 electric rate case order approved the revenue requirement settlement filed in the case, with the exception of a change in the agreed to return on equity; the approved return on equity is 9.75%. The order included approval of the depreciation rates as requested, as well as authorization to create a regulatory asset upon the retirement of R.M. Schahfer Generating Units 14, 15, 17 and 18 and Michigan City Generating Station Unit 12. The order allows for the recovery of and on the net book value of the units by the end of 2032.

9.     Risk Management Activities

We are exposed to certain risks relating to 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.

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Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

Risk management assets and liabilities on our derivatives are presented on the Consolidated Balance Sheets as shown below:

December 31, (in millions)	2019		2018
Risk Management Assets - Current(1)
Interest rate risk programs	$	—	$	—
Commodity price risk programs	0.6		1.1
Total	$	0.6	$	1.1
Risk Management Assets - Noncurrent(2)
Interest rate risk programs	$	—	$	18.5
Commodity price risk programs	3.8		4.4
Total	$	3.8	$	22.9
Risk Management Liabilities - Current(3)
Interest rate risk programs	$	—	$	—
Commodity price risk programs	12.6		5.0
Total	$	12.6	$	5.0
Risk Management Liabilities - Noncurrent
Interest rate risk programs	$	76.2	$	9.5
Commodity price risk programs	57.8		37.2
Total	$	134.0	$	46.7

⁽¹⁾Presented in "Prepayments and other" on the Consolidated Balance Sheets.

⁽²⁾Presented in "Deferred charges and other" on the Consolidated Balance Sheets.

⁽³⁾Presented in "Other accruals" on the Consolidated Balance Sheets.

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 ten years and is limited to twenty percent 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, 2019, we have 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 effective portions of the gains and losses related to these swaps are recorded to AOCI and are 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" on the Statements of Consolidated Income (Loss) due to the probability associated with the forecasted borrowing transactions no longer occurring.

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Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

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

Our derivative instruments measured at fair value as of December 31, 2019 and 2018 do not contain any credit-risk-related contingent features.

10.    Income Taxes

Income Tax Expense

The components of income tax expense (benefit) were as follows: 

Year Ended December 31, (in millions)	2019			2018			2017
Income Taxes
Current
Federal	$	—		$	—		$	—
State	5.2			8.2			7.8
Total Current	5.2			8.2			7.8
Deferred
Federal	110.7			(209.4		)	302.7
State	9.0			22.2			5.0
Total Deferred	119.7			(187.2		)	307.7
Deferred Investment Credits	(1.4		)	(1.0		)	(1.0		)
Income Taxes	$	123.5		$	(180.0	)	$	314.5

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)	2019					2018					2017
Book income (loss) before income taxes	$	506.6				$	(230.6	)			$	443.0
Tax expense (benefit) at statutory federal income tax rate	106.5			21.0	%	(48.4		)	21.0	%	155.0			35.0	%
Increases (reductions) in taxes resulting from:
State income taxes, net of federal income tax benefit	10.1			2.0		24.7			(10.7	)	6.9			1.5
Amortization of regulatory liabilities	(29.4		)	(5.8	)	(29.3		)	12.7		(2.4		)	(0.5	)
Goodwill impairment	43.0			8.5		—			—		—			—
Fines and penalties	11.5			2.3		0.2			(0.1	)	2.8			0.6
Charitable contribution carryover	(2.5		)	(0.5	)	—			—		(1.2		)	(0.3	)
State regulatory proceedings	(9.5		)	(1.9	)	(127.8		)	55.4		—			—
Remeasurement due to TCJA	—			—		—			—		161.1			36.4
Employee stock ownership plan dividends and other compensation	(2.0		)	(0.4	)	(2.2		)	1.0		(6.5		)	(1.5	)
Other adjustments	(4.2		)	(0.8	)	2.8			(1.2	)	(1.2		)	(0.2	)
Income Taxes	$	123.5		24.4	%	$	(180.0	)	78.1	%	$	314.5		71.0	%

The effective income tax rates were 24.4%, 78.1% and 71.0% in 2019, 2018 and 2017, respectively. 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 6, "Goodwill and Other Intangible Assets" for additional information)

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Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

and non-deductible fines and penalties related to the Greater Lawrence Incident (see Note 19, "Legal Proceedings" for additional information). The rate is also impacted by the relative impact of permanent differences on higher pre-tax income.

The 7.1% increase in the overall effective tax rate in 2018 versus 2017 was primarily the result of state regulatory proceedings which resulted in a $127.8 million decrease in federal income taxes offset by a related increase in state income taxes of $7.1 million. Additionally, the increase was driven by a $26.9 million decrease in income taxes related to amortization of the regulatory liability primarily associated with excess deferred taxes.

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)	2019		2018
Deferred tax liabilities
Accelerated depreciation and other property differences	$	2,516.9	$	2,458.0
Other regulatory assets	381.5		375.4
Total Deferred Tax Liabilities	2,898.4		2,833.4
Deferred tax assets
Other regulatory liabilities and deferred investment tax credits (including TCJA)	336.1		365.5
Pension and other postretirement/postemployment benefits	152.1		157.5
Net operating loss carryforward and AMT credit carryforward	765.9		849.8
Environmental liabilities	25.4		24.4
Other accrued liabilities	35.3		37.5
Other, net	98.3		68.2
Total Deferred Tax Assets	1,413.1		1,502.9
Net Deferred Tax Liabilities	$	1,485.3	$	1,330.5

At December 31, 2019, we had $657.1 million of federal net operating loss carryforwards. The federal net operating loss carryforwards are available to offset taxable income and will begin to expire in 2028. We also have $1.6 million of federal alternative minimum tax credit carryforwards which do not expire. In addition, we have $1.4 million in charitable contribution carryforwards to offset future taxable income, which begin to expire in 2023. We also have $107.2 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 we will realize the benefit from the state net operating loss carryforwards.

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)	2019			2018			2017
Unrecognized Tax Benefits - Opening Balance	$	1.2		$	1.4		$	2.6
Gross decreases - tax positions in prior period	(0.6		)	(0.4		)	(1.4		)
Gross increases - current period tax positions	22.6			0.2			0.2
Unrecognized Tax Benefits - Ending Balance	$	23.2		$	1.2		$	1.4
Offset for net operating loss carryforwards	(22.6		)	—			—
Balance - Less Net Operating Loss Carryforwards	$	0.6		$	1.2		$	1.4

In 2019, we resolved prior unrecognized tax benefits of $0.6 million and established new unrecognized tax benefits related to state matters of $22.6 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, 2019, 2018 and 2017, and there were no balances for accrued penalties recorded on the Consolidated Balance Sheets as of December 31, 2019 and 2018.

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Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

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

We participate in the IRS CAP which provides the opportunity to resolve tax matters with the IRS before filing each year's consolidated federal income tax return. As of December 31, 2019, tax years through 2018 have been audited and are effectively closed to further assessment. The audit of tax year 2019 under the CAP program is expected to be completed in 2020.

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, 2019, there were no state income tax audits in progress that would have a material impact on the consolidated financial statements.

In December 22, 2017, the TCJA was signed into law. As a result of the implementation of the TCJA, we remeasured deferred taxes and recognized $161.1 million of income tax expense in our Consolidated Statements of Income (Loss) for the year ended December 31, 2017. The result of this remeasurement was a reduction in the net deferred tax liability of approximately $1.3 billion, including approximately $0.4 billion of regulatory "gross up" to account for over collection of past taxes from customers. Offsetting the reduction in net deferred tax liabilities was an increase in regulatory liabilities of approximately $1.5 billion as of December 31, 2017. In 2018, we received regulatory orders on the treatment of excess deferred taxes from the jurisdictions in which we operate. As a result of these orders, we reduced our regulatory liability related to excess deferred income taxes by $120.7 million (net of tax). This adjustment is reflected in "Income Taxes" on our Consolidated Statements of Income (Loss) for the year ended December 31, 2018.

As of December 31, 2019, we received approval from regulators to return excess deferred taxes in all of our jurisdictions in accordance with regulatory proceedings.

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

11.     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. We employ a liability-driven investing strategy for the pension plan, as noted below. A mix of equities and fixed income investments are used to maximize the long-term return of plan assets and hedge the liabilities at a prudent level of risk. We utilize a total return investment approach for the other postretirement benefit plans. Risk tolerance is established through careful consideration of plan liabilities, plan funded status, and asset class volatility. The investment portfolio contains a diversified blend of equity and fixed income investments. Furthermore, equity investments are diversified across U.S. and non-U.S. stocks, as well as growth, value, small and large capitalizations. Other assets such as private equity funds are used judiciously to enhance long-term returns while improving portfolio diversification. Derivatives may be used to gain market exposure in an efficient and timely manner; however, derivatives may not be used to leverage the portfolio beyond the market value of the underlying assets. Investment risk is measured and monitored on an ongoing basis through quarterly investment portfolio reviews, annual liability measurements, and periodic asset/liability studies.

We utilize a building block approach with proper consideration of diversification and rebalancing in determining the long-term rate of return for plan assets. Historical markets are studied and long-term historical relationships between equities and fixed income are analyzed to ensure that they are consistent with the widely accepted capital market principle that assets with higher volatility generate greater return over the long run. Current market factors, such as inflation and interest rates, are evaluated before long-term capital market assumptions are determined. Peer data and historical returns are reviewed to check for reasonability and appropriateness.

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Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

The most important component of an investment strategy is the portfolio asset mix, or the allocation between the various classes of securities available to the pension and other postretirement benefit plans for investment purposes. The asset mix and acceptable minimum and maximum ranges established for our plan assets represents a long-term view and are listed in the table below.

In 2012, a dynamic asset allocation policy for the pension fund was approved. This 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 above 90% (as measured by the market value of qualified pension plan assets divided by the projected benefit obligations of the qualified pension plans). A new asset-liability study was completed in 2018 resulting in a more conservative glide path and an increase in the allocation to liability-hedging assets held in the portfolio.

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 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%
Short-Term Investments/Other	0%	15%	0%	10%

As of December 31, 2018, 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%
Short-Term Investments/Other	0%	15%	0%	10%

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Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

Pension Plan and Postretirement Plan Asset Mix at December 31, 2019 and December 31, 2018:

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

The categorization of investments into the asset classes in the table 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 Master Trust and other postretirement benefits investment assets at fair value as of December 31, 2019 and 2018. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Total Master Trust and other postretirement benefits investment assets at fair value classified within Level 3 were $0 million and $86.1 million as of December 31, 2019 and December 31, 2018, respectively. Such amounts were approximately 0% and 4% of the Master Trust and other postretirement benefits’ total investments as reported on the statement of net assets available for benefits at fair value as of December 31, 2019 and 2018, respectively.

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.

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Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

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, 2019, 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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NISOURCE INC.

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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NISOURCE INC.

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		)	—
Distressed opportunities	2.4		(2.4		)	—
Real estate	52.7		(52.7		)	—
Total	$	86.1	$	(86.1	)	$	—

⁽¹⁾ Level 3 assets from the prior year were reclassified in the current year 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	1 day
International equities	168.2		Monthly	10-30 days
Fixed income	351.8		Daily	3 days
Total	$	860.5

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Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

Fair Value Measurements at December 31, 2018: 

(in millions)	December 31, 2018			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	$	9.2		$	8.8	$	0.4		$	—
Equity securities
U.S. equities	0.2			0.2		—			—
Fixed income securities
Government	250.2			—		250.2			—
Corporate	442.8			—		442.8			—
Mutual Funds
U.S. multi-strategy	110.3			110.3		—			—
International equities	43.2			43.2		—			—
Fixed income	166.8			166.8		—			—
Private equity limited partnerships
U.S. multi-strategy(1)	18.5			—		—			18.5
International multi-strategy(2)	12.5			—		—			12.5
Distressed opportunities	2.4			—		—			2.4
Real Estate	52.7			—		—			52.7
Commingled funds(3)
Short-term money markets	18.3			—		—			—
U.S. equities	245.2			—		—			—
International equities	122.3			—		—			—
Fixed income	365.7			—		—			—
Pension plan assets subtotal	1,860.3			329.3		693.4			86.1
Other postretirement benefit plan assets:
Mutual funds
U.S. equities	68.4			68.4		—			—
International equities	17.5			17.5		—			—
Fixed income	114.8			114.8		—			—
Commingled funds(3)
Short-term money markets	5.2			—		—			—
U.S. equities	10.4			—		—			—
Other postretirement benefit plan assets subtotal	216.3			200.7		—			—
Due to brokers, net(4)	(1.1		)	—		(1.1		)	—
Accrued investment income/dividends	8.6			8.6		—			—
Total pension and other postretirement benefit plan assets	$	2,084.1		$	538.6	$	692.3		$	86.1

⁽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 a 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, 2018:

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

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, 2018:

(in millions)	Fair Value		Redemption Frequency	Redemption Notice Period
Commingled Funds
Short-term money markets	$	23.5	Daily	1 day
U.S. equities	255.6		Monthly	3 days
International equities	122.3		Monthly	10-30 days
Fixed income	365.7		Monthly	3 days
Total	$	767.1

 

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Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

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

	Pension Benefits						Other Postretirement Benefits
(in millions)	2019			2018			2019			2018
Change in projected benefit obligation(1)
Benefit obligation at beginning of year	$	1,981.3		$	2,192.6		$	492.5		$	556.3
Service cost	29.2			31.3			5.1			5.0
Interest cost	72.3			67.1			19.2			17.6
Plan participants’ contributions	—			—			4.8			5.7
Plan amendments	—			0.2			5.1			0.1
Actuarial (gain) loss	204.3			(103.9		)	88.8			(51.7		)
Settlement loss	—			0.8			—			—
Benefits paid	(156.6		)	(206.8		)	(39.5		)	(41.1		)
Estimated benefits paid by incurred subsidy	—			—			0.5			0.6
Projected benefit obligation at end of year	$	2,130.5		$	1,981.3		$	576.5		$	492.5
Change in plan assets
Fair value of plan assets at beginning of year	$	1,867.7		$	2,160.0		$	216.3		$	262.5
Actual (loss) return on plan assets	366.8			(88.4		)	56.9			(31.8		)
Employer contributions	2.9			2.9			23.0			21.0
Plan participants’ contributions	—			—			4.7			5.7
Benefits paid	(156.5		)	(206.8		)	(39.5		)	(41.1		)
Fair value of plan assets at end of year	$	2,080.9		$	1,867.7		$	261.4		$	216.3
Funded Status at end of year	$	(49.6	)	$	(113.6	)	$	(315.1	)	$	(276.2	)
Amounts recognized in the statement of financial position consist of:
Noncurrent assets	8.2			—			—			—
Current liabilities	(3.0		)	(3.0		)	(0.8		)	(0.8		)
Noncurrent liabilities	(54.8		)	(110.6		)	(314.3		)	(275.4		)
Net amount recognized at end of year(2)	$	(49.6	)	$	(113.6	)	$	(315.1	)	$	(276.2	)
Amounts recognized in accumulated other comprehensive income or regulatory asset/liability(3)
Unrecognized prior service credit	$	3.0		$	3.2		$	(10.7	)	$	(19.0	)
Unrecognized actuarial loss	652.8			761.2			118.4			75.3
Net amount recognized at end of year	$	655.8		$	764.4		$	107.7		$	56.3

⁽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⁾ 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 $739.1 million and $0.1 million, respectively, as of December 31, 2019, and $798.3 million and $0.1 million, respectively, as of December 31, 2018 that would otherwise have been recorded to accumulated other comprehensive loss.

Our accumulated benefit obligation for our pension plans was $2,111.5 million and $1,965.6 million as of December 31, 2019 and 2018, respectively. The accumulated benefit obligation as of a 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 the pension and postretirement benefit plans on the Consolidated Balance Sheet. The funded status of the plans is measured as the difference between the plan assets' fair value and the projected benefit obligation. We present the noncurrent aggregate of all underfunded plans within "Accrued liability for postretirement and postemployment benefits." The portion of the amount by which the actuarial present value of benefits included in the projected benefit obligation

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Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

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,
	2019			2018
Accumulated Benefit Obligation	$	1,473.9		$	1,965.6
Funded Status
Projected Benefit Obligation	1,492.9			1,981.3
Fair Value of Plan Assets	1,435.1			1,867.7
Funded Status of Underfunded Pension Plans at End of Year	$	(57.8	)	$	(113.6	)

Information for pension plans with plan assets in excess of the projected benefit obligation:

	December 31,
	2019		2018
Accumulated Benefit Obligation	$	637.6	$	—
Funded Status
Projected Benefit Obligation	637.6		—
Fair Value of Plan Assets	645.8		—
Funded Status of Overfunded Pension Plans at End of Year	$	8.2	$	—

Our pension plans were underfunded, in aggregate, by $49.6 million at December 31, 2019 compared to being underfunded by $113.6 million at December 31, 2018. 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 2019 and 2018.

Our other postretirement benefit plans were underfunded by $315.1 million at December 31, 2019 compared to being underfunded by $276.2 million at December 31, 2018. The decline in funded status was primarily due to a decrease in discount rates offset by favorable asset returns. We contributed $23.0 million and $21.0 million to our other postretirement benefit plans in 2019 and 2018, respectively.

No amounts of our pension or other postretirement benefit plans’ assets are expected to be returned to us or any of our subsidiaries in 2019.

In 2019 and 2018, 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 $9.5 million and $18.5 million in 2019 and 2018, respectively. Net periodic pension benefit cost for 2019 was decreased by $0.7 million as a result of the interim remeasurement.

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NISOURCE INC.

Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

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

	Pension Benefits				Other Postretirement  Benefits
	2019		2018		2019		2018
Weighted-average assumptions to Determine Benefit Obligation
Discount Rate	3.12	%	4.26	%	3.21	%	4.31	%
Rate of Compensation Increases	4.00	%	4.00	%	—		—
Health Care Trend Rates
Trend for Next Year	—		—		6.68	%	8.48	%
Ultimate Trend	—		—		4.50	%	4.50	%
Year Ultimate Trend Reached	—		—		2028		2026

Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects:

(in millions)	1% point increase		1% point decrease
Effect on service and interest components of net periodic cost	$	1.2	$	(1.1	)
Effect on accumulated postretirement benefit obligation	30.1		(26.3		)

We expect to make contributions of approximately $3.0 million to our pension plans and approximately $24.0 million to our postretirement medical and life plans in 2020.

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)
2020	$	178.8	$	38.1	$	0.5
2021	177.8		38.6		0.4
2022	175.8		38.4		0.4
2023	168.5		38.1		0.4
2024	164.4		37.9		0.4
2025-2029	723.7		181.0		1.5

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NISOURCE INC.

Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

The following table provides the components of the plans’ actuarially determined net periodic benefits cost for each of the three years ended December 31, 2019, 2018 and 2017:

	Pension Benefits									Other Postretirement Benefits
(in millions)	2019			2018			2017			2019			2018			2017
Components of Net Periodic Benefit Cost(1)
Service cost	$	29.2		$	31.3		$	30.0		$	5.1		$	5.0		$	4.8
Interest cost	72.3			67.1			68.3			19.2			17.6			17.8
Expected return on assets	(108.8		)	(142.3		)	(123.1		)	(13.1		)	(14.9		)	(15.9		)
Amortization of prior service cost (credit)	0.2			(0.4		)	(0.7		)	(3.2		)	(4.0		)	(4.4		)
Recognized actuarial loss	45.2			40.6			52.9			2.0			3.8			3.0
Settlement loss	9.5			18.5			13.7			—			—			—
Total Net Periodic Benefits Cost	$	47.6		$	14.8		$	41.1		$	10.0		$	7.5		$	5.3

⁽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."

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
	2019		2018		2017		2019		2018		2017
Weighted-average Assumptions to Determine Net Periodic Benefit Cost
Discount rate - service cost(1)	4.48	%	3.79	%	4.40	%	4.59	%	3.89	%	4.58	%
Discount rate - interest cost(1)	3.84	%	3.15	%	3.31	%	3.94	%	3.27	%	3.48	%
Expected Long-Term Rate of Return on Plan Assets	6.10	%	7.00	%	7.25	%	5.83	%	5.80	%	6.99	%
Rate of Compensation Increases	4.00	%	4.00	%	4.00	%	—		—		—

⁽¹⁾  In January 2017, we changed the method used to estimate the service and interest components of net periodic benefit cost for pension and other postretirement benefits. This change, compared to the previous method, resulted in a decrease in the actuarially-determined service and interest cost components. Historically, we estimated service and interest cost utilizing a single weighted-average discount rate derived from the yield curve used to measure the benefit obligation at the beginning of the period. For fiscal 2017 and beyond, we now utilize a full yield curve approach to estimate these components by applying the specific spot rates along the yield curve used in the determination of the benefit obligation to the relevant projected cash flows.

We believe it is appropriate to assume a 6.10% and 5.83% rate of return on pension and other postretirement plan assets, respectively, for our calculation of 2019 pension benefits cost. These rates are primarily based on asset mix and historical rates of return and were adjusted in the current year due to anticipated changes in asset allocation and projected market returns.

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NISOURCE INC.

Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

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)	2019			2018			2019			2018
Other Changes in Plan Assets and Projected Benefit Obligations Recognized in Other Comprehensive Income or Regulatory Asset or Liability
Net prior service cost	$	—		$	0.2		$	5.1		$	0.1
Net actuarial loss (gain)	(53.8		)	127.5			45.1			(5.0		)
Settlements	(9.5		)	(18.5		)	—			—
Less: amortization of prior service cost	(0.2		)	0.4			3.2			4.0
Less: amortization of net actuarial loss	(45.2		)	(40.6		)	(2.0		)	(3.8		)
Total Recognized in Other Comprehensive Income or Regulatory Asset or  Liability	$	(108.7	)	$	69.0		$	51.4		$	(4.7	)
Amount Recognized in Net Periodic Benefits Cost and Other Comprehensive Income or Regulatory Asset or Liability	$	(61.1	)	$	83.8		$	61.4		$	2.8

Based on a December 31 measurement date, the estimated net unrecognized actuarial loss, unrecognized prior service cost, and unrecognized transition obligation that will be amortized into net periodic benefit cost during 2020 for the pension plans are $34.7 million, $0.8 million and zero, respectively, and for other postretirement benefit plans are $4.9 million, $(1.8) million and zero, respectively.

12.     Equity

We raise equity financing through a variety of programs including traditional common equity issuances and preferred stock issuances. As of December 31, 2019, we had 600,000,000 shares of common stock and 20,000,000 shares of preferred stock authorized for issuance, of which 382,135,680 shares of common stock and 440,000 shares of preferred stock are currently outstanding.

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 paid quarterly common dividends totaling $0.80, $0.78, and $0.70 per share for the years ended December 31, 2019, 2018 and 2017, respectively. Our Board declared a quarterly common dividend of $0.21 per share, payable on February 20, 2020 to holders of record on February 11, 2020. 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 14, "Long-Term Debt," for more information. As of December 31, 2019, 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 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 2019, 2018 and 2017 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.

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NISOURCE INC.

Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

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 separate 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.

As of December 31, 2019, the ATM program had approximately $200.7 million of equity available for issuance. The program expires on December 31, 2020.

The following table summarizes our activity under the ATM program:

Year Ending December 31,	2019		2018		2017
Number of shares issued	8,422,498		8,883,014		11,931,376
Average price per share	$	27.75	$	26.85	$	26.58
Proceeds, net of fees (in millions)	$	229.1	$	232.5	$	314.7

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 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.

Proceeds from the issuance of the Series A Preferred Stock were used to pay a portion of the notes tendered in June 2018 and the redemption of the remaining notes in July 2018. See Note 14, “Long-term Debt” for additional information regarding the tender offer and redemption.

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, 2019 and 2018, Series A Preferred Stock had $1.0 million of cumulative preferred dividends in arrears, or $2.51 per share.

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NISOURCE INC.

Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

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, 2019 and 2018, Series B Preferred Stock had $1.4 million and $2.4 million, respectively, of cumulative preferred dividends in arrears, or $72.23 and $121.88 per share, respectively.

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 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.

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NISOURCE INC.

Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

The following table summarizes preferred stock by outstanding series of shares:

				Year ended December 31,						December 31,		December 31,
				2019		2018		2017		2019		2018
(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	$	28.88	$	—	$	393.9	$	393.9
6.500% Series B	$	25,000.00	20,000	$	1,674.65	$	—	$	—	$	486.1	$	486.1

13.     Share-Based Compensation

Our stockholders most recently approved the NiSource Inc. 2010 Omnibus Incentive Plan (“Omnibus Plan”) at the Annual Meeting of Stockholders held on May 12, 2015. The 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 long-term incentive plan approved by stockholders on April 13, 1994 (“1994 Plan”) and the Director Stock Incentive Plan (“Director Plan”). The Omnibus Plan provides that the number of shares of common stock of NiSource available for awards is 8,000,000 plus the number of shares subject to outstanding awards that expire or terminate for any reason that were granted under either the 1994 Plan or the Director Plan, plus the number of shares that were awarded as a result of the Separation-related adjustments. At December 31, 2019, there were 3,313,183 shares reserved for future awards under the Omnibus Plan.

We recognized stock-based employee compensation expense of $16.3 million, $15.2 million and $15.3 million, during 2019, 2018 and 2017, respectively, as well as related tax benefits of $4.0 million, $3.7 million and $5.9 million, respectively. We recognized related excess tax benefits from the distribution of vested share-based employee compensation of $0.8 million, $1.0 million and $4.4 million in 2019, 2018 and 2017, respectively.

As of December 31, 2019, the total remaining unrecognized compensation cost related to non-vested awards amounted to $19.5 million, which will be amortized over the weighted-average remaining requisite service period of 1.8 years.

Restricted Stock Units and Restricted Stock. In 2019, we granted 166,031 restricted stock units and shares of restricted stock to employees, subject to service conditions. The total grant date fair value of the restricted stock units and shares of restricted stock was $4.1 million, based on the average market price of our common stock at the date of each grant less the present value of any dividends not received during the vesting period, which will be expensed over the vesting period which is generally three years. As of December 31, 2019, 157,786 non-vested restricted stock units and shares of restricted stock granted in 2019 were outstanding as of December 31, 2019.

In 2018, we granted 158,689 restricted stock units and shares of restricted stock to employees, subject to service conditions. The total grant date fair value of the restricted stock units and shares of restricted stock was $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 years. As of December 31, 2019, 136,820 non-vested restricted stock units and shares of restricted stock granted in 2018 were outstanding as of December 31, 2019.

Restricted stock units and shares of restricted stock granted to employees in 2017 were immaterial.

If an employee terminates employment before the service conditions lapse under the 2017, 2018 or 2019 awards due to (1) retirement or disability (as defined in the award agreement), or (2) death, the service conditions will lapse on the date of such termination with respect to a pro rata portion of the restricted stock units and shares of restricted stock based upon the percentage of the service period satisfied between the grant date and the date of the termination of employment. In the event of a change in control (as defined in the award agreement), all unvested shares of restricted stock and restricted stock units awarded will immediately vest upon termination of employment occurring in connection with a change in control. Termination due to any other reason will result in all unvested shares of restricted stock and restricted stock units awarded being forfeited effective on the employee’s date of termination.

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NISOURCE INC.

Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

(shares)	Restricted Stock Units		Weighted Average Award Date Fair  Value Per Unit ($)
Non-vested at December 31, 2018	178,678		21.82
Granted	166,031		24.93
Forfeited	(21,547	)	22.99
Vested	(20,556	)	21.08
Non-vested at December 31, 2019	302,606		23.49

Performance Shares. In 2019, we granted 552,389 performance shares subject to service, performance and market conditions. The service conditions for these awards lapse on February 28, 2022. The performance period for the awards is the period beginning January 1, 2019 and ending December 31, 2021. The performance conditions are based on the achievement of one non-GAAP financial measure 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 unusual or non-recurring 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 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 beginning on December 31, 2018 and ending on December 31, 2021) 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 market conditions. The grant date fair value of the awards was $11.7 million, 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. As of December 31, 2019, 422,825 of these non-vested performance shares granted in 2019 remained outstanding.

If a threshold level of cumulative NOEPS financial performance is achieved, additional operational measures which we refer to as the customer value index, which consists of five equally weighted areas of focus including safety, customer satisfaction, financial, culture and environmental apply. Each area of focus represents 20% of the customer value index shares, and the targets for all areas must be met for these awards to be eligible for 100% payout of these awards. The grant date fair value of the awards was $2.5 million, 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. As of December 31, 2019, 97,574 of these awards that were issued in 2019 remained outstanding.

In 2018, we awarded 514,338 performance shares subject to service, performance and market conditions. The service conditions for these awards lapse on February 26, 2021. The performance period for the awards is the period beginning January 1, 2018 and ending December 31, 2020. The performance conditions are based on the achievement of one non-GAAP financial measure 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 unusual or non-recurring 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 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 beginning on December 31, 2017 and ending on December 31, 2020) 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 market conditions. The grant date fair value of the awards was $9.2 million, 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. As of December 31, 2019, 368,811 of these non-vested performance shares granted in 2018 remained outstanding.

If a threshold level of cumulative NOEPS financial performance is achieved, additional operational measures which we refer to as the customer value index, which consists of five equally weighted areas of focus including safety, customer satisfaction, financial, culture and environmental apply. Each area of focus represents 20% of the customer value index shares and the targets for all areas must be met for these awards to be eligible for 100% payout of these awards. Individual payout percentages for these shares may

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NISOURCE INC.

Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

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 718. The service inception date fair value of the awards was $2.4 million, 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. As of December 31, 2019, 85,111 of these awards that were issued in 2018 remained outstanding. The service conditions for these awards lapse on February 26, 2021.

In 2017, we granted 660,750 performance shares subject to service, performance and market conditions. The grant date fair value of the awards was $12.9 million, 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. The performance conditions are based on achievement of non-GAAP financial measures similar to those discussed above: cumulative net operating earnings per share for the three-year period ending December 31, 2019 and relative total shareholder return (calculated using a 20 trading day average of our closing price beginning on December 31, 2016 and ending on December 31, 2019). As of December 31, 2019, 528,928 non-vested performance shares granted in 2017 remained outstanding. The service conditions for these awards lapse on February 28, 2020.

(shares)	Performance Awards		Weighted Average Grant Date Fair  Value Per Unit ($)(1)
Non-vested at December 31, 2018	1,634,718		20.45
Granted	552,389		25.77
Forfeited	(156,700	)	26.72
Vested	(527,156	)	28.11
Non-vested at December 31, 2019	1,503,251		22.74

⁽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 11, 2010, awards to non-employee directors may be made only under the 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 election to defer. Certain restricted stock units remain outstanding from 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, 2019, 165,768 restricted stock units are outstanding to non-employee directors under either the Omnibus Plan or the Director Plan. Of this amount, 49,926 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 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, 2019, 2018 and 2017, we recognized 401(k) match, profit sharing and non-elective contribution expense of $37.5 million, $37.6 million and $37.6 million, respectively.

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NISOURCE INC.

Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

14.     Long-Term Debt

Our long-term debt as of December 31, 2019 and 2018 is as follows:

Long-term debt type	Maturity as of December 31, 2019	Weighted average interest rate (%)		Outstanding balance as of December 31, (in millions)
				2019			2018
Senior notes:
NiSource	December 2021	4.45	%	63.6			63.6
NiSource	November 2022	2.65	%	500.0			500.0
NiSource	February 2023	3.85	%	250.0			250.0
NiSource	June 2023	3.65	%	350.0			350.0
NiSource	November 2025	5.89	%	265.0			265.0
NiSource	May 2027	3.49	%	1,000.0			1,000.0
NiSource	December 2027	6.78	%	3.0			3.0
NiSource	September 2029	2.95	%	750.0			—
NiSource	December 2040	6.25	%	250.0			250.0
NiSource	June 2041	5.95	%	400.0			400.0
NiSource	February 2042	5.80	%	250.0			250.0
NiSource	February 2043	5.25	%	500.0			500.0
NiSource	February 2044	4.80	%	750.0			750.0
NiSource	February 2045	5.65	%	500.0			500.0
NiSource	May 2047	4.38	%	1,000.0			1,000.0
NiSource	March 2048	3.95	%	750.0			750.0
Total senior notes				$	7,581.6		$	6,831.6
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	December 2025 to February 2028	6.30	%	40.0			40.0
Total medium term notes				$	157.0		$	157.0
Finance leases:
NiSource Corporate Services	January 2020 to November 2023	3.47	%	22.3			11.6
Columbia of Ohio	October 2021 to March 2044	6.16	%	94.8			91.5
Columbia of Virginia	July 2029 to November 2039	6.31	%	19.1			15.2
Columbia of Kentucky	May 2027	3.79	%	0.3			0.3
Columbia of Pennsylvania	August 2027 to May 2035	5.67	%	20.7			30.0
Columbia of Massachusetts	December 2033 to November 2043	5.49	%	44.3			45.7
Total finance leases				201.5			194.3
Pollution control bonds - NIPSCO	April 2019	5.85	%	—			41.0
Unamortized issuance costs and discounts				(70.5		)	$	(68.5	)
Total Long-Term Debt				$	7,869.6		$	7,155.4

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 closed our placement 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.

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NISOURCE INC.

Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

Details of our 2018 long-term debt related activity are summarized below:

• On March 15, 2018, we redeemed $275.1 million of 6.40% senior unsecured notes at maturity.

• In June 2018, we executed a tender offer for $209.0 million of outstanding notes consisting of a combination of our 6.80% notes due 2019, 5.45% notes due 2020, and 6.125% notes due 2022. In conjunction with the debt retired, we recorded a $12.5 million loss on early extinguishment of long-term debt, primarily attributable to early redemption premiums.

• On June 11, 2018, we closed our private placement of $350.0 million of 3.65% senior unsecured notes maturing in 2023 which resulted in approximately $346.6 million of net proceeds after deducting commissions and expenses. We used the net proceeds from this private placement to pay a portion of the redemption price for the notes subject to the tender offer described above.

• In July 2018, we redeemed $551.1 million of outstanding notes representing the remainder of our 6.80% notes due 2019, 5.45% notes due 2020 and 6.125% notes due 2022. During the third quarter of 2018, we recorded a $33.0 million loss on early extinguishment of long-term debt, primarily attributable to early redemption premiums.

See Note 19-A, "Contractual Obligations," for the outstanding long-term debt maturities at December 31, 2019.

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 and term loan agreement which requires us to maintain a debt to capitalization ratio that does not exceed 70%. A similar covenant in a 2005 private placement note purchase agreement requires us to maintain a debt to capitalization ratio that does not exceed 75%. As of December 31, 2019, the ratio was 61.7%.

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.

15.     Short-Term Borrowings

We generate short-term borrowings from our revolving credit facility, commercial paper program, accounts receivable transfer programs and term loan borrowings. Each of these borrowing sources is described further below.

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, 2019 and 2018, 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 $570.0 million and $978.0 million of commercial paper outstanding as of December 31, 2019 and 2018, 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 $353.2 million and $399.2 million in transfers as of December 31, 2019 and 2018, respectively. Refer to Note 18, "Transfers of Financial Assets," for additional information.

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NISOURCE INC.

Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

On April 17, 2019, we amended our existing term loan agreement with a syndicate of banks, with MUFG Bank Ltd. as the Administrative Agent, Sole Lead Arranger and Sole Bookrunner. The amendment increased the amount of our term loan from $600.0 million to $850.0 million and extended the maturity date to April 16, 2020. Interest charged on borrowings depends on the variable rate structure we elect at the time of each borrowing. The available variable rate structures from which we may choose are defined in the term loan agreement. Under the agreement, we borrowed $850.0 million on April 17, 2019 with an interest rate of LIBOR plus 60 basis points.

Short-term borrowings were as follows: 

At December 31, (in millions)	2019		2018
Commercial Paper weighted-average interest rate of 2.03% and 2.96% at December 31, 2019 and 2018, respectively	$	570.0	$	978.0
Accounts receivable securitization facility borrowings	353.2		399.2
Term loan weighted-average interest rate of 2.40% and 3.07% at December 31, 2019 and 2018, respectively	850.0		$	600.0
Total Short-Term Borrowings	$	1,773.2	$	1,977.2

Other than for the term loan 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.

16.    Leases

ASC 842 Adoption. In February 2016, the FASB issued ASU 2016-02, Leases (ASC 842). ASU 2016-02 introduces a lessee model that brings most leases onto the balance sheet. The standard requires that lessees recognize the following for all leases (with the exception of short-term leases, as that term is defined in the standard) at the lease commencement date: (1) a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and (2) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. In 2018, the FASB issued ASU 2018-01, Leases (ASC 842): Land Easement Practical Expedient for Transition to ASC 842, which allows us to not evaluate existing land easements under ASC 842, and ASU 2018-11, Leases (ASC 842): Targeted Improvements, which allows calendar year entities to initially apply ASC 842 prospectively from January 1, 2019.

We adopted the provisions of ASC 842 beginning on January 1, 2019, using the transition method provided in ASU 2018-11, which was applied to all existing leases at that date. As such, results for reporting periods beginning after January 1, 2019 will be presented under ASC 842, while prior period amounts will continue to be reported in accordance with ASC 840. We elected a number of practical expedients, including the "practical expedient package" described in ASC 842-10-65-1 and the provisions of ASU 2018-01, which allows us to not evaluate existing land easements under ASC 842. Further, ASC 842 provides lessees the option of electing an accounting policy, by class of underlying asset, in which the lessee may choose not to separate nonlease components from lease components. We elected this practical expedient for our leases of fleet vehicles, IT assets and railcars. We elected to use a practical expedient that allows the use of hindsight in determining lease terms when evaluating leases that existed at the implementation date. We also elected the short-term lease recognition exemption, allowing us to not recognize ROU assets or lease liabilities for all leases that qualify.

Adoption of the new 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 24 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 3 years with options to renew for 1 year. Our fleet vehicles include trucks, trailers and equipment that have been customized specifically for use in the utility industry. We lease fleet vehicles 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 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.

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NISOURCE INC.

Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

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 year ended 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	2019
Finance lease cost
Amortization of right-of-use assets	Depreciation and amortization	$	15.5
Interest on lease liabilities	Interest expense, net	11.3
Total finance lease cost		26.8
Operating lease cost	Operation and maintenance	17.9
Short-term lease cost	Operation and maintenance	1.0
Total lease cost		$	45.7

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

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

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NISOURCE INC.

Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

Other pertinent information related to leases was as follows:

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

	December 31, 2019
Weighted-average remaining lease term (years)
Finance leases	14.8
Operating leases	9.2
Weighted-average discount rate
Finance leases	5.9	%
Operating leases	4.3	%

Maturities of our lease liabilities presented on a rolling 12-month basis were as follows:

As of December 31, 2019, (in millions)	Total			Finance Leases			Operating Leases
Year 1	$	42.8		$	27.2		$	15.6
Year 2	36.7			27.3			9.4
Year 3	35.0			26.8			8.2
Year 4	30.7			23.1			7.6
Year 5	26.5			19.9			6.6
Thereafter	233.3			201.6			31.7
Total lease payments(1)	405.0			325.9			79.1
Less: Imputed interest	(116.6		)	(102.3		)	(14.3		)
Less: Leases not yet commenced	(22.1		)	(22.1		)	—
Total	266.3			201.5			64.8
Reported as of December 31, 2019
Short-term lease liabilities	26.6			13.4			13.2
Long-term lease liabilities	239.7			188.1			51.6
Total lease liabilities	$	266.3		$	201.5		$	64.8

⁽¹⁾ Expected payments include obligations for leases not yet commenced of approximately $22.1 million for IT assets and interconnection facilities. These leases have terms between 4 years and 20 years, with estimated commencements in the first quarter of 2020 and in the third quarter of 2020.

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NISOURCE INC.

Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

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 $49.5 million in 2017, and are primarily charged to operation and maintenance expense as incurred.

As of December 31, 2018, total contractual obligations for capital and operating leases were as follows:

As of December 31, 2018, (in millions)	Total		Capital Leases(1)		Operating Leases(2)
2019	$	34.0	$	23.0	$	11.0
2020	29.8		22.5		7.3
2021	28.7		22.6		6.1
2022	26.3		22.1		4.2
2023	22.6		19.8		2.8
Thereafter	226.9		212.4		14.5
Total lease payments	$	368.3	$	322.4	$	45.9

⁽¹⁾Capital lease payments shown above are inclusive of interest totaling $114.6 million.

⁽²⁾Operating lease balances do not include obligations for possible fleet vehicle lease renewals beyond the initial lease term. While we have the ability to renew these leases beyond the initial term, we are not reasonably certain to do so. Expected payments are $26.7 million in 2019, $22.4 million in 2020, $16.6 million in 2021, $12.3 million in 2022, $9.3 million in 2023 and $8.8 million thereafter.

17.    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, 2019 and December 31, 2018:

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

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NISOURCE INC.

Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

Recurring Fair Value Measurements December 31, 2018 (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, 2018
Assets
Risk management assets	$	—	$	24.0	$	—	$	24.0
Available-for-sale securities	—		138.3		—		138.3
Total	$	—	$	162.3	$	—	$	162.3
Liabilities
Risk management liabilities	$	—	$	51.7	$	—	$	51.7
Total	$	—	$	51.7	$	—	$	51.7

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 which reduce exposures. As of December 31, 2019 and 2018, there were no material transfers between fair value hierarchies. Additionally, there were no changes in the method or significant assumptions used to estimate the fair value of our financial instruments.

We have entered into forward-starting interest rate swaps to hedge the interest rate risk on coupon payments of forecasted issuances of long-term debt. These derivatives are designated as cash flow hedges. Credit risk is considered in the fair value calculation of each agreement. 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. For additional information, see Note 9, "Risk Management Activities."

NIPSCO has entered into long-term forward natural gas purchase instruments that range from five to ten years 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 9, “Risk Management Activities.”

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NISOURCE INC.

Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

Available-for-sale securities are investments pledged as collateral for trust accounts related to our wholly-owned insurance company. Available-for-sale securities are included within “Other investments” in the Consolidated Balance Sheets. 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. Total unrealized gains and losses from available-for-sale securities are included in other comprehensive income. The amortized cost, gross unrealized gains and losses and fair value of available-for-sale securities at December 31, 2019 and 2018 were: 

December 31, 2019 (in millions)	Amortized Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
Available-for-sale 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
December 31, 2018 (in millions)	Amortized Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
Available-for-sale securities
U.S. Treasury debt securities	$	23.6	$	0.1	$	(0.1	)	$	23.6
Corporate/Other debt securities	117.7		0.4		(3.4		)	114.7
Total	$	141.3	$	0.5	$	(3.5	)	$	138.3

 

Realized gains and losses on available-for-sale securities were immaterial for the year-ended December 31, 2019 and 2018.

The cost of maturities sold is based upon specific identification. At December 31, 2019, approximately $7.7 million of U.S. Treasury debt securities and approximately $6.0 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, 2019 and 2018.

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.

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 6, “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, 2019 and 2018, there was no change in the method or significant assumptions used to estimate the fair value of long-term debt.

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NISOURCE INC.

Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

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

At December 31, (in millions)	Carrying Amount 2019		Estimated Fair Value 2019		Carrying Amount 2018		Estimated Fair Value 2018
Long-term debt (including current portion)	$	7,869.6	$	8,764.4	$	7,155.4	$	7,228.3

18.     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 2020 and October 2020 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, 2019, the maximum amount of debt that could be recognized related to our accounts receivable programs is $465.0 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, 2019 and 2018:

At December 31, (in millions)	2019		2018
Gross receivables	$	569.1	$	694.4
Less: receivables not transferred	215.9		295.2
Net receivables transferred	$	353.2	$	399.2
Short-term debt due to asset securitization	$	353.2	$	399.2

During 2019, $46.0 million was recorded as cash flows used for financing activities related to the change in short-term borrowings due to securitization transactions. During 2018, $62.5 million was recorded as cash flows from financing activities related to the change in short-term borrowings due to securitization transactions. Fees associated with the securitization transactions were $2.6 million, $2.6 million and $2.5 million for the years ended December 31, 2019, 2018 and 2017, respectively. Columbia of Ohio, NIPSCO and Columbia of Pennsylvania remain responsible for collecting on the receivables securitized, and the receivables cannot be transferred to another party.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

19.    Other Commitments and Contingencies

A.    Contractual Obligations. We have certain contractual obligations requiring payments at specified periods. The obligations include long-term debt, lease obligations, energy commodity contracts and obligations for various services including pipeline capacity and outsourcing of IT services. The total contractual obligations in existence at December 31, 2019 and their maturities were:

(in millions)	Total		2020		2021		2022		2023		2024		After
Long-term debt (1)	$	7,738.6	$	—	$	63.6	$	530.0	$	600.0	$	—	$	6,545.0
Interest payments on long-term debt	6,214.2		342.0		340.7		337.1		311.1		299.9		4,583.4
Finance leases(2)	325.9		27.2		27.3		26.8		23.1		19.9		201.6
Operating leases(3)	79.1		15.6		9.4		8.2		7.6		6.6		31.7
Energy commodity contracts(4)	95.9		65.5		30.4		—		—		—		—
Service obligations:
Pipeline service obligations	3,450.7		605.0		590.1		546.8		357.2		237.5		1,114.1
IT service obligations	153.2		63.6		49.4		38.0		1.1		1.1		—
Other service obligations(5)	59.8		45.8		14.0		—		—		—		—
Other liabilities	27.3		27.3		—		—		—		—		—
Total contractual obligations	$	18,144.7	$	1,192.0	$	1,124.9	$	1,486.9	$	1,300.1	$	565.0	$	12,475.8

⁽¹⁾ Long-term debt balance excludes unamortized issuance costs and discounts of $70.5 million.

⁽²⁾ Finance lease payments shown above are inclusive of interest totaling $108.3 million.

⁽³⁾ Operating lease payments shown above are inclusive of interest totaling $14.3 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. If we were to continue the fleet vehicle leases outstanding at December 31, 2019, payments would be $34.5 million in 2020, $28.3 million in 2021, $23.4 million in 2022, $19.9 million in 2023, $15.2 million in 2024 and $15.2 million thereafter.  

⁽⁴⁾In January 2020, NIPSCO signed new coal contract commitments of $14.4 million for 2020. These contracts are not included above.  

⁽⁵⁾In February 2020, NIPSCO signed a new railcar coal transportation contract commitment of $12.0 million for 2020. This contract is not included above.

Operating and Finance Lease Commitments. We lease assets in several areas of our operations including corporate and field offices, railcars, fleet vehicles and certain IT assets. Payments made in connection with operating and month-to-month leases were $52.5 million in 2019, $49.1 million in 2018 and $49.5 million in 2017, and are primarily charged to operation and maintenance expense as incurred. See Note 16, "Leases" for additional details.

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 minimum quantities 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, 2019.

In July 2008, the IURC issued an order approving NIPSCO’s purchase power agreements with subsidiaries of Iberdrola Renewables, Buffalo Ridge I LLC and Barton Windpower LLC. These agreements provide NIPSCO the opportunity and obligation to purchase up to 100 MW of wind power generated commencing in early 2009. The contracts extend 15 and 20 years, representing 50 MW of wind power each. 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 any termination of the agreements by NIPSCO for any reason (other than material breach by Buffalo Ridge I LLC or Barton Windpower LLC), 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. NIPSCO began purchasing wind power in April 2009.

We have pipeline service agreements that provide for pipeline capacity, transportation and storage services. These agreements, which have expiration dates ranging from 2020 to 2045, require us to pay fixed monthly charges.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

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 2024.

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, 2019 and 2018, we had issued stand-by letters of credit of $10.2 million for the benefit of third parties.

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.

We are 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 described below. We are cooperating with all inquiries and investigations. In addition, 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, as described below.

NTSB Investigation. As previously disclosed, the NTSB concluded its investigation into the Greater Lawrence Incident, and we are implementing the one remaining safety recommendation resulting from the investigation.

Massachusetts Investigations. Under Massachusetts law, the DPU is authorized to investigate potential violations of pipeline safety regulations and to assess a civil penalty of up to $218,647 for a violation of federal pipeline safety regulations. A separate violation occurs for each day of violation up to $2.2 million for a related series of violations. The Massachusetts DPU also is authorized to investigate potential violations of the Columbia of Massachusetts emergency response plan and to assess penalties of up to $250,000 per violation per day, or up to $20 million per related series of violations. Further, as a result of the declaration of emergency by the Governor, the DPU is authorized to investigate potential violations of the DPU's operational directives during the restoration efforts and assess penalties of up to $1 million per violation. Pursuant to these authorities, the DPU is investigating Columbia of Massachusetts as described below. Columbia of Massachusetts will likely be subject to potential compliance actions related to the Greater Lawrence Incident and the restoration work following the incident, the timing and outcomes of which are uncertain at this time.

After the Greater Lawrence Incident, the Massachusetts DPU retained an independent evaluator to conduct a statewide examination of the safety of the natural gas distribution system and the operational and maintenance functions of natural gas companies in the Commonwealth of Massachusetts. Through authority granted by the Massachusetts Governor under the state of emergency, the Chair of the Massachusetts DPU has directed all natural gas distribution companies operating in the Commonwealth to fund the statewide examination. The statewide examination is complete. The Phase I report, which was issued in May 2019, included a program level assessment and evaluation of natural gas distribution companies. The Phase I report's conclusions were statewide and contained no specific conclusions about Columbia of Massachusetts. Phase II, which was focused on field assessments of each Massachusetts gas company, concluded in December 2019. The Phase II report made several observations about and recommendations to Massachusetts gas companies, including Columbia of Massachusetts, with regard to safety culture and assets. The final report was issued in late January 2020, and the DPU directed each natural gas distribution company operating in Massachusetts to submit a plan in response to the report no later than February 28, 2020.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

On September 11, 2019, the Massachusetts DPU issued an order directing Columbia of Massachusetts to take several specific actions to address concerns related to service lines abandoned during the restoration work following the Greater Lawrence Incident and to furnish certain information and periodic reports to the DPU.

On October 1, 2019, the Massachusetts DPU issued four orders to Columbia of Massachusetts in connection with the service lines abandoned during the Greater Lawrence Incident restoration, which require: (1) the submission of a detailed work plan to the DPU, (2) the completion of quality control work on certain abandoned services, (3) the payment for a third-party independent audit, to be contracted through the DPU, of all gas pipeline work completed as part of the incident restoration effort, and (4) prompt and full response to any requests for information by the third-party auditor. The Massachusetts DPU retained an independent evaluator to conduct this audit, and that third party is currently evaluating compliance with Massachusetts and federal law, as well as any other operational or safety risks that may be posed by the pipeline work. The audit scope also includes Columbia of Massachusetts' operations in the Lawrence Division and other service territories as appropriate.

Also in October 2019, the Massachusetts DPU issued three additional orders requiring: (1) daily leak surveillance and reporting in areas where abandoned services are located, (2) completion by November 15, 2019 of the work plan previously submitted describing how Columbia of Massachusetts would address the estimated 2,200 locations at which an inside meter set was moved outside the property as part of the abandoned service work completed during the Greater Lawrence Incident restoration, and (3) submission of a report by December 2, 2019 showing any patterns, trends or correlations among the non-compliant work related to the abandonment of service lines, gate boxes and curb boxes during the incident restoration.

On October 3, 2019, the Massachusetts DPU notified Columbia of Massachusetts that, absent DPU approval, it is currently allowed to perform only emergency work on its gas distribution system throughout its service territories in Massachusetts. The restrictions do not apply to Columbia of Massachusetts’ work to address the previously identified issues with abandoned service lines and valve boxes in the Greater Lawrence, Massachusetts area. Columbia of Massachusetts is subject to daily monitoring by the DPU on any work that Columbia of Massachusetts conducts in Massachusetts. Such restrictions on work remain in place until modified by the DPU.

On October 25, 2019, the Massachusetts DPU issued two orders opening public investigations into Columbia of Massachusetts with respect to the Greater Lawrence Incident. The Massachusetts DPU opened the first investigation under its authority to determine compliance with federal and state pipeline safety laws and regulations, and to investigate Columbia of Massachusetts’ responsibility for and response to the Greater Lawrence Incident and its restoration efforts following the incident. The Massachusetts DPU opened the second investigation under its authority to determine whether a gas distribution company has violated established standards regarding acceptable performance for emergency preparedness and restoration of service to investigate efforts by Columbia of Massachusetts to prepare for and restore service following the Greater Lawrence Incident. Separate penalties are applicable under each exercise of authority.

On December 23, 2019, the Massachusetts DPU issued an order defining the scope of its investigation into the response of Columbia of Massachusetts related to the Greater Lawrence Incident. The DPU identified three distinct time frames in which Columbia of Massachusetts handled emergency response and restoration directly: (1) September 13-14, 2018, (2) September 21 through December 16, 2018 (the Phase I restoration), and (3) September 27, 2019 through completion of restoration of outages resulting from the gas release event in Lawrence, Massachusetts that occurred on September 27, 2019. The DPU determined that it is appropriate to investigate separately, for each time period described above, the areas of response, recovery and restoration for which Columbia of Massachusetts was responsible. The DPU noted that it also may investigate the continued restoration and related repair work that took place after December 16, 2018 and, depending on the outcome of that investigation, may deem it appropriate to consider that period of restoration as an additional separate time period.

The DPU also noted that its investigation into all of the above described time periods is ongoing and that if the DPU determines, based on its investigation, that it is appropriate to treat the separate time frames as separate emergency events, it may impose up to the maximum statutory penalty for each event, pursuant to Mass. G.L. c. 164 Section 1J. This provision authorizes the DPU to investigate potential violations of the Columbia of Massachusetts emergency response plan and to assess penalties of up to $250,000 per violation per day, or up to $20 million per related series of violations. The DPU noted that at this preliminary stage of the investigation, it does not have the factual basis to make those determinations.

In connection with its investigation related to the Greater Lawrence Incident, on February 4, 2020, the Massachusetts Attorney General's Office issued a request for documents primarily focused on the restoration work following the incident.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

Columbia of Massachusetts is cooperating with the investigations set forth above as well as other inquiries resulting from an increased amount of enforcement activity, for all of which the outcomes are uncertain at this time.

Massachusetts Legislative Matters. On November 12, 2019, the Joint Committee on Telecommunications, Utilities and Energy held a hearing that focused on gas safety, but the Committee has not taken action on any bills. Increased scrutiny related to gas system safety and regulatory oversight in Massachusetts, including additional legislative oversight hearings and new legislative proposals, is expected to continue during the current two-year legislative session that ends in December 2020.

U.S. Department of Justice Investigation. As previously disclosed, the Company and Columbia of Massachusetts are subject to a criminal investigation related to the Greater Lawrence Incident that is being conducted under the supervision of the U.S. Attorney's Office. The initial grand jury subpoenas were served on the Company and Columbia of Massachusetts on September 24, 2018.

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 DPA.

Under the Plea Agreement, which must be approved by the Court, Columbia of Massachusetts will be subject to the following terms, among others: (i) a criminal fine in the amount of $53,030,116 paid within 30 days of sentencing; (ii) a three year probationary period that will early terminate 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; (iii) compliance with each of the NTSB recommendations stemming from the Greater Lawrence Incident; and (iv) employment of an in-house monitor during the term of the probationary period.

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. 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 Gas of Massachusetts or its gas distribution business, a fine equal to the total amount of any profit or gain 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’ guilty plea is not accepted by the Court or is withdrawn for any reason, 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.

U.S. Congressional Activity. On September 30, 2019, the U.S. Pipeline Safety Act expired. There is no effect on PHMSA's authority. Action on past re-authorization bills has extended past the expiration date and action on this re-authorization is expected to continue well into 2020. Pipeline safety jurisdiction resides with the U.S. Senate Commerce Committee, and is divided between two committees in the U.S. House of Representatives (Energy and Commerce, and Transportation and Infrastructure). Legislative proposals are currently in various stages of committee development and the timing of further action is uncertain. Certain legislative proposals, if enacted into law, may increase costs for natural gas industry companies, including the Company and Columbia of Massachusetts.

SEC Investigation. On November 27, 2019, the SEC staff notified the Company that it concluded its investigation related to disclosures made by the Company prior to the Greater Lawrence Incident and, based on the information provided as of such date, it does not intend to recommend an enforcement action against the Company.

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. A special judge has been appointed to hear all pending and future cases and the class actions have been consolidated into one class action. On January 14, 2019, the special judge granted the parties’ joint motion to stay all cases until

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

April 30, 2019 to allow mediation, and the parties subsequently agreed to extend the stay until July 25, 2019. The class action lawsuits allege varying causes of action, including those for strict liability for ultra-hazardous activity, negligence, private nuisance, public nuisance, premises liability, trespass, breach of warranty, breach of contract, failure to warn, unjust enrichment, consumer protection act claims, negligent, reckless and intentional infliction of emotional distress and gross negligence, and seek actual compensatory damages, plus treble damages, and punitive damages.

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 proposed settlement is subject to final court approval, and a hearing occurred on February 27, 2020. The court took the matter under advisement.

Many residents and business owners have submitted individual damage claims to Columbia of Massachusetts. Most of the wrongful death and bodily injury claims that have been asserted have been settled, and we continue to discuss potential settlements with plaintiffs asserting such claims. In addition, the Commonwealth of Massachusetts is seeking reimbursement from Columbia of Massachusetts for its expenses incurred in connection with the Greater Lawrence Incident. The outcomes and impacts of such private actions are uncertain at this time.

Financial Impact. Since the Greater Lawrence Incident, we have recorded expenses of approximately $1,041 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 $1,041 million to $1,065 million, depending on the number, nature, final outcome and value of third-party claims and the final outcome of government investigations. 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, nor do they include non-claims related and government investigation-related legal expenses resulting from the incident and the capital cost of the pipeline replacement, which are set forth in " - E. Other Matters - Greater Lawrence Incident Restoration" and "- Greater Lawrence Incident Pipeline Replacement," respectively, below.

The process for estimating costs associated with third-party claims and fines, penalties, and settlements associated with government investigations 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, including additional information regarding ongoing investigations, 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 have 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

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

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 that we are in substantial compliance with the environmental regulations currently applicable to our operations.

It is management's continued intent to address environmental issues in cooperation with regulatory authorities in such a manner as to achieve mutually acceptable compliance plans. However, there can be no assurance that fines and penalties will not be incurred. Management expects a significant portion of environmental assessment, improvement and remediation costs to be recoverable through rates for certain of our companies.

As of December 31, 2019 and 2018, we had recorded a liability of $104.4 million and $101.2 million, respectively, to cover environmental remediation at various sites. The current portion of this liability is included in "Legal and environmental" 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.

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 coal-fired units at NIPSCO’s R.M. Schahfer Generating Station and Michigan City Generating Station are potentially affected sources, and compliance requirements for these units which NIPSCO plans to retire by 2023 and 2028, respectively, will be determined by future Indiana rulemaking. The ACE rule notes that states have “broad flexibility in setting standards of performance for designated facilities” and that a state may set a “business as usual” standard for sources that have a remaining useful life “so short that imposing any costs on the electric generating unit is unreasonable.” State plans are due by 2022, and the EPA will have six months to determine completeness and then one additional year to determine whether to approve the submitted plan. States have the discretion to determine the compliance period for each source. As a result, NIPSCO will continue to monitor this matter and cannot estimate its impact at this time.

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 63 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

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

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, 2019. Our total estimated liability related to the facilities subject to remediation was $102.2 million and $97.5 million at December 31, 2019 and 2018, 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 to modify its infrastructure and manage CCRs during 2019. 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 has filed initial CCR closure plans for R.M. Schahfer Generating Station and Michigan City Generating Station with the Indiana Department of Environmental Management.

Water

ELG. On November 3, 2015, the EPA issued a final rule to amend the ELG and standards for the Steam Electric Power Generating category. Based upon a study performed in 2016 of the final rule, capital compliance costs were expected to be approximately $170.0 million. The EPA has proposed revisions to the final rule, and public comments were due on January 21, 2020. NIPSCO does not anticipate material ELG compliance costs based on the preferred option announced as part of NIPSCO's 2018 Integrated Resource Plan (discussed below).

E.         Other Matters.

NIPSCO 2018 Integrated Resource Plan. Multiple factors, but primarily economic ones, including low natural gas prices, advancing cost effective renewable technology and increasing capital and operating costs associated with existing coal plants, have led NIPSCO to conclude in its October 2018 Integrated Resource Plan submission that NIPSCO’s current fleet of coal generation facilities will be retired earlier than previous Integrated Resource 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 R.M. Schahfer Generating Station (Units 14, 15, 17, and 18) by 2023 and Michigan City Generating Station (Unit 12) by 2028. These units represent 2,080 MW of generating capacity, equal to 72% of NIPSCO’s remaining generating capacity (and 100% of NIPSCO's remaining coal-fired generating capacity) after the retirement of Bailly Units 7 and 8 on May 31, 2018.

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.

In January 2019, NIPSCO executed two 20 year PPAs to purchase 100% of the output from renewable generation facilities at a fixed price per MWh. NIPSCO submitted the PPAs to the IURC for approval in February 2019 and the IURC approved the PPAs on June 5, 2019. Payments under the PPAs will not begin until the associated generation facilities are constructed by the owner / seller which is currently scheduled to be complete by the end of 2020 for one facility. NIPSCO has filed a notice with the IURC of its intention not to move forward with one of its approved PPAs due to the failure to meet a condition precedent in the agreement as a result of local zoning restrictions.

Also in January 2019, NIPSCO executed a BTA with a developer to construct a renewable generation facility with a nameplate capacity of approximately 100 MW. Once complete, ownership of the facility would be transferred to a joint venture owned by NIPSCO, the developer and an unrelated tax equity partner. The aforementioned joint venture is expected to be fully owned by NIPSCO after the PTC are monetized from the project (approximately 10 years after the facility goes into service). NIPSCO's purchase requirement under the BTA 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 submitted the BTA to the IURC for approval

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Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

in February 2019 and the IURC approved the BTA on August 7, 2019. Required FERC filings occurred after receiving the IURC order and the related approvals were received. Construction of the facility is expected to be completed by the end of 2020.

On October 1, 2019, NIPSCO announced the opening of its next round of RFP to consider potential resources to meet the future electric needs of its customers. The RFP closed on November 20, 2019, and NIPSCO continues to evaluate the results. NIPSCO is considering all sources in the RFP process.

In October 2019, NIPSCO executed a BTA with a developer to construct an additional renewable generation facility with a nameplate capacity of approximately 300 MW. Once complete, ownership of the facility would be transferred to a joint venture owned by NIPSCO, the developer and an unrelated tax equity partner. The aforementioned joint venture is expected to be fully owned by NIPSCO after the PTC are monetized from the project (approximately 10 years after the facility goes into service). NIPSCO's purchase requirement under the BTA 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 submitted the BTA to the IURC for approval on October 22, 2019, and the IURC approved the BTA on February 19, 2020. Required FERC filings are expected to be filed by the end of June 2020. Construction of the facility is expected to be completed by the end of 2021.

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, since the Greater Lawrence Incident, we have recorded expenses of approximately $420 million for other incident-related costs. We estimate that total other incident-related costs will range from $450 million to $460 million, depending on the incurrence of costs associated with resolving outstanding inquiries and investigations discuss above in " - C. Legal Proceedings." 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. The amounts set forth above do not include the capital cost of the pipeline replacement, which is set forth below, or any estimates for fines and penalties, which are discussed above in " - C. Legal Proceedings."

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. We have collected the entire $800 million as of December 31, 2019. Expenses related to the incident have exceeded the total amount of insurance coverage available under our policies.

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).

	Year Ended			Year Ended
(in millions)	December 31, 2018			December 31, 2019			Incident to Date
Third-party claims and government fines, penalties and settlements	$	757		$	284		$	1,041
Other incident-related costs	266			154			420
Total	1,023			438			1,461
Insurance recoveries recorded	(135		)	(665		)	(800		)
Loss (benefit) to income before income taxes	$	888		$	(227	)	$	661

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Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

The following table presents activity related to our Greater Lawrence Incident insurance recovery, which we have recovered in full as of December 31, 2019.

(in millions)	Insurance receivable(1)
Balance, December 31, 2018	$	130
Insurance recoveries recorded in first quarter of 2019	100
Cash collected from insurance recoveries in the first quarter of 2019	(108		)
Balance, March 31, 2019	122
Insurance recoveries recorded in the second quarter of 2019	435
Cash collected from insurance recoveries in the second quarter of 2019	(297		)
Balance, June 30, 2019	$	260
Insurance recoveries recorded in third quarter of 2019	—
Cash collected from insurance recoveries in the third quarter of 2019	(260		)
Balance, September 30, 2019	$	—
Insurance recoveries recorded in the fourth quarter of 2019	130
Cash collected from insurance recoveries in the fourth quarter of 2019	(130		)
Balance, December 31, 2019	$	—

⁽¹⁾$5 million of insurance recoveries were collected during 2018.

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 45-mile cast iron and bare steel pipeline system that delivers gas to approximately 7,500 gas meters, the majority of which serve residences and approximately 700 of which serve businesses impacted in the Greater Lawrence Incident. This system was replaced with plastic distribution mains and service lines, as well as enhanced safety features such as pressure regulation and excess flow valves at each premise.

Since the Greater Lawrence Incident and through December 31, 2019, we have 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 full cost of 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. The recovery of any capital investment not reimbursed through insurance will be addressed in a future regulatory proceeding; a future regulatory proceeding is dependent on the outcome of the sale of the Massachusetts Business. The outcome of such a proceeding (if any) is uncertain. In accordance with ASC 980-360, if it becomes probable that a portion of the pipeline replacement cost will not be recoverable through customer rates and an amount can be reasonably estimated, we will reduce our regulated plant balance for the amount of the probable disallowance and record an associated charge to earnings. This could result in a material adverse effect to our financial condition, results of operations and cash flows. Additionally, if a rate order is received allowing recovery of the investment with no or reduced return on investment, a loss on disallowance may be required.

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 is expected to review the application within nine months from the date of filing, and we believe it is reasonably possible that the application will be accepted, or an alternative method proposed.

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Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

20.     Accumulated Other Comprehensive Loss

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

(in millions)	Gains and Losses on Securities(1)			Gains and Losses on Cash Flow Hedges(1)			Pension and OPEB Items(1)			Accumulated Other Comprehensive Loss(1)
Balance as of January 1, 2017	$	(0.6	)	$	(6.9	)	$	(17.6	)	$	(25.1	)
Other comprehensive income (loss) before reclassifications	0.6			(24.2		)	1.9			(21.7		)
Amounts reclassified from accumulated other comprehensive loss	0.2			1.7			1.5			3.4
Net current-period other comprehensive income (loss)	0.8			(22.5		)	3.4			(18.3		)
Balance as of December 31, 2017	$	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	)

 

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

21.     Other, Net

Year Ended December 31, (in millions)	2019			2018			2017
Interest income	$	7.7		$	6.6		$	4.6
AFUDC equity	8.0			14.2			12.6
Charitable contributions(1)	(5.1		)	(45.3		)	(19.9		)
Pension and other postretirement non-service cost(2)	(16.5		)	18.0			(10.6		)
Interest rate swap settlement gain(3)	—			46.2			—
Miscellaneous	0.7			3.8			(0.2		)
Total Other, net	$	(5.2	)	$	43.5		$	(13.5	)

⁽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 19, "Other Commitments and Contingencies" for additional information on the Greater Lawrence Incident.

⁽²⁾ See Note 11, "Pension and Other Postretirement Benefits" for additional information.

⁽³⁾ See Note 9, "Risk Management Activities" for additional information.

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Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

22.     Interest Expense, Net

Year Ended December 31, (in millions)	2019			2018			2017
Interest on long-term debt	$	327.7		$	342.2		$	354.8
Interest on short-term borrowings	50.8			31.8			14.9
Debt discount/cost amortization	8.3			7.7			7.2
Accounts receivable securitization fees	2.6			2.6			2.5
Allowance for borrowed funds used and interest capitalized during construction	(7.5		)	(9.1		)	(6.2		)
Debt-based post-in-service carrying charges	(18.7		)	(35.0		)	(36.4		)
Other	15.7			13.1			16.4
Total Interest Expense, net	$	378.9		$	353.3		$	353.2

23.     Segments of Business

At December 31, 2019, our operations are divided into two primary reportable segments. 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. The Electric Operations segment provides electric service in 20 counties in the northern part of Indiana.

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)	2019			2018			2017
Operating Revenues
Gas Distribution Operations
Unaffiliated	$	3,509.7		$	3,406.4		$	3,087.9
Intersegment	13.1			13.1			14.2
Total	3,522.8			3,419.5			3,102.1
Electric Operations
Unaffiliated	1,698.4			1,707.4			1,785.7
Intersegment	0.8			0.8			0.8
Total	1,699.2			1,708.2			1,786.5
Corporate and Other
Unaffiliated	0.8			0.7			1.0
Intersegment	468.1			517.6			510.8
Total	468.9			518.3			511.8
Eliminations	(482.0		)	(531.5		)	(525.8		)
Consolidated Operating Revenues	$	5,208.9		$	5,114.5		$	4,874.6

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Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

Year Ended December 31, (in millions)	2019			2018			2017
Operating Income (Loss)
Gas Distribution Operations	$	675.4		$	(254.1	)	$	550.1
Electric Operations	406.8			386.1			367.4
Corporate and Other(2)	(191.5		)	(7.3		)	3.7
Consolidated Operating Income	$	890.7		$	124.7		$	921.2
Depreciation and Amortization
Gas Distribution Operations	$	403.2		$	301.0		$	269.3
Electric Operations	277.3			262.9			277.8
Corporate and Other	36.9			35.7			23.2
Consolidated Depreciation and Amortization	$	717.4		$	599.6		$	570.3
Assets
Gas Distribution Operations	$	14,224.5		$	13,527.0		$	12,048.8
Electric Operations	6,027.6			5,735.2			5,478.6
Corporate and Other	2,407.7			2,541.8			2,434.3
Consolidated Assets	$	22,659.8		$	21,804.0		$	19,961.7
Capital Expenditures(1)
Gas Distribution Operations	$	1,380.3		$	1,315.3		$	1,125.6
Electric Operations	468.9			499.3			592.4
Corporate and Other	18.6			—			35.8
Consolidated Capital Expenditures	$	1,867.8		$	1,814.6		$	1,753.8

⁽¹⁾Amounts differ from those presented on the Statements of Consolidated Cash Flows primarily due to the inclusion of capital expenditures included in current liabilities and AFUDC Equity.

⁽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 6, "Goodwill and Other Intangible Assets."

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Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

24.     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)
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	)
2018
Operating Revenues	$	1,750.8		$	1,007.0		$	895.0		$	1,461.7
Operating Income (Loss)	400.6			118.4			(315.9		)	(78.4		)
Net Income (Loss)	276.1			24.5			(339.5		)	(11.7		)
Preferred Dividends	—			(1.3		)	(5.6		)	(8.1		)
Net Income (Loss) Available to Common Shareholders	276.1			23.2			(345.1		)	(19.8		)
Earnings (Loss) Per Share
Basic Earnings (Loss) Per Share	$	0.82		$	0.07		$	(0.95	)	$	(0.05	)
Diluted Earnings (Loss) Per Share	$	0.81		$	0.07		$	(0.95	)	$	(0.05	)

⁽¹⁾ 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 19-E, "Other Matters" for additional information.

⁽²⁾ 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 19-E, "Other Matters" for additional information.

⁽³⁾ Net loss for the third quarter of 2018 was impacted by approximately $462 million in expenses (pretax) related to the Greater Lawrence Incident restoration and a $33.0 million loss (pretax) on an early extinguishment of long-term debt. See Note 19-E, "Other Matters" and Note 14, "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 6, "Goodwill and Other Intangible Assets."

25.     Supplemental Cash Flow Information

The following table provides additional information regarding our Consolidated Statements of Cash Flows for the years ended December 31, 2019, 2018 and 2017:

Year Ended December 31, (in millions)	2019		2018		2017
Supplemental Disclosures of Cash Flow Information
Non-cash transactions:
Capital expenditures included in current liabilities	$	223.6	$	152.0	$	173.0
Assets acquired under a finance lease	26.4		54.6		11.5
Assets acquired under an operating lease	13.4		—		—
Reclassification of other property to regulatory assets(1)	—		245.3		—
Assets recorded for asset retirement obligations(2)	54.6		78.1		11.4
Schedule of interest and income taxes paid:
Cash paid for interest, net of interest capitalized amounts	$	349.7	$	354.2	$	339.9
Cash paid for income taxes, net of refunds	10.8		3.3		5.5

⁽¹⁾See Note 8 "Regulatory Matters" for additional information.

⁽²⁾See Note 7 "Asset Retirement Obligations" for additional information.

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Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

26.     Subsequent Event

On February 26, 2020, NiSource and Columbia of Massachusetts entered into the Asset Purchase Agreement with Eversource. 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 Eversource agreed to assume certain liabilities of Columbia of Massachusetts and its affiliates. The liabilities assumed by Eversource under the Asset Purchase Agreement do not include, among others, any liabilities arising out of the Greater Lawrence Incident or 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 occurs prior to the closing in connection with the Massachusetts Business. The Asset Purchase Agreement provides for a purchase price of $1,100 million in cash, subject to adjustment based on Columbia of Massachusetts’ net working capital as of the closing. The closing of the transactions contemplated by the Asset Purchase Agreement is subject to Hart-Scott Rodino Antitrust Improvements Act of 1976 and regulatory approvals, resolution of certain proceedings before governmental bodies and other conditions. The Massachusetts Business did not meet the requirements under GAAP to be classified as held-for-sale as of December 31, 2019. When the Massachusetts Business meets the requirements to be classified as held-for-sale, in each period leading up to the closing date of the transaction, the assets and liabilities of the Massachusetts Business will be measured at fair value, less costs to sell. The final pre-tax gain or loss on the transaction will be determined as of the closing date. Assuming the Massachusetts Business is classified as held-for-sale at March 31, 2020, we estimate that the total pre-tax loss to be measured in the quarter ended March 31, 2020 will be approximately $360 million, based on December 31, 2019 asset and liability balances and estimated transaction costs. This estimated pre-tax loss is subject to change based on estimated transaction costs, working capital adjustments and asset and liability balances at each measurement date leading up to the closing date. The sale is expected to close by September 30, 2020, subject to closing conditions.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

NISOURCE INC.

SCHEDULE II – VALUATION AND QUALIFYING ACCOUNTS

Twelve months ended December 31, 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
Twelve months ended December 31, 2017
			Additions
($ in millions)	Balance Jan. 1, 2017		Charged to Costs and Expenses		Charged to Other Account (1)		Deductions for Purposes for which Reserves were Created		Balance Dec. 31, 2017
Reserves Deducted in Consolidated Balance Sheet from Assets to Which They Apply:
Reserve for accounts receivable	$	23.3	$	14.8	$	39.1	$	58.9	$	18.3
Reserve for other investments	3.0		—		—		—		3.0

⁽¹⁾ Charged to Other Accounts reflects the deferral of bad debt expense to a regulatory asset.

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

None.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Our chief executive officer and chief financial officer are responsible for evaluating the effectiveness of disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)). Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by the Company in reports that are filed or submitted under the Exchange Act are accumulated and communicated to management, including our chief executive officer and chief financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon that evaluation, our chief executive officer and chief financial officer concluded that, as of the end of the period covered by this report, disclosure controls and procedures were effective to provide reasonable assurance that financial information was processed, recorded and reported accurately.

Management’s Annual Report on Internal Control over Financial Reporting

Our management, including our chief executive officer and chief financial officer, are responsible for establishing and maintaining internal control over financial reporting, as such term is defined under Rule 13a-15(f) or Rule 15d-15(f) promulgated under the Exchange Act. However, management would note that a control system can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Our management has adopted the 2013 framework set forth in the Committee of Sponsoring Organizations of the Treadway Commission report, Internal Control - Integrated Framework, the most commonly used and understood framework for evaluating internal control over financial reporting, as its framework for evaluating the reliability and effectiveness of internal control over financial reporting. During 2019, 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

NISOURCE INC.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the stockholders 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, 2019, 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, 2019, 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, 2019, of the Company and our report dated February 27, 2020, 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 27, 2020

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ITEM 9B. OTHER INFORMATION

NISOURCE INC.

Not applicable.

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NISOURCE INC.

PART III

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," and "Corporate Governance" of the Proxy Statement for the Annual Meeting of Stockholders to be held on May 19, 2020.

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 19, 2020.

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 19, 2020.

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 19, 2020.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

The information required by this Item 14 is incorporated herein by reference to the discussion in "Independent Auditor Fees" of the Proxy Statement for the Annual Meeting of Stockholders to be held on May 19, 2020.

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PART IV

NISOURCE INC.

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)	54
Statements of Consolidated Comprehensive Income (Loss)	55
Consolidated Balance Sheets	56
Statements of Consolidated Cash Flows	58
Statements of Consolidated Stockholders’ Equity	59
Notes to Consolidated Financial Statements	61
Schedule II	124

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).

129

(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).
(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).

130

(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. **
(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) *
(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).

131

(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)	Amended and Restated NiSource Inc. Supplemental Executive Retirement Plan effective August 10, 2017 (incorporated by reference to Exhibit 10.1 of the NiSource Inc. Form 10-Q filed on November 1, 2018).
(10.33)	Amended and Restated Pension Restoration Plan for NiSource Inc. and Affiliates effective August 10, 2017 (incorporated by reference to Exhibit 10.2 of the NiSource Inc. Form 10-Q filed on November 1, 2018).
(10.34)	Amended Restated Savings Restoration Plan for NiSource Inc. and Affiliates effective August 10, 2017 (incorporated by reference to Exhibit 10.3 of the NiSource Inc. Form 10-Q filed on November 1, 2018).
(10.35)	Form of 2019 Performance Share Award Agreement under the 2010 Omnibus Incentive Plan. (incorporated by reference to Exhibit 10.45 of the NiSource Inc. Form 10-K filed on February 20, 2019).
(10.36)	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).
(10.37)	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).

132

(10.38)	Amended and Restated Term Loan Agreement, dated as of April 17, 2019, among NiSource Inc., as Borrower, the Lenders party thereto, and MUFG Bank Ltd., as Administrative Agent and Sole Lead Arranger and Sole Bookrunner (incorporated by reference to Exhibit 10.1 of the NiSource Inc. Form 8-K filed on April 17, 2019).
(10.39)	Form of Performance Share Award Agreement* **
(10.40)	Form of Restricted Stock Unit Award Agreement* **
(10.41)	Form of Cash-Based Award Agreement* **
(10.42)	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).
(10.43)	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).
(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.

133

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 27, 2020	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 27, 2020
	Joseph Hamrock	Executive Officer and Director (Principal Executive Officer)
/s/	DONALD E. BROWN	Executive Vice President and	Date: February 27, 2020
	Donald E. Brown	Chief Financial Officer (Principal Financial Officer)
/s/	JOSEPH W. MULPAS	Vice President and	Date: February 27, 2020
	Joseph W. Mulpas	Chief Accounting Officer (Principal Accounting Officer)
/s/	KEVIN T. KABAT	Chairman and Director	Date: February 27, 2020
	Kevin T. Kabat
/s/	PETER A. ALTABEF	Director	Date: February 27, 2020
	Peter A. Altabef
/s/	THEODORE H. BUNTING, JR.	Director	Date: February 27, 2020
	Theodore H. Bunting, Jr.
/s/	ERIC L. BUTLER	Director	Date: February 27, 2020
	Eric L. Butler
/s/	ARISTIDES S. CANDRIS	Director	Date: February 27, 2020
	Aristides S. Candris
/s/	WAYNE S. DEVEYDT	Director	Date: February 27, 2020
	Wayne S. DeVeydt
/s/	DEBORAH A. HENRETTA	Director	Date: February 27, 2020
	Deborah A. Henretta
/s/	DEBORAH A.P. HERSMAN	Director	Date: February 27, 2020
	Deborah A. P. Hersman
/s/	MICHAEL E. JESANIS	Director	Date: February 27, 2020
	Michael E. Jesanis
/s/	CAROLYN Y. WOO	Director	Date: February 27, 2020
	Carolyn Y. Woo

134

EX-4.20

Exhibit 4.20

DESCRIPTION OF THE REGISTRANT’S SECURITIES

REGISTERED PURSUANT TO SECTION 12 OF THE

SECURITIES EXCHANGE ACT OF 1934

NiSource Inc. (“NiSource”) has two classes of securities registered under Section 12 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”):

(i) common stock, par value $0.01 per share (the “common stock”); and

(ii) depositary shares, each representing a 1/1,000^th ownership interest in a share of 6.50% Series B Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Stock (“Series B Preferred Stock”), par value $0.01 per share, liquidation preference $25,000 per share and a 1/1,000^th ownership interest in a share of Series B-1 Preferred Stock (“Series B-1 Preferred Stock”), par value $0.01 per share, liquidation preference $0.01 per share (the “Depositary Shares”).

The following is a summary description of the material terms of such securities. It may not contain all the information that is important to you. For additional information, you should refer to the provisions of our Amended and Restated Certificate of Incorporation (the “certificate of incorporation”) and our bylaws, as amended and restated (the “bylaws”), each of which is an exhibit to the Annual Report on Form 10-K to which this description is an exhibit and are incorporated herein by reference.

GENERAL

Authorized Capital Stock

The authorized capital stock of NiSource consists of 620,000,000 shares, of which 600,000,000 are common stock, par value $0.01, and 20,000,000 are preferred stock, par value $0.01. The board of directors of NiSource has designated (i) 400,000 shares of the preferred stock as 5.650% Series A Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Stock (“Series A Preferred Stock”), liquidation preference $1,000 per share, (ii) 20,000 shares of the preferred stock as Series B Preferred Stock, and (iii) 20,000 shares of the preferred stock as Series B-1 Preferred Stock. The shares of Series B Preferred Stock and Series B-1 Preferred Stock are represented by 20,000,000 Depositary Shares, each representing 1/1000th ownership interest in a share of each of the Series B Preferred Stock and the Series B-1 Preferred Stock.

The shares of Series A Preferred Stock are not registered pursuant to Section 12 of the Exchange Act and are not separately described below, but they are referenced as relevant when describing the other securities discussed herein.

Anti-Takeover Provisions

NiSource’s certificate of incorporation includes provisions that may have the effect of deterring hostile takeovers or delaying or preventing changes in control of management of NiSource. More specifically, the certificate of incorporation provides that stockholders may not cumulate their votes and stockholder action may be taken only at a duly called meeting and not by written consent. In addition, NiSource’s bylaws contain requirements for advance notice of stockholder proposals and director nominations. These and other provisions of the certificate of incorporation and bylaws and Delaware law could discourage potential acquisition proposals and could delay or prevent a change in control of management of NiSource.

Under Delaware law, the approval of the holders of a majority of the outstanding shares of a class of NiSource’s capital stock would be necessary to authorize any amendment to the certificate of incorporation that would increase or decrease the aggregate number of authorized shares of such class of capital stock or that would adversely alter or change the powers, preferences or special right of such class of capital stock. Further, pursuant to the certificates of designations for the Series A Preferred Stock, Series B Preferred Stock and Series B-1 Preferred Stock, the holders of two-thirds of any series of such preferred stock must approve certain amendments to the certificate of incorporation that would have a material adverse effect on the existing preferences, rights, powers, duties or obligations of such series of preferred stock. The effect of these provision may permit the holders of NiSource’s outstanding shares of capital stock to block a proposed amendment to the certificate of incorporation in connection with a potential acquisition of NiSource if such amendment would adversely affect the powers, preferences or special rights of such capital stock.

NiSource is subject to the provisions of Section 203 of the Delaware General Corporation Law regulating corporate takeovers. Section 203 prevents certain Delaware corporations, including those whose securities are listed on a national securities exchange, such as the New York Stock Exchange, from engaging, under certain circumstances, in a “business combination” (as defined therein), which includes, among other things, a merger or sale of more than 10% of the corporation’s assets, with any interested stockholder for three years following the date that the stockholder became an interested stockholder. An interested stockholder is a stockholder who acquired 15% or more of the corporation’s outstanding voting stock or an affiliate or associate of such person.

DESCRIPTION OF COMMON STOCK

Liquidation Rights

In the event of any liquidation, dissolution or winding up of NiSource, whether voluntary or involuntary, after payment or provision for payment of the debts and other liabilities of NiSource and the distribution in full of all preferential amounts (including any accumulated and unpaid dividends) to which the holders of the Series A Preferred Stock, Series B Preferred Stock, Series B-1 Preferred Stock and any other series of preferred stock of NiSource hereafter created are entitled, the holders of common stock will share ratably in the remaining assets in proportion to the number of shares of common stock held by them respectively. A consolidation or merger of NiSource with or into any other corporation, or any purchase or redemption of shares of any class of NiSource’s capital stock, will not be deemed to be a liquidation, dissolution or winding up of NiSource’s affairs.

Voting Rights

Except as otherwise required by Delaware law or as otherwise provided in the certificate of designations for the Series A Preferred Stock, Series B Preferred Stock, Series B-1 Preferred Stock or any other series of preferred stock of NiSource hereafter created, holders of NiSource’s common stock exclusively possess voting power for the election of NiSource’s directors and all other matters requiring stockholder action. Each holder of common stock, if entitled to vote on a matter, is entitled to one vote per share. Holders of common stock are not entitled to cumulative voting rights. Holders of common stock will be notified of any stockholders’ meeting according to applicable law.

Dividend Rights

Holders of common stock will be entitled to receive dividends, when, as and if declared by NiSource’s board of directors out of legally available funds for such purpose in accordance with Delaware law, subject to the powers, preferences and rights afforded to the holders of the Series A Preferred Stock, Series B Preferred Stock and any other series of preferred stock of NiSource hereafter created. Dividends may be paid in cash, capital stock or other property of NiSource.

NiSource is prohibited by the terms of each of its Series A Preferred Stock and its Series B Preferred Stock from declaring or paying dividends on any shares of NiSource’s common stock (other than dividends payable solely in shares of its common stock) or redeeming, repurchasing or acquiring shares of its common stock unless full cumulative dividends have been paid with respect to the Series A Preferred Stock and the Series B Preferred Stock, respectively, through the most recently completed respective dividend periods.

NiSource is an energy holding company that derives substantially all of its revenues and earnings from the operating results of the rate-regulated businesses of its subsidiaries. Accordingly, NiSource’s ability to pay dividends on its capital stock is dependent primarily upon the earnings and cash flows of its subsidiaries and the distribution or other payment of such earnings to NiSource. NiSource’s subsidiaries are separate and distinct legal entities and have no obligation, contingent or otherwise, to pay any amounts on the capital stock of NiSource or to make any funds available therefor, whether by dividends, loans or other payments.

No Preemptive Rights

Holders of NiSource’s common stock are not entitled to, as holders of common stock, any preemptive rights with respect to any shares of NiSource’s capital stock or any of its securities convertible into or exercisable for its capital stock.

SERIES B PREFERRED STOCK

Ranking

The Series B Preferred Stock ranks, with respect to dividends and distributions upon liquidation: (i) senior to NiSource’s common stock and any other class or series of capital stock that does not expressly provide that it ranks on a parity with or senior to the Series B Preferred Stock with respect to dividends and such distributions (the “Series B Junior Securities”); (ii) on a parity with the Series A Preferred Stock, the Series B-1 Preferred Stock (except with respect to dividends) and any other class or series of capital stock that does not expressly provide that it ranks junior or senior to the Series B Preferred Stock with respect to dividends and such distributions (the “Series B Parity Securities”); and (iii) junior to any class or series of capital stock that expressly provides that it ranks senior to the Series B Preferred Stock with respect to dividends and such distributions (the “Series B Senior Securities”).

Liquidation Rights

In the event of any liquidation, the holders of the Series B Preferred Stock are entitled to receive out of NiSource’s assets available for distribution to stockholders (subject to the rights of holders of Series B Senior Securities and Series B Parity Securities in respect of distributions upon the liquidation) before any distribution of assets is made to holders of Series B Junior Securities, a liquidation preference of $25,000 per share. Any accumulated and unpaid dividends on the Series B Preferred Stock and Series B Parity Securities will be paid prior to any distributions in liquidation. A consolidation or merger of NiSource with or into any other entity will not be deemed to be a liquidation.

Voting Rights

The Series B Preferred Stock has no voting, consent or approval rights except as set forth below or as otherwise provided by Delaware law. On any matter described below in which the holders of the Series B Preferred Stock are entitled to vote as a class (whether separately or together with the holders of any Series B Parity Securities), such holders will be entitled to twenty-five votes per share. The Series B Preferred Stock is paired with the Series B-1 Preferred Stock and the holders of the Series B-1 Preferred Stock are entitled to the voting rights described below under the heading “-Series B-1 Preferred Stock-Voting Rights.”

Adverse Changes. Unless NiSource has received the affirmative vote or consent of the holders of at least two-thirds of the outstanding shares of Series B Preferred Stock, voting as a single class, no amendment to the certificate of incorporation may be adopted that would have a material adverse effect on the existing preferences, rights, powers, duties or obligations of the Series B Preferred Stock. However, such voting requirement shall not be implicated by any amendment to the certificate of incorporation (i) relating to the issuance of additional shares of preferred stock (subject to the voting rights discussed in the following paragraph) and (ii) in connection with a merger or another transaction in which either the Series B Preferred Stock remains outstanding or is exchanged for a series of preferred stock of the surviving entity, in either case, with the terms thereof materially unchanged in any respect adverse to the holders of Series B Preferred Stock.

Parity and Senior Preferred Stock. Unless NiSource has received the affirmative vote or consent of the holders of at least two-thirds of the outstanding shares of Series B Preferred Stock, voting as a class together with holders of the Series A Preferred Stock and any other Series B Parity Securities and upon which like voting rights have been conferred and are exercisable, NiSource may not: (i) create or issue any Series B Parity Securities (including any additional shares of Series A Preferred Stock or Series B Preferred Stock, but excluding any payments-in-kind on such shares) if the cumulative dividends payable on the outstanding shares of Series B Preferred Stock (or Series B Parity Securities, if applicable) are in arrears; or (ii) create or issue any Series B Senior Securities.

Dividends

Holders of Series B Preferred Stock will be entitled to receive, when, as and if declared by NiSource’s board of directors out of legally available funds for such purpose, cumulative quarterly cash dividends (subject to the dividend rights of any Series B Parity Securities or Series B Senior Securities) at an initial rate of 6.50% per annum of the $25,000 liquidation preference per share (equal to $1,625 per share per annum). On and after March 15, 2024, dividends will accumulate for each five-year period thereafter according to a formula based on the rate of certain U.S. Treasury securities with a five year maturity plus the applicable margin.

NiSource is prohibited by the terms of the Series B Preferred Stock from declaring or paying dividends on any Series B Junior Securities (other than a dividend payable solely in such Series B Junior Securities) or redeeming, repurchasing or acquiring shares of any Series B Junior Securities unless full cumulative dividends have been paid on all outstanding shares of Series B Preferred Stock and any Series B Parity Securities entitled to dividends through the most recently completed respective dividend periods. In addition, NiSource may not repurchase, redeem or otherwise acquire any shares of Series A Preferred Stock or Series A Parity Securities, unless (i) effected pursuant to a purchase or exchange offer made on the same

relative terms to all holders of such shares of preferred stock or (ii) (A) full cumulative dividends have been paid or provided for on all outstanding shares of such preferred stock entitled to dividends through the most recently completed respective dividend periods and (B) NiSource expects to have sufficient funds to pay in full the next dividend on all such outstanding shares of preferred stock.

Redemption

NiSource may redeem the Series B Preferred Stock, at its option, in whole or in part, on March 15, 2024 or on any fifth anniversary thereafter by paying $25,000 per share plus an amount equal to all accumulated and unpaid dividends thereon to, but not including, the redemption date, whether or not declared. In addition, following the occurrence of a “Ratings Event” (as defined in the certificate of designations of the Series B Preferred Stock), NiSource may, at its option, redeem the Series B Preferred Stock in whole, but not in part, at a redemption price equal to $25,500 per share (102% of the liquidation preference) plus an amount equal to all accumulated and unpaid dividends thereon to the redemption date, whether or not declared.

No Conversion or Preemptive Rights

The Series B Preferred Stock is not convertible into any other class of NiSource’s capital stock and the holders of the Series B Preferred Stock do not, as holders of Series B Preferred Stock, have any preemptive rights with respect to any shares of NiSource’s capital stock or any of its securities convertible into or exercisable for its capital stock.

SERIES B-1 PREFERRED STOCK

The Series B-1 Preferred Stock was issued as a distribution with respect to the Series B Preferred Stock in order to enhance the voting rights of the Series B Preferred Stock to comply with the New York Stock Exchange’s minimum voting rights policy. The Series B-1 Preferred Stock is paired with the Series B Preferred Stock and may not be transferred, redeemed or repurchased except in connection with the simultaneous transfer, redemption or repurchase of the underlying Series B Preferred Stock, and upon the transfer, redemption or repurchase of the underlying Series B Preferred Stock, the same number of shares of Series B-1 Preferred Stock must simultaneously be transferred (to the same transferee), redeemed or repurchased, as the case may be. A summary of certain powers, preferences, rights, qualifications, limitations and restrictions of the Series B-1 Preferred Stock are set forth below.

Ranking

The Series B-1 Preferred Stock ranks, with respect to distributions upon liquidation: (i) senior to NiSource’s common stock and any other class or series of capital stock that does not expressly provide that it ranks on a parity with or senior to the Series B-1 Preferred Stock with respect to such distributions (the “Series B-1 Junior Securities”); (ii) on a parity with the Series A Preferred Stock, the Series B Preferred Stock and any other class or series of capital stock that does not expressly provide that it ranks junior or senior to the Series B-1 Preferred Stock with respect to such distributions (the “Series B-1 Parity Securities”); and (iii) junior to any class or series of capital stock that expressly provides that it ranks senior to the Series B-1 Preferred Stock with respect to such distributions (the “Series B-1 Senior Securities”).

Liquidation Rights

In the event of any liquidation, the holders of the Series B-1 Preferred Stock are entitled to receive out of NiSource’s assets available for distribution to stockholders (subject to the rights of holders of Series B-1 Senior Securities and Series B-1 Parity Securities in respect of distributions upon liquidation), before any distribution of assets is made to holders of Series B-1 Junior Securities, a liquidation preference of $0.01 per share. Any accumulated and unpaid dividends on the Series B-1 Parity Securities will be paid prior to any distributions in liquidation. A consolidation or merger of NiSource with or into any other entity will not be deemed to be a liquidation.

Voting Rights

The Series B-1 Preferred Stock has no voting, consent or approval rights except as set forth below or as otherwise provided by Delaware law. On any matter described below in which the holders of the Series B-1 Preferred Stock are entitled to vote as a class (whether separately or together with the holders of any Series B-1 Parity Securities), such holders will be entitled to twenty-five votes per share.

Adverse Changes. Unless NiSource has received the affirmative vote or consent of the holders of at least two-thirds of the outstanding shares of Series B-1 Preferred Stock, voting as a single class, no amendment to the certificate of incorporation may be adopted that would have a material adverse effect on the existing preferences, rights, powers, duties or obligations of the Series B-1 Preferred Stock. However, such voting requirement shall not be implicated by any amendment to the certificate of incorporation (i) relating to the issuance of additional shares of preferred stock and (ii) in connection with a merger or another transaction in which either the Series B-1 Preferred Stock remains outstanding or is exchanged for a series of preferred stock of the surviving entity, in either case, with the terms thereof materially unchanged in any respect adverse to the holders of Series B-1 Preferred Stock.

Election of Directors upon Nonpayment Events. 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 (a “Nonpayment Event”), the number of directors then constituting NiSource’s board of directors will automatically be increased by two and the holders of Series B-1 Preferred Stock, voting as a class together with the holders of any outstanding Series B-1 Parity Securities having like voting rights that are exercisable at that time (“Director Voting Preferred Stock”), shall be entitled to elect the two additional directors (the “Preferred Stock Directors”), provided that (i) such election does not violate the corporate governance requirements of the New York Stock Exchange that companies must have a majority of independent directors and (ii) such director is not prohibited or disqualified from serving as a director of NiSource by any applicable law. The Preferred Stock Directors shall each be entitled to one vote per director on any matter before NiSource’s board of directors for a vote.

When all accumulated and unpaid dividends on the Series B Preferred Stock have been paid in full, then (a) the right of the holders of Series B-1 Preferred Stock to elect the Preferred Stock Directors shall cease, (b) the terms of office of the Preferred Stock Directors will automatically terminate and (c) the number of directors constituting NiSource’s board of directors will automatically decrease by two. Any Preferred Stock Director may be removed at any time without cause by holders of a majority of the outstanding shares of the Series B-1 Preferred Stock and Director Voting Preferred Stock (voting together as a single class). So long as a Nonpayment Event continues, any vacancy in the office of a Preferred Stock Director (after the initial election of Preferred Stock Directors) may be filled by the written consent of the Preferred Stock Director remaining in office (if any), in lieu of a vote by the Series B-1 Preferred Stock and Voting Preferred Stock (voting together as a single class).

Dividends

Holders of Series B-1 Preferred Stock are not entitled to receive dividends.

Redemption

The shares of Series B-1 Preferred Stock are subject to mandatory redemption, in whole or in part, at a redemption price of $0.01 per share upon the redemption of the underlying shares of Series B Preferred Stock with which such shares of Series B-1 Preferred Stock are paired. The shares of Series B-1 Preferred Stock are not otherwise subject to redemption.

No Conversion or Preemptive Rights

The Series B-1 Preferred Stock is not convertible into any other class of NiSource’s capital stock and the holders of the Series B-1 Preferred Stock do not, as holders of Series B-1 Preferred Stock, have any preemptive rights with respect to any shares of NiSource’s capital stock or any of its securities convertible into or exercisable for its capital stock.

DEPOSITARY SHARES REPRESENTING

SERIES B PREFERRED STOCK AND SERIES B-1 PREFERRED STOCK

General

Each Depositary Share represents a 1/1,000th ownership interest in a share of the Series B Preferred Stock and a 1/1,000th ownership interest in a share of the Series B-1 Preferred Stock. The Depositary Shares are evidenced by depositary receipts issued pursuant to a deposit agreement (the “Deposit Agreement”) among NiSource, Computershare Inc. and Computershare Trust Company, N.A., acting jointly as the depositary (the “depositary”), and the holders from time to time of the depositary receipts evidencing the Depositary Shares. This description of the Depositary Shares is qualified in its entirety by the provisions of the respective certificates of designations of the Series B Preferred Stock and Series B-1 Preferred Stock and the Deposit Agreement, each of which is an exhibit to the Annual Report on Form 10-K to which this description is an exhibit and are incorporated herein by reference.

Dividends and Other Distributions

The depositary will distribute any cash dividends or other cash distributions received in respect of the deposited Series B Preferred Stock and Series B-1 Preferred Stock to the record holders of Depositary Shares relating to the underlying Series B Preferred Stock and Series B-1 Preferred Stock in proportion to the number of Depositary Shares held by the holders. The depositary will distribute any property received by it other than cash to the record holders of Depositary Shares entitled to those distributions, unless it determines, in consultation with NiSource, that the distribution cannot be made proportionally among those holders or that it is not feasible to make a distribution. In that event, the depositary may, with NiSource’s approval, sell the property (at a public or private sale) and distribute the net proceeds from the sale to the holders of the Depositary Shares in proportion to the number of Depositary Shares they hold.

Redemption of Depositary Shares

If NiSource redeems the Series B Preferred Stock and Series B-1 Preferred Stock represented by the Depositary Shares, a proportionate number of Depositary Shares will be redeemed from the proceeds received by the depositary resulting from the redemption of the Series B Preferred Stock and Series B-1 Preferred Stock held by the depositary. The redemption price per depositary share will be equal to 1/1,000th of the redemption price per share payable with respect to each of the Series B Preferred Stock and Series B-1 Preferred Stock. Whenever NiSource redeems shares of Series B Preferred Stock and Series B-1 Preferred Stock held by the depositary, the depositary will redeem, as of the same redemption date, the number of Depositary Shares representing shares of Series B Preferred Stock and Series B-1 Preferred Stock so redeemed.

Voting the Preferred Stock

When the depositary receives notice of any meeting at which the holders of the Series B Preferred Stock and/or Series B-1 Preferred Stock are entitled to vote, the depositary will mail, or otherwise transmit by an authorized method, the information contained in the notice to the record holders of the Depositary Shares. Each record holder of the Depositary Shares on the record date, which will be the same date as the record date for the Series B Preferred Stock and/or Series B-1 Preferred Stock, may instruct the depositary to vote the amount of the Series B Preferred Stock and/or Series B-1 Preferred Stock entitled to vote represented by the holder’s Depositary Shares. To the extent practicable, the depositary will vote the number of shares entitled to vote represented by such Depositary Shares in accordance with the instructions it receives. If the depositary does not receive specific instructions from the holders of any Depositary Shares representing the Series B Preferred Stock and/or Series B-1 Preferred Stock entitled to vote, it will abstain from voting the number of shares of Series B Preferred Stock and/or Series B-1 Preferred Stock represented thereby.

Amendment and Termination of the Depositary Agreement

The form of depositary receipt evidencing the Depositary Shares and any provision of the Depositary Agreement may be amended by agreement between the depositary and NiSource. However, any amendment that materially and adversely alters the rights of the holders of Depositary Shares will not be effective unless such amendment has been approved by the holders of at least a majority of the Depositary Shares then outstanding. The Depositary Agreement may be terminated by NiSource upon sixty days’ prior written notice to the depositary or by the depositary upon mailing notice to NiSource and the holders of all Depositary Shares then outstanding if at any time sixty days have expired after the depositary provided written notice to NiSource of its resignation and a successor depositary has not been appointed. The Depositary Agreement shall automatically terminate after there has been a final distribution in respect of the Series B Preferred Stock and Series B-1 Preferred Stock in connection with NiSource’s liquidation, dissolution or winding and such distribution has been distributed to the holders of Depositary Shares.

EX-10.39

Exhibit 10.39

NiSource Inc.

20__ Omnibus Incentive Plan

20__ Performance Share Award Agreement

This Performance Share Award Agreement (the “Agreement”) is made and entered into as of _______________ (the “Grant Date”), by and between NiSource Inc., a Delaware corporation (the “Company”), and __________________ an Employee of the Company (the “Grantee”), pursuant to the terms of the NiSource Inc. 20__ Omnibus Incentive Plan, as amended (the “Plan”). Any term capitalized but not defined in this Agreement shall have the meaning set forth in the Plan.

Section 1.Performance Share Award. The Company hereby grants to the Grantee, on the terms and conditions hereinafter set forth, a target award of ______________Performance Shares (the “Performance Shares”). The Performance Shares shall be represented by a bookkeeping entry with respect to the Grantee (the “Performance Share Account”), and each Performance Share shall be settled in one Share, to the extent provided under this Agreement and the Plan. This Agreement and the award shall be null and void unless the Grantee accepts this Agreement electronically within the Grantee’s stock plan account with the Company’s stock plan administrator according to the procedures then in effect.

Section 2.Performance-Based Vesting Conditions.

(a) General. Subject to the remainder of this Agreement, the Performance Shares shall vest pursuant to the terms of this Agreement and the Plan based on the achievement of the performance goals set forth in this Section 2 over the performance period beginning on _________________ and ending on _________________ (the “Performance Period”), provided (i) that that the Grantee remains in continuous Service through _________________ (the “Vesting Date”) and (ii) the Company achieves the threshold cumulative NOEPS goal set forth in Section 2(b). Attainment of the performance goals shall be determined and certified by the Compensation Committee of the Board of Directors of the Company (the “Committee”) prior to the settlement of the Performance Shares.

(b) Financial Performance Goal. Subject to the terms of this Agreement and the Plan, _________________shall be eligible to vest based on the Company’s achievement of cumulative NOEPS during the Performance Period, as follows:

Performance Level(1)	Cumulative NOEPS	Percentage of Performance Shares that Shall Vest(2)
Threshold	$________	____________
Target	$________	____________
Maximum	$_______and above	____________

(1) The vesting percentage for performance between performance levels shall be determined based on linear interpolation.

(2) The number of Performance Shares that shall vest based on the Company’s cumulative NOEPS performance shall be subject to a performance modifier of +/- 25% based on the Company’s RTSR over the Performance Period, with such Performance Shares (i) increasing by 25% if the Company’s RTSR is in the top quartile of the TSR Peer Group, (ii) decreasing by 25% if the Company’s RTSR is in the bottom quartile of the TSR Peer Group, and (iii) remaining the same if the Company’s RTSR is in the second or third quartiles of the TSR Peer Group. No other adjustment shall be made based on the Company’s RTSR.

(c) [Insert Secondary] Performance Goals. Subject to the terms of this Agreement and the Plan and provided the Company’s threshold cumulative NOEPS goal is met, _________________shall be

eligible to vest based on the achievement of the [Insert Secondary Performance] Goals set forth below, with each goal equally weighted:

Performance Measure Goal(1)

(1)If the Company fails to achieve the applicable performance goal, then the Performance Shares allocated to such performance goal shall not be eligible to vest.

(d) Definitions.

(i) “cumulative NOEPS” means the Company’s cumulative net operating earnings per share, as reported in the Company’s annual financial statements. Additional adjustments to cumulative net operating earnings per share shall be made to the targets and results for: (x) transactions that the Company discloses on Form 8-K filed with the Securities and Exchange Commission, including merger, acquisition, divestiture, consolidation or corporate restructuring, any recapitalization, reorganization, spin-off, split-up, combination, liquidation, dissolution, sale of assets or similar corporate transactions that meet disclosure thresholds; and (y) pending transactions as a result of requirements to present operations as “held for sale” under Accounting Standard Codification 205.

(ii)

(iii) “RTSR” means the annualized growth in the dividends and share price of a Share, calculated using a 20 day trading average of the Company’s closing price beginning on __________________ and ending ________________ compared to the TSR performance of the TSR Peer Group. The starting and ending share prices for the computation of RTSR will equal the average closing price of each company’s common stock over the 20 trading days immediately preceding the first and last day of the performance period.

(iv) “TSR Peer Group” means the peer group of companies determined by the Committee at its meeting on _________________.

Section 3.Termination of Employment.

(a) Termination of Service Prior to Vesting Date. Except as set forth below, if the Grantee’s Service is terminated for any reason prior to the Vesting Date, then the Grantee shall forfeit the Performance Shares credited to the Grantee’s Performance Share Account.

(b) Retirement, Disability or Death.

(i) Notwithstanding the foregoing, in the event that the Grantee’s Service terminates prior to the Vesting Date as a result of the Grantee’s (i) Retirement, (ii) Disability, or (iii) death and such death occurs with less than or equal to twelve months remaining in the Performance Period, then the Grantee (or the Grantee’s beneficiary or estate in the case of the Grantee’s death) shall vest in a pro rata portion of the Performance Shares, based on the actual performance results for the Performance Period. Such pro rata portion of the Performance Shares shall be determined by multiplying the number of Performance Shares earned based on actual performance by a fraction, where the numerator shall equal the number of calendar months (including partial calendar months) that have elapsed from the Grant Date through the date of the Grantee’s termination of Service,

and the denominator shall be the number of calendar months (including partial calendar months) that have elapsed between the Grant Date and the Vesting Date.

(ii) If the Grantee terminates Service due to death prior to the Vesting Date and with more than 12 months remaining in the Performance Period, then the Grantee’s beneficiary or estate shall vest, on the date of termination, in a pro rata portion of the target Performance Shares. Such pro rata portion of the Performance Shares shall be determined by multiplying the number of target Performance Shares by a fraction, where the numerator shall equal the number of calendar months (including partial calendar months) that have elapsed from the Grant Date through the date of the Grantee’s termination of Service, and the denominator shall be the number of calendar months (including partial calendar months) that have elapsed between the Grant Date and the Vesting Date.

(iii) “Retirement” means the Grantee’s termination from Service at or after attainment of age 55 and completing at least ten years of service (within the meaning of the Company’s tax-qualified pension plan as in effect on the Grant Date, regardless of whether the Grantee is eligible for such plan).

(c) Change in Control. Notwithstanding the foregoing provisions, in the event of a Change in Control, the Performance Shares under this Agreement shall be subject to the Change in Control provisions set forth in the Plan. In the event of any conflict between the Plan and this Agreement, the Plan shall control. Notwithstanding any other agreement between the Company and the Grantee, the “Good Reason” definition set forth in the Plan shall govern this award.

Section 4.Delivery of Shares. Subject to the terms of this Agreement and except as otherwise provided for herein, the Company shall convert the Performance Shares in the Grantee’s Performance Share Account into Shares and issue or deliver the total number of Shares due to the Grantee within 60 days following the Vesting Date (but in any event no later than the March 15th immediately following the year in which the substantial risk of forfeiture with respect to the Performance Shares lapses) or, if earlier, within 30 days following (a) the Grantee’s death in accordance with Section 3(b)(ii), (b) Grantee’s termination of Service without Cause or due to Good Reason in accordance with the Change in Control provisions of the Plan or (c) a Change in Control in the event the Performance Shares do not become Alternative Awards under the Plan. The delivery of the Shares shall be subject to payment of the applicable withholding tax liability and the forfeiture provisions of this Agreement. If the Grantee dies before the Company has issued or distributed the vested Performance Shares, the Company shall transfer any Shares with respect to the vested Performance Shares in accordance with the Grantee’s written beneficiary designation or to the Grantee’s estate if no written beneficiary designation is provided. The issuance or deliver of the Shares hereunder shall be evidenced by the appropriate entry on the books of the Company or of a duly authorized transfer agent of the Company. The Company shall pay all original issue or transfer taxes and all fees and expenses incident to such issuance or delivery, except as otherwise provided in Section 5.

Section 5.Withholding of Taxes. As a condition precedent to the delivery to Grantee of any Shares upon vesting of the Performance Shares, Grantee shall, upon request by the Company, pay to the Company such amount of cash as the Company may be required, under all applicable federal, state, local or other laws or regulations, to withhold and pay over as income or other withholding taxes (the “Required Tax Payments”) with respect to the Performance Shares. If Grantee shall fail to advance the Required Tax Payments after request by the Company, the Company may, in its discretion, deduct any Required Tax Payments from any amount then or thereafter payable by the Company to Grantee or withhold Shares. Grantee may elect to satisfy his or her obligation to advance the Required Tax Payments by any of the following means: (a) a cash payment to the Company; (b) delivery to the Company (either actual delivery or by attestation procedures established by the Company) of previously owned whole Shares having a Fair Market Value, determined as

of the date the obligation to withhold or pay taxes first arises in connection with the Performance Shares (the “Tax Date”), equal to the Required Tax Payments; (c) authorizing the Company to withhold from the Shares otherwise to be delivered to Grantee upon the vesting of the Performance Shares, a number of whole Shares having a Fair Market Value, determined as of the Tax Date, equal to the Required Tax Payments; or (d) any combination of (a), (b) and (c). Shares to be delivered or withheld may not have a Fair Market Value in excess of the minimum amount of the Required Tax Payments. Any fraction of a Share which would be required to satisfy such an obligation shall be disregarded and the remaining amount due shall be paid in cash by Grantee. No Shares shall be delivered until the Required Tax Payments have been satisfied in full.

Section 6.Compliance with Applicable Law. Notwithstanding anything contained herein to the contrary, the Company’s obligation to issue or deliver certificates evidencing the Performance Shares shall be subject to all applicable laws, rules and regulations, and to such approvals by any governmental agencies or national securities exchanges as may be required. The delivery of all or any Shares that relate to the Performance Shares shall be effective only at such time that the issuance of such Shares shall not violate any state or federal securities or other laws. The Company is under no obligation to effect any registration of Shares under the Securities Act of 1933 or to effect any state registration or qualification of the Shares that may be issued under this Agreement. Subject to Section 409A of the Code (the “Section 409A”), the Company may, in its sole discretion, delay the delivery of Shares or place restrictive legends on Shares in order to ensure that the issuance of any Shares shall be in compliance with federal or state securities laws and the rules of any exchange upon which the Company’s Shares are traded. If the Company delays the delivery of Shares in order to ensure compliance with any state or federal securities or other laws, the Company shall deliver the Shares at the earliest date at which the Company reasonably believes that such delivery shall not cause such violation, or at such later date that may be permitted under Section 409A.

Section 7.Restriction on Transferability. Except as otherwise provided under the Plan, until the Performance Shares have vested under this Agreement, the Performance Shares granted herein and the rights and privileges conferred hereby may not be sold, transferred, pledged, assigned, or otherwise alienated or hypothecated (by operation of law or otherwise), other than by will or the laws of descent and distribution. Any attempted transfer in violation of the provisions of this paragraph shall be void, and the purported transferee shall obtain no rights with respect to such Performance Shares.

Section 8.Grantee’s Rights Unsecured. The right of the Grantee or his or her beneficiary to receive a distribution hereunder shall be an unsecured claim against the general assets of the Company, and neither the Grantee nor his or her beneficiary shall have any rights in or against any amounts credited to the Grantee’s Performance Share Account, any Shares or any other specific assets of the Company. All amounts credited to the Grantee’s Performance Share Account shall constitute general assets of the Company and may be disposed of by the Company at such time and for such purposes as it may deem appropriate.

Section 9.No Rights as Stockholder or Employee. The Grantee shall not have any privileges of a stockholder of the Company (including, without limitation, any voting rights or rights to receive dividends) with respect to the Performance Shares subject to this Agreement. Furthermore, nothing in this Agreement shall confer upon the Grantee any right to continue as an Employee of the Company or any Affiliate or to interfere in any way with the right of the Company or any Affiliate to terminate the Grantee’s Service at any time.

Section 10. Adjustments. If at any time while the award is outstanding, the number of outstanding Performance Shares is changed by reason of a reorganization, recapitalization, stock split or any of the other events described in the Plan, the number and kind of Performance Shares and the performance goals, as applicable, shall be adjusted in accordance with the provisions of the Plan.

Section 11. Notices. Any notice hereunder by the Grantee shall be given to the Company in writing, and such notice shall be deemed duly given only upon receipt thereof at the following address: Corporate Secretary, NiSource Inc., 801 East 86th Avenue, Merrillville, IN 46410-6271 (or at such other address as the Company may designate by notice to the Grantee). Any notice hereunder by the Company shall be given to the Grantee in writing, and such notice shall be deemed duly given only upon receipt thereof at such address as the Grantee may have on file with the Company.

Section 12. Administration. The administration of this Agreement, including the interpretation and amendment or termination of this Agreement, shall be performed in accordance with the Plan. All determinations and decisions made by the Committee, the Board, or any delegate of the Committee as to the provisions of this Agreement shall be conclusive, final, and binding on all persons. Notwithstanding the foregoing, if subsequent guidance is issued under Section 409A that would impose additional taxes, penalties, or interest to either the Company or the Grantee, the Company may administer this Agreement in accordance with such guidance and amend this Agreement without the consent of the Grantee to the extent such actions, in the reasonable judgment of the Company, are considered necessary to avoid the imposition of such additional taxes, penalties, or interest.

Section 13. Governing Law. This Agreement shall be construed and enforced in accordance with the laws of the State of Indiana, without giving effect to the choice of law principles thereof.

Section 14. Entire Agreement; Agreement Subject to Plan. This Agreement and the Plan contain all of the terms and conditions with respect to the subject matter hereof and supersede any previous agreements, written or oral, relating to the subject matter hereof. This Agreement is subject to the provisions of the Plan and shall be interpreted in accordance therewith. In the event that the provisions of this Agreement and the Plan conflict, the Plan shall control. The Grantee hereby acknowledges receipt of a copy of the Plan.

Section 15. Section 409A Compliance. This Agreement and the Performance Shares granted hereunder are intended to be exempt from Section 409A to the maximum extent possible, and shall be interpreted and construed accordingly.

[SIGNATURE PAGE TO FOLLOW]

IN WITNESS WHEREOF, the Company has caused the Performance Shares subject to this Agreement to be granted, and the Grantee has accepted the Performance Shares subject to the terms of the Agreement, as of the date first above written.

NiSource Inc.

____________________________________________

By: _________________

Its: _________________

GRANTEE

By: _________________________________________

_________________

EX-10.40

Exhibit 10.40

NiSource Inc.

20__ Omnibus Incentive Plan

20__ Restricted Stock Unit Award Agreement

This Restricted Stock Unit Award Agreement (the “Agreement”), is made and entered into as of [________] (the “Date of Grant”), by and between NiSource Inc., a Delaware corporation (the “Company”), and [________], an Employee of the Company (the “Grantee”).

Section 1.  Restricted Stock Unit Award. The Company hereby grants to the Grantee, on the terms and conditions hereinafter set forth, an Award of [________] Restricted Stock Units. The Restricted Stock Units will be represented by a bookkeeping entry (the “RSU Account”) of the Company, and each Restricted Stock Unit shall be equivalent to one share of the Company’s common stock.

Section 2. Grantee Accounts. The number of Restricted Stock Units granted pursuant to this Agreement shall be credited to the Grantee’s RSU Account. Each RSU Account shall be maintained on the books of the Company until full payment of the balance thereof has been made to the Grantee (or the Grantee’s beneficiaries or estate if the Grantee is deceased) in accordance with Section 1 above. No funds shall be set aside or earmarked for any RSU Account, which shall be purely a bookkeeping device.

Section 3.  Vesting and Lapse of Restrictions.

(a) Vesting. Subject to the forfeiture conditions described later in this Agreement, the Restricted Stock Units shall vest [________] (the “Vesting Date”), at which date they shall become 100% vested, provided that the Grantee is continuously employed by the Company through and including the Vesting Date. Except as set forth in subsection (b) hereof, if Grantee’s Service is terminated for any reason prior to the Vesting Date, the unvested Restricted Stock Units subject to this Agreement shall immediately terminate and be automatically forfeited by Grantee.

(b) Effect of Termination of Service Prior to Vesting. Notwithstanding the foregoing, in the event that the Grantee’s Service terminates prior to the Vesting Date as a result of (i) the Grantee’s Retirement, (ii) the Grantee’s death, or (iii) the Grantee’s Disability, the restrictions set forth in subsection (a) above shall lapse with respect to a pro rata portion of such Restricted Stock Units on the date of termination of Service. Such pro rata lapse of restrictions shall be determined using a fraction, where the numerator shall be the number of full or partial calendar months elapsed between the Date of Grant and the date the Grantee terminates Service, and the denominator shall be the number of full or partial calendar months between the Date of Grant and the Vesting Date. For purposes of this Agreement, “Retirement” means the Grantee’s termination from Service with the Company at or after attainment of age 55 and completing 10 years of service (within the meaning of the Company’s tax-qualified pension plan in effect on the Date of Grant, regardless of whether the Grantee is eligible for such plan).

(c) Change in Control. Notwithstanding the foregoing provisions, in the event of a Change in Control, the Restricted Stock Units under this Agreement shall be subject to the Change in Control provisions set forth in the Plan. In the event of any conflict between the Plan and this Agreement, the Plan shall control. Notwithstanding the foregoing or anything herein to the contrary, in the event the Restricted Stock Units do not become Alternative Awards under

the Plan, then the Restricted Stock Units shall be settled within 60 days following the Change in Control; provided, however, in the event the Restricted Stock Units constitute nonqualified deferred compensation subject to Code Section 409A and the Change in Control is not a “change in control event” within the meaning of Code Section 409A, then, to the extent required to comply with Code Section 409A, the vested Restricted Stock Units shall be settled within 60 days following the Vesting Date or, if earlier and subject to Section 4, upon Grantee’s termination of Service.

Section 4. Delivery of Shares. Once Restricted Stock Units have vested under this Agreement, the Company will determine the number of Shares represented by the vested Restricted Stock Units in the Grantee’s RSU Account and deliver the total number of Shares due to the Grantee within 60 days following the Vesting Date or, if earlier, Grantee’s termination of Service in accordance with Section 3(b). Notwithstanding the foregoing, to the extent any portion of the Restricted Stock Units are subject to Code Section 409A, if any Restricted Stock Units vest prior to the Vesting Date in connection with a Grantee’s “separation from service” within the meaning of Code Section 409A and the Grantee is a “specified employee” within the meaning of Code Section 409A at the time of such separation from service, the Shares represented by the vested Restricted Stock Units shall be issued and delivered on the first business day after the date that is six (6) months following the date of the Grantee’s separation from service (or if earlier, the Grantee’s date of death). The delivery of the Shares shall be subject to payment of the applicable withholding tax liability and the forfeiture provisions of this Agreement. If the Grantee dies before the Company has distributed any portion of the vested Restricted Stock Units, the Company will transfer any Shares payable with respect to the vested Restricted Stock Units in accordance with the Grantee’s written beneficiary designation or to the Grantee’s estate if no written beneficiary designation is provided.

Section 5.  Withholding of Taxes. The Company shall have the power and the right to deduct or withhold, or require the Grantee to remit to the Company, an amount sufficient to satisfy federal, state, and local taxes, domestic or foreign, required by law or regulation to be withheld with respect to any taxable event arising as a result of this Agreement.

Section 6. Securities Law Compliance. The delivery of all or any Shares that relate to the Restricted Stock Units shall only be effective at such time that the issuance of such Shares will not violate any state or federal securities or other laws. The Company is under no obligation to effect any registration of Shares under the Securities Act of 1933 or to effect any state registration or qualification of the Shares that may be issued under this Agreement. The Company may, in its sole discretion, delay the delivery of Shares or place restrictive legends on Shares in order to ensure that the issuance of any Shares will be in compliance with federal or state securities laws and the rules of any exchange upon which the Shares are then traded. If the Company delays the delivery of Shares in order to ensure compliance with any state or federal securities or other laws, the Company shall deliver the Shares at the earliest date at which the Company reasonably believes that such delivery will not cause such violation, or at such later date that may be permitted under Code Section 409A.

Section 7. Restriction on Transferability. Except as otherwise provided under the Plan, until the Restricted Stock Units have vested under this Agreement, the Restricted Stock Units granted herein and the rights and privileges conferred hereby may not be sold, transferred, pledged, assigned, or otherwise alienated or hypothecated (by operation of law or otherwise), other than by will or the laws of descent and distribution. Any attempted transfer in violation of the provisions of this paragraph shall be void, and the purported transferee shall obtain no rights with respect to such Restricted Stock Units.

Section 8. Grantee’s Rights Unsecured. The right of the Grantee or his or her beneficiary to receive a distribution hereunder shall be an unsecured claim against the general assets of the Company, and neither

the Grantee nor his or her beneficiary shall have any rights in or against any amounts credited to the Grantee’s RSU Account or any other specific assets of the Company. All amounts credited to the Grantee’s RSU Account shall constitute general assets of the Company and may be disposed of by the Company at such time and for such purposes, as it may deem appropriate.

Section 9.  No Rights as Stockholder or Employee.

(a) Unless and until Shares have been issued to the Grantee, the Grantee shall not have any privileges of a stockholder of the Company with respect to any Restricted Stock Units subject to this Agreement, nor shall the Company have any obligation to issue any dividends or otherwise afford any rights to which Shares are entitled with respect to any such Restricted Stock Units.

(b) Nothing in this Agreement or the Award shall confer upon the Grantee any right to continue as an Employee of the Company or any Affiliate or to interfere in any way with the right of the Company or any Affiliate to terminate the Grantee’s Service at any time.

Section 10.  Adjustments. If at any time while the Award is outstanding, the number of outstanding Restricted Stock Units is changed by reason of a reorganization, recapitalization, stock split or any of the other events described in the Plan, the number and kind of Restricted Stock Units shall be adjusted in accordance with the provisions of the Plan. In the event of certain corporate events specified in the Change in Control provisions of the Plan, any unvested Restricted Stock Units may be replaced by substituted Awards or forfeited in exchange for payment of cash in accordance with the Change in Control procedures and provisions of the Plan.

Section 11.  Notices. Any notice hereunder by the Grantee shall be given to the Company in writing and such notice shall be deemed duly given only upon receipt thereof at the following address: Corporate Secretary, NiSource Inc., 801 East 86^th Avenue, Merrillville, IN 46410-6271, or at such other address as the Company may designate by notice to the Grantee. Any notice hereunder by the Company shall be given to the Grantee in writing and such notice shall be deemed duly given only upon receipt thereof at such address as the Grantee may have on file with the Company.

Section 12.  Administration. The administration of this Agreement, including the interpretation and amendment or termination of this Agreement, will be performed in accordance with the Plan. All determinations and decisions made by the Committee, the Board, or any delegate of the Committee as to the provisions of this Agreement shall be conclusive, final, and binding on all persons. This Agreement at all times shall be governed by the Plan, which is incorporated in this Agreement by reference, and in no way alter or modify the Plan. All capitalized terms used in this Agreement and not defined herein shall have the meaning set forth in the Plan. To the extent a conflict exists between this Agreement and the Plan, the provisions of the Plan shall govern. Notwithstanding the foregoing, if subsequent guidance is issued under Code Section 409A that would impose additional taxes, penalties, or interest to either the Company or the Grantee, the Company may administer this Agreement in accordance with such guidance and amend this Agreement without the consent of the Grantee to the extent such actions, in the reasonable judgment of the Company, are considered necessary to avoid the imposition of such additional taxes, penalties, or interest.

Section 13. Governing Law. This Agreement shall be construed and enforced in accordance with the laws of the State of Indiana, without giving effect to the choice of law principles thereof.

Section 14. Government Regulations. Notwithstanding anything contained herein to the contrary, the Company’s obligation to issue or deliver certificates evidencing the Restricted Stock Units shall be subject

to all applicable laws, rules and regulations, and to such approvals by any governmental agencies or national securities exchanges as may be required.

Section 15. Entire Agreement; Code Section 409A Compliance. This Agreement and the Plan contain the terms and conditions with respect to the subject matter hereof and supersede any previous agreements, written or oral, relating to the subject matter hereof. This Agreement is pursuant to the terms of the Company’s 20__ Omnibus Incentive Plan (the “Plan”). The applicable terms of the Plan are incorporated herein by reference, including the definition of capitalized terms contained in the Plan, and including the Code Section 409A provisions of the Plan. This Agreement shall be interpreted in accordance with Code Section 409A including the rules related to payment timing for “specified employees” within the meaning of Code Section 409A. This Agreement shall be deemed to be modified to the maximum extent necessary to be in compliance with Code Section 409A’s rules. If the Grantee is unexpectedly required to include in the Grantee’s current year’s income any amount of compensation relating to the Restricted Stock Units because of a failure to meet the requirements of Code Section 409A, then to the extent permitted by Code Section 409A, the Grantee may receive a distribution of cash or Shares in an amount not to exceed the amount required to be included in income as a result of the failure to comply with Code Section 409A.

[SIGNATURE PAGE TO FOLLOW]

IN WITNESS WHEREOF, the Company has caused this Award to be granted, and the Grantee has accepted this Award, as of the date first above written.

NiSource Inc.

____________________________________________

By:

Its:

GRANTEE

By:   _____________________

EX-10.41

Exhibit 10.41

NiSource Inc.

20__ Omnibus Incentive Plan

20__ Cash Based Award Agreement

This Cash-Based Award Agreement (the “Agreement”), is made and entered into as of _____ 20__ (the “Date of Grant”), by and between NiSource Inc., a Delaware corporation (the “Company”), and ___________, an Employee of the Company (the “Grantee”).

Section 1.  Cash-Based Award. The Company hereby grants to the Grantee, on the terms and conditions hereinafter set forth, an Award of $__________________as a Cash-Based Award. The Cash-Based Award may be recorded as a bookkeeping entry (the “Cash-Based Account”) of the Company.

Section 2. Grantee Accounts. If determined to be desirable by the Company, the amount of the Cash-Based Award pursuant to this Agreement will be credited to the Grantee’s Cash-Based Account and each Cash-Based Account will be maintained on the books of the Company until full payment of the balance thereof has been made to the Grantee (or the Grantee’s beneficiaries or estate if the Grantee is deceased) in accordance with Section 1 above. No funds shall be set aside or earmarked for any Cash-Based Account, which, if utilized, shall be purely a bookkeeping device.

Section 3.  Vesting and Lapse of Restrictions.

(a) Vesting. Subject to the forfeiture conditions described later in this Agreement, the Cash-Based Award shall vest as set forth on Schedule A, attached hereto, provided that the Grantee is continuously employed by the Company through and including the vesting dates as described on Schedule A. Except as set forth in subsection (b) hereof, if Grantee’s Service is terminated for any reason prior to the applicable Vesting Date(s) (as defined on Schedule A), any unvested portion of the Cash-Based Award subject to this Agreement shall immediately terminate and be automatically forfeited by Grantee.

(b) Effect of Termination of Service Prior to Vesting. Notwithstanding the foregoing, in the event that the Grantee’s Service terminates prior to the Vesting Date as a result of (i) the Grantee’s death or (ii) the Grantee’s Disability, any remaining vesting conditions set forth in subsection (a) above shall lapse with respect to a pro rata portion of any remaining unvested portion of such Cash-Based Award on the date of termination of Service. Such pro rata lapse of the remaining vesting conditions shall be determined using a fraction, where the numerator shall be the number of full or partial calendar months elapsed between the Date of Grant and the date the Grantee terminates Service, and the denominator shall be the number of full or partial calendar months between the Date of Grant and the final Vesting Date. In addition, notwithstanding the foregoing, in the event that the Grantee’s Service terminates prior to the Vesting Date as a result of the termination of the Grantee’s Service by the Company without Cause, any remaining vesting conditions set forth in subsection (a) above shall lapse with respect to one-hundred percent (100%) of any remaining unvested portion of such Cash-Based Award on the date of termination of Service.

(c) Change in Control. Notwithstanding the foregoing provisions, in the event of a Change in Control, the Cash-Based Award under this Agreement shall be subject to the Change in Control

Provisions set forth in the Plan. In the event of any conflict between the Plan and this Agreement, the Plan shall control.

Section 4. Payment of Cash Amount. Once the Cash-Based Award has vested under this Agreement, the Company will deliver the total amount in the Cash-Based Account of the Grantee, without interest or any other appreciation factor, within 60 days following the Vesting Date, or if earlier, the Grantee’s termination of service in accordance with Section 3(b). Notwithstanding the foregoing, to the extent any portion of the Cash-Based Award is subject to Code Section 409A, if any portion of the Cash-Based Award vests prior to the Vesting Date in connection with a Grantee’s “separation from service” within the meaning of Code Section 409A and the Grantee is a “specified employee” within the meaning of Code Section 409A at the time of such separation from service, that portion of the Cash-Based Award will be paid on the first business day after the date that is six (6) months following the date of the Grantee’s separation from service (or if earlier, the Grantee’s date of death). The payment of the Cash-Based Award shall be subject to payment of the applicable withholding tax liability and the forfeiture provisions of this Agreement. If the Grantee dies before the Company has distributed any portion of the vested Cash-Based Award, the Company will transfer any amount payable with respect to the vested Cash-Based Award in accordance with the Grantee’s written beneficiary designation or to the Grantee’s estate if no written beneficiary designation is provided.

Section 5.  Withholding of Taxes. The Company shall have the power and the right to deduct or withhold, or require the Grantee to remit to the Company, an amount sufficient to satisfy federal, state, and local taxes, domestic or foreign, required by law or regulation to be withheld with respect to any taxable event arising as a result of this Agreement.

Section 6. Restriction on Transferability. Except as otherwise provided under the Plan, until the Cash-Based Award has vested under this Agreement, the right to the value of the Cash-Based Award granted herein and the rights and privileges conferred hereby may not be sold, transferred, pledged, assigned, or otherwise alienated or hypothecated (by operation of law or otherwise), other than by will or the laws of descent and distribution. Any attempted transfer in violation of the provisions of this paragraph shall be void, and the purported transferee shall obtain no rights with respect to such Cash-Based Award.

Section 7. Grantee’s Rights Unsecured. The right of the Grantee or his or her beneficiary to receive a distribution hereunder shall be an unsecured claim against the general assets of the Company, and neither the Grantee nor his or her beneficiary shall have any rights in or against any amounts credited to the Grantee’s Cash-Based Account or any other specific assets of the Company. All amounts credited to the Grantee’s Cash-Based Account shall constitute general assets of the Company and may be disposed of by the Company at such time and for such purposes, as it may deem appropriate.

Section 8.  No Rights as Employee. Nothing in this Agreement or the Award shall confer upon the Grantee any right to continue as an Employee of the Company or any Affiliate or to interfere in any way with the right of the Company or any Affiliate to terminate the Grantee’s Service at any time.

Section 9.  Notices. Any notice hereunder by the Grantee shall be given to the Company in writing and such notice shall be deemed duly given only upon receipt thereof at the following address: Corporate Secretary, NiSource Inc., 801 East 86^th Avenue, Merrillville, IN 46410-6271, or at such other address as the Company may designate by notice to the Grantee. Any notice hereunder by the Company shall be given to the Grantee in writing and such notice shall be deemed duly given only upon receipt thereof at such address as the Grantee may have on file with the Company.

Section 10.  Administration. The administration of this Agreement, including the interpretation and amendment or termination of this Agreement, will be performed in accordance with the Plan. All

determinations and decisions made by the Committee, the Board, or any delegate of the Committee as to the provisions of this Agreement shall be conclusive, final, and binding on all persons. This Agreement at all times shall be governed by the Plan, which is incorporated in this Agreement by reference, and in no way alter or modify the Plan. All capitalized terms used in this Agreement and not defined herein shall have the meaning set forth in the Plan. To the extent a conflict exists between this Agreement and the Plan, the provisions of the Plan shall govern. Notwithstanding the foregoing, if subsequent guidance is issued under Code Section 409A that would impose additional taxes, penalties, or interest to either the Company or the Grantee, the Company may administer this Agreement in accordance with such guidance and amend this Agreement without the consent of the Grantee to the extent such actions, in the reasonable judgment of the Company, are considered necessary to avoid the imposition of such additional taxes, penalties, or interest.

Section 11. Governing Law. This Agreement shall be construed and enforced in accordance with the laws of the State of Indiana, without giving effect to the choice of law principles thereof.

Section 12. Government Regulations. Notwithstanding anything contained herein to the contrary, the Company’s obligation to issue or deliver certificates evidencing the Restricted Stock Units shall be subject to all applicable laws, rules and regulations, and to such approvals by any governmental agencies or national securities exchanges as may be required.

Section 13. Entire Agreement; Code Section 409A Compliance. This Agreement and the Plan contain the terms and conditions with respect to the subject matter hereof and supersede any previous agreements, written or oral, relating to the subject matter hereof. This Agreement is pursuant to the terms of the Company’s 20__ Omnibus Incentive Plan, as amended (the “Plan”). The applicable terms of the Plan are incorporated herein by reference, including the definition of capitalized terms contained in the Plan, and including the Code Section 409A provisions of the Plan. This Agreement shall be interpreted in accordance with Code Section 409A including the rules related to payment timing for “specified employees” within the meaning of Code Section 409A. This Agreement shall be deemed to be modified to the maximum extent necessary to be in compliance with Code Section 409A’s rules. If the Grantee is unexpectedly required to include in the Grantee’s current year’s income any amount of compensation relating to the Cash-Based Award because of a failure to meet the requirements of Code Section 409A, then to the extent permitted by Code Section 409A, the Grantee may receive a distribution of cash in an amount not to exceed the amount required to be included in income as a result of the failure to comply with Code Section 409A.

[SIGNATURE PAGE TO FOLLOW]

IN WITNESS WHEREOF, the Company has caused this Award to be granted, and the Grantee has accepted this Award, as of the date first above written.

NiSource Inc.

By:

Its:

GRANTEE

By: ____________________________________________

[____________]

SCHEDULE A

EX-21

Exhibit 21

SUBSIDIARIES OF NISOURCE

as of December 31, 2019

Segment/Subsidiary GAS DISTRIBUTION OPERATIONS	State of Incorporation
Bay State Gas Company d/b/a Columbia Gas of Massachusetts	Massachusetts
Central Kentucky Transmission Company	Delaware
Columbia Gas of Kentucky, Inc.	Kentucky
Columbia Gas of Maryland, Inc.	Delaware
Columbia Gas of Ohio, Inc.	Ohio
Columbia Gas of Pennsylvania, Inc.	Pennsylvania
Columbia Gas of Virginia, Inc.	Virginia
NiSource Gas Distribution Group, Inc.	Delaware
ELECTRIC OPERATIONS
Northern Indiana Public Service Company LLC*	Indiana
CORPORATE AND OTHER OPERATIONS
Columbia Gas of Ohio Receivables Corporation	Delaware
Columbia Gas of Pennsylvania Receivables Corporation	Delaware
Indiana Crossroads Wind Generation LLC	Indiana
NIPSCO Accounts Receivable Corporation	Indiana
NiSource Corporate Group, LLC	Delaware
NiSource Corporate Services Company	Delaware
NiSource Development Company, Inc.	Indiana
NiSource Energy Technologies, Inc.	Indiana
NiSource Strategic Sourcing Inc.	Ohio
NiSource Insurance Corporation, Inc.	Utah
Lake Erie Land Company	Indiana
RoseWater Wind Generation LLC	Indiana
NiSource Retail Services, Inc.	Delaware (Inactive)
EnergyUSA-TPC, Inc.	Indiana (Inactive)

* Reported under Gas Distribution Operations and Electric Operations.

EX-23

Exhibit 23

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement No. 333-234422 on Form S-3, Registration Statement Nos. 333-107743, 333-166888, 333-204168, and 333-233382 on Form S-8, and Registration Statement Nos. 333-228790 and 333-228791 on Form S-4of our reports dated February 27, 2020, relating to the financial statements of NiSource Inc. and subsidiaries (the “Company”) and the effectiveness of the Company’s internal control over financial reporting appearing in this Annual Report on Form 10-K for the year ended December 31, 2019.

/s/ DELOITTE & TOUCHE LLP

Columbus, Ohio

February 27, 2020

EX-31.1

Exhibit 31.1

Certification Pursuant to

Section 302 of the Sarbanes-Oxley Act of 2002

I, Joseph Hamrock, certify that:

1. I have reviewed this Annual Report on Form 10-K of NiSource Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	February 27, 2020	By:	/s/ Joseph Hamrock
			Joseph Hamrock
			President and Chief Executive Officer

EX-31.2

Exhibit 31.2

Certification Pursuant to

Section 302 of the Sarbanes-Oxley Act of 2002

I, Donald E. Brown, certify that:

1. I have reviewed this Annual Report on Form 10-K of NiSource Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	February 27, 2020	By:	/s/ Donald E. Brown
			Donald E. Brown
			Executive Vice President and Chief Financial Officer

EX-32.1

Exhibit 32.1

Certification Pursuant to

Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the Annual Report of NiSource Inc. (the “Company”) on Form 10-K for the year ending December 31, 2019 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Joseph Hamrock, Chief Executive Officer of the Company, certify, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Company.

/s/ Joseph Hamrock

Joseph Hamrock

President and Chief Executive Officer

Date:                     February 27, 2020

EX-32.2

Exhibit 32.2

Certification Pursuant to

Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the Annual Report of NiSource Inc. (the “Company”) on Form 10-K for the year ending December 31, 2019 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Donald E. Brown, Executive Vice President and Chief Financial Officer of the Company, certify, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Company.

/s/ Donald E. Brown

Donald E. Brown

Executive Vice President and Chief Financial Officer

Date:             February 27, 2020

XML

Equity

12 Months Ended

Dec. 31, 2019

Equity [Abstract]

Equity

Equity

We raise equity financing through a variety of programs including traditional common equity issuances and preferred stock issuances. As of December 31, 2019, we had 600,000,000 shares of common stock and 20,000,000 shares of preferred stock authorized for issuance, of which 382,135,680 shares of common stock and 440,000 shares of preferred stock are currently outstanding.

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 paid quarterly common dividends totaling $0.80, $0.78, and $0.70 per share for the years ended December 31, 2019, 2018 and 2017, respectively. Our Board declared a quarterly common dividend of $0.21 per share, payable on February 20, 2020 to holders of record on February 11, 2020. 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 14, "Long-Term Debt," for more information. As of December 31, 2019, 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 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 2019, 2018 and 2017 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 separate 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.

As of December 31, 2019, the ATM program had approximately $200.7 million of equity available for issuance. The program expires on December 31, 2020.

The following table summarizes our activity under the ATM program:

Year Ending December 31,	2019		2018		2017
Number of shares issued	8,422,498		8,883,014		11,931,376
Average price per share	$	27.75	$	26.85	$	26.58
Proceeds, net of fees (in millions)	$	229.1	$	232.5	$	314.7

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 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.

Proceeds from the issuance of the Series A Preferred Stock were used to pay a portion of the notes tendered in June 2018 and the redemption of the remaining notes in July 2018. See Note 14, “Long-term Debt” for additional information regarding the tender offer and redemption.

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, 2019 and 2018, 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, 2019 and 2018, Series B Preferred Stock had $1.4 million and $2.4 million, respectively, of cumulative preferred dividends in arrears, or $72.23 and $121.88 per share, respectively.

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 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,
				2019		2018		2017		2019		2018
(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	$	28.88	$	—	$	393.9	$	393.9
6.500% Series B	$	25,000.00	20,000	$	1,674.65	$	—	$	—	$	486.1	$	486.1

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Leases

12 Months Ended

Dec. 31, 2019

Leases [Abstract]

Leases

Leases

ASC 842 Adoption. In February 2016, the FASB issued ASU 2016-02, Leases (ASC 842). ASU 2016-02 introduces a lessee model that brings most leases onto the balance sheet. The standard requires that lessees recognize the following for all leases (with the exception of short-term leases, as that term is defined in the standard) at the lease commencement date: (1) a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and (2) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. In 2018, the FASB issued ASU 2018-01, Leases (ASC 842): Land Easement Practical Expedient for Transition to ASC 842, which allows us to not evaluate existing land easements under ASC 842, and ASU 2018-11, Leases (ASC 842): Targeted Improvements, which allows calendar year entities to initially apply ASC 842 prospectively from January 1, 2019.

We adopted the provisions of ASC 842 beginning on January 1, 2019, using the transition method provided in ASU 2018-11, which was applied to all existing leases at that date. As such, results for reporting periods beginning after January 1, 2019 will be presented under ASC 842, while prior period amounts will continue to be reported in accordance with ASC 840. We elected a number of practical expedients, including the "practical expedient package" described in ASC 842-10-65-1 and the provisions of ASU 2018-01, which allows us to not evaluate existing land easements under ASC 842. Further, ASC 842 provides lessees the option of electing an accounting policy, by class of underlying asset, in which the lessee may choose not to separate nonlease components from lease components. We elected this practical expedient for our leases of fleet vehicles, IT assets and railcars. We elected to use a practical expedient that allows the use of hindsight in determining lease terms when evaluating leases that existed at the implementation date. We also elected the short-term lease recognition exemption, allowing us to not recognize ROU assets or lease liabilities for all leases that qualify.

Adoption of the new 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 24 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 3 years with options to renew for 1 year. Our fleet vehicles include trucks, trailers and equipment that have been customized specifically for use in the utility industry. We lease fleet vehicles 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 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 year ended 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	2019
Finance lease cost
Amortization of right-of-use assets	Depreciation and amortization	$	15.5
Interest on lease liabilities	Interest expense, net	11.3
Total finance lease cost		26.8
Operating lease cost	Operation and maintenance	17.9
Short-term lease cost	Operation and maintenance	1.0
Total lease cost		$	45.7

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

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

Other pertinent information related to leases was as follows:

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

	December 31, 2019
Weighted-average remaining lease term (years)
Finance leases	14.8
Operating leases	9.2
Weighted-average discount rate
Finance leases	5.9	%
Operating leases	4.3	%

Maturities of our lease liabilities presented on a rolling 12-month basis were as follows:

As of December 31, 2019, (in millions)	Total			Finance Leases			Operating Leases
Year 1	$	42.8		$	27.2		$	15.6
Year 2	36.7			27.3			9.4
Year 3	35.0			26.8			8.2
Year 4	30.7			23.1			7.6
Year 5	26.5			19.9			6.6
Thereafter	233.3			201.6			31.7
Total lease payments(1)	405.0			325.9			79.1
Less: Imputed interest	(116.6		)	(102.3		)	(14.3		)
Less: Leases not yet commenced	(22.1		)	(22.1		)	—
Total	266.3			201.5			64.8
Reported as of December 31, 2019
Short-term lease liabilities	26.6			13.4			13.2
Long-term lease liabilities	239.7			188.1			51.6
Total lease liabilities	$	266.3		$	201.5		$	64.8

⁽¹⁾ Expected payments include obligations for leases not yet commenced of approximately $22.1 million for IT assets and interconnection facilities. These leases have terms between 4 years and 20 years, with estimated commencements in the first quarter of 2020 and in the third quarter of 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 $49.5 million in 2017, and are primarily charged to operation and maintenance expense as incurred.

As of December 31, 2018, total contractual obligations for capital and operating leases were as follows:

As of December 31, 2018, (in millions)	Total		Capital Leases(1)		Operating Leases(2)
2019	$	34.0	$	23.0	$	11.0
2020	29.8		22.5		7.3
2021	28.7		22.6		6.1
2022	26.3		22.1		4.2
2023	22.6		19.8		2.8
Thereafter	226.9		212.4		14.5
Total lease payments	$	368.3	$	322.4	$	45.9

⁽¹⁾Capital lease payments shown above are inclusive of interest totaling $114.6 million.

⁽²⁾Operating lease balances do not include obligations for possible fleet vehicle lease renewals beyond the initial lease term. While we have the ability to renew these leases beyond the initial term, we are not reasonably certain to do so. Expected payments are $26.7 million in 2019, $22.4 million in 2020, $16.6 million in 2021, $12.3 million in 2022, $9.3 million in 2023 and $8.8 million thereafter.

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Quarterly Financial Data (Tables)

12 Months Ended

Dec. 31, 2019

Quarterly Financial Data [Abstract]

Schedule Of Quarterly Financial Data

(in millions, except per share data)	First Quarter(1)			Second Quarter(2)			Third    Quarter(3)			Fourth Quarter(4)
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	)
2018
Operating Revenues	$	1,750.8		$	1,007.0		$	895.0		$	1,461.7
Operating Income (Loss)	400.6			118.4			(315.9		)	(78.4		)
Net Income (Loss)	276.1			24.5			(339.5		)	(11.7		)
Preferred Dividends	—			(1.3		)	(5.6		)	(8.1		)
Net Income (Loss) Available to Common Shareholders	276.1			23.2			(345.1		)	(19.8		)
Earnings (Loss) Per Share
Basic Earnings (Loss) Per Share	$	0.82		$	0.07		$	(0.95	)	$	(0.05	)
Diluted Earnings (Loss) Per Share	$	0.81		$	0.07		$	(0.95	)	$	(0.05	)

⁽¹⁾ 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 19-E, "Other Matters" for additional information.

⁽²⁾ 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 19-E, "Other Matters" for additional information.

⁽³⁾ Net loss for the third quarter of 2018 was impacted by approximately $462 million in expenses (pretax) related to the Greater Lawrence Incident restoration and a $33.0 million loss (pretax) on an early extinguishment of long-term debt. See Note 19-E, "Other Matters" and Note 14, "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 6, "Goodwill and Other Intangible Assets."

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Pension and Other Postretirement Benefits (Schedule Of Fair Value Of Pension Plan Assets) (Details) - USD ($) $ in Millions		Dec. 31, 2019		Dec. 31, 2018		Dec. 31, 2017
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		$ 2,342.3		$ 2,084.1
Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		436.3		538.6
Significant Other Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		968.6		692.3
Significant Unobservable Inputs (Level 3) [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		0.0		86.1		$ 98.9
Due To Brokers Net [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		(2.8)	[1]	(1.1)	[2]
Due To Brokers Net [Member] | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[1]	0.0
Due To Brokers Net [Member] | Significant Other Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[1]	(2.8)
Due To Brokers Net [Member] | Significant Unobservable Inputs (Level 3) [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[1]	0.0
Accrued Investment Income Dividends [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount				8.6
Receivables/Payables [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		10.7
Receivables/Payables [Member] | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		10.7
Receivables/Payables [Member] | Significant Other Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		0.0
Receivables/Payables [Member] | Significant Unobservable Inputs (Level 3) [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		0.0
Private Equity Limited Partnerships [Member] | U.S. Multi-Strategy [Member] | Significant Unobservable Inputs (Level 3) [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		0.0		18.5		26.7
Private Equity Limited Partnerships [Member] | International Multi-Strategy [Member] | Significant Unobservable Inputs (Level 3) [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		0.0		12.5		19.1
Private Equity Limited Partnerships [Member] | Distressed Opportunities [Member] | Significant Unobservable Inputs (Level 3) [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		0.0		2.4		3.2
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Accumulated Benefit Obligation		2,111.5		1,965.6
Defined Benefit Plan, Plan Assets, Amount		2,080.9		1,867.7		2,160.0
Defined Benefit Plan Fair Value Of Plan Assets Before Pending Items		2,073.0		1,860.3
Defined Benefit Plan, Benefit Obligation		2,130.5		1,981.3	[3]	2,192.6	[3]
Defined Benefit Plan, Funded (Unfunded) Status of Plan		(49.6)		(113.6)
Pension Plan | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan Fair Value Of Plan Assets Before Pending Items		204.1		329.3
Pension Plan | Significant Other Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan Fair Value Of Plan Assets Before Pending Items		971.4		693.4
Pension Plan | Significant Unobservable Inputs (Level 3) [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan Fair Value Of Plan Assets Before Pending Items		0.0		86.1
Pension Plan | Cash [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		6.7		9.2
Pension Plan | Cash [Member] | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		6.7		8.8
Pension Plan | Cash [Member] | Significant Other Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		0.0		0.4
Pension Plan | Cash [Member] | Significant Unobservable Inputs (Level 3) [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		0.0		0.0
Pension Plan | International Equities
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		205.0		165.5
Pension Plan | Fixed Income
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		1,337.2		1,241.9
Pension Plan | Equity Securities [Member] | United States Equities
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount				0.2
Pension Plan | Equity Securities [Member] | United States Equities | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount				0.2
Pension Plan | Equity Securities [Member] | United States Equities | Significant Other Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount				0.0
Pension Plan | Equity Securities [Member] | United States Equities | Significant Unobservable Inputs (Level 3) [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount				0.0
Pension Plan | Fixed Income Securities [Member] | Government
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		319.6		250.2
Pension Plan | Fixed Income Securities [Member] | Government | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		0.0		0.0
Pension Plan | Fixed Income Securities [Member] | Government | Significant Other Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		319.6		250.2
Pension Plan | Fixed Income Securities [Member] | Government | Significant Unobservable Inputs (Level 3) [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		0.0		0.0
Pension Plan | Fixed Income Securities [Member] | Corporate [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		651.8		442.8
Pension Plan | Fixed Income Securities [Member] | Corporate [Member] | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		0.0		0.0
Pension Plan | Fixed Income Securities [Member] | Corporate [Member] | Significant Other Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		651.8		442.8
Pension Plan | Fixed Income Securities [Member] | Corporate [Member] | Significant Unobservable Inputs (Level 3) [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		0.0		0.0
Pension Plan | Commingled Funds | International Equities
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		148.1	[4]	122.3	[5]
Pension Plan | Commingled Funds | Fixed Income
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		351.8	[4]	365.7	[5]
Pension Plan | Commingled Funds | United States Equities
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		305.9	[4]	245.2	[5]
Pension Plan | Commingled Funds | Short-Term Money Markets
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		14.8	[4]	18.3	[5]
Pension Plan | Private Equity Limited Partnerships [Member] | U.S. Multi-Strategy [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		14.0	[6]	18.5	[7]
Pension Plan | Private Equity Limited Partnerships [Member] | U.S. Multi-Strategy [Member] | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		0.0	[6]	0.0	[7]
Pension Plan | Private Equity Limited Partnerships [Member] | U.S. Multi-Strategy [Member] | Significant Other Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		0.0	[6]	0.0	[7]
Pension Plan | Private Equity Limited Partnerships [Member] | U.S. Multi-Strategy [Member] | Significant Unobservable Inputs (Level 3) [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		0.0	[6]	18.5	[7]
Pension Plan | Private Equity Limited Partnerships [Member] | International Multi-Strategy [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		8.5	[8]	12.5	[9]
Pension Plan | Private Equity Limited Partnerships [Member] | International Multi-Strategy [Member] | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		0.0	[8]	0.0	[9]
Pension Plan | Private Equity Limited Partnerships [Member] | International Multi-Strategy [Member] | Significant Other Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		0.0	[8]	0.0	[9]
Pension Plan | Private Equity Limited Partnerships [Member] | International Multi-Strategy [Member] | Significant Unobservable Inputs (Level 3) [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		0.0	[8]	12.5	[9]
Pension Plan | Private Equity Limited Partnerships [Member] | Distressed Opportunities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		0.5		2.4
Pension Plan | Private Equity Limited Partnerships [Member] | Distressed Opportunities [Member] | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		0.0		0.0
Pension Plan | Private Equity Limited Partnerships [Member] | Distressed Opportunities [Member] | Significant Other Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		0.0		0.0
Pension Plan | Private Equity Limited Partnerships [Member] | Distressed Opportunities [Member] | Significant Unobservable Inputs (Level 3) [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		0.0		2.4
Pension Plan | Real Estate [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		53.9		52.7
Pension Plan | Real Estate [Member] | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		0.0		0.0
Pension Plan | Real Estate [Member] | Significant Other Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		0.0		0.0
Pension Plan | Real Estate [Member] | Significant Unobservable Inputs (Level 3) [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		0.0		52.7
Pension Plan | Mutual Funds [Member] | International Equities
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		56.9		43.2
Pension Plan | Mutual Funds [Member] | International Equities | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		56.9		43.2
Pension Plan | Mutual Funds [Member] | U.S. Multi-Strategy [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		140.5		110.3
Pension Plan | Mutual Funds [Member] | U.S. Multi-Strategy [Member] | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		140.5		110.3
Pension Plan | Mutual Funds [Member] | Fixed Income
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount				166.8
Pension Plan | Mutual Funds [Member] | Fixed Income | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount				166.8
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		261.4		216.3		262.5
Defined Benefit Plan Fair Value Of Plan Assets Before Pending Items		261.4		216.3
Defined Benefit Plan, Benefit Obligation		576.5		492.5	[3]	$ 556.3	[3]
Defined Benefit Plan, Funded (Unfunded) Status of Plan		(315.1)		(276.2)
Other Postretirement Benefits | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount				200.7
Defined Benefit Plan Fair Value Of Plan Assets Before Pending Items		221.5
Other Postretirement Benefits | Significant Other Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount				0.0
Defined Benefit Plan Fair Value Of Plan Assets Before Pending Items		0.0
Other Postretirement Benefits | Significant Unobservable Inputs (Level 3) [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount				0.0
Defined Benefit Plan Fair Value Of Plan Assets Before Pending Items		0.0
Other Postretirement Benefits | International Equities
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		40.7		17.5
Other Postretirement Benefits | Fixed Income
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		119.5		115.1
Other Postretirement Benefits | Commingled Funds | International Equities
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[4]	20.1
Other Postretirement Benefits | Commingled Funds | United States Equities
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		12.1	[4]	10.4	[5]
Other Postretirement Benefits | Commingled Funds | Short-Term Money Markets
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		7.7	[4]	5.2	[5]
Other Postretirement Benefits | Mutual Funds [Member] | International Equities
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		20.6		17.5
Other Postretirement Benefits | Mutual Funds [Member] | International Equities | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		20.6		17.5
Other Postretirement Benefits | Mutual Funds [Member] | International Equities | Significant Other Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		0.0		0.0
Other Postretirement Benefits | Mutual Funds [Member] | International Equities | Significant Unobservable Inputs (Level 3) [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		0.0		0.0
Other Postretirement Benefits | Mutual Funds [Member] | Fixed Income
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		119.2		114.8
Other Postretirement Benefits | Mutual Funds [Member] | Fixed Income | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		119.2		114.8
Other Postretirement Benefits | Mutual Funds [Member] | Fixed Income | Significant Other Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		0.0		0.0
Other Postretirement Benefits | Mutual Funds [Member] | Fixed Income | Significant Unobservable Inputs (Level 3) [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		0.0		0.0
Other Postretirement Benefits | Mutual Funds [Member] | United States Equities
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		81.7		68.4
Other Postretirement Benefits | Mutual Funds [Member] | United States Equities | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		81.7		68.4
Other Postretirement Benefits | Mutual Funds [Member] | United States Equities | Significant Other Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		0.0		0.0
Other Postretirement Benefits | Mutual Funds [Member] | United States Equities | Significant Unobservable Inputs (Level 3) [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		0.0		0.0
Underfunded Plan [Member] | Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Accumulated Benefit Obligation		637.6		0.0
Defined Benefit Plan, Plan Assets, Amount		645.8		0.0
Defined Benefit Plan, Benefit Obligation		637.6		0.0
Defined Benefit Plan, Funded (Unfunded) Status of Plan		8.2		0.0
Underfunded Plan [Member] | Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Accumulated Benefit Obligation		1,473.9		1,965.6
Defined Benefit Plan, Plan Assets, Amount		1,435.1		1,867.7
Defined Benefit Plan, Benefit Obligation		1,492.9		1,981.3
Defined Benefit Plan, Funded (Unfunded) Status of Plan		$ (57.8)		$ (113.6)

[1] This class represents pending trades with brokers.

[2] This class represents pending trades with brokers.

[3] 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.

[4] 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.

[5] 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.

[6] 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.

[7] 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.

[8] 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.

[9]  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 outside the United States.

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Leases (Lease Cost) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019 USD ($)
Finance lease cost
Amortization of right-of-use assets	$ 15.5
Interest on lease liabilities	11.3
Total finance lease cost	26.8
Operating lease cost	17.9
Short-term lease cost	1.0
Total lease cost	$ 45.7

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Pension and Other Postretirement Benefits (Schedule of Benefit Obligations in Excess of Fair Value) (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018		Dec. 31, 2017
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Plan Assets, Amount	$ 2,342.3	$ 2,084.1
Pension Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Accumulated Benefit Obligation	2,111.5	1,965.6
Defined Benefit Plan, Benefit Obligation	2,130.5	1,981.3	[1]	$ 2,192.6	[1]
Defined Benefit Plan, Plan Assets, Amount	2,080.9	1,867.7		$ 2,160.0
Defined Benefit Plan, Funded (Unfunded) Status of Plan	(49.6)	(113.6)
Underfunded Plan [Member] | Pension Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Accumulated Benefit Obligation	1,473.9	1,965.6
Defined Benefit Plan, Benefit Obligation	1,492.9	1,981.3
Defined Benefit Plan, Plan Assets, Amount	1,435.1	1,867.7
Defined Benefit Plan, Funded (Unfunded) Status of Plan	$ (57.8)	$ (113.6)

[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.

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Leases (Lease Maturity under ASC 840) (Details) - USD ($) $ in Millions		Dec. 31, 2019	Dec. 31, 2018
Lease Maturity under 840 [Line Items]
Total Future Minimum Lease Payments Due, Next Twelve Months		$ 42.8	$ 34.0
Total Future Minimum Lease Payments, Due in Two Years		36.7	29.8
Total Future Minimum Lease Payments, Due in Three Years		35.0	28.7
Total Future Minimum Lease Payments, Due in Four Years		30.7	26.3
Total Future Minimum Lease Payments, Due in Five Years		26.5	22.6
Total Future Minimum Lease Payments, Due Thereafter		233.3	226.9
Total Future Minimum Lease Payments Due		$ 405.0	368.3
Capital Leases, Future Minimum Payments, Interest Included in Payments			114.6
Fleet Lease
Lease Maturity under 840 [Line Items]
Operating Leases, Future Minimum Payments Due, Next Twelve Months			26.7
Operating Leases, Future Minimum Payments, Due in Two Years			22.4
Operating Leases, Future Minimum Payments, Due in Three Years			16.6
Operating Leases, Future Minimum Payments, Due in Four Years			12.3
Operating Leases, Future Minimum Payments, Due in Five Years			9.3
Operating Leases, Future Minimum Payments, Due Thereafter			8.8
Operating Lease
Lease Maturity under 840 [Line Items]
Operating Leases, Future Minimum Payments Due, Next Twelve Months	[1]		11.0
Operating Leases, Future Minimum Payments, Due in Two Years	[1]		7.3
Operating Leases, Future Minimum Payments, Due in Three Years	[1]		6.1
Operating Leases, Future Minimum Payments, Due in Four Years	[1]		4.2
Operating Leases, Future Minimum Payments, Due in Five Years	[1]		2.8
Operating Leases, Future Minimum Payments, Due Thereafter	[1]		14.5
Operating Leases, Future Minimum Payments Due	[1]		45.9
Capital Lease Obligations
Lease Maturity under 840 [Line Items]
Capital Leases, Future Minimum Payments Due, Next Twelve Months	[2]		23.0
Capital Leases, Future Minimum Payments Due in Two Years	[2]		22.5
Capital Leases, Future Minimum Payments Due in Three Years	[2]		22.6
Capital Leases, Future Minimum Payments Due in Four Years	[2]		22.1
Capital Leases, Future Minimum Payments Due in Five Years	[2]		19.8
Capital Leases, Future Minimum Payments Due Thereafter	[2]		212.4
Capital Leases, Future Minimum Payments Due	[2]		$ 322.4

[1] Operating lease balances do not include obligations for possible fleet vehicle lease renewals beyond the initial lease term. While we have the ability to renew these leases beyond the initial term, we are not reasonably certain to do so. Expected payments are $26.7 million in 2019, $22.4 million in 2020, $16.6 million in 2021, $12.3 million in 2022, $9.3 million in 2023 and $8.8 million thereafter.

[2] Capital lease payments shown above are inclusive of interest totaling $114.6 million.

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Revenue Recognition (Narrative) (Details)	12 Months Ended
	Dec. 31, 2019
Revenue from Contract with Customer [Abstract]
Service Area By County	20

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Earnings Per Share (Details) - shares shares in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Earnings Per Share [Abstract]
Basic Average Common Shares Outstanding	374,650	356,491	329,388
Shares contingently issuable under employee stock plans	929	0	547
Shares restricted under stock plans	154	0	821
Forward agreements	253	0	0
Diluted Average Common Shares	375,986	356,491	330,756

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Pension and Other Postretirement Benefits (Components Of The Plans' Net Periodic Benefits Cost) (Details) - USD ($) $ in Millions	3 Months Ended		12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Service Cost	$ 29.2	$ 31.3	$ 29.2	$ 31.3	$ 30.0
Interest cost	72.3	67.1	72.3	67.1	68.3
Expected return on assets	(108.8)	(142.3)			(123.1)
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)	0.2	(0.4)	0.2	(0.4)	(0.7)
Recognized actuarial loss	45.2	40.6	45.2	40.6	52.9
Settlement loss	9.5	18.5	9.5	18.5	13.7
Total Net Periodic Benefits Cost			47.6	14.8	41.1
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Service Cost	5.1	5.0	5.1	5.0	4.8
Interest cost	19.2	17.6	19.2	17.6	17.8
Expected return on assets	(13.1)	(14.9)			(15.9)
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)	(3.2)	(4.0)	(3.2)	(4.0)	(4.4)
Recognized actuarial loss	2.0	3.8	2.0	3.8	3.0
Settlement loss	$ 0.0	$ 0.0	0.0	0.0	0.0
Total Net Periodic Benefits Cost			$ 10.0	$ 7.5	$ 5.3

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Pension and Other Postretirement Benefits (Tables)

12 Months Ended

Dec. 31, 2019

Defined Benefit Plan Disclosure [Line Items]

Schedule Of Allocation of Plan Assets

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%
Short-Term Investments/Other	0%	15%	0%	10%

As of December 31, 2018, 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%
Short-Term Investments/Other	0%	15%	0%	10%

Pension Plan and Postretirement Plan Asset Mix at December 31, 2019 and December 31, 2018:

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

Schedule Of Fair Value and Changes In The Fair Value Of The Plan Assets

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.

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		)	—
Distressed opportunities	2.4		(2.4		)	—
Real estate	52.7		(52.7		)	—
Total	$	86.1	$	(86.1	)	$	—

⁽¹⁾ Level 3 assets from the prior year were reclassified in the current year 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	1 day
International equities	168.2		Monthly	10-30 days
Fixed income	351.8		Daily	3 days
Total	$	860.5

Fair Value Measurements at December 31, 2018: 

(in millions)	December 31, 2018			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	$	9.2		$	8.8	$	0.4		$	—
Equity securities
U.S. equities	0.2			0.2		—			—
Fixed income securities
Government	250.2			—		250.2			—
Corporate	442.8			—		442.8			—
Mutual Funds
U.S. multi-strategy	110.3			110.3		—			—
International equities	43.2			43.2		—			—
Fixed income	166.8			166.8		—			—
Private equity limited partnerships
U.S. multi-strategy(1)	18.5			—		—			18.5
International multi-strategy(2)	12.5			—		—			12.5
Distressed opportunities	2.4			—		—			2.4
Real Estate	52.7			—		—			52.7
Commingled funds(3)
Short-term money markets	18.3			—		—			—
U.S. equities	245.2			—		—			—
International equities	122.3			—		—			—
Fixed income	365.7			—		—			—
Pension plan assets subtotal	1,860.3			329.3		693.4			86.1
Other postretirement benefit plan assets:
Mutual funds
U.S. equities	68.4			68.4		—			—
International equities	17.5			17.5		—			—
Fixed income	114.8			114.8		—			—
Commingled funds(3)
Short-term money markets	5.2			—		—			—
U.S. equities	10.4			—		—			—
Other postretirement benefit plan assets subtotal	216.3			200.7		—			—
Due to brokers, net(4)	(1.1		)	—		(1.1		)	—
Accrued investment income/dividends	8.6			8.6		—			—
Total pension and other postretirement benefit plan assets	$	2,084.1		$	538.6	$	692.3		$	86.1

⁽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 a 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.

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, 2018:

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

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, 2018:

(in millions)	Fair Value		Redemption Frequency	Redemption Notice Period
Commingled Funds
Short-term money markets	$	23.5	Daily	1 day
U.S. equities	255.6		Monthly	3 days
International equities	122.3		Monthly	10-30 days
Fixed income	365.7		Monthly	3 days
Total	$	767.1

 

Schedule Of Reconciliation Of The Plan Funded Status

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)	2019			2018			2019			2018
Change in projected benefit obligation(1)
Benefit obligation at beginning of year	$	1,981.3		$	2,192.6		$	492.5		$	556.3
Service cost	29.2			31.3			5.1			5.0
Interest cost	72.3			67.1			19.2			17.6
Plan participants’ contributions	—			—			4.8			5.7
Plan amendments	—			0.2			5.1			0.1
Actuarial (gain) loss	204.3			(103.9		)	88.8			(51.7		)
Settlement loss	—			0.8			—			—
Benefits paid	(156.6		)	(206.8		)	(39.5		)	(41.1		)
Estimated benefits paid by incurred subsidy	—			—			0.5			0.6
Projected benefit obligation at end of year	$	2,130.5		$	1,981.3		$	576.5		$	492.5
Change in plan assets
Fair value of plan assets at beginning of year	$	1,867.7		$	2,160.0		$	216.3		$	262.5
Actual (loss) return on plan assets	366.8			(88.4		)	56.9			(31.8		)
Employer contributions	2.9			2.9			23.0			21.0
Plan participants’ contributions	—			—			4.7			5.7
Benefits paid	(156.5		)	(206.8		)	(39.5		)	(41.1		)
Fair value of plan assets at end of year	$	2,080.9		$	1,867.7		$	261.4		$	216.3
Funded Status at end of year	$	(49.6	)	$	(113.6	)	$	(315.1	)	$	(276.2	)
Amounts recognized in the statement of financial position consist of:
Noncurrent assets	8.2			—			—			—
Current liabilities	(3.0		)	(3.0		)	(0.8		)	(0.8		)
Noncurrent liabilities	(54.8		)	(110.6		)	(314.3		)	(275.4		)
Net amount recognized at end of year(2)	$	(49.6	)	$	(113.6	)	$	(315.1	)	$	(276.2	)
Amounts recognized in accumulated other comprehensive income or regulatory asset/liability(3)
Unrecognized prior service credit	$	3.0		$	3.2		$	(10.7	)	$	(19.0	)
Unrecognized actuarial loss	652.8			761.2			118.4			75.3
Net amount recognized at end of year	$	655.8		$	764.4		$	107.7		$	56.3

⁽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⁾ 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 $739.1 million and $0.1 million, respectively, as of December 31, 2019, and $798.3 million and $0.1 million, respectively, as of December 31, 2018 that would otherwise have been recorded to accumulated other comprehensive loss.

Schedule of Benefit Obligations in Excess of Fair Value of Plan Assets

Information for pension plans with a projected benefit obligation in excess of plan assets:

	December 31,
	2019			2018
Accumulated Benefit Obligation	$	1,473.9		$	1,965.6
Funded Status
Projected Benefit Obligation	1,492.9			1,981.3
Fair Value of Plan Assets	1,435.1			1,867.7
Funded Status of Underfunded Pension Plans at End of Year	$	(57.8	)	$	(113.6	)

Information for pension plans with plan assets in excess of the projected benefit obligation:

	December 31,
	2019		2018
Accumulated Benefit Obligation	$	637.6	$	—
Funded Status
Projected Benefit Obligation	637.6		—
Fair Value of Plan Assets	645.8		—
Funded Status of Overfunded Pension Plans at End of Year	$	8.2	$	—

Schedule Of Significant Actuarial Assumptions In Determining Funded Status Plan

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
	2019		2018		2019		2018
Weighted-average assumptions to Determine Benefit Obligation
Discount Rate	3.12	%	4.26	%	3.21	%	4.31	%
Rate of Compensation Increases	4.00	%	4.00	%	—		—
Health Care Trend Rates
Trend for Next Year	—		—		6.68	%	8.48	%
Ultimate Trend	—		—		4.50	%	4.50	%
Year Ultimate Trend Reached	—		—		2028		2026

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
	2019		2018		2017		2019		2018		2017
Weighted-average Assumptions to Determine Net Periodic Benefit Cost
Discount rate - service cost(1)	4.48	%	3.79	%	4.40	%	4.59	%	3.89	%	4.58	%
Discount rate - interest cost(1)	3.84	%	3.15	%	3.31	%	3.94	%	3.27	%	3.48	%
Expected Long-Term Rate of Return on Plan Assets	6.10	%	7.00	%	7.25	%	5.83	%	5.80	%	6.99	%
Rate of Compensation Increases	4.00	%	4.00	%	4.00	%	—		—		—

Schedule Of One-Percentage-Point Change In Assumed Health Care Cost Trend Rates

Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects:

(in millions)	1% point increase		1% point decrease
Effect on service and interest components of net periodic cost	$	1.2	$	(1.1	)
Effect on accumulated postretirement benefit obligation	30.1		(26.3		)

Schedule Of Expected Payments To Participants In Pension Plan

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)
2020	$	178.8	$	38.1	$	0.5
2021	177.8		38.6		0.4
2022	175.8		38.4		0.4
2023	168.5		38.1		0.4
2024	164.4		37.9		0.4
2025-2029	723.7		181.0		1.5

Components Of The Plans' Net Periodic Benefits Cost

The following table provides the components of the plans’ actuarially determined net periodic benefits cost for each of the three years ended December 31, 2019, 2018 and 2017:

	Pension Benefits									Other Postretirement Benefits
(in millions)	2019			2018			2017			2019			2018			2017
Components of Net Periodic Benefit Cost(1)
Service cost	$	29.2		$	31.3		$	30.0		$	5.1		$	5.0		$	4.8
Interest cost	72.3			67.1			68.3			19.2			17.6			17.8
Expected return on assets	(108.8		)	(142.3		)	(123.1		)	(13.1		)	(14.9		)	(15.9		)
Amortization of prior service cost (credit)	0.2			(0.4		)	(0.7		)	(3.2		)	(4.0		)	(4.4		)
Recognized actuarial loss	45.2			40.6			52.9			2.0			3.8			3.0
Settlement loss	9.5			18.5			13.7			—			—			—
Total Net Periodic Benefits Cost	$	47.6		$	14.8		$	41.1		$	10.0		$	7.5		$	5.3

⁽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."

Schedule Of Changes In Plan Assets And Projected Benefit Obligations Recognized In Other Comprehensive Income

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)	2019			2018			2019			2018
Other Changes in Plan Assets and Projected Benefit Obligations Recognized in Other Comprehensive Income or Regulatory Asset or Liability
Net prior service cost	$	—		$	0.2		$	5.1		$	0.1
Net actuarial loss (gain)	(53.8		)	127.5			45.1			(5.0		)
Settlements	(9.5		)	(18.5		)	—			—
Less: amortization of prior service cost	(0.2		)	0.4			3.2			4.0
Less: amortization of net actuarial loss	(45.2		)	(40.6		)	(2.0		)	(3.8		)
Total Recognized in Other Comprehensive Income or Regulatory Asset or  Liability	$	(108.7	)	$	69.0		$	51.4		$	(4.7	)
Amount Recognized in Net Periodic Benefits Cost and Other Comprehensive Income or Regulatory Asset or Liability	$	(61.1	)	$	83.8		$	61.4		$	2.8

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Subsequent Event (Narrative) (Details) - Subsequent Event $ in Millions	Feb. 26, 2020 USD ($)
Subsequent Event [Line Items]
Purchase Price	$ 1,100
Gain (Loss) on Sale of Assets and Asset Impairment Charges	$ 360

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Segments Of Business (Schedule Of Operating Income Derived From Revenues And Expenses By Segment) (Details) - USD ($) $ in Millions		3 Months Ended								12 Months Ended
		Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Segment Reporting Information [Line Items]
Operating Revenues										$ 5,208.9	$ 5,114.5	$ 4,874.6
Operating Income (Loss)		$ (38.0)	$ 91.0	$ 463.5	$ 374.2	$ (78.4)	$ (315.9)	$ 118.4	$ 400.6	890.7	124.7	921.2
Consolidated Depreciation and Amortization										717.4	599.6	570.3
Consolidated Assets		22,659.8				21,804.0				22,659.8	21,804.0	19,961.7
Payments to Acquire Property Plant and Equipment Including Captial Expenditures From Current Liabilities And Equity Method Investments	[1]									1,867.8	1,814.6	1,753.8
Gas Distribution Operations
Segment Reporting Information [Line Items]
Operating Revenues										3,509.7	3,406.4
Intersegment										3,522.8	3,419.5	3,102.1
Operating Income (Loss)						(254.1)				675.4		550.1
Consolidated Depreciation and Amortization										403.2	301.0	269.3
Consolidated Assets		14,224.5				13,527.0				14,224.5	13,527.0	12,048.8
Payments to Acquire Property Plant and Equipment Including Captial Expenditures From Current Liabilities And Equity Method Investments	[1]									1,380.3	1,315.3	1,125.6
Electric Operations
Segment Reporting Information [Line Items]
Operating Revenues										1,698.4	1,707.4
Intersegment										1,699.2	1,708.2	1,786.5
Operating Income (Loss)						386.1				406.8		367.4
Consolidated Depreciation and Amortization										277.3	262.9	277.8
Consolidated Assets		6,027.6				5,735.2				6,027.6	5,735.2	5,478.6
Payments to Acquire Property Plant and Equipment Including Captial Expenditures From Current Liabilities And Equity Method Investments	[1]									468.9	499.3	592.4
Corporate and Other
Segment Reporting Information [Line Items]
Operating Revenues										0.8	0.7
Intersegment										468.9	518.3	511.8
Operating Income (Loss)						(7.3)				(191.5)		3.7
Consolidated Depreciation and Amortization										36.9	35.7	23.2
Consolidated Assets		$ 2,407.7				$ 2,541.8				2,407.7	2,541.8	2,434.3
Payments to Acquire Property Plant and Equipment Including Captial Expenditures From Current Liabilities And Equity Method Investments	[1]									18.6	0.0	35.8
Eliminations
Segment Reporting Information [Line Items]
Intersegment										(482.0)	(531.5)	(525.8)
Unaffiliated | Gas Distribution Operations
Segment Reporting Information [Line Items]
Operating Revenues										3,509.7	3,406.4	3,087.9
Unaffiliated | Electric Operations
Segment Reporting Information [Line Items]
Operating Revenues										1,698.4	1,707.4	1,785.7
Unaffiliated | Corporate and Other
Segment Reporting Information [Line Items]
Operating Revenues										0.8	0.7	1.0
Intersegment | Gas Distribution Operations
Segment Reporting Information [Line Items]
Intersegment										13.1	13.1	14.2
Intersegment | Electric Operations
Segment Reporting Information [Line Items]
Intersegment										0.8	0.8	0.8
Intersegment | Corporate and Other
Segment Reporting Information [Line Items]
Intersegment										$ 468.1	$ 517.6	$ 510.8

[1] Amounts differ from those presented on the Statements of Consolidated Cash Flows primarily due to the inclusion of capital expenditures included in current liabilities and AFUDC Equity. ⁽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 6, "Goodwill and Other Intangible Assets."

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Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2019

Asset Retirement Obligation [Abstract]

Changes In Liability For Asset Retirement Obligations

Changes in our liability for asset retirement obligations for the years 2019 and 2018 are presented in the table below:

(in millions)	2019				2018
Beginning Balance	$	352.0			$	268.7
Accretion recorded as a regulatory asset/liability	15.7				11.1
Additions	—				63.3			(2)
Settlements	(5.4		)		(5.9		)
Change in estimated cash flows	54.6			(1)	14.8			(2)
Ending Balance	$	416.9			$	352.0

⁽¹⁾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.

⁽²⁾In 2018, $59.8 million of additions and $17.7 million of the change in estimated cash flows are attributed to costs associated with refining the CCR compliance plan. See Note 19-D, "Environmental Matters," for additional information on CCRs.

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Statements of Consolidated Comprehensive Income (Loss) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Net Income (Loss)		$ 383.1	$ (50.6)	$ 128.5
Other comprehensive income (loss):
Net unrealized gain (loss) on available-for-sale securities	[1]	5.7	(2.6)	0.8
Net unrealized gain (loss) on cash flow hedges	[2]	(64.2)	22.7	(22.5)
Unrecognized pension and OPEB benefit (costs)	[3]	3.1	(4.4)	3.4
Total other comprehensive income (loss)	[4]	(55.4)	15.7	(18.3)
Total Comprehensive Income (Loss)		$ 327.7	$ (34.9)	$ 110.2

[1] Net unrealized gain (loss) on available-for-sale securities, net of $1.5 million tax expense, $0.6 million tax benefit and $0.4 million tax expense in 2019, 2018 and 2017, respectively.

[2] Net unrealized gain (loss) on derivatives qualifying as cash flow hedges, net of $21.2 million tax benefit, $7.5 million tax expense and $13.9 million tax benefit in 2019, 2018 and 2017, respectively.

[3] Unrecognized pension and OPEB benefit (costs), net of $1.6 million tax expense, $1.5 million tax benefit and $2.1 million tax expense in 2019, 2018 and 2017, respectively.

[4] All amounts are net of tax. Amounts in parentheses indicate debits.

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Pension and Other Postretirement Benefits (Schedule Of Pension Plan And Postretirement Plan Asset Mix) (Details) - USD ($) $ in Millions		Dec. 31, 2019		Dec. 31, 2018		Dec. 31, 2017
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		$ 2,342.3		$ 2,084.1
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		$ 2,080.9		$ 1,867.7		$ 2,160.0
Percentage of total asset		100.00%		100.00%
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		$ 261.4		$ 216.3		$ 262.5
Percentage of total asset		100.00%		100.00%
Domestic Equities | Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		$ 446.4		$ 355.5
Percentage of total asset		21.50%		19.00%
Domestic Equities | Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		$ 93.8		$ 78.8
Percentage of total asset		35.90%		36.40%
International Equities | Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		$ 205.0		$ 165.5
Percentage of total asset		9.90%		8.90%
International Equities | Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		$ 40.7		$ 17.5
Percentage of total asset		15.60%		8.10%
Fixed Income | Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		$ 1,337.2		$ 1,241.9
Percentage of total asset		64.20%		66.50%
Fixed Income | Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		$ 119.5		$ 115.1
Percentage of total asset		45.70%		53.20%
Real Estate | Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		$ 53.9		$ 52.7
Percentage of total asset		2.60%		2.80%
Real Estate | Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		$ 0.0		$ 0.0
Percentage of total asset		0.00%		0.00%
Cash/Other [Member] | Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		$ 38.4		$ 52.1
Percentage of total asset		1.80%		2.80%
Cash/Other [Member] | Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		$ 7.4		$ 4.9
Percentage of total asset		2.80%		2.30%
Commingled Funds | Short-Term Money Markets | Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		$ 14.8	[1]	$ 18.3	[2]
Commingled Funds | Short-Term Money Markets | Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		7.7	[1]	5.2	[2]
Commingled Funds | International Equities | Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		148.1	[1]	122.3	[2]
Commingled Funds | International Equities | Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[1]	20.1
Commingled Funds | Fixed Income | Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		351.8	[1]	365.7	[2]
Commingled Funds | United States Equities | Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		305.9	[1]	245.2	[2]
Commingled Funds | United States Equities | Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		$ 12.1	[1]	$ 10.4	[2]

[1] This class of investments is measured at fair value using the net asset value per share and has not been classified in the fair value hierarchy.

[2] This class of investments is measured at fair value using the net asset value per share and has not been classified in the fair value hierarchy.

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Risk Management Activities (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019		Dec. 31, 2018	Dec. 31, 2017
Derivative [Line Items]
Limit of GCA Volumes	2000.00%
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net	$ 0.0		$ 0.0	$ 0.0
Interest Rate Swap
Derivative [Line Items]
Derivative, Notional Amount	500.0
Interest Rate Swap Settled
Derivative [Line Items]
Derivative, Notional Amount			750.0
Derivative, Gain (Loss) on Derivative, Net	$ 0.0	[1]	$ 46.2

[1] ⁽³⁾ See Note 9, "Risk Management Activities" for additional information.

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Statements Of Consolidated Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Operating Activities
Net Income (Loss)	$ 383.1	$ (50.6)	$ 128.5
Adjustments to Reconcile Net Income (Loss) to Net Cash from Operating Activities:
Loss on early extinguishment of debt	0.0	45.5	111.5
Depreciation and amortization	717.4	599.6	570.3
Deferred income taxes and investment tax credits	118.2	(188.2)	306.7
Stock compensation expense and 401(k) profit sharing contribution	25.9	28.6	40.1
Impairment of goodwill and other intangible assets	414.5	0.0	0.0
Amortization of discount/premium on debt	8.2	7.5	7.4
AFUDC equity	(8.0)	(14.2)	(12.6)
Other adjustments	(0.9)	1.7	6.6
Changes in Assets and Liabilities:
Accounts receivable	187.8	(186.2)	(52.3)
Inventories	(2.0)	41.4	19.0
Accounts payable	(299.9)	268.4	49.0
Customer deposits and credits	16.9	(25.4)	(2.5)
Taxes accrued	7.3	20.2	10.2
Interest accrued	8.8	(21.7)	(33.9)
Exchange gas receivable/payable	55.5	(21.5)	(64.5)
Other accruals	105.3	43.5	31.8
Prepayments and other current assets	(33.6)	(14.5)	(13.3)
Regulatory assets/liabilities	(85.6)	(53.2)	57.5
Postretirement and postemployment benefits	(21.1)	58.2	(380.9)
Deferred charges and other noncurrent assets	(76.1)	3.8	(2.0)
Other noncurrent liabilities	61.6	(2.8)	(34.4)
Net Cash Flows from Operating Activities	1,583.3	540.1	742.2
Investing Activities
Capital expenditures	(1,802.4)	(1,818.2)	(1,695.8)
Cost of removal	(113.2)	(104.3)	(109.0)
Purchases of available-for-sale securities	(140.4)	(90.0)	(168.4)
Sales of available-for-sale securities	132.1	82.3	163.1
Other investing activities	1.5	4.1	1.6
Net Cash Flows used for Investing Activities	(1,922.4)	(1,926.1)	(1,808.5)
Financing Activities
Issuance of long-term debt	750.0	350.0	3,250.0
Repayments of long-term debt and finance lease obligations	(51.6)	(1,046.1)	(1,855.0)
Issuance of short-term debt (maturity 90 days)	600.0	950.0	0.0
Repayments of short-term debt (maturity 90 days)	(700.0)	0.0	0.0
Change in short-term borrowings, net (maturity ≤ 90 days)	(104.0)	(178.5)	(282.4)
Issuance of common stock, net of issuance costs	244.4	848.2	336.7
Issuance of preferred stock, net of issuance costs	0.0	880.0	0.0
Equity costs, premiums and other debt related costs	(17.8)	(46.0)	(144.3)
Acquisition of treasury stock	0.0	(4.0)	(7.2)
Dividends paid - common stock	(298.5)	(273.3)	(229.1)
Dividends paid - preferred stock	(56.1)	(11.6)	0.0
Net Cash Flows from Financing Activities	366.4	1,468.7	1,068.7
Change in cash, cash equivalents and restricted cash	27.3	82.7	2.4
Cash, cash equivalents and restricted cash at beginning of period	121.1	38.4	36.0
Cash, Cash Equivalents and Restricted Cash at End of Period	$ 148.4	$ 121.1	$ 38.4

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Regulatory Matters (Regulatory Assets) (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Regulatory Assets [Line Items]
Total Assets	$ 2,239.6	$ 2,237.5
Unrecognized Pension Benefit And Other Postretirement Benefit Costs
Regulatory Assets [Line Items]
Total Assets	739.1	798.3
Other Postretirement Costs
Regulatory Assets [Line Items]
Total Assets	91.3	74.1
Environmental Costs
Regulatory Assets [Line Items]
Total Assets	73.4	61.5
Regulatory Effects Of Accounting For Income Taxes
Regulatory Assets [Line Items]
Total Assets	234.0	233.1
Underrecovered Gas And Fuel Costs
Regulatory Assets [Line Items]
Total Assets	3.9	34.7
Depreciation
Regulatory Assets [Line Items]
Total Assets	210.7	209.6
Post-In Service Carrying Charges
Regulatory Assets [Line Items]
Total Assets	219.8	206.6
Safety Activity Costs
Regulatory Assets [Line Items]
Total Assets	118.6	91.7
DSM Program
Regulatory Assets [Line Items]
Total Assets	50.1	45.5
Bailly Generating Station [Member]
Regulatory Assets [Line Items]
Total Assets	221.8	244.3
Other Assets
Regulatory Assets [Line Items]
Total Assets	$ 276.9	$ 238.1

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Long-Term Debt (Narrative) (Details) - USD ($) $ in Millions		6 Months Ended	12 Months Ended
	Jul. 16, 2018	Jun. 30, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Aug. 12, 2019	Apr. 01, 2019	Jun. 11, 2018	Mar. 15, 2018
Debt Instrument [Line Items]
Debt Instrument Tendered				$ 209.0
Loss on early extinguishment of long-term debt	$ 33.0	$ 12.5	$ 0.0	(45.5)	$ (111.5)
Debt Instrument, Convertible, Conversion Ratio			61.70%
Security interest and other subset of asset			$ 150.0
Asset sale covenant percentage of consolidated total assets			10.00%
Cross default provision on default relating to any indebtedness			$ 50.0
Percentage of additional subset of assets capped			10.00%
Senior Notes
Debt Instrument [Line Items]
Face amount of notes						$ 750.0
Maximum
Debt Instrument [Line Items]
Cross default provision on default relating to any indebtedness			$ 50.0
Minimum
Debt Instrument [Line Items]
Cross default provision on default relating to any indebtedness			$ 5.0
5.85% Notes Due 2019
Debt Instrument [Line Items]
Debt Instrument, Repurchase Amount							$ 41.0
Interest rate on debt							5.85%
2.95% Notes Due 2029
Debt Instrument [Line Items]
Interest rate on debt			2.95%
2.95% Notes Due 2029 | Senior Notes
Debt Instrument [Line Items]
Proceeds from Debt, Net of Issuance Costs			$ 742.4
6.40% Notes Due 2018
Debt Instrument [Line Items]
Debt Instrument, Repurchased Face Amount									$ 275.1
Interest rate on debt									6.40%
6.80% Notes Due 2019
Debt Instrument [Line Items]
Debt Instrument, Repurchased Face Amount				$ 551.1
Interest rate on debt				6.80%
5.45% Notes due 2020
Debt Instrument [Line Items]
Interest rate on debt				5.45%
3.65% Notes Due 2023
Debt Instrument [Line Items]
Interest rate on debt				3.65%
3.65% Notes Due 2023 | Senior Notes
Debt Instrument [Line Items]
Face amount of notes								$ 350.0
Proceeds from Issuance of Debt				$ 346.6
Senior Note Redeemed 2018
Debt Instrument [Line Items]
Loss on early extinguishment of long-term debt	$ 33.0
6.13% Notes Due 2022
Debt Instrument [Line Items]
Interest rate on debt				6.125%
Revolving Credit Facility | Maximum
Debt Instrument [Line Items]
Debt Instrument, Convertible, Conversion Ratio			70.00%
Private Placement [Member] | Maximum
Debt Instrument [Line Items]
Debt Instrument, Convertible, Conversion Ratio			75.00%

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Income Taxes (Schedule of Unrecognized Tax Benefits Roll Forward) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Unrecognized Tax Benefits - Opening Balance	$ 1.2	$ 1.4	$ 2.6
Gross decreases - tax positions in prior period	(0.6)	(0.4)	(1.4)
Gross increases - current period tax positions	22.6	0.2	0.2
Unrecognized Tax Benefits - Ending Balance	23.2	1.2	1.4
Offset for net operating loss carryforwards	(22.6)	0.0	0.0
Balance - Less Net Operating Loss Carryforwards	$ 0.6	$ 1.2	$ 1.4

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Equity (Schedule of Stock by Class - Preferred) (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Class of Stock [Line Items]
Preferred Stock, Shares Outstanding	440,000	420,000
Preferred Stock, Dividends Per Share, Declared	$ 0.00	$ 28.88	$ 0.00
Preferred Stock, Value, Outstanding	$ 880.0	$ 880.0
Series A Preferred Stock
Class of Stock [Line Items]
Preferred Stock, Liquidation Preference Per Share	$ 1,000
Preferred Stock, Shares Outstanding	400,000
Preferred Stock, Dividends Per Share, Declared	$ 56.50	$ 28.88	0
Preferred Stock, Value, Outstanding	$ 393.9	$ 393.9
Series B Preferred Stock
Class of Stock [Line Items]
Preferred Stock, Liquidation Preference Per Share	$ 25,000.00
Preferred Stock, Shares Outstanding	20,000
Preferred Stock, Dividends Per Share, Declared	$ 1,674.65	$ 0	$ 0
Preferred Stock, Value, Outstanding	$ 486.1	$ 486.1

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Income Taxes (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2019	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2017	Dec. 31, 2017
Income Taxes [Line Items]
Effective income tax rate	24.40%		24.40%	78.10%		78.10%	71.00%		71.00%
Increase (Decrease) in Effective Tax Rate	(53.70%)			7.10%
State regulatory proceedings, value		$ 9.5			$ 127.8			$ 0.0
Increase in State Income Taxes					7.1
Tax Benefit From Excess Deferred Tax Amortization Related To Regulatory LIabilities					26.9
Deferred Tax Assets, Operating Loss Carryforwards	$ 765.9	765.9	$ 765.9	$ 849.8	849.8	$ 849.8
Deferred Tax Assets, Tax Credit Carryforwards, Alternative Minimum Tax	1.6	1.6	1.6
Deferred Tax Assets, Charitable Contribution Carryforwards	1.4	1.4	1.4
Unrecognized Tax Benefits, Decrease Resulting from Prior Period Tax Positions		0.6			0.4			1.4
Unrecognized Tax Benefits, Increase Resulting from Current Period Tax Positions		22.6			0.2			0.2
Unrecognized Tax Benefits, Income Tax Penalties Expense		0.0
Unrecognized Tax Benefits, Income Tax Penalties Accrued	0.0	0.0	0.0	$ 0.0	0.0	$ 0.0	$ 0.0	0.0	$ 0.0
Remeasurement due to TCJA, value		0.0			0.0			161.1
Reduction in Deferred Tax Liability Due To Tax Law Change								1,300.0
Reduction in Regulatory Deferred tax Liabilities								400.0
Increase in Regulatory Liability Due to Tax Law Change								$ 1,500.0
Change in tax expense					$ 120.7
Internal Revenue Service (IRS)
Income Taxes [Line Items]
Deferred Tax Assets, Operating Loss Carryforwards	657.1	657.1	657.1
State and Local Jurisdiction
Income Taxes [Line Items]
Deferred Tax Assets, Operating Loss Carryforwards	$ 107.2	$ 107.2	$ 107.2

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Property, Plant And Equipment Property, Plant and Equipment (Schedule of Depreciation Provisions For Utility Plant as a Percentage of the Original Cost) (Details)	12 Months Ended
	Dec. 31, 2019		Dec. 31, 2018		Dec. 31, 2017
Electric Operations
Property, Plant and Equipment [Line Items]
Depreciation Provisions For Utility Plant Percentage	2.80%	[1]	2.90%	[1]	3.40%
Gas Distribution Operations
Property, Plant and Equipment [Line Items]
Depreciation Provisions For Utility Plant Percentage	2.50%		2.20%		2.10%

[1] Lower depreciation rate beginning in 2018 due to reduced EERM-related depreciation expense and higher depreciable base from transmission assets being placed into service in 2018.

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Other, Net (Schedule Of Other Net) (Details) - USD ($) $ in Millions		3 Months Ended	12 Months Ended
		Dec. 31, 2018	Dec. 31, 2019		Dec. 31, 2018		Dec. 31, 2017
Other Nonoperating Income (Expense) [Abstract]
Charitable Contributions, Greater Lawrence Incident		$ 20.7
Interest income			$ 7.7		$ 6.6		$ 4.6
AFUDC equity			8.0		14.2		12.6
Charitable Contributions		$ 20.0	(5.1)	[1]	(45.3)	[1]	(19.9)	[1]
Pension and Other Postretirement Non Service Cost	[2]		(16.5)		18.0		(10.6)
Interest rate swap settlement gain	[3]				46.2		0.0
Miscellaneous			0.7		3.8		(0.2)
Total Other, net			$ (5.2)		$ 43.5		$ (13.5)

[1] ⁽¹⁾ 2018 charitable contributions include $20.7 million related to the Greater Lawrence Incident and $20.0 million of discretionary contributions made to the

[2] ⁽²⁾ See Note 11, "Pension and Other Postretirement Benefits" for additional information.

[3] ⁽³⁾ See Note 9, "Risk Management Activities" for additional information.

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Leases (Tables)

12 Months Ended

Dec. 31, 2019

Leases [Abstract]

Lease Cost

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	2019
Finance lease cost
Amortization of right-of-use assets	Depreciation and amortization	$	15.5
Interest on lease liabilities	Interest expense, net	11.3
Total finance lease cost		26.8
Operating lease cost	Operation and maintenance	17.9
Short-term lease cost	Operation and maintenance	1.0
Total lease cost		$	45.7

Right-of-Use Assets and Liabilities

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

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

Lease Information

Other pertinent information related to leases was as follows:

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

	December 31, 2019
Weighted-average remaining lease term (years)
Finance leases	14.8
Operating leases	9.2
Weighted-average discount rate
Finance leases	5.9	%
Operating leases	4.3	%

Lease Maturity

Maturities of our lease liabilities presented on a rolling 12-month basis were as follows:

As of December 31, 2019, (in millions)	Total			Finance Leases			Operating Leases
Year 1	$	42.8		$	27.2		$	15.6
Year 2	36.7			27.3			9.4
Year 3	35.0			26.8			8.2
Year 4	30.7			23.1			7.6
Year 5	26.5			19.9			6.6
Thereafter	233.3			201.6			31.7
Total lease payments(1)	405.0			325.9			79.1
Less: Imputed interest	(116.6		)	(102.3		)	(14.3		)
Less: Leases not yet commenced	(22.1		)	(22.1		)	—
Total	266.3			201.5			64.8
Reported as of December 31, 2019
Short-term lease liabilities	26.6			13.4			13.2
Long-term lease liabilities	239.7			188.1			51.6
Total lease liabilities	$	266.3		$	201.5		$	64.8

⁽¹⁾ Expected payments include obligations for leases not yet commenced of approximately $22.1 million for IT assets and interconnection facilities. These leases have terms between 4 years and 20 years, with estimated commencements in the first quarter of 2020 and in the third quarter of 2020.

Lease Maturity under 840

As of December 31, 2018, total contractual obligations for capital and operating leases were as follows:

As of December 31, 2018, (in millions)	Total		Capital Leases(1)		Operating Leases(2)
2019	$	34.0	$	23.0	$	11.0
2020	29.8		22.5		7.3
2021	28.7		22.6		6.1
2022	26.3		22.1		4.2
2023	22.6		19.8		2.8
Thereafter	226.9		212.4		14.5
Total lease payments	$	368.3	$	322.4	$	45.9

⁽¹⁾Capital lease payments shown above are inclusive of interest totaling $114.6 million.

⁽²⁾Operating lease balances do not include obligations for possible fleet vehicle lease renewals beyond the initial lease term. While we have the ability to renew these leases beyond the initial term, we are not reasonably certain to do so. Expected payments are $26.7 million in 2019, $22.4 million in 2020, $16.6 million in 2021, $12.3 million in 2022, $9.3 million in 2023 and $8.8 million thereafter.

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Fair Value (Carrying Amount And Estimated Fair Values Of Financial Instruments) (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Fair Value Disclosures [Abstract]
Long-term debt (including current portion), Carrying Amount	$ 7,869.6	$ 7,155.4
Long-term debt (including current portion), Estimated Fair Value	$ 8,764.4	$ 7,228.3

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Other Commitments And Contingencies Other Commitments and Contingencies (Contractual Obligation, Fiscal Year Maturity Schedule) (Details) - USD ($) $ in Millions		Dec. 31, 2019	Dec. 31, 2018
Long-term Purchase Commitment [Line Items]
Long-term Debt, Future Minimum Payments Due	[1]	$ 7,738.6
Long-term Debt, Future Minimum Payments Due, Next Twelve Months	[1]	0.0
Long-term Debt, Future Minimum Payments, Due in Two Years	[1]	63.6
Long-term Debt, Future Minimum Payments, Due in Three Years	[1]	530.0
Long-term Debt, Future Minimum Payments, Due in Four Years	[1]	600.0
Long-term Debt, Future Minimum Payments, Due in Five Years	[1]	0.0
Long-term Debt, Future Minimum Payments, Due Thereafter	[1]	6,545.0
Interest Payments on Long-term Debt, Future Minimum Payments Due		6,214.2
Interest Payments on Long-term Debt, Future Minimum Payments Due, Next Twelve Months		342.0
Interest Payments on Long-term Debt, Future Minimum Payments, Due in Two Years		340.7
Interest Payments on Long-term Debt, Future Minimum Payments, Due in Three Years		337.1
Interest Payments on Long-term Debt, Future Minimum Payments, Due in Four Years		311.1
Interest Payments on Long-term Debt, Future Minimum Payments, Due in Five Years		299.9
Interest Payments on Long-term Debt, Future Minimum Payments, Due Thereafter		4,583.4
Finance Leases, Future Minimum Payments Due	[2]	325.9
Finance Leases, Future Minimum Payments Due, Next Twelve Months	[2]	27.2
Finance Leases, Future Minimum Payments Due in Two Years	[2]	27.3
Finance Leases, Future Minimum Payments Due in Three Years	[2]	26.8
Finance Leases, Future Minimum Payments Due in Four Years	[2]	23.1
Finance Leases, Future Minimum Payments Due in Five Years	[2]	19.9
Finance Leases, Future Minimum Payments Due Thereafter	[2]	201.6
Operating Leases, Future Minimum Payments Due	[3]	79.1
Operating Leases, Future Minimum Payments Due, Next Twelve Months	[3]	15.6
Operating Leases, Future Minimum Payments, Due in Two Years	[3]	9.4
Operating Leases, Future Minimum Payments, Due in Three Years	[3]	8.2
Operating Leases, Future Minimum Payments, Due in Four Years	[3]	7.6
Operating Leases, Future Minimum Payments, Due in Five Years	[3]	6.6
Operating Leases, Future Minimum Payments, Due Thereafter	[3]	31.7
Energy Commodity Contracts, Future Minimum Payments Due	[4]	95.9
Energy Commodity Contracts, Future Minimum Payments Due, Next Twelve Months	[4]	65.5
Energy Commodity Contracts, Future Minimum Payments, Due in Two Years	[4]	30.4
Energy Commodity Contracts, Future Minimum Payments, Due in Three Years	[4]	0.0
Energy Commodity Contracts, Future Minimum Payments, Due in Four Years	[4]	0.0
Energy Commodity Contracts, Future Minimum Payments, Due in Five Years	[4]	0.0
Energy Commodity Contracts, Future Minimum Payments, Due Thereafter	[4]	0.0
Service Obligations, Pipeline Service Obligations, Future Minimum Payments Due		3,450.7
Service Obligations, Pipeline Service Obligations, Future Minimum Payments Due, Next Twelve Months		605.0
Service Obligations, Pipeline Service Obligations, Future Minimum Payments, Due in Two Years		590.1
Service Obligations, Pipeline Service Obligations, Future Minimum Payments, Due in Three Years		546.8
Service Obligations, Pipeline Service Obligations, Future Minimum Payments, Due in Four Years		357.2
Service Obligations, Pipeline Service Obligations, Future Minimum Payments, Due in Five Years		237.5
Service Obligations, Pipeline Service Obligations, Future Minimum Payments, Due Thereafter		1,114.1
Service Obligations, IT Service Obligations, Future Minimum Payments Due		153.2
Service Obligations, IT Service Obligations, Future Minimum Payments Due, Next Twelve Months		63.6
Service Obligations, IT Service Obligations, Future Minimum Payments, Due in Two Years		49.4
Service Obligations, IT Service Obligations, Future Minimum Payments, Due in Three Years		38.0
Service Obligations, IT Service Obligations, Future Minimum Payments, Due in Four Years		1.1
Service Obligations, IT Service Obligations, Future Minimum Payments, Due in Five Years		1.1
Service Obligations, IT Service Obligations, Future Minimum Payments, Due Thereafter		0.0
Service Obligations, Other Service Obligations, Future Minimum Payments Due		59.8
Service Obligations, Other Service Obligations, Future Minimum Payments Due, Next Twelve Months		45.8
Service Obligations, Other Service Obligations, Future Minimum Payments, Due in Two Years		14.0
Service Obligations, Other Service Obligations, Future Minimum Payments, Due in Three Years		0.0
Service Obligations, Other Service Obligations, Future Minimum Payments, Due in Four Years		0.0
Service Obligations, Other Service Obligations, Future Minimum Payments, Due in Five Years		0.0
Service Obligations, Other Service Obligations, Future Minimum Payments, Due Thereafter		0.0
Other Liabilities, Future Minimum Payments Due		27.3
Other Liabilities, Future Minimum Payments Due, Next Twelve Months		27.3
Other Liabilities, Future Minimum Payments, Due in Two Years		0.0
Other Liabilities, Future Minimum Payments, Due in Three Years		0.0
Other Liabilities, Future Minimum Payments, Due in Four Years		0.0
Other Liabilities, Future Minimum Payments, Due in Five Years		0.0
Other Liabilities, Future Minimum Payments, Due Thereafter		0.0
Total Future Minimum Lease Payments Due		18,144.7
Total Future Minimum Lease Payments Due, Next Twelve Months		1,192.0
Total Future Minimum Lease Payments, Due in Two Years		1,124.9
Total Future Minimum Lease Payments, Due in Three Years		1,486.9
Total Future Minimum Lease Payments, Due in Four Years		1,300.1
Total Future Minimum Lease Payments, Due in Five Years		565.0
Total Future Minimum Lease Payments, Due Thereafter		12,475.8
Debt Instrument, Unamortized Discount (Premium) and Debt Issuance Costs, Net		(70.5)	$ (68.5)
Finance Leases, Future Minimum Payments, Interest Included in Payments		108.3
Operating Leases, Future Minimum Payaments, Interest Included in Payments		14.3
Coal [Member]
Long-term Purchase Commitment [Line Items]
Energy Commodity Contracts, Future Minimum Payments Due		14.4
Fleet Lease
Long-term Purchase Commitment [Line Items]
Operating Leases, Future Minimum Payments Due, Next Twelve Months		34.5
Operating Leases, Future Minimum Payments, Due in Two Years		28.3
Operating Leases, Future Minimum Payments, Due in Three Years		23.4
Operating Leases, Future Minimum Payments, Due in Four Years		19.9
Operating Leases, Future Minimum Payments, Due in Five Years		15.2
Operating Leases, Future Minimum Payments, Due Thereafter		$ 15.2

[1] Long-term debt balance excludes unamortized issuance costs and discounts of $70.5 million.

[2] Finance lease payments shown above are inclusive of interest totaling $108.3 million.

[3] Operating lease payments shown above are inclusive of interest totaling $14.3 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. If we were to continue the fleet vehicle leases outstanding at December 31, 2019, payments would be $34.5 million in 2020, $28.3 million in 2021, $23.4 million in 2022, $19.9 million in 2023, $15.2 million in 2024 and $15.2 million thereafter.

[4] In January 2020, NIPSCO signed new coal contract commitments of $14.4 million for 2020. These contracts are not included above.

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Accumulated Other Comprehensive Loss (Tables)

12 Months Ended

Dec. 31, 2019

Components of Accumulated Other Comprehensive Income (Loss) [Abstract]

Schedule of Accumulated Other Comprehensive Income (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, 2017	$	(0.6	)	$	(6.9	)	$	(17.6	)	$	(25.1	)
Other comprehensive income (loss) before reclassifications	0.6			(24.2		)	1.9			(21.7		)
Amounts reclassified from accumulated other comprehensive loss	0.2			1.7			1.5			3.4
Net current-period other comprehensive income (loss)	0.8			(22.5		)	3.4			(18.3		)
Balance as of December 31, 2017	$	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	)

 

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

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Nature of Operations And Summary of Significant Accounting Policies (Policy)

12 Months Ended

Dec. 31, 2019

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Company Structure And Principles Of Consolidation

Company Structure and Principles of Consolidation.  We are an energy holding company incorporated in Delaware and headquartered in Merrillville, Indiana. Our subsidiaries are fully regulated natural gas and electric utility companies serving approximately 4.0 million customers in seven states. We generate substantially all of our operating income through these rate-regulated businesses. The consolidated financial statements include the accounts of us and our majority-owned subsidiaries after the elimination of all intercompany accounts and transactions.

Use Of Estimates

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.

Cash, Cash Equivalents, And Restricted Cash

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.

Accounts Receivable And Unbilled Revenue

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 and weather. 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 $350.5 million and $324.2 million as of December 31, 2019 and 2018, 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.

Investments In Debt And Equity Securities

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 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, 2019, 2018 or 2017. Refer to Note 17, "Fair Value," for additional information.

Basis Of Accounting For Rate-Regulated Subsidiaries

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.

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 regulatory accounting. In such an event, a write-down of all or a portion of our existing regulatory assets and liabilities could result. If transition cost recovery was approved by the appropriate regulatory bodies that would meet the requirements under GAAP for continued accounting as regulatory assets and liabilities during such recovery period, the regulatory assets and liabilities would be reported at the recoverable amounts. If unable to continue to apply

the provisions of regulatory accounting, we would be required to apply the provisions of ASC 980-20, Discontinuation of Rate-Regulated Accounting. In management’s opinion, our regulated subsidiaries will be subject to regulatory accounting for the foreseeable future. Refer to Note 8, "Regulatory Matters," for additional information.

Utility Plant And Other Property And Related Depreciation And Maintenance

Plant and Other Property and Related Depreciation and Maintenance.    Property, plant and equipment (principally utility plant) is stated at cost. The 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 is generally depreciated on a straight-line basis over the life of the associated asset. Refer to Note 5, "Property, Plant and Equipment," for additional information related to depreciation expense.

For rate-regulated companies, AFUDC is capitalized on all classes of property except organization costs, land, autos, office equipment, tools and other general property purchases. The allowance is applied to construction costs for that period of time between the date of the expenditure and the date on which such project is placed in service. Our pre-tax rate for AFUDC was 3.0% in 2019, 3.5% in 2018 and 4.0% in 2017.

Generally, our subsidiaries follow the practice of charging maintenance and repairs, including the cost of removal of minor items of property, to expense as incurred. When our subsidiaries retire regulated property, plant and equipment, original cost plus the cost of retirement, less salvage value, is charged to accumulated depreciation. However, when it becomes probable a regulated asset will be retired substantially in advance of its original expected useful life or is abandoned, the cost of the asset and the corresponding accumulated depreciation is recognized as a separate asset. If the asset is still in operation, the net amount is classified as "Other property, at cost, less accumulated depreciation" on the Consolidated Balance Sheets. If the asset is no longer operating, the net amount is classified in "Regulatory assets" on the Consolidated Balance Sheets. If we are able to recover a full return of and on investment, the carrying value of the asset is based on historical cost. If we are not able to recover a full return on investment, a loss on impairment is recognized to the extent the net book value of the asset exceeds the present value of future revenues discounted at the incremental borrowing rate.

When our subsidiaries sell entire regulated operating units, or retire or sell nonregulated properties, the original cost and accumulated depreciation and amortization balances are removed from "Property, Plant and Equipment" on the Consolidated Balance Sheets. Any gain or loss is recorded in earnings, unless otherwise required by the applicable regulatory body. Refer to Note 5, "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, except for certain significant enterprise-wide technology investments which are amortized over a ten-year period.

External and internal up-front implementation costs associated with cloud computing arrangements that are service contracts are deferred on the Consolidated Balance Sheets. Once the installed software is ready for its intended use, such deferred costs are amortized on a straight-line basis to "Operation and maintenance," over the minimum term of the contract plus contractually-provided renewal periods that are reasonable expected to be exercised -- generally up to a maximum of five years.

Goodwill And Other Intangible Assets

Goodwill and Other Intangible Assets.    Substantially all of our goodwill relates to the excess of cost over the fair value of the net assets acquired in the Columbia acquisition on November 1, 2000. We test our goodwill for impairment annually as of May 1, or more frequently if events and circumstances indicate that goodwill might be impaired. Fair value of our reporting units is determined using a combination of income and market approaches.

We had other intangible assets consisting primarily of franchise rights apart from goodwill that were identified as part of the purchase price allocations associated with the acquisition of Columbia of Massachusetts, which were being amortized on a straight-line basis over forty years from the date of acquisition.

During the fourth quarter of 2019, we impaired goodwill and intangible assets related to Columbia of Massachusetts. See Note 6, "Goodwill and Other Intangible Assets," for additional information.

Accounts Receivable Transfer Program

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, 2019 and 2018 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 18, "Transfers of Financial Assets," for further information.

Fuel Adjustment Clause

Gas Cost and Fuel Adjustment Clause.    Our regulated subsidiaries defer most differences between gas and fuel purchase costs and the recovery of such costs in revenues, and adjust future billings for such deferrals on a basis consistent with applicable state-approved tariff provisions. These deferred balances are recorded as "Regulatory assets" or "Regulatory liabilities," as appropriate, on the Consolidated Balance Sheets. Refer to Note 8, "Regulatory Matters," for additional information.

Gas Inventory

Inventory.    Both the LIFO inventory methodology and the weighted average cost methodology are used to value natural gas in storage, as approved by regulators for all of our regulated subsidiaries. Inventory valued using LIFO was $47.2 million and $47.5 million at December 31, 2019 and 2018, 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 $25.5 million and $12.2 million at December 31, 2019 and 2018, respectively. Gas inventory valued using the weighted average cost methodology was $203.7 million at December 31, 2019 and $239.3 million at December 31, 2018.

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.

Accounting For Exchange And Balancing Arrangements Of Natural Gas

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.

Accounting For Risk Management Activities

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 9, "Risk Management Activities," for additional information.

Income Taxes And Investment Tax Credits

Income Taxes and Investment Tax Credits.    We record income taxes to recognize full interperiod tax allocations. Under the asset and liability method, deferred income taxes are provided for the tax consequences of temporary differences by applying enacted statutory tax rates applicable to future years to differences between the financial statement carrying amount and the tax basis of existing assets and liabilities. Investment tax credits associated with regulated operations are deferred and amortized as a reduction to income tax expense over the estimated useful lives of the related properties.

To the extent certain deferred income taxes of the regulated companies are recoverable or payable through future rates, regulatory assets and liabilities have been established. Regulatory assets for income taxes are primarily attributable to property-related tax timing differences for which deferred taxes had not been provided in the past, when regulators did not recognize such taxes as costs in the rate-making process. Regulatory liabilities for income taxes are primarily attributable to the regulated companies’ obligation to refund to ratepayers deferred income taxes provided at rates higher than the current Federal income tax rate. Such property-related amounts are credited to ratepayers using either the average rate assumption method or the reverse South Georgia method. Non property-related amounts are credited to ratepayers consistent with state utility commission direction.

Pursuant to the Internal Revenue Code and relevant state taxing authorities, we and our subsidiaries file consolidated income tax returns for federal and certain state jurisdictions. We and our subsidiaries are parties to a tax sharing agreement. Income taxes recorded by each party represent amounts that would be owed had the party been separately subject to tax.

Environmental Expenditures

Environmental Expenditures.    We accrue for costs associated with environmental remediation obligations when the incurrence of such costs is probable and the amounts can be reasonably estimated, regardless of when the expenditures are actually made. The undiscounted estimated future expenditures are based on currently enacted laws and regulations, existing technology and estimated site-specific costs where assumptions may be made about the nature and extent of site contamination, the extent of

cleanup efforts, costs of alternative cleanup methods and other variables. The liability is adjusted as further information is discovered or circumstances change. The accruals for estimated environmental expenditures are recorded on the Consolidated Balance Sheets in “Legal and environmental” 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 19, "Other Commitments and Contingencies," for further information.

Excise Taxes

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).

Accrued Insurance Liabilities

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 19-E "Other Matters" for further information on accrued insurance liabilities related to the Greater Lawrence Incident.

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Segments Of Business

12 Months Ended

Dec. 31, 2019

Segment Reporting [Abstract]

Segments Of Business

Segments of Business

At December 31, 2019, our operations are divided into two primary reportable segments. 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. The Electric Operations segment provides electric service in 20 counties in the northern part of Indiana.

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)	2019			2018			2017
Operating Revenues
Gas Distribution Operations
Unaffiliated	$	3,509.7		$	3,406.4		$	3,087.9
Intersegment	13.1			13.1			14.2
Total	3,522.8			3,419.5			3,102.1
Electric Operations
Unaffiliated	1,698.4			1,707.4			1,785.7
Intersegment	0.8			0.8			0.8
Total	1,699.2			1,708.2			1,786.5
Corporate and Other
Unaffiliated	0.8			0.7			1.0
Intersegment	468.1			517.6			510.8
Total	468.9			518.3			511.8
Eliminations	(482.0		)	(531.5		)	(525.8		)
Consolidated Operating Revenues	$	5,208.9		$	5,114.5		$	4,874.6

Year Ended December 31, (in millions)	2019			2018			2017
Operating Income (Loss)
Gas Distribution Operations	$	675.4		$	(254.1	)	$	550.1
Electric Operations	406.8			386.1			367.4
Corporate and Other(2)	(191.5		)	(7.3		)	3.7
Consolidated Operating Income	$	890.7		$	124.7		$	921.2
Depreciation and Amortization
Gas Distribution Operations	$	403.2		$	301.0		$	269.3
Electric Operations	277.3			262.9			277.8
Corporate and Other	36.9			35.7			23.2
Consolidated Depreciation and Amortization	$	717.4		$	599.6		$	570.3
Assets
Gas Distribution Operations	$	14,224.5		$	13,527.0		$	12,048.8
Electric Operations	6,027.6			5,735.2			5,478.6
Corporate and Other	2,407.7			2,541.8			2,434.3
Consolidated Assets	$	22,659.8		$	21,804.0		$	19,961.7
Capital Expenditures(1)
Gas Distribution Operations	$	1,380.3		$	1,315.3		$	1,125.6
Electric Operations	468.9			499.3			592.4
Corporate and Other	18.6			—			35.8
Consolidated Capital Expenditures	$	1,867.8		$	1,814.6		$	1,753.8

⁽¹⁾Amounts differ from those presented on the Statements of Consolidated Cash Flows primarily due to the inclusion of capital expenditures included in current liabilities and AFUDC Equity.

⁽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 6, "Goodwill and Other Intangible Assets."

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Statements of Consolidated Stockholders' Equity (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Common Stock, Dividends, Per Share, Declared	$ 0.80	$ 0.78	$ 0.70
Preferred Stock, Dividends Per Share, Declared	0.00	28.88	0.00
Series A Preferred Stock
Preferred Stock, Dividends Per Share, Declared	$ 56.50	28.88	0
Preferred Stock, Liquidation Preference, Value	$ 400
Series B Preferred Stock
Preferred Stock, Dividends Per Share, Declared	$ 1,674.65	$ 0	$ 0
Preferred Stock, Liquidation Preference, Value	$ 500

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Earnings Per Share

12 Months Ended

Dec. 31, 2019

Earnings Per Share [Abstract]

Earnings Per Share

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 year ended 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 that period, and any incremental shares would have had an anti-dilutive impact on EPS. The calculation of diluted earnings per share for the year ended December 31, 2017 excludes the impact of forward agreements, which had an anti-dilutive effect for that period. The computation of diluted average common shares is as follows:

Year Ended December 31, (in thousands)	2019	2018	2017
Denominator
Basic average common shares outstanding	374,650	356,491	329,388
Dilutive potential common shares:
Shares contingently issuable under employee stock plans	929	—	547
Shares restricted under stock plans	154	—	821
Forward agreements	253	—	—
Diluted Average Common Shares	375,986	356,491	330,756

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Regulatory Matters

12 Months Ended

Dec. 31, 2019

Regulatory Assets and Liabilities Disclosure [Abstract]

Regulatory Matters

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 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 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.

Regulatory assets were comprised of the following items: 

At December 31, (in millions)	2019		2018
Regulatory Assets
Unrecognized pension and other postretirement benefit costs (see Note 11)	$	739.1	$	798.3
Deferred pension and other postretirement benefit costs (see Note 11)	91.3		74.1
Environmental costs (see Note 19-D)	73.4		61.5
Regulatory effects of accounting for income taxes (see Note 1-N and Note 10)	234.0		233.1
Under-recovered gas and fuel costs (see Note 1-J)	3.9		34.7
Depreciation	210.7		209.6
Post-in-service carrying charges	219.8		206.6
Safety activity costs	118.6		91.7
DSM programs	50.1		45.5
Bailly Generating Station	221.8		244.3
Other	276.9		238.1
Total Regulatory Assets	$	2,239.6	$	2,237.5

Regulatory liabilities were comprised of the following items: 

At December 31, (in millions)	2019		2018
Regulatory Liabilities
Over-recovered gas and fuel costs (see Note 1-J)	$	42.6	$	32.0
Cost of removal (see Note 7)	1,047.5		1,076.0
Regulatory effects of accounting for income taxes (see Note 1-N and Note 10)	1,307.0		1,428.3
Deferred pension and other postretirement benefit costs (see Note 11)	64.7		62.7
Other	50.4		61.0
Total Regulatory Liabilities	$	2,512.2	$	2,660.0

Regulatory assets, including under-recovered gas and fuel cost, of approximately $1,524.3 million as of December 31, 2019 are not earning a return on investment. These costs are recovered over a remaining life of up to 41 years. Regulatory assets of approximately $1,932.4 million include expenses that are recovered as components of the cost of service and are covered by regulatory orders. Regulatory assets of approximately $307.2 million at December 31, 2019, require specific rate action.

Assets:

Unrecognized pension and other postretirement benefit costs. In 2007, we adopted certain updates of ASC 715 which required, among other things, the recognition in other comprehensive income or loss of the actuarial gains or losses and the prior service costs or credits that arise during the period but that are not immediately recognized as components of net periodic benefit costs. Certain subsidiaries defer these gains or losses as a regulatory asset in accordance with regulatory orders or as a result of regulatory precedent, to be recovered through base rates.

Deferred pension and other postretirement benefit costs. Primarily relates to the difference between postretirement expense recorded by certain subsidiaries due to regulatory orders and the postretirement expense recorded in accordance with GAAP. These costs are expected to be collected through future base rates, revenue riders or tracking mechanisms.

Environmental costs. Includes certain recoverable costs of investigating, testing, remediating and other costs related to gas plant sites, disposal sites or other sites onto which material may have migrated. Certain of our companies defer the costs as a regulatory asset in accordance with regulatory orders, to be recovered in future base rates, billing riders or tracking mechanisms.

Regulatory effects of accounting for income taxes. Represents the deferral and under collection of deferred taxes in the rate making process. In prior years, we have lowered customer rates in certain jurisdictions for the benefits of accelerated tax deductions. Amounts are expensed for financial reporting purposes as we recover deferred taxes in the rate making process.

Under-recovered gas and fuel costs. Represents the difference between the costs of gas and fuel and the recovery of such costs in revenue and is used to adjust future billings for such deferrals on a basis consistent with applicable state-approved tariff provisions. Recovery of these costs is achieved through tracking mechanisms.

Depreciation. Represents differences between depreciation expense incurred on a GAAP basis and that prescribed through regulatory order. Significant components of this balance include:

• Columbia of Ohio depreciation rates. Prior to 2005, the PUCO-approved depreciation rates for rate-making had been lower than those which would have been utilized if Columbia of Ohio were not subject to regulation resulting in the creation of a regulatory asset. In 2005, the PUCO authorized Columbia of Ohio to revise its depreciation accrual rates for the period beginning January 1, 2005. The revised depreciation rates are higher than those which would have been utilized if Columbia of Ohio were not subject to regulation allowing for amortization of the previously created regulatory asset. The amount of depreciation that would have been recorded from 2005 through 2019 had Columbia of Ohio not been subject to rate regulation is a cumulative $923.5 million, $103.8 million less than that reflected in rates. The resulting regulatory asset balance was $27.9 million and $39.5 million as of December 31, 2019 and 2018, respectively.

• Columbia of Ohio IRP and CEP. Columbia of Ohio also has PUCO approval to defer depreciation and debt-based post-in-service carrying charges (see "Post-in-service carrying charges" below) associated with its IRP and CEP. As of December 31, 2019, depreciation of $31.9 million and $77.2 million was deferred for the respective programs. Depreciation deferral balances for the respective programs as of December 31, 2018 were $29.1 million and $76.0 million. Recovery of the depreciation is approved annually through the IRP and CEP riders. The equivalent of annual depreciation expense, based on the average life of the related assets, is included in the calculation of the IRP and CEP riders approved by the PUCO and billed to customers. Deferred depreciation expense is recognized as the IRP and CEP riders are billed to customers.

• NIPSCO ECRM. NIPSCO obtained approval from the IURC to recover certain environmental related costs including operation and maintenance and depreciation expense once the environmental facilities become operational. The ECRM deferred charges represent expenses that will be recovered from customers through an annual ECRM Cost Tracker (ECT) which authorizes the collection of deferred balances over a six month period. Depreciation of $15.2 million and $14.4 million was deferred to a regulatory asset as of December 31, 2019 and 2018, respectively. This regulatory asset was included in electric base rates, which was approved by the IURC on December 4, 2019.

• NIPSCO TDSIC. NIPSCO obtained approval from the IURC to recover costs for certain system modernization projects outside of a base rate proceeding. Eighty percent of the related costs, including depreciation, property taxes, and debt and equity based carrying charges (see "Post-in-service carrying charges" below) are recovered through a semi-annual recovery mechanism. Recovery of these costs will continue through the TDSIC tracker until such assets are included in rate base through a gas or electric base rate case, respectively. The remaining twenty percent of the costs are deferred until the next base rate case. As of December 31, 2019 and 2018, depreciation of $22.0 million and $16.5 million, respectively, was deferred as a regulatory asset.

Post-in-service carrying charges. Represents deferred debt-based carrying charges incurred on certain assets placed into service but not yet included in customer rates. This balance includes:

• Columbia of Ohio IRP and CEP. See description of IRP and CEP programs above under the heading "Depreciation." As of December 31, 2019 and 2018, Columbia of Ohio had deferred PISCC of $206.4 million and $197.1 million, respectively.

• NIPSCO TDSIC. See description of TDSIC program above under the heading "Depreciation." Deferral of equity-based carrying charges for the TDSIC program is allowed; however, such amounts are not reflected in regulatory asset balances for financial reporting as equity-based returns do not meet the definition of incurred costs under ASC 980. As of December 31, 2019 and 2018, NIPSCO had deferred PISCC of $13.4 million and $9.5 million, respectively.

Safety activity costs. Represents the difference between costs incurred in eligible safety programs in excess of those being recovered in rates. The eligible cost deferrals represent necessary business expenses incurred in compliance with PHMSA regulations and are targeted to enhance the safety of the pipeline systems. Certain subsidiaries defer the excess costs as a regulatory asset in accordance with regulatory orders and recovery of these costs will be addressed in future base rate proceedings.

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

Bailly Generating Station. 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.

 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 that have been, and continue to be, included in depreciation rates and collected in customer rates of the rate-regulated subsidiaries 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 that are established during the rate making process. Balance includes excess deferred taxes recorded upon implementation of the TCJA in December 2017, net of amounts amortized through 2019.

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

Cost Recovery and Trackers

Comparability of our line item operating results is impacted by regulatory trackers that allow for the recovery in rates of certain costs such as those described below. Increases in the expenses that are the subject of trackers generally result in a corresponding increase in operating revenues and, therefore, have essentially no impact on total operating income results.

Certain costs of our operating companies are significant, recurring in nature and generally outside the control of the operating companies. Some states allow the recovery of such costs through cost tracking mechanisms. Such tracking mechanisms allow for abbreviated regulatory proceedings in order for the operating companies to implement charges and recover appropriate costs. Tracking mechanisms allow for more timely recovery of such costs as compared with more traditional cost recovery mechanisms. Examples of such mechanisms include GCR adjustment mechanisms, tax riders, bad debt recovery mechanisms, electric energy efficiency programs, MISO non-fuel costs and revenues, resource capacity charges, federally mandated costs and environmental-related costs.

A portion of the Gas Distribution revenue is related to the recovery of gas costs, the review and recovery of which occurs through standard regulatory proceedings. All states in our operating area require periodic review of actual gas procurement activity to determine prudence and to permit the recovery of prudently incurred costs related to the supply of gas for customers. Our distribution companies have historically been found prudent in the procurement of gas supplies to serve customers.

A portion of the Electric Operations revenue is related to the recovery of fuel costs to generate power and the fuel costs related to purchased power. These costs are recovered through a FAC, a quarterly regulatory proceeding in Indiana.

Infrastructure Replacement and Federally-Mandated Compliance Programs

All of our operating utility companies have completed rate proceedings involving infrastructure replacement or enhancement, and have embarked upon initiatives to replace significant portions of their operating systems that are nearing the end of their useful lives. Each company's approach to cost recovery is unique, given the different laws, regulations and precedent that exist in each jurisdiction.

Columbia of Ohio, IRP - On December 3, 2008, the PUCO issued an order which established Columbia of Ohio’s IRP. Pursuant to that order, the IRP provides for recovery of costs resulting from: (1) the maintenance, repair and replacement of customer-owned service lines that have been determined by Columbia of Ohio to present an existing or probable hazard to persons and property;

(2) Columbia of Ohio’s replacement of cast iron, wrought iron, unprotected coated steel and bare steel pipe and associated company and customer-owned metallic service lines; (3) the replacement of customer-owned natural gas risers identified by the PUCO as prone to failure; and (4) the installation of AMR devices on all residential and commercial meters served by Columbia of Ohio. Recoverable costs include a return on investment, depreciation and property taxes, offset by specified cost savings. Columbia of Ohio’s five-year IRP plan renewal was last approved on January 31, 2018 for the years 2018-2022.

Columbia of Ohio, CEP - On October 3, 2011, Columbia of Ohio filed an application for approval to establish the CEP that would provide for the deferral of PISCC on those assets placed into service, but not reflected in rates as plant in service, and the deferral of depreciation expense and property taxes directly attributable to the CEP assets for the period October 1, 2011 through December 31, 2012. Capital expenditures covered under this program included those placed into service that were not part of Columbia of Ohio's IRP. CEP was approved by the PUCO on August 29, 2012. Under this program, the PUCO’s approval provided for the deferral of related PISCC, depreciation and property taxes up to the point where the deferred amount, if included in rates, would exceed $1.50 per month impact on the Small General Service class of customers, subject to the PUCO’s determination of the prudence and reasonableness of investments covered under this program in a future regulatory proceeding. Subsequently, on October 3, 2013, the PUCO modified and approved Columbia of Ohio’s application to continue its CEP deferrals in 2013 and succeeding years, subject to the determination of the prudence, reasonableness and magnitude of the deferrals and capital expenditures in a future cost recovery proceeding. On December 1, 2017, Columbia of Ohio filed an application in which it requested authority to implement a rider to begin recovering plant and associated deferrals related to its CEP. On October 25, 2018, a joint stipulation and recommendation was filed to recover CEP investments and deferrals through December 31, 2017, with annual adjustments for capital investments made in subsequent years. Additionally, the signatory parties to the stipulation agreed to a reduction in rates to adjust for the impacts of the Tax Cut Jobs Act and for a base rate case filing to be made by Columbia of Ohio no later than June 30, 2021. On November 28, 2018 the PUCO issued an order unanimously approving the settlement, without modification.

NIPSCO Gas and Electric, TDSIC - On April 30, 2013, the Indiana Governor signed Senate Enrolled Act 560, known as the TDSIC statute, into law. Among other provisions, the TDSIC statute provides for cost recovery outside of a base rate proceeding for new or replacement electric and gas transmission, distribution, and storage projects that a public utility undertakes for the purposes of safety, reliability, system modernization or economic development. Provisions of the TDSIC statute require that, among other things, requests for recovery include a seven-year plan of eligible investments. Once the plan is approved by the IURC, eighty percent of eligible costs can be recovered using a periodic rate adjustment mechanism, known as the TDSIC mechanism. Recoverable costs include a return on the investment, including AFUDC, PISCC, depreciation and property taxes. The remaining twenty percent of recoverable costs are deferred for future recovery in NIPSCO's next general rate case. This rate adjustment mechanism is typically filed semi-annually and has a cap at an annual increase of two percent of total retail revenues. During the 2019 Legislative session, the Indiana General Assembly amended the TDSIC statute in House Enrolled Act 1470 that was signed into law by the Governor on April 24, 2019. The revisions that became effective on July 1, 2019 permit flexibility in TDSIC Plans between five and seven years in length, permits the IURC to authorize multi-unit projects that do not include specific locations or an exact number of inspections, repairs, or replacements and projects involving advanced technology investments to support the modernization of transmission, distribution, or storage systems. The amendments also authorize termination of TDSIC Plans prior to their expiration and provide that the projects associated with the terminated plan will continue to receive TDSIC treatment until an Order is issued in the utility’s next general rate case, and provide for the ability to seek approval of a new TDSIC Plan. The amended statute also provides that the two percent revenue cap applies to the aggregate of approved TDSIC Plans and requires that the utility file a base rate case at some point during the term of each TDSIC plan. On December 31, 2019, NIPSCO Gas filed a new 6-year TDSIC for the periods 2020 through 2025.

NIPSCO Electric, ECRM - NIPSCO has approval from the IURC to recover certain environmental related costs through an ECT (environmental cost tracker). Under the ECT, NIPSCO is permitted to recover (1) AFUDC and a return on the capital investment expended by NIPSCO to implement environmental compliance plan projects and (2) related operation and maintenance and depreciation expenses once the environmental facilities become operational. All deferred costs associated with ECRM were included in electric rate base and approved by the IURC on December 4, 2019.

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

federally mandated costs of the approved compliance project by more than twenty-five percent shall require specific justification by NIPSCO and specific approval by the IURC before being authorized in the next general rate case.

Columbia of Massachusetts, GSEP - On July 7, 2014, the Governor of Massachusetts signed into law Chapter 149 of the Acts of 2014, an Act Relative to Natural Gas Leaks (“the Act”). Adopted into the Massachusetts Utility Provisions, G.L. c. 164, § 145, the Act authorizes natural gas distribution companies to file a GSEP for capital investments made on or after January 1, 2015, that are not included in the company’s current rate base as determined in the most recent base rate case, with the Massachusetts DPU to (1) address the replacement or improvement of existing aging natural gas pipeline infrastructure to improve public safety or infrastructure reliability, and (2) reduce the lost and unaccounted for natural gas through a reduction in natural gas system leaks. In addition, the Act provides that the Massachusetts DPU may, after review of the plan, allow the proposed estimated costs of the plan into rates as of May 1 of the subsequent year. Recoverable costs include a return on investment, depreciation and property taxes, offset by identified operations and maintenance cost savings. Beginning with the 2019 GSEP, rates are subject to a capped annual revenue increase of three percent of total annual firm delivery revenues, plus imputed gas revenues for sales and transportation customers, calculated as the product of (1) the historical average cost of gas per therm, and (2) the average weather normalized sales, for the period beginning with 2013 and ending with the most recent year that actual data is available at the time of the October GSEP Plan filing, per the Massachusetts DPU order in Columbia of Massachusetts' 2019 GSEP. Prior to the 2019 GSEP, the annual revenue increase was capped at one and a half percent. At the end of each 12-month period, in May of the subsequent year, Columbia of Massachusetts must file a reconciliation of the amount collected and actual costs. Any over-collection or under-collection balance is passed back to, or recovered from, customers through the surcharge over a 12-month period beginning in November. On October 31, 2019, the Massachusetts DPU issued an order on Columbia of Massachusetts' GSEP reconciliation proceeding finding that, due to pending investigations of the Greater Lawrence Incident and other operational matters, the Massachusetts DPU could not, at this time, make a finding of prudence with respect to the Columbia of Massachusetts' 2018 GSEP investments and deferred the decision on the prudency of the 2018 GSEP investments in the annual GSEP and GSEP reconciliation filings until the investigations by the DPU are complete. The DPU added that its inability to make a finding of prudence did not constitute a finding of imprudence. Once new base rates are established under a base rate proceeding, the GSEP factor is re-set to remove the capital investment and associated revenue reflected in the base rates. Columbia of Massachusetts' current five year GSEP plan for the periods 2019-2023 was approved April 30, 2019.

Columbia of Pennsylvania, DSIC - On February 14, 2012, the Governor of Pennsylvania signed into law Act 11 of 2012, which provided a DSIC mechanism for certain utilities to recover costs related to repair, replacement or improvement of eligible distribution property that has not previously been reflected in rates or rate base. Through a DSIC, a utility may recover the fixed costs of eligible infrastructure incurred during the three months ended one month prior to the effective date of the charge, thereby reducing the historical regulatory lag associated with cost recovery through the traditional rate-making process. On March 14, 2013, the Pennsylvania PUC approved Columbia of Pennsylvania’s petition to implement a DSIC as of April 1, 2013. Accordingly, Columbia of Pennsylvania is authorized to recover the cost of eligible plant associated with repair, replacement or improvement that was not previously reflected in rate base and has been placed in service during the applicable three-month period. After the initial charge is established, the DSIC is updated quarterly to recover the cost of further plant additions and cannot exceed five percent of distribution revenues. Recoverable costs include a return on investment, exclusive of accumulated deferred income taxes from the calculation of rate base, and depreciation. Once new base rates are established under a base rate proceeding, the DSIC is set to zero. Additionally, the DSIC rate is also reset to zero if, in any quarter, the data reflected in the Columbia of Pennsylvania's most recent quarterly financial earnings report show that the utility will earn an overall rate of return that would exceed the allowable rate of return used to calculate its fixed costs under the DSIC mechanism. A utility is exempt from filing a quarterly financial earnings report when a base rate proceeding is pending before the Pennsylvania PUC.

Columbia of Virginia, SAVE - On March 11, 2010, the Virginia Governor signed legislation into law that allows natural gas utilities to implement programs to replace qualifying infrastructure on an expedited basis and provides for timely cost recovery. Known as the SAVE Act, the law allows natural gas utilities to file programs with the VSCC providing a timeline and estimated costs for replacing eligible infrastructure. Eligible infrastructure replacement projects are those that (1) enhance safety or reliability by reducing system integrity risks associated with customer outages, corrosion, equipment failures, material failures, or natural forces; (2) do not increase revenues by directly connecting the infrastructure replacement to new customers; (3) reduce or have the potential to reduce greenhouse gas emissions; (4) are not included in the natural gas utility’s rate base in its most recent rate case; and (5) are commenced on or after January 1, 2010. The SAVE Act provides for recovery of costs associated with the eligible infrastructure through a rate rider. Recoverable costs include a return on investment, depreciation and property taxes. Columbia of Virginia’s current five year SAVE plan was approved by the VSCC in 2016 and amended in 2017 for the years 2016 through 2020 and amended in 2019 for calendar year 2020.

Columbia of Kentucky, SMRP (formerly AMRP) - On October 26, 2009, the Kentucky PSC approved a mechanism for recovering the costs of Columbia of Kentucky’s AMRP not previously reflected in rate base through an annual fixed monthly rate rider filed in October. In its 2013 rate case, Columbia of Kentucky was allowed to base the AMRP rider on the expected annual cost of service. Recoverable costs include a return on investment, depreciation and property taxes, offset by specific cost savings. At the end of each 12-month period, Columbia of Kentucky must file a reconciliation of the amount collected and actual costs. Any over-collection or under-collection balance is passed back to, or recovered from, customers through the surcharge over a 12-month period beginning in June of the subsequent year. Once new base rates are established under a base rate proceeding, the AMRP rider is set to zero. On July 29, 2019, CKY filed its SMRP to clarify approval of low pressure project spend and expand its AMRP to include for recovery of system safety investments, including low pressure project spend. On November 7, 2019, the Commission approved Columbia of Kentucky's request to amend and expand its annual AMRP to become the SMRP.

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

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	Filed	Status	Rates Effective
Columbia of Ohio	IRP - 2019(1)	$	18.2		$	199.6	1/18-12/18	February 28, 2019	Approved April 24, 2019	May 2019
Columbia of Ohio	CEP - 2018	$	74.5		$	659.9	1/11-12/17	December 1, 2017	Approved November 28, 2018	December 2018
Columbia of Ohio	CEP - 2019	$	15.0		$	121.7	1/18-12/18	February 28, 2019	Approved August 28, 2019	September 2019
NIPSCO - Gas	TDSIC 9(1)(2)	$	(10.6	)	$	54.4	1/18-6/18	August 28, 2018	Approved December 27, 2018	January 2019
NIPSCO - Gas	TDSIC 10(3)	$	1.6		$	12.4	7/18-4/19	June 25, 2019	Approved October 16, 2019	November 2019
NIPSCO - Gas	TDSIC 11(4)	$	(1.7	)	$	38.7	5/19-12/19	February 25, 2020	Order Expected June 2020	July 2020
NIPSCO - Gas	FMCA 1(5)	$	9.9		$	1.5	11/17-9/18	November 30, 2018	Approved March 27, 2019	April 2019
NIPSCO - Gas	FMCA 2(5)	$	(3.5	)	$	1.8	10/18-3/19	May 29, 2019	Approved September 25, 2019	October 2019
NIPSCO - Gas	FMCA 3(5)	$	0.3		$	43.0	4/19-9/19	November 26, 2019	Order Expected March 2020	April 2020
Columbia of Massachusetts	GSEP - 2019(6)	$	9.6		$	36.0	1/19-12/19	October 31, 2018	Approved April 30, 2019	May 2019
Columbia of Massachusetts	GSEP - 2020(6)(7)	$	2.4		$	75.0	1/20-12/20	October 31, 2019	Order Expected April 2020	May 2020
Columbia of Virginia	SAVE - 2019	$	2.4		$	36.0	1/19-12/19	August 17, 2018	Approved October 26, 2018	January 2019
Columbia of Virginia	SAVE - 2020	$	3.8		$	50.0	1/20-12/20	August 15, 2019	Approved December 6, 2019	January 2020
Columbia of Kentucky	AMRP - 2019	$	3.6		$	30.1	1/19-12/19	October 15, 2018	Approved December 5, 2018	January 2019
Columbia of Kentucky	SMRP - 2020	$	4.2		$	40.4	1/20-12/20	October 15, 2019	Approved December 20, 2019	January 2020
Columbia of Maryland	STRIDE - 2019	$	1.2		$	19.7	1/19-12/19	November 1, 2018	Approved December 12, 2018	January 2019
Columbia of Maryland	STRIDE - 2020	$	1.3		$	15.0	1/20-12/20	January 29, 2020	Approved February 19, 2020	February 2020
NIPSCO - Electric	TDSIC - 5(1)	$	15.9		$	58.8	6/18-11/18	January 29, 2019	Approved June 12, 2019	June 2019
NIPSCO - Electric	TDSIC - 6	$	28.1		$	131.1	12/18-6/19	August 21, 2019	Approved December 18, 2019	January 2020
NIPSCO - Electric	FMCA - 11(5)	$	0.9		$	22.4	9/18-2/19	April 17, 2019	Approved July 29, 2019	August 2019
NIPSCO - Electric	FMCA - 12(5)	$	1.6		$	4.7	3/19-8/19	October 18, 2019	Approved January 29, 2020	February 2020

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

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

⁽³⁾Incremental capital and revenue are net of amounts included in the step 2 rates.

⁽⁴⁾Incremental revenue is net of amounts included in the step 2 rates and reflects a more typical filing period.

⁽⁵⁾Incremental revenue is inclusive of tracker eligible operations and maintenance expense.

⁽⁶⁾Due to an order from the Massachusetts DPU on October 3, 2019 imposing work restrictions on Columbia of Massachusetts, Columbia of Massachusetts did not meet the approved projected 2019 GSEP spend of $64 million and associated incremental revenue of $10.7 million. In the 2020 GSEP, Columbia of Massachusetts reduced the projected capital spend for calendar year 2019 to $36 million and the associated incremental revenue in 2019 GSEP to $9.6 million.

⁽⁷⁾Incremental capital investment is anticipated to be lower than $75 million in 2020 due to the Massachusetts DPU imposed work restrictions.

Rate Case Actions

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

(in millions)
Company	Requested Incremental Revenue		Approved Incremental Revenue			Filed	Status	Rates Effective
NIPSCO - Gas(1)	$	138.1	$	105.6		September 27, 2017	Approved September 19, 2018	October 2018
Columbia of Virginia(2)	$	14.2	$	1.3		August 28, 2018	Approved June 12, 2019	February 2019
NIPSCO - Electric(3)	$	21.4	$	(53.5	)	October 31, 2018	Approved December 4, 2019	January 2020
Columbia of Maryland	$	2.5	$	(0.1	)	May 22, 2019	Approved December 18, 2019	December 2019

⁽¹⁾Rates were implemented in three steps, with implementation of step 1 rates effective October 1, 2018. Step 2 rates were effective on March 1, 2019, and step 3 rates were effective on January 1, 2020. The step 3 increase was approved based on actual information and revised from $107.3 million to $105.6 million. The IURC’s order also dismissed NIPSCO from phase 2 of the IURC’s TCJA investigation.

⁽²⁾Rates, as originally filed, were implemented in February 2019 on an interim basis, subject to refund. The final approved rates, which replaced interim rates, were implemented in July 2019.

⁽³⁾An order was received on December 4, 2019, which included the resolution of outstanding TCJA impacts to rates. Incremental revenues decreased due to a reduction in fuel costs associated with the new industrial service structure. Rates will be implemented in two steps, with implementation of step 1 rates effective January 2, 2020 and step 2 rates effective March 2, 2020.

Additional Regulatory Matters

NIPSCO Electric. On March 29, 2018, WCE, which is currently owned by BP p.l.c ("BP") and BP Products North America, which operates the BP Refinery, filed a petition at the IURC asking that the combined operations of WCE and BP be treated as a single premise, and the WCE generation be dedicated primarily to BP Refinery operations beginning in May 2019 as WCE has self-certified as a qualifying facility at FERC. BP Refinery planned to continue to purchase electric service from NIPSCO at a reduced demand level beginning in May 2019; however, a settlement agreement was filed on November 2, 2018 agreeing that BP and WCE would not move forward with construction of a private transmission line to serve BP until conclusion of NIPSCO’s pending electric rate case. The IURC approved the settlement agreement as filed on February 20, 2019. On December 4, 2019, the IURC issued an order in the electric rate case approving the implementation of a new industrial service structure. This resolved the issues included in BP’s original petition.

The December 4, 2019 electric rate case order approved the revenue requirement settlement filed in the case, with the exception of a change in the agreed to return on equity; the approved return on equity is 9.75%. The order included approval of the depreciation rates as requested, as well as authorization to create a regulatory asset upon the retirement of R.M. Schahfer Generating Units 14, 15, 17 and 18 and Michigan City Generating Station Unit 12. The order allows for the recovery of and on the net book value of the units by the end of 2032.

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Regulatory Matters (Narrative) (Details) - USD ($) $ in Millions					12 Months Ended	156 Months Ended
	May 29, 2019	May 22, 2019	Aug. 28, 2018	Dec. 27, 2016	Dec. 31, 2019	Dec. 31, 2017	Dec. 31, 2018
Regulatory Matters [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Adjustment			$ 5.2
Remaining Recovery Period of Regulatory Assets for which No Return on Investment During Recovery Period is Provided					41 years
Regulatory asset not earning return on investment					$ 1,524.3
Expenses recovered as components of cost of service and regulatory orders					1,932.4
Regulatory assets Requiring Specific Rate Action					307.2
Columbia Of Ohio
Regulatory Matters [Line Items]
Depreciation Before Rate Regulation						$ 923.5
Decrease In Depreciation And Amortization Over That Reflected In Rates						$ 103.8
Depreciation Regulatory Asset					27.9		$ 39.5
Requested IRP Extension				5 years
Columbia Of Virginia
Regulatory Matters [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount			14.2
Public Utilities, Approved Rate Increase (Decrease), Amount			$ 1.3
Columbia Of Maryland
Regulatory Matters [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount		$ 2.5
Public Utilities, Approved Rate Increase (Decrease), Amount	$ (0.1)
IRP | Columbia Of Ohio
Regulatory Matters [Line Items]
Deferred Depreciation					31.9		76.0
Capital Expenditure Program | Columbia Of Ohio
Regulatory Matters [Line Items]
Deferred Depreciation					77.2		29.1
EERM [Domain] | NIPSCO
Regulatory Matters [Line Items]
Deferred Depreciation					15.2		14.4
TDSIC [Domain] | NIPSCO
Regulatory Matters [Line Items]
Deferred Depreciation					22.0		16.5
Deferred Post-in-Service Carrying Charges					13.4		9.5
IRP and CEP [Domain] | Columbia Of Ohio
Regulatory Matters [Line Items]
Deferred Post-in-Service Carrying Charges					$ 206.4		$ 197.1

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Share-Based Compensation (Schedule Of Transactions Of Contingent Awards) (Details) - Performance Shares - $ / shares	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Nonvested, Other Than Options	1,634,718
Nonvested, Weighted Average Grant Date Fair Value	$ 20.45
Granted, Other Than Options	552,389	514,338	660,750
Granted, Weighted Average Grant Date Fair Value	$ 25.77
Forfeited, Other Than Options	(156,700)
Forfeited, Weighted Average Grant Date Fair Value	$ 26.72
Vested, Other Than Options	(527,156)
Vested, Weighted Average Grant Date Fair Value	$ 28.11
Nonvested, Other Than Options	1,503,251	1,634,718
Nonvested, Weighted Average Grant Date Fair Value	$ 22.74	$ 20.45

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Income Taxes (Schedule Of Principal Components Of Net Deferred Tax Liability) (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Deferred Tax Liabilities
Accelerated depreciation and other property differences	$ 2,516.9	$ 2,458.0
Other regulatory assets	381.5	375.4
Total Deferred Tax Liabilities	2,898.4	2,833.4
Deferred Tax Assets
Other regulatory liabilities and deferred investment tax credits (including TCJA)	336.1	365.5
Pension and other postretirement/postemployment benefits	152.1	157.5
Net operating loss carryforward and AMT credit carryforward	765.9	849.8
Environmental liabilities	25.4	24.4
Other accrued liabilities	35.3	37.5
Other, net	98.3	68.2
Total Deferred Tax Assets	1,413.1	1,502.9
Net Deferred Tax Liabilities	$ 1,485.3	$ 1,330.5

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Equity (Schedule of Stock Offering Program) (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
At The Market Stock Offering [Line Items]
Stock Issued During Period, Shares, New Issues		24,964,000
Proceeds, net of fees (in millions)	$ 244.4	$ 848.2	$ 336.7
At The Market Program
At The Market Stock Offering [Line Items]
Stock Issued During Period, Shares, New Issues	8,422,498	8,883,014	11,931,376
Common Stock Issued Average Price Per Share	$ 27.75	$ 26.85	$ 26.58
Proceeds, net of fees (in millions)	$ 229.1	$ 232.5	$ 314.7

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Risk Management Activities (Schedule of Derivative Instruments in Statement of Financial Position, Fair Value) (Details) - USD ($) $ in Millions		Dec. 31, 2019	Dec. 31, 2018
Derivatives, Fair Value [Line Items]
Derivative Asset		$ 4.4	$ 24.0
Derivative Liability		146.6	51.7
Risk Management Assets Current
Derivatives, Fair Value [Line Items]
Derivative Asset	[1]	0.6	1.1
Risk Management Assets Noncurrent
Derivatives, Fair Value [Line Items]
Derivative Asset	[2]	3.8	22.9
Risk Management Liabilities Current
Derivatives, Fair Value [Line Items]
Derivative Liability	[3]	12.6	5.0
Risk Management Liabilities Noncurrent
Derivatives, Fair Value [Line Items]
Derivative Liability		134.0	46.7
Interest rate risk programs | Risk Management Assets Current
Derivatives, Fair Value [Line Items]
Derivative Asset		0.0	0.0
Interest rate risk programs | Risk Management Assets Noncurrent
Derivatives, Fair Value [Line Items]
Derivative Asset		0.0	18.5
Interest rate risk programs | Risk Management Liabilities Current
Derivatives, Fair Value [Line Items]
Derivative Liability		0.0	0.0
Interest rate risk programs | Risk Management Liabilities Noncurrent
Derivatives, Fair Value [Line Items]
Derivative Liability		76.2	9.5
Commodity price risk programs | Risk Management Assets Current
Derivatives, Fair Value [Line Items]
Derivative Asset		0.6	1.1
Commodity price risk programs | Risk Management Assets Noncurrent
Derivatives, Fair Value [Line Items]
Derivative Asset		3.8	4.4
Commodity price risk programs | Risk Management Liabilities Current
Derivatives, Fair Value [Line Items]
Derivative Liability		12.6	5.0
Commodity price risk programs | Risk Management Liabilities Noncurrent
Derivatives, Fair Value [Line Items]
Derivative Liability		$ 57.8	$ 37.2

[1] Presented in "Prepayments and other" on the Consolidated Balance Sheets.

[2] Presented in "Other accruals" on the Consolidated Balance Sheets.

[3] ⁽³⁾Presented in "Other accruals" on the Consolidated Balance Sheets.

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Property, Plant And Equipment (Schedule Of Property, Plant And Equipment) (Details) - USD ($) $ in Millions		Dec. 31, 2019	Dec. 31, 2018
Property, Plant and Equipment [Line Items]
Property Plant and Equipment		$ 24,541.9	$ 22,819.5
Accumulated Depreciation and Amortization		(7,629.7)	(7,277.0)
Net Property, Plant and Equipment		16,912.2	15,542.5
Gas Distribution Utility
Property, Plant and Equipment [Line Items]
Property Plant and Equipment	[1]	14,989.7	13,776.0
Accumulated Depreciation and Amortization	[1]	(3,556.0)	(3,373.8)
Electric Utility
Property, Plant and Equipment [Line Items]
Property Plant and Equipment	[1]	8,902.3	8,374.2
Accumulated Depreciation and Amortization	[1]	(3,973.8)	(3,809.5)
Common Utility
Property, Plant and Equipment [Line Items]
Property Plant and Equipment		153.3	155.8
Accumulated Depreciation and Amortization		(79.5)	(74.6)
Construction Work In Process
Property, Plant and Equipment [Line Items]
Property Plant and Equipment		457.3	474.8
Non-Utility And Other
Property, Plant and Equipment [Line Items]
Property Plant and Equipment		39.3	38.7
Accumulated Depreciation and Amortization		$ (20.4)	$ (19.1)

[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.

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Pension and Other Postretirement Benefits (Schedule of Plan Asset Mix Prior Year) (Details)	Dec. 31, 2019	Dec. 31, 2018
Pension Plan | Domestic Equities | Minimum
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	12.00%	12.00%
Pension Plan | Domestic Equities | Maximum
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	32.00%	32.00%
Pension Plan | International Equities | Minimum
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	6.00%	6.00%
Pension Plan | International Equities | Maximum
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	16.00%	16.00%
Pension Plan | Fixed Income | Minimum
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage		59.00%
Pension Plan | Fixed Income | Maximum
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage		71.00%
Pension Plan | Real Estate | Minimum
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage		0.00%
Pension Plan | Real Estate | Maximum
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage		7.00%
Pension Plan | Short-Term Investments/Other | Minimum
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	0.00%	0.00%
Pension Plan | Short-Term Investments/Other | Maximum
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	15.00%	15.00%
Other Postretirement Benefits | Domestic Equities | Minimum
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	0.00%	0.00%
Other Postretirement Benefits | Domestic Equities | Maximum
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	55.00%	55.00%
Other Postretirement Benefits | International Equities | Minimum
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	0.00%	0.00%
Other Postretirement Benefits | International Equities | Maximum
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	25.00%	25.00%
Other Postretirement Benefits | Fixed Income | Minimum
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage		20.00%
Other Postretirement Benefits | Fixed Income | Maximum
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage		100.00%
Other Postretirement Benefits | Real Estate | Minimum
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage		0.00%
Other Postretirement Benefits | Real Estate | Maximum
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage		0.00%
Other Postretirement Benefits | Short-Term Investments/Other | Minimum
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	0.00%	0.00%
Other Postretirement Benefits | Short-Term Investments/Other | Maximum
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	10.00%	10.00%

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Statements Of Consolidated Income (Loss) - USD ($) shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2019		Dec. 31, 2018		Dec. 31, 2017
Operating Revenues
Customer revenues	$ 5,053.4	[1]	$ 4,991.1	[1]	$ 4,730.2
Other revenues	155.5		123.4		144.4
Total Operating Revenues	5,208.9		5,114.5		4,874.6
Operating Expenses
Cost of Sales (excluding depreciation and amortization)	1,534.8		1,761.3		1,518.7
Operation and maintenance	1,354.7		2,352.9		1,601.7
Depreciation and amortization	717.4		599.6		570.3
Goodwill and Intangible Asset Impairment	414.5		0.0		0.0
Loss on sale of fixed assets and impairments, net	0.0		1.2		5.5
Other taxes	296.8		274.8		257.2
Total Operating Expenses	4,318.2		4,989.8		3,953.4
Operating Income (Loss)	890.7		124.7		921.2
Other Income (Deductions)
Interest expense, net	(378.9)		(353.3)		(353.2)
Other, net	(5.2)		43.5		(13.5)
Loss on early extinguishment of long-term debt	0.0		(45.5)		(111.5)
Total Other Deductions, Net	(384.1)		(355.3)		(478.2)
Income (Loss) before Income Taxes	506.6		(230.6)		443.0
Income Taxes	123.5		(180.0)		314.5
Net Income (Loss)	383.1		(50.6)		128.5
Preferred dividends	(55.1)		(15.0)		0.0
Net Income (Loss) Available to Common Shareholders	$ 328.0		$ (65.6)		$ 128.5
Earnings Per Share
Basic Earnings (Loss) Per Share	$ 0.88		$ (0.18)		$ 0.39
Diluted Earnings (Loss) Per Share	$ 0.87		$ (0.18)		$ 0.39
Basic Average Common Shares Outstanding	374,650		356,491		329,388
Diluted Average Common Shares	375,986		356,491		330,756

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

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Regulatory Matters (Rate Case Action) (Details) - USD ($) $ in Millions	May 29, 2019	May 22, 2019	Oct. 31, 2018	Aug. 28, 2018	Sep. 27, 2017
NIPSCO - Gas
Regulatory Matters [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount					$ 138.1
Public Utilities, Approved Rate Increase (Decrease), Amount					$ 105.6
Columbia Of Virginia
Regulatory Matters [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount				$ 14.2
Public Utilities, Approved Rate Increase (Decrease), Amount				$ 1.3
Columbia Of Maryland
Regulatory Matters [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount		$ 2.5
Public Utilities, Approved Rate Increase (Decrease), Amount	$ (0.1)
NIPSCO - Electric
Regulatory Matters [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount			$ 21.4
Public Utilities, Approved Rate Increase (Decrease), Amount			$ (53.5)

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Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Accounts receivable less reserve	$ 19.2	$ 21.1
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	600,000,000	400,000,000
Common stock, shares outstanding	382,135,680	372,363,656
Preferred Stock, Par or Stated Value Per Share	$ 0.01	$ 0.01
Preferred Stock, Shares Authorized	20,000,000	20,000,000
Preferred Stock, Shares Outstanding	440,000	420,000

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Fair Value (Tables)

12 Months Ended

Dec. 31, 2019

Fair Value Disclosures [Abstract]

Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis

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, 2019 and December 31, 2018:

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

Recurring Fair Value Measurements December 31, 2018 (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, 2018
Assets
Risk management assets	$	—	$	24.0	$	—	$	24.0
Available-for-sale securities	—		138.3		—		138.3
Total	$	—	$	162.3	$	—	$	162.3
Liabilities
Risk management liabilities	$	—	$	51.7	$	—	$	51.7
Total	$	—	$	51.7	$	—	$	51.7

Available-For-Sale Debt Securities

The amortized cost, gross unrealized gains and losses and fair value of available-for-sale securities at December 31, 2019 and 2018 were: 

December 31, 2019 (in millions)	Amortized Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
Available-for-sale 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
December 31, 2018 (in millions)	Amortized Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
Available-for-sale securities
U.S. Treasury debt securities	$	23.6	$	0.1	$	(0.1	)	$	23.6
Corporate/Other debt securities	117.7		0.4		(3.4		)	114.7
Total	$	141.3	$	0.5	$	(3.5	)	$	138.3

Carrying Amount And Estimated Fair Values Of Financial Instruments

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

At December 31, (in millions)	Carrying Amount 2019		Estimated Fair Value 2019		Carrying Amount 2018		Estimated Fair Value 2018
Long-term debt (including current portion)	$	7,869.6	$	8,764.4	$	7,155.4	$	7,228.3

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Transfers Of Financial Assets (Narrative) (Details) - USD ($) $ in Millions	3 Months Ended		12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Assets and Associated Liabilities of Transfers Accounted for as Secured Borrowings [Line Items]
Cash from financing activities			$ 46.0	$ 62.5
Securitization transaction fees	$ 2.6	$ 2.6	2.6	$ 2.6	$ 2.5
Accounts Receivable Program
Assets and Associated Liabilities of Transfers Accounted for as Secured Borrowings [Line Items]
Seasonal Limit	$ 465.0		$ 465.0

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Other Commitments And Contingencies Other Commitments and Contingencies (Expense Incurred and Insurance Recoveries) (Details) - USD ($) $ in Millions	3 Months Ended								4 Months Ended	12 Months Ended	16 Months Ended
	Dec. 31, 2019	[1]	Sep. 30, 2019	[1]	Jun. 30, 2019	[1]	Mar. 31, 2019	[1]	Dec. 31, 2018	Dec. 31, 2019	Dec. 31, 2019
Expense and Insurance Recoveries [Line Items]
Third-Party Claims, fines, penalties, and settlements									$ 757	$ 284	$ 1,041
Other incident-related costs									266	154	420
Total									1,023	438	1,461
Insurance Recoveries	$ (130)		$ 0		$ (435)		$ (100)		(135)	(665)	(800)
Impact to income (loss) before income taxes									$ 888	$ (227)	$ 661

[1] $5 million of insurance recoveries were collected during 2018.

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Other, Net (Tables)

12 Months Ended

Dec. 31, 2019

Other Nonoperating Income (Expense) [Abstract]

Schedule Of Other, Net

Year Ended December 31, (in millions)	2019			2018			2017
Interest income	$	7.7		$	6.6		$	4.6
AFUDC equity	8.0			14.2			12.6
Charitable contributions(1)	(5.1		)	(45.3		)	(19.9		)
Pension and other postretirement non-service cost(2)	(16.5		)	18.0			(10.6		)
Interest rate swap settlement gain(3)	—			46.2			—
Miscellaneous	0.7			3.8			(0.2		)
Total Other, net	$	(5.2	)	$	43.5		$	(13.5	)

⁽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 19, "Other Commitments and Contingencies" for additional information on the Greater Lawrence Incident.

⁽²⁾ See Note 11, "Pension and Other Postretirement Benefits" for additional information.

⁽³⁾ See Note 9, "Risk Management Activities" for additional information.

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Interest Expense, Net (Details) - USD ($) $ in Millions	3 Months Ended		12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Interest Expense [Abstract]
Interest on long-term debt			$ 327.7	$ 342.2	$ 354.8
Interest on short-term borrowings			50.8	31.8	14.9
Debt discount/cost amortization			8.3	7.7	7.2
Accounts receivable securitization fees	$ 2.6	$ 2.6	2.6	2.6	2.5
Allowance for borrowed funds used and interest capitalized during construction			(7.5)	(9.1)	(6.2)
Debt-based post-in-service carrying charges			(18.7)	(35.0)	(36.4)
Other			15.7	13.1	16.4
Total Interest Expense, net			$ 378.9	$ 353.3	$ 353.2

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Subsequent Event

12 Months Ended

Dec. 31, 2019

Subsequent Event [Abstract]

Subsequent Event

Subsequent Event

On February 26, 2020, NiSource and Columbia of Massachusetts entered into the Asset Purchase Agreement with Eversource. 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 Eversource agreed to assume certain liabilities of Columbia of Massachusetts and its affiliates. The liabilities assumed by Eversource under the Asset Purchase Agreement do not include, among others, any liabilities arising out of the Greater Lawrence Incident or 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 occurs prior to the closing in connection with the Massachusetts Business. The Asset Purchase Agreement provides for a purchase price of $1,100 million in cash, subject to adjustment based on Columbia of Massachusetts’ net working capital as of the closing. The closing of the transactions contemplated by the Asset Purchase Agreement is subject to Hart-Scott Rodino Antitrust Improvements Act of 1976 and regulatory approvals, resolution of certain proceedings before governmental bodies and other conditions. The Massachusetts Business did not meet the requirements under GAAP to be classified as held-for-sale as of December 31, 2019. When the Massachusetts Business meets the requirements to be classified as held-for-sale, in each period leading up to the closing date of the transaction, the assets and liabilities of the Massachusetts Business will be measured at fair value, less costs to sell. The final pre-tax gain or loss on the transaction will be determined as of the closing date. Assuming the Massachusetts Business is classified as held-for-sale at March 31, 2020, we estimate that the total pre-tax loss to be measured in the quarter ended March 31, 2020 will be approximately $360 million, based on December 31, 2019 asset and liability balances and estimated transaction costs. This estimated pre-tax loss is subject to change based on estimated transaction costs, working capital adjustments and asset and liability balances at each measurement date leading up to the closing date. The sale is expected to close by September 30, 2020, subject to closing conditions.

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Interest Expense, Net

12 Months Ended

Dec. 31, 2019

Interest Expense [Abstract]

Interest Expense, Net

Interest Expense, Net

Year Ended December 31, (in millions)	2019			2018			2017
Interest on long-term debt	$	327.7		$	342.2		$	354.8
Interest on short-term borrowings	50.8			31.8			14.9
Debt discount/cost amortization	8.3			7.7			7.2
Accounts receivable securitization fees	2.6			2.6			2.5
Allowance for borrowed funds used and interest capitalized during construction	(7.5		)	(9.1		)	(6.2		)
Debt-based post-in-service carrying charges	(18.7		)	(35.0		)	(36.4		)
Other	15.7			13.1			16.4
Total Interest Expense, net	$	378.9		$	353.3		$	353.2

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Risk Management Activities

12 Months Ended

Dec. 31, 2019

Risk Management Activities [Abstract]

Risk Management Activities

Risk Management Activities

We are exposed to certain risks relating to 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)	2019		2018
Risk Management Assets - Current(1)
Interest rate risk programs	$	—	$	—
Commodity price risk programs	0.6		1.1
Total	$	0.6	$	1.1
Risk Management Assets - Noncurrent(2)
Interest rate risk programs	$	—	$	18.5
Commodity price risk programs	3.8		4.4
Total	$	3.8	$	22.9
Risk Management Liabilities - Current(3)
Interest rate risk programs	$	—	$	—
Commodity price risk programs	12.6		5.0
Total	$	12.6	$	5.0
Risk Management Liabilities - Noncurrent
Interest rate risk programs	$	76.2	$	9.5
Commodity price risk programs	57.8		37.2
Total	$	134.0	$	46.7

⁽¹⁾Presented in "Prepayments and other" on the Consolidated Balance Sheets.

⁽²⁾Presented in "Deferred charges and other" on the Consolidated Balance Sheets.

⁽³⁾Presented in "Other accruals" on the Consolidated Balance Sheets.

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 ten years and is limited to twenty percent 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, 2019, we have 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 effective portions of the gains and losses related to these swaps are recorded to AOCI and are 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" on the Statements of Consolidated Income (Loss) due to the probability associated with the forecasted borrowing transactions no longer occurring.

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

Our derivative instruments measured at fair value as of December 31, 2019 and 2018 do not contain any credit-risk-related contingent features.

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Nature of Operations And Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2019

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Nature of Operations and Summary of Significant Accounting Policies

Nature of Operations and Summary of Significant Accounting Policies

A.       Company Structure and Principles of Consolidation.  We are an energy holding company incorporated in Delaware and headquartered in Merrillville, Indiana. Our subsidiaries are fully regulated natural gas and electric utility companies serving approximately 4.0 million customers in seven states. We generate substantially all of our operating income through these rate-regulated businesses. The consolidated financial statements include the accounts of us and our majority-owned subsidiaries after the elimination of all intercompany accounts and transactions.

On February 26, 2020, NiSource and Columbia of Massachusetts entered into the Asset Purchase Agreement with Eversource, a Massachusetts voluntary association. 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 business of storing, distributing or transporting natural gas to residential, commercial and industrial customers in Massachusetts, as conducted by Columbia of Massachusetts, and Eversource agreed to assume certain liabilities of Columbia of Massachusetts and its affiliates. For additional information, see Note 26, “Subsequent Event.”

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 and weather. 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 $350.5 million and $324.2 million as of December 31, 2019 and 2018, 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 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, 2019, 2018 or 2017. Refer to Note 17, "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.

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 regulatory accounting. In such an event, a write-down of all or a portion of our existing regulatory assets and liabilities could result. If transition cost recovery was approved by the appropriate regulatory bodies that would meet the requirements under GAAP for continued accounting as regulatory assets and liabilities during such recovery period, the regulatory assets and liabilities would be reported at the recoverable amounts. If unable to continue to apply

the provisions of regulatory accounting, we would be required to apply the provisions of ASC 980-20, Discontinuation of Rate-Regulated Accounting. In management’s opinion, our regulated subsidiaries will be subject to regulatory accounting for the foreseeable future. Refer to Note 8, "Regulatory Matters," for additional information.

G.       Plant and Other Property and Related Depreciation and Maintenance.    Property, plant and equipment (principally utility plant) is stated at cost. The 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 is generally depreciated on a straight-line basis over the life of the associated asset. Refer to Note 5, "Property, Plant and Equipment," for additional information related to depreciation expense.

For rate-regulated companies, AFUDC is capitalized on all classes of property except organization costs, land, autos, office equipment, tools and other general property purchases. The allowance is applied to construction costs for that period of time between the date of the expenditure and the date on which such project is placed in service. Our pre-tax rate for AFUDC was 3.0% in 2019, 3.5% in 2018 and 4.0% in 2017.

Generally, our subsidiaries follow the practice of charging maintenance and repairs, including the cost of removal of minor items of property, to expense as incurred. When our subsidiaries retire regulated property, plant and equipment, original cost plus the cost of retirement, less salvage value, is charged to accumulated depreciation. However, when it becomes probable a regulated asset will be retired substantially in advance of its original expected useful life or is abandoned, the cost of the asset and the corresponding accumulated depreciation is recognized as a separate asset. If the asset is still in operation, the net amount is classified as "Other property, at cost, less accumulated depreciation" on the Consolidated Balance Sheets. If the asset is no longer operating, the net amount is classified in "Regulatory assets" on the Consolidated Balance Sheets. If we are able to recover a full return of and on investment, the carrying value of the asset is based on historical cost. If we are not able to recover a full return on investment, a loss on impairment is recognized to the extent the net book value of the asset exceeds the present value of future revenues discounted at the incremental borrowing rate.

When our subsidiaries sell entire regulated operating units, or retire or sell nonregulated properties, the original cost and accumulated depreciation and amortization balances are removed from "Property, Plant and Equipment" on the Consolidated Balance Sheets. Any gain or loss is recorded in earnings, unless otherwise required by the applicable regulatory body. Refer to Note 5, "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, except for certain significant enterprise-wide technology investments which are amortized over a ten-year period.

External and internal up-front implementation costs associated with cloud computing arrangements that are service contracts are deferred on the Consolidated Balance Sheets. Once the installed software is ready for its intended use, such deferred costs are amortized on a straight-line basis to "Operation and maintenance," over the minimum term of the contract plus contractually-provided renewal periods that are reasonable expected to be exercised -- generally up to a maximum of five years.

H.        Goodwill and Other Intangible Assets.    Substantially all of our goodwill relates to the excess of cost over the fair value of the net assets acquired in the Columbia acquisition on November 1, 2000. We test our goodwill for impairment annually as of May 1, or more frequently if events and circumstances indicate that goodwill might be impaired. Fair value of our reporting units is determined using a combination of income and market approaches.

We had other intangible assets consisting primarily of franchise rights apart from goodwill that were identified as part of the purchase price allocations associated with the acquisition of Columbia of Massachusetts, which were being amortized on a straight-line basis over forty years from the date of acquisition.

During the fourth quarter of 2019, we impaired goodwill and intangible assets related to Columbia of Massachusetts. See Note 6, "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, 2019 and 2018 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 18, "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 8, "Regulatory Matters," for additional information.

K.        Inventory.    Both the LIFO inventory methodology and the weighted average cost methodology are used to value natural gas in storage, as approved by regulators for all of our regulated subsidiaries. Inventory valued using LIFO was $47.2 million and $47.5 million at December 31, 2019 and 2018, 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 $25.5 million and $12.2 million at December 31, 2019 and 2018, respectively. Gas inventory valued using the weighted average cost methodology was $203.7 million at December 31, 2019 and $239.3 million at December 31, 2018.

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 9, "Risk Management Activities," for additional information.

N.        Income Taxes and Investment Tax Credits.    We record income taxes to recognize full interperiod tax allocations. Under the asset and liability method, deferred income taxes are provided for the tax consequences of temporary differences by applying enacted statutory tax rates applicable to future years to differences between the financial statement carrying amount and the tax basis of existing assets and liabilities. Investment tax credits associated with regulated operations are deferred and amortized as a reduction to income tax expense over the estimated useful lives of the related properties.

To the extent certain deferred income taxes of the regulated companies are recoverable or payable through future rates, regulatory assets and liabilities have been established. Regulatory assets for income taxes are primarily attributable to property-related tax timing differences for which deferred taxes had not been provided in the past, when regulators did not recognize such taxes as costs in the rate-making process. Regulatory liabilities for income taxes are primarily attributable to the regulated companies’ obligation to refund to ratepayers deferred income taxes provided at rates higher than the current Federal income tax rate. Such property-related amounts are credited to ratepayers using either the average rate assumption method or the reverse South Georgia method. Non property-related amounts are credited to ratepayers consistent with state utility commission direction.

Pursuant to the Internal Revenue Code and relevant state taxing authorities, we and our subsidiaries file consolidated income tax returns for federal and certain state jurisdictions. We and our subsidiaries are parties to a tax sharing agreement. Income taxes recorded by each party represent amounts that would be owed had the party been separately subject to tax.

O.       Environmental Expenditures.    We accrue for costs associated with environmental remediation obligations when the incurrence of such costs is probable and the amounts can be reasonably estimated, regardless of when the expenditures are actually made. The undiscounted estimated future expenditures are based on currently enacted laws and regulations, existing technology and estimated site-specific costs where assumptions may be made about the nature and extent of site contamination, the extent of

cleanup efforts, costs of alternative cleanup methods and other variables. The liability is adjusted as further information is discovered or circumstances change. The accruals for estimated environmental expenditures are recorded on the Consolidated Balance Sheets in “Legal and environmental” 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 19, "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 19-E "Other Matters" for further information on accrued insurance liabilities related to the Greater Lawrence Incident.

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Property, Plant And Equipment

12 Months Ended

Dec. 31, 2019

Property, Plant and Equipment [Abstract]

Property, Plant And Equipment

Property, Plant and Equipment

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

At December 31, (in millions)	2019			2018
Property, Plant and Equipment
Gas Distribution Utility(1)	$	14,989.7		$	13,776.0
Electric Utility(1)	8,902.3			8,374.2
Corporate	153.3			155.8
Construction Work in Process	457.3			474.8
Non-Utility and Other	39.3			38.7
Total Property, Plant and Equipment	$	24,541.9		$	22,819.5
Accumulated Depreciation and Amortization
Gas Distribution Utility(1)	$	(3,556.0	)	$	(3,373.8	)
Electric Utility(1)	(3,973.8		)	(3,809.5		)
Corporate	(79.5		)	(74.6		)
Non-Utility and Other	(20.4		)	(19.1		)
Total Accumulated Depreciation and Amortization	$	(7,629.7	)	$	(7,277.0	)
Net Property, Plant and Equipment	$	16,912.2		$	15,542.5

⁽¹⁾NIPSCO’s common utility plant and associated accumulated depreciation and amortization are allocated between Gas Distribution Utility and Electric Utility Property, Plant and Equipment.

The weighted average depreciation provisions for utility plant, as a percentage of the original cost, for the periods ended December 31, 2019, 2018 and 2017 were as follows:

	2019		2018		2017
Electric Operations(1)	2.8	%	2.9	%	3.4	%
Gas Distribution Operations	2.5	%	2.2	%	2.1	%

⁽¹⁾Lower depreciation rate beginning in 2018 due to reduced EERM-related depreciation expense and higher depreciable base from transmission assets being placed into service in 2018.

We recognized depreciation expense of $612.2 million, $503.4 million and $501.5 million for the years ended 2019, 2018 and 2017, respectively.

Amortization of Software Costs. We amortized $55.5 million, $54.1 million and $44.0 million in 2019, 2018 and 2017, respectively, related to software costs. Our unamortized software balance was $169.6 million and $159.5 million at December 31, 2019 and 2018, respectively.

Amortization of Cloud Computing Costs. We amortized $1.6 million and $0.1 million in 2019 and 2018, respectively, related to cloud computing costs. Our unamortized cloud computing balance was $14.2 million and $4.9 million at December 31, 2019 and 2018, respectively.

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Share-Based Compensation

12 Months Ended

Dec. 31, 2019

Share-based Payment Arrangement, Noncash Expense [Abstract]

Share-Based Compensation

Share-Based Compensation

Our stockholders most recently approved the NiSource Inc. 2010 Omnibus Incentive Plan (“Omnibus Plan”) at the Annual Meeting of Stockholders held on May 12, 2015. The 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 long-term incentive plan approved by stockholders on April 13, 1994 (“1994 Plan”) and the Director Stock Incentive Plan (“Director Plan”). The Omnibus Plan provides that the number of shares of common stock of NiSource available for awards is 8,000,000 plus the number of shares subject to outstanding awards that expire or terminate for any reason that were granted under either the 1994 Plan or the Director Plan, plus the number of shares that were awarded as a result of the Separation-related adjustments. At December 31, 2019, there were 3,313,183 shares reserved for future awards under the Omnibus Plan.

We recognized stock-based employee compensation expense of $16.3 million, $15.2 million and $15.3 million, during 2019, 2018 and 2017, respectively, as well as related tax benefits of $4.0 million, $3.7 million and $5.9 million, respectively. We recognized related excess tax benefits from the distribution of vested share-based employee compensation of $0.8 million, $1.0 million and $4.4 million in 2019, 2018 and 2017, respectively.

As of December 31, 2019, the total remaining unrecognized compensation cost related to non-vested awards amounted to $19.5 million, which will be amortized over the weighted-average remaining requisite service period of 1.8 years.

Restricted Stock Units and Restricted Stock. In 2019, we granted 166,031 restricted stock units and shares of restricted stock to employees, subject to service conditions. The total grant date fair value of the restricted stock units and shares of restricted stock was $4.1 million, based on the average market price of our common stock at the date of each grant less the present value of any dividends not received during the vesting period, which will be expensed over the vesting period which is generally three years. As of December 31, 2019, 157,786 non-vested restricted stock units and shares of restricted stock granted in 2019 were outstanding as of December 31, 2019.

In 2018, we granted 158,689 restricted stock units and shares of restricted stock to employees, subject to service conditions. The total grant date fair value of the restricted stock units and shares of restricted stock was $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 years. As of December 31, 2019, 136,820 non-vested restricted stock units and shares of restricted stock granted in 2018 were outstanding as of December 31, 2019.

Restricted stock units and shares of restricted stock granted to employees in 2017 were immaterial.

If an employee terminates employment before the service conditions lapse under the 2017, 2018 or 2019 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.

(shares)	Restricted Stock Units		Weighted Average Award Date Fair  Value Per Unit ($)
Non-vested at December 31, 2018	178,678		21.82
Granted	166,031		24.93
Forfeited	(21,547	)	22.99
Vested	(20,556	)	21.08
Non-vested at December 31, 2019	302,606		23.49

Performance Shares. In 2019, we granted 552,389 performance shares subject to service, performance and market conditions. The service conditions for these awards lapse on February 28, 2022. The performance period for the awards is the period beginning January 1, 2019 and ending December 31, 2021. The performance conditions are based on the achievement of one non-GAAP financial measure 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 unusual or non-recurring 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 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 beginning on December 31, 2018 and ending on December 31, 2021) 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 market conditions. The grant date fair value of the awards was $11.7 million, 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. As of December 31, 2019, 422,825 of these non-vested performance shares granted in 2019 remained outstanding.

If a threshold level of cumulative NOEPS financial performance is achieved, additional operational measures which we refer to as the customer value index, which consists of five equally weighted areas of focus including safety, customer satisfaction, financial, culture and environmental apply. Each area of focus represents 20% of the customer value index shares, and the targets for all areas must be met for these awards to be eligible for 100% payout of these awards. The grant date fair value of the awards was $2.5 million, 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. As of December 31, 2019, 97,574 of these awards that were issued in 2019 remained outstanding.

In 2018, we awarded 514,338 performance shares subject to service, performance and market conditions. The service conditions for these awards lapse on February 26, 2021. The performance period for the awards is the period beginning January 1, 2018 and ending December 31, 2020. The performance conditions are based on the achievement of one non-GAAP financial measure 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 unusual or non-recurring 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 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 beginning on December 31, 2017 and ending on December 31, 2020) 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 market conditions. The grant date fair value of the awards was $9.2 million, 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. As of December 31, 2019, 368,811 of these non-vested performance shares granted in 2018 remained outstanding.

If a threshold level of cumulative NOEPS financial performance is achieved, additional operational measures which we refer to as the customer value index, which consists of five equally weighted areas of focus including safety, customer satisfaction, financial, culture and environmental apply. Each area of focus represents 20% of the customer value index shares and the targets for all areas must be met for these awards to be eligible for 100% payout of these 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 718. The service inception date fair value of the awards was $2.4 million, 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. As of December 31, 2019, 85,111 of these awards that were issued in 2018 remained outstanding. The service conditions for these awards lapse on February 26, 2021.

In 2017, we granted 660,750 performance shares subject to service, performance and market conditions. The grant date fair value of the awards was $12.9 million, 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. The performance conditions are based on achievement of non-GAAP financial measures similar to those discussed above: cumulative net operating earnings per share for the three-year period ending December 31, 2019 and relative total shareholder return (calculated using a 20 trading day average of our closing price beginning on December 31, 2016 and ending on December 31, 2019). As of December 31, 2019, 528,928 non-vested performance shares granted in 2017 remained outstanding. The service conditions for these awards lapse on February 28, 2020.

(shares)	Performance Awards		Weighted Average Grant Date Fair  Value Per Unit ($)(1)
Non-vested at December 31, 2018	1,634,718		20.45
Granted	552,389		25.77
Forfeited	(156,700	)	26.72
Vested	(527,156	)	28.11
Non-vested at December 31, 2019	1,503,251		22.74

⁽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 11, 2010, awards to non-employee directors may be made only under the 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 election to defer. Certain restricted stock units remain outstanding from 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, 2019, 165,768 restricted stock units are outstanding to non-employee directors under either the Omnibus Plan or the Director Plan. Of this amount, 49,926 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 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, 2019, 2018 and 2017, we recognized 401(k) match, profit sharing and non-elective contribution expense of $37.5 million, $37.6 million and $37.6 million, respectively.

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Fair Value

12 Months Ended

Dec. 31, 2019

Fair Value Disclosures [Abstract]

Fair Value

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, 2019 and December 31, 2018:

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

Recurring Fair Value Measurements December 31, 2018 (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, 2018
Assets
Risk management assets	$	—	$	24.0	$	—	$	24.0
Available-for-sale securities	—		138.3		—		138.3
Total	$	—	$	162.3	$	—	$	162.3
Liabilities
Risk management liabilities	$	—	$	51.7	$	—	$	51.7
Total	$	—	$	51.7	$	—	$	51.7

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 which reduce exposures. As of December 31, 2019 and 2018, there were no material transfers between fair value hierarchies. Additionally, there were no changes in the method or significant assumptions used to estimate the fair value of our financial instruments.

We have entered into forward-starting interest rate swaps to hedge the interest rate risk on coupon payments of forecasted issuances of long-term debt. These derivatives are designated as cash flow hedges. Credit risk is considered in the fair value calculation of each agreement. 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. For additional information, see Note 9, "Risk Management Activities."

NIPSCO has entered into long-term forward natural gas purchase instruments that range from five to ten years 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 9, “Risk Management Activities.”

Available-for-sale securities are investments pledged as collateral for trust accounts related to our wholly-owned insurance company. Available-for-sale securities are included within “Other investments” in the Consolidated Balance Sheets. 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. Total unrealized gains and losses from available-for-sale securities are included in other comprehensive income. The amortized cost, gross unrealized gains and losses and fair value of available-for-sale securities at December 31, 2019 and 2018 were: 

December 31, 2019 (in millions)	Amortized Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
Available-for-sale 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
December 31, 2018 (in millions)	Amortized Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
Available-for-sale securities
U.S. Treasury debt securities	$	23.6	$	0.1	$	(0.1	)	$	23.6
Corporate/Other debt securities	117.7		0.4		(3.4		)	114.7
Total	$	141.3	$	0.5	$	(3.5	)	$	138.3

 

Realized gains and losses on available-for-sale securities were immaterial for the year-ended December 31, 2019 and 2018.

The cost of maturities sold is based upon specific identification. At December 31, 2019, approximately $7.7 million of U.S. Treasury debt securities and approximately $6.0 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, 2019 and 2018.

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.

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 6, “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, 2019 and 2018, there was no change in the method or significant assumptions used to estimate the fair value of long-term debt.

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

At December 31, (in millions)	Carrying Amount 2019		Estimated Fair Value 2019		Carrying Amount 2018		Estimated Fair Value 2018
Long-term debt (including current portion)	$	7,869.6	$	8,764.4	$	7,155.4	$	7,228.3

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Property, Plant and Equipment (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Property, Plant and Equipment [Line Items]
Depreciation	$ 612.2	$ 503.4	$ 501.5
Capitalized Computer Software, Amortization	55.5	54.1	$ 44.0
Capitalized Computer Software, Gross	169.6	159.5
Capitalized Cloud Computing, Amortization	1.6	0.1
Capitalized Cloud Computing, Gross	$ 14.2	$ 4.9

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Pension and Other Postretirement Benefits (Schedule Of Key Assumptions That Were Used To Calculate The Net Periodic Benefits Cost) (Details)		12 Months Ended
		Dec. 31, 2019		Dec. 31, 2018	Dec. 31, 2017
Defined Benefit Plan Disclosure [Line Items]
Expected Long-Term Rate of Return on Plan Assets		6.10%
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Discount Rate		4.48%	[1]	3.79%	4.40%	[1]
Defined Benefit Plan Assumptions Used In Calculating Net Periodic Cost Discount Rate for Interest Cost		3.84%	[1]	3.15%	3.31%	[1]
Expected Long-Term Rate of Return on Plan Assets		6.10%		7.00%	7.25%
Rate of Compensation Increases		4.00%		4.00%	4.00%
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Discount Rate	[1]	4.59%		3.89%	4.58%
Defined Benefit Plan Assumptions Used In Calculating Net Periodic Cost Discount Rate for Interest Cost	[1]	3.94%		3.27%	3.48%
Expected Long-Term Rate of Return on Plan Assets		5.83%		5.80%	6.99%
Rate of Compensation Increases		0.00%		0.00%	0.00%

[1] In January 2017, we changed the method used to estimate the service and interest components of net periodic benefit cost for pension and other postretirement benefits. This change, compared to the previous method, resulted in a decrease in the actuarially-determined service and interest cost components. Historically, we estimated service and interest cost utilizing a single weighted-average discount rate derived from the yield curve used to measure the benefit obligation at the beginning of the period. For fiscal 2017 and beyond, we now utilize a full yield curve approach to estimate these components by applying the specific spot rates along the yield curve used in the determination of the benefit obligation to the relevant projected cash flows.

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Supplemental Cash Flow Information (Tables)

12 Months Ended

Dec. 31, 2019

Supplemental Cash Flow Information [Abstract]

Schedule of Cash Flow, Supplemental Disclosures

The following table provides additional information regarding our Consolidated Statements of Cash Flows for the years ended December 31, 2019, 2018 and 2017:

Year Ended December 31, (in millions)	2019		2018		2017
Supplemental Disclosures of Cash Flow Information
Non-cash transactions:
Capital expenditures included in current liabilities	$	223.6	$	152.0	$	173.0
Assets acquired under a finance lease	26.4		54.6		11.5
Assets acquired under an operating lease	13.4		—		—
Reclassification of other property to regulatory assets(1)	—		245.3		—
Assets recorded for asset retirement obligations(2)	54.6		78.1		11.4
Schedule of interest and income taxes paid:
Cash paid for interest, net of interest capitalized amounts	$	349.7	$	354.2	$	339.9
Cash paid for income taxes, net of refunds	10.8		3.3		5.5

⁽¹⁾See Note 8 "Regulatory Matters" for additional information.

⁽²⁾See Note 7 "Asset Retirement Obligations" for additional information.

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Pension and Other Postretirement Benefits (Schedule Of Changes In The Fair Value Of The Plan Level Three Assets) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at beginning of year		$ 2,084.1
Fair value of plan assets at end of year		2,342.3	$ 2,084.1
Significant Unobservable Inputs (Level 3) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at beginning of year		86.1	98.9
Total gains or losses (unrealized / realized)			2.7
Purchases			2.5
(Sales)			(18.0)
Fair value of plan assets at end of year		0.0	86.1
Defined Benefit Plan, Plan Assets Level 3 Reconciliation, Increase (Decrease) for Assets Transferred into (out of) Level 3	[1]	(86.1)
Real Estate [Member] | Significant Unobservable Inputs (Level 3) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at beginning of year		52.7	49.9
Total gains or losses (unrealized / realized)			1.7
Purchases			1.8
(Sales)			(0.7)
Fair value of plan assets at end of year		0.0	52.7
Defined Benefit Plan, Plan Assets Level 3 Reconciliation, Increase (Decrease) for Assets Transferred into (out of) Level 3	[1]	(52.7)
Private Equity Limited Partnerships [Member] | U.S. Multi-Strategy [Member] | Significant Unobservable Inputs (Level 3) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at beginning of year		18.5	26.7
Total gains or losses (unrealized / realized)			2.4
Purchases			0.7
(Sales)			(11.3)
Fair value of plan assets at end of year		0.0	18.5
Defined Benefit Plan, Plan Assets Level 3 Reconciliation, Increase (Decrease) for Assets Transferred into (out of) Level 3	[1]	(18.5)
Private Equity Limited Partnerships [Member] | International Multi-Strategy [Member] | Significant Unobservable Inputs (Level 3) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at beginning of year		12.5	19.1
Total gains or losses (unrealized / realized)			(0.6)
Purchases			0.0
(Sales)			(6.0)
Fair value of plan assets at end of year		0.0	12.5
Defined Benefit Plan, Plan Assets Level 3 Reconciliation, Increase (Decrease) for Assets Transferred into (out of) Level 3	[1]	(12.5)
Private Equity Limited Partnerships [Member] | Distressed Opportunities [Member] | Significant Unobservable Inputs (Level 3) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at beginning of year		2.4	3.2
Total gains or losses (unrealized / realized)			(0.8)
Purchases			0.0
(Sales)			0.0
Fair value of plan assets at end of year		0.0	$ 2.4
Defined Benefit Plan, Plan Assets Level 3 Reconciliation, Increase (Decrease) for Assets Transferred into (out of) Level 3	[1]	$ (2.4)

[1] ⁽¹⁾ Level 3 assets from the prior year were reclassified in the current year 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.

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Leases (Right-of-Use Assets and Liabilities) (Details) - USD ($) $ in Millions	Dec. 31, 2019	Jan. 01, 2019
Lessee, Lease, Description [Line Items]
Finance Lease, Right-of-Use Asset, Statement of Financial Position [Extensible List]	us-gaap:NetPropertyPlantandEquipment
Finance Lease, Right-of-Use Asset	$ 179.5
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible List]	us-gaap:DeferredChargesAndOther
Operating Lease, Right-of-Use Asset	$ 64.2	$ 57.0
Total leased assets	$ 243.7
Finance Lease, Liability, Current, Statement of Financial Position [Extensible List]	us-gaap:Currentportionoflong-termdebt
Finance Lease, Liability, Current	$ 13.4
Operating Lease, Liability, Current, Statement of Financial Position [Extensible List]	us-gaap:OtherAccruals
Operating Lease, Liability, Current	$ 13.2
Finance Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List]	us-gaap:Long-termDebtExcludingAmountsDueWithinOneYear
Finance Lease, Liability, Noncurrent	$ 188.1
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List]	us-gaap:OtherNoncurrentLiabilities
Operating Lease, Liability, Noncurrent	$ 51.6
Total Lease Liability	$ 266.3

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Pension and Other Postretirement Benefits (Schedule Of Significant Actuarial Assumptions In Determining Funded Status Plan) (Details)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Discount Rate	3.12%	4.26%
Rate of Compensation Increases	4.00%	4.00%
Trend for Next Year	0.00%	0.00%
Ultimate Trend	0.00%	0.00%
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Discount Rate	3.21%	4.31%
Rate of Compensation Increases	0.00%	0.00%
Trend for Next Year	6.68%	8.48%
Ultimate Trend	4.50%	4.50%
Year Ultimate Trend Reached	2028	2026

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Fair Value (Narrative) (Details) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2019 USD ($)	Dec. 31, 2019 USD ($)
Fair Value Disclosure [Line Items]
Transfers between Fair Value Hierarchies		$ 0.0
U.S. Treasury debt securities
Fair Value Disclosure [Line Items]
Available-for-sale securities, maturities of less than a year	$ 7.7	7.7
Corporate/Other debt securities
Fair Value Disclosure [Line Items]
Available-for-sale securities, maturities of less than a year	6.0	$ 6.0
Columbia Of Massachusetts
Fair Value Disclosure [Line Items]
Goodwill, Impairment Loss	204.8
Impairment of Intangible Assets, Finite-lived	$ 209.7

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Revenue Recognition (Revenue Recognition Under Previous Guidance) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Revenue Recognition Under Previous Guidance [Line Items]
Total Operating Revenues	$ 5,208.9	$ 5,114.5	$ 4,874.6
Previous Accounting Guidance | Gas Distribution [Member]
Revenue Recognition Under Previous Guidance [Line Items]
Total Operating Revenues	2,336.1	2,348.4	2,063.2
Previous Accounting Guidance | Gas Transportation [Member]
Revenue Recognition Under Previous Guidance [Line Items]
Total Operating Revenues	1,171.3	1,055.2	1,021.5
Previous Accounting Guidance | Electric [Member]
Revenue Recognition Under Previous Guidance [Line Items]
Total Operating Revenues	1,698.5	1,707.4	1,785.5
Previous Accounting Guidance | Other [Member]
Revenue Recognition Under Previous Guidance [Line Items]
Total Operating Revenues	$ 3.0	$ 3.5	$ 4.4

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2019

Income Tax Disclosure [Abstract]

Schedule Of Components Of Income Tax Expense

The components of income tax expense (benefit) were as follows: 

Year Ended December 31, (in millions)	2019			2018			2017
Income Taxes
Current
Federal	$	—		$	—		$	—
State	5.2			8.2			7.8
Total Current	5.2			8.2			7.8
Deferred
Federal	110.7			(209.4		)	302.7
State	9.0			22.2			5.0
Total Deferred	119.7			(187.2		)	307.7
Deferred Investment Credits	(1.4		)	(1.0		)	(1.0		)
Income Taxes	$	123.5		$	(180.0	)	$	314.5

Schedule Of Reasons Behind Differences In Computation Of Total Income Taxes

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)	2019					2018					2017
Book income (loss) before income taxes	$	506.6				$	(230.6	)			$	443.0
Tax expense (benefit) at statutory federal income tax rate	106.5			21.0	%	(48.4		)	21.0	%	155.0			35.0	%
Increases (reductions) in taxes resulting from:
State income taxes, net of federal income tax benefit	10.1			2.0		24.7			(10.7	)	6.9			1.5
Amortization of regulatory liabilities	(29.4		)	(5.8	)	(29.3		)	12.7		(2.4		)	(0.5	)
Goodwill impairment	43.0			8.5		—			—		—			—
Fines and penalties	11.5			2.3		0.2			(0.1	)	2.8			0.6
Charitable contribution carryover	(2.5		)	(0.5	)	—			—		(1.2		)	(0.3	)
State regulatory proceedings	(9.5		)	(1.9	)	(127.8		)	55.4		—			—
Remeasurement due to TCJA	—			—		—			—		161.1			36.4
Employee stock ownership plan dividends and other compensation	(2.0		)	(0.4	)	(2.2		)	1.0		(6.5		)	(1.5	)
Other adjustments	(4.2		)	(0.8	)	2.8			(1.2	)	(1.2		)	(0.2	)
Income Taxes	$	123.5		24.4	%	$	(180.0	)	78.1	%	$	314.5		71.0	%

Schedule Of Principal Components Of Net Deferred Tax Liability

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)	2019		2018
Deferred tax liabilities
Accelerated depreciation and other property differences	$	2,516.9	$	2,458.0
Other regulatory assets	381.5		375.4
Total Deferred Tax Liabilities	2,898.4		2,833.4
Deferred tax assets
Other regulatory liabilities and deferred investment tax credits (including TCJA)	336.1		365.5
Pension and other postretirement/postemployment benefits	152.1		157.5
Net operating loss carryforward and AMT credit carryforward	765.9		849.8
Environmental liabilities	25.4		24.4
Other accrued liabilities	35.3		37.5
Other, net	98.3		68.2
Total Deferred Tax Assets	1,413.1		1,502.9
Net Deferred Tax Liabilities	$	1,485.3	$	1,330.5

Schedule of Unrecognized Tax Benefits Roll Forward

A reconciliation of the beginning and ending amounts of unrecognized tax benefits is as follows:

Reconciliation of Unrecognized Tax Benefits (in millions)	2019			2018			2017
Unrecognized Tax Benefits - Opening Balance	$	1.2		$	1.4		$	2.6
Gross decreases - tax positions in prior period	(0.6		)	(0.4		)	(1.4		)
Gross increases - current period tax positions	22.6			0.2			0.2
Unrecognized Tax Benefits - Ending Balance	$	23.2		$	1.2		$	1.4
Offset for net operating loss carryforwards	(22.6		)	—			—
Balance - Less Net Operating Loss Carryforwards	$	0.6		$	1.2		$	1.4

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Supplemental Cash Flow Information (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Non-cash transactions:
Capital expenditures included in current liabilities		$ 223.6	$ 152.0	$ 173.0
Assets acquired under a finance lease		26.4	54.6	11.5
Assets acquired under an operating lease		13.4	0.0	0.0
Reclassification of other property to regulatory assets	[1]	0.0	245.3	0.0
Assets recorded for asset retirement obligations	[2]	54.6	78.1	11.4
Schedule of interest and income taxes paid:
Cash paid for interest, net of interest capitalized amounts		349.7	354.2	339.9
Cash paid for income taxes, net of refunds		$ 10.8	$ 3.3	$ 5.5

[1] See Note 8 "Regulatory Matters" for additional information.

[2] See Note 7 "Asset Retirement Obligations" for additional information.

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Segments Of Business (Narrative) (Details) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2019 USD ($)	Dec. 31, 2019
Goodwill [Line Items]
Number of Reportable Segments		2
Number of counties in which electric service provided by Electric Operations		20
Columbia Of Massachusetts
Goodwill [Line Items]
Goodwill, Impairment Loss	$ 204.8

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Goodwill and Other Intangible Assets (Tables)

12 Months Ended

Dec. 31, 2019

Goodwill and Intangible Assets Disclosure [Abstract]

Schedule of Goodwill

The following presents our goodwill balance allocated by segment as of December 31, 2019 and 2018:

(in millions)	2019		2018
Gas Distribution Operations	$	1,485.9	$	1,690.7
Electric Operations	—		—
Corporate and Other	—		—
Total	$	1,485.9	$	1,690.7

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Short-Term Borrowings (Tables)

12 Months Ended

Dec. 31, 2019

Short-term Debt [Abstract]

Schedule Of Short-Term Borrowings

Short-term borrowings were as follows: 

At December 31, (in millions)	2019		2018
Commercial Paper weighted-average interest rate of 2.03% and 2.96% at December 31, 2019 and 2018, respectively	$	570.0	$	978.0
Accounts receivable securitization facility borrowings	353.2		399.2
Term loan weighted-average interest rate of 2.40% and 3.07% at December 31, 2019 and 2018, respectively	850.0		$	600.0
Total Short-Term Borrowings	$	1,773.2	$	1,977.2

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Other Commitments And Contingencies (Narrative) (Details)			3 Months Ended								4 Months Ended	12 Months Ended			16 Months Ended
	Oct. 31, 2019 MW	Jul. 31, 2008 MW	Dec. 31, 2019 USD ($)		Sep. 30, 2019 USD ($)	[1]	Jun. 30, 2019 USD ($)	[1]	Mar. 31, 2019 USD ($)	[1]	Dec. 31, 2018 USD ($)	Dec. 31, 2019 USD ($) Rate MW	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)	Dec. 31, 2019 USD ($)	Jul. 26, 2019 USD ($)	Jan. 01, 2019 Rate MW
Other Commitments And Contingencies [Line Items]
Payments made in connection with operating leases												$ 52,500,000	$ 49,100,000	$ 49,500,000
Wind power purchase agreement capacity | MW		100
Each wind power purchase agreement capacity | MW		50
Major Rail Operators			3									3			3
Line of Credit Facility, Amount Outstanding			$ 0								$ 0	$ 0	0		$ 0
Safety Recommendations Remaining to implement												1
Gas Meters moved from inside to outside	2,200
Proposed Class Action Settlement																$ 143,000,000
Expenses Related to Third-Party Claims, Fines, Penalties, and settlements											757,000,000	$ 284,000,000			1,041,000,000
Liability Insurance for Damages			800,000,000									800,000,000			800,000,000
Proceeds From Insurance Settlement			130,000,000	[1]	$ 260,000,000		$ 297,000,000		$ 108,000,000.0						800,000,000
Recorded reserves to cover environmental remediation at various sites			$ 104,400,000								101,200,000	$ 104,400,000	101,200,000		104,400,000
Coal-fired Generating Capacity | MW												2,080
Coal-fired Generating Capacity, Percent of Total Capacity | Rate												72.00%
Coal-fired Generating Capacity, Percent of Total Coal-Fired Capacity | Rate												100.00%
Wind Power Purchase Agreement, Purchase Percentage | Rate																	100.00%
Expenses Other Than Third Party Claims											266,000,000	$ 154,000,000			420,000,000
Costs Resulting from the Greater Lawrence Incident											1,023,000,000	$ 438,000,000			$ 1,461,000,000
MGP Sites
Other Commitments And Contingencies [Line Items]
Number of waste disposal sites identified by program			63									63			63
Liability for estimated remediation costs			$ 102,200,000								97,500,000	$ 102,200,000	97,500,000		$ 102,200,000
Reasonably possible remediation costs variance from reserve			20,000,000									20,000,000			20,000,000
NIPSCO
Other Commitments And Contingencies [Line Items]
Estimated Cost of Compliance with Effluent Limitations Guidelines												$ 170,000,000.0
Columbia Of Massachusetts
Other Commitments And Contingencies [Line Items]
Gas Meters Affected												7,500
Businesses Impacted by Incident												700
Miles of Affected Cast Iron and Bare Steel Pipeline System												45
Pipeline Replacement Expenses															258,000,000
Deferred Tax Assets, Net			50,000,000									$ 50,000,000			50,000,000
Maximum
Other Commitments And Contingencies [Line Items]
Long term purchase commitment time period												20 years
Maximum | Columbia Of Massachusetts
Other Commitments And Contingencies [Line Items]
Civil Penalty Assessed for Violation of Federal Pipeline Safety Regulations												$ 218,647
Civil Penalty Assessed for Series of Violations of Federal Pipeline Safety Regulations												2,200,000
Penalty Per Violation of Emergency Response Plan												250,000
Penalty for Violations of Emergency Response Plan												20,000,000
Penalty Per Violation of Operational Directives During Restoration Efforts												$ 1,000,000
Expenses Related to Third-Party Claims, Fines, Penalties, and settlements															1,065,000,000
Expenses Other Than Third Party Claims															460,000,000
Minimum
Other Commitments And Contingencies [Line Items]
Long term purchase commitment time period												15 years
Minimum | Columbia Of Massachusetts
Other Commitments And Contingencies [Line Items]
Expenses Related to Third-Party Claims, Fines, Penalties, and settlements															1,041,000,000
Expenses Other Than Third Party Claims															450,000,000
Coal Transportation | Maximum
Other Commitments And Contingencies [Line Items]
Long Term Purchase Commitment Expiration Year												2021
Purchase Power Agreements - Jan 2019
Other Commitments And Contingencies [Line Items]
Long term purchase commitment time period												20 years
Build Transfer Agreement
Other Commitments And Contingencies [Line Items]
Nameplate Capacity | MW	300																100
Standby Letters of Credit
Other Commitments And Contingencies [Line Items]
Line of Credit Facility, Amount Outstanding			$ 10,200,000								$ 10,200,000	$ 10,200,000	$ 10,200,000		$ 10,200,000

[1] $5 million of insurance recoveries were collected during 2018.

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Accumulated Other Comprehensive Loss (Components Of Accumulated Other Comprehensive Loss) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	[1]	$ (55.9)	$ 48.4	$ (21.7)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	[1]	0.5	(32.7)	3.4
Net current-period other comprehensive income (loss)	[1]	(55.4)	15.7	(18.3)
New Accounting Pronouncement or Change in Accounting Principle, Cumulative Effect of Change on Equity or Net Assets			(9.5)
Accumulated other comprehensive loss	[1]	(92.6)	(37.2)	(43.4)	$ (25.1)
Gains and Losses on Securities
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	[1]	6.1	(3.0)	0.6
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	[1]	(0.4)	0.4	0.2
Net current-period other comprehensive income (loss)	[1]	5.7	(2.6)	0.8
New Accounting Pronouncement or Change in Accounting Principle, Cumulative Effect of Change on Equity or Net Assets	[1]		0.0
Accumulated other comprehensive loss	[1]	3.3	(2.4)	0.2	(0.6)
Gains and Losses on Cash Flow Hedges
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	[1]	(64.3)	55.8	(24.2)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	[1]	0.1	(33.1)	1.7
Net current-period other comprehensive income (loss)	[1]	(64.2)	22.7	(22.5)
New Accounting Pronouncement or Change in Accounting Principle, Cumulative Effect of Change on Equity or Net Assets	[1]		(6.3)
Accumulated other comprehensive loss	[1]	(77.2)	(13.0)	(29.4)	(6.9)
Pension and OPEB Items
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	[1]	2.3	(4.4)	1.9
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	[1]	0.8	0.0	1.5
Net current-period other comprehensive income (loss)	[1]	3.1	(4.4)	3.4
New Accounting Pronouncement or Change in Accounting Principle, Cumulative Effect of Change on Equity or Net Assets	[1]		(3.2)
Accumulated other comprehensive loss	[1]	$ (18.7)	$ (21.8)	$ (14.2)	$ (17.6)

[1] All amounts are net of tax. Amounts in parentheses indicate debits.

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Other Commitments And Contingencies (Tables)

12 Months Ended

Dec. 31, 2019

Commitments and Contingencies Disclosure [Abstract]

Contractual Obligation, Fiscal Year Maturity

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, 2019 and their maturities were:

(in millions)	Total		2020		2021		2022		2023		2024		After
Long-term debt (1)	$	7,738.6	$	—	$	63.6	$	530.0	$	600.0	$	—	$	6,545.0
Interest payments on long-term debt	6,214.2		342.0		340.7		337.1		311.1		299.9		4,583.4
Finance leases(2)	325.9		27.2		27.3		26.8		23.1		19.9		201.6
Operating leases(3)	79.1		15.6		9.4		8.2		7.6		6.6		31.7
Energy commodity contracts(4)	95.9		65.5		30.4		—		—		—		—
Service obligations:
Pipeline service obligations	3,450.7		605.0		590.1		546.8		357.2		237.5		1,114.1
IT service obligations	153.2		63.6		49.4		38.0		1.1		1.1		—
Other service obligations(5)	59.8		45.8		14.0		—		—		—		—
Other liabilities	27.3		27.3		—		—		—		—		—
Total contractual obligations	$	18,144.7	$	1,192.0	$	1,124.9	$	1,486.9	$	1,300.1	$	565.0	$	12,475.8

⁽¹⁾ Long-term debt balance excludes unamortized issuance costs and discounts of $70.5 million.

⁽²⁾ Finance lease payments shown above are inclusive of interest totaling $108.3 million.

⁽³⁾ Operating lease payments shown above are inclusive of interest totaling $14.3 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. If we were to continue the fleet vehicle leases outstanding at December 31, 2019, payments would be $34.5 million in 2020, $28.3 million in 2021, $23.4 million in 2022, $19.9 million in 2023, $15.2 million in 2024 and $15.2 million thereafter.  

⁽⁴⁾In January 2020, NIPSCO signed new coal contract commitments of $14.4 million for 2020. These contracts are not included above.  

⁽⁵⁾In February 2020, NIPSCO signed a new railcar coal transportation contract commitment of $12.0 million for 2020. This contract is not included above.

Expenses Incurred and Insurance Recoveries

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).

	Year Ended			Year Ended
(in millions)	December 31, 2018			December 31, 2019			Incident to Date
Third-party claims and government fines, penalties and settlements	$	757		$	284		$	1,041
Other incident-related costs	266			154			420
Total	1,023			438			1,461
Insurance recoveries recorded	(135		)	(665		)	(800		)
Loss (benefit) to income before income taxes	$	888		$	(227	)	$	661

Insurance Recoveries and Cash Collected

The following table presents activity related to our Greater Lawrence Incident insurance recovery, which we have recovered in full as of December 31, 2019.

(in millions)	Insurance receivable(1)
Balance, December 31, 2018	$	130
Insurance recoveries recorded in first quarter of 2019	100
Cash collected from insurance recoveries in the first quarter of 2019	(108		)
Balance, March 31, 2019	122
Insurance recoveries recorded in the second quarter of 2019	435
Cash collected from insurance recoveries in the second quarter of 2019	(297		)
Balance, June 30, 2019	$	260
Insurance recoveries recorded in third quarter of 2019	—
Cash collected from insurance recoveries in the third quarter of 2019	(260		)
Balance, September 30, 2019	$	—
Insurance recoveries recorded in the fourth quarter of 2019	130
Cash collected from insurance recoveries in the fourth quarter of 2019	(130		)
Balance, December 31, 2019	$	—

⁽¹⁾$5 million of insurance recoveries were collected during 2018.

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Segments Of Business (Tables)

12 Months Ended

Dec. 31, 2019

Segment Reporting [Abstract]

Schedule Of Operating Income Derived From Revenues And Expenses By Segment

Year Ended December 31, (in millions)	2019			2018			2017
Operating Revenues
Gas Distribution Operations
Unaffiliated	$	3,509.7		$	3,406.4		$	3,087.9
Intersegment	13.1			13.1			14.2
Total	3,522.8			3,419.5			3,102.1
Electric Operations
Unaffiliated	1,698.4			1,707.4			1,785.7
Intersegment	0.8			0.8			0.8
Total	1,699.2			1,708.2			1,786.5
Corporate and Other
Unaffiliated	0.8			0.7			1.0
Intersegment	468.1			517.6			510.8
Total	468.9			518.3			511.8
Eliminations	(482.0		)	(531.5		)	(525.8		)
Consolidated Operating Revenues	$	5,208.9		$	5,114.5		$	4,874.6

Year Ended December 31, (in millions)	2019			2018			2017
Operating Income (Loss)
Gas Distribution Operations	$	675.4		$	(254.1	)	$	550.1
Electric Operations	406.8			386.1			367.4
Corporate and Other(2)	(191.5		)	(7.3		)	3.7
Consolidated Operating Income	$	890.7		$	124.7		$	921.2
Depreciation and Amortization
Gas Distribution Operations	$	403.2		$	301.0		$	269.3
Electric Operations	277.3			262.9			277.8
Corporate and Other	36.9			35.7			23.2
Consolidated Depreciation and Amortization	$	717.4		$	599.6		$	570.3
Assets
Gas Distribution Operations	$	14,224.5		$	13,527.0		$	12,048.8
Electric Operations	6,027.6			5,735.2			5,478.6
Corporate and Other	2,407.7			2,541.8			2,434.3
Consolidated Assets	$	22,659.8		$	21,804.0		$	19,961.7
Capital Expenditures(1)
Gas Distribution Operations	$	1,380.3		$	1,315.3		$	1,125.6
Electric Operations	468.9			499.3			592.4
Corporate and Other	18.6			—			35.8
Consolidated Capital Expenditures	$	1,867.8		$	1,814.6		$	1,753.8

⁽¹⁾Amounts differ from those presented on the Statements of Consolidated Cash Flows primarily due to the inclusion of capital expenditures included in current liabilities and AFUDC Equity.

⁽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 6, "Goodwill and Other Intangible Assets."

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Regulatory Matters (Regulatory Liabilities) (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Regulatory Liabilities [Line Items]
Regulatory Liabilities	$ 2,512.2	$ 2,660.0
Overrecovered Gas And Fuel Costs
Regulatory Liabilities [Line Items]
Regulatory Liabilities	42.6	32.0
Cost Of Removal
Regulatory Liabilities [Line Items]
Regulatory Liabilities	1,047.5	1,076.0
Regulatory Effects Of Accounting For Income Taxes
Regulatory Liabilities [Line Items]
Regulatory Liabilities	1,307.0	1,428.3
Other Postretirement Costs
Regulatory Liabilities [Line Items]
Regulatory Liabilities	64.7	62.7
Other Liabilities
Regulatory Liabilities [Line Items]
Regulatory Liabilities	$ 50.4	$ 61.0

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Pension and Other Postretirement Benefits (Narrative) (Details) - USD ($) $ in Millions		3 Months Ended				12 Months Ended
		Dec. 31, 2019		Dec. 31, 2018		Dec. 31, 2020	Dec. 31, 2019		Dec. 31, 2018		Dec. 31, 2017
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		$ 2,342.3		$ 2,084.1			$ 2,342.3		$ 2,084.1
Regulatory assets		2,239.6		2,237.5			2,239.6		2,237.5
Regulatory Liabilities		2,512.2		2,660.0			$ 2,512.2		2,660.0
Expected return on plan assets							6.10%
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		2,080.9		1,867.7			$ 2,080.9		1,867.7		$ 2,160.0
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)							53.8		(127.5)
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)		0.2		(0.4)			0.2		(0.4)		(0.7)
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)							47.6		14.8		$ 41.1
Employer contributions							2.9		2.9
Expected contribution		3.0					3.0
Defined Benefit Plan, Accumulated Benefit Obligation		2,111.5		1,965.6			2,111.5		1,965.6
Funded status of plan		49.6		113.6			49.6		113.6
Liability, Defined Benefit Plan	[1]	49.6		113.6			$ 49.6		$ 113.6
Expected return on plan assets							6.10%		7.00%		7.25%
Settlement loss		9.5		18.5			$ 9.5		$ 18.5		$ 13.7
Defined Benefit Plan, Benefit Obligation, (Increase) Decrease for Remeasurement due to Settlement							0.7
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		261.4		216.3			261.4		216.3		262.5
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)							(45.1)		5.0
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)		(3.2)		(4.0)			(3.2)		(4.0)		(4.4)
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)							10.0		7.5		$ 5.3
Employer contributions							23.0		21.0
Expected contribution		24.0					24.0
Funded status of plan		315.1		276.2			315.1		276.2
Liability, Defined Benefit Plan	[1]	315.1		276.2			$ 315.1		$ 276.2
Expected return on plan assets							5.83%		5.80%		6.99%
Settlement loss		0.0		0.0			$ 0.0		$ 0.0		$ 0.0
Significant Unobservable Inputs (Level 3) [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		$ 0.0		$ 86.1			$ 0.0		$ 86.1		$ 98.9
Percentage of investments		0.00%		4.00%			0.00%		4.00%
Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount				$ 0.0					$ 0.0
Scenario, Forecast | Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)						$ 34.7
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)						(0.8)
Amortization of transition obligation						0.0
Scenario, Forecast | Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)						4.9
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)						1.8
Amortization of transition obligation						$ 0.0
Unrecognized Pension Benefit And Other Postretirement Benefit Costs
Defined Benefit Plan Disclosure [Line Items]
Regulatory assets		$ 739.1		798.3			$ 739.1		798.3
Regulatory Liabilities		0.1		0.1			0.1		0.1
International Equities | Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		205.0		165.5			205.0		165.5
International Equities | Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		40.7		17.5			40.7		17.5
Commingled Funds | Short-Term Money Markets | Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		14.8	[2]	18.3	[3]		14.8	[2]	18.3	[3]
Commingled Funds | Short-Term Money Markets | Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		7.7	[2]	5.2	[3]		7.7	[2]	5.2	[3]
Commingled Funds | United States Equities | Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		305.9	[2]	245.2	[3]		305.9	[2]	245.2	[3]
Commingled Funds | United States Equities | Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		12.1	[2]	10.4	[3]		12.1	[2]	10.4	[3]
Commingled Funds | International Equities | Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		148.1	[2]	$ 122.3	[3]		148.1	[2]	$ 122.3	[3]
Commingled Funds | International Equities | Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[2]	$ 20.1					$ 20.1

[1] 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.

[2] 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.

[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.

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Share-Based Compensation (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended			36 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	May 12, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common stock available for awards, shares							8,000,000
Common stock reserved for future awards, shares	3,313,183					3,313,183
Stock-based employee compensation expense	$ 16.3	$ 15.2	$ 15.3
Related tax benefits	4.0	3.7	5.9
Excess Tax Benefit from Share-based Compensation, Operating Activities	0.8	1.0	4.4
Unrecognized compensation cost related to nonvested awards	$ 19.5					$ 19.5
Weighted-average remaining requisite service period, years	1 year 9 months 18 days
RTSR Modifier	25.00%
Defined Contribution Plan, Employer Matching Contribution, Percent of Employees' Gross Pay	3.00%
401(k) match, profit sharing and non-elective expense	$ 37.5	$ 37.6	$ 37.6
Restricted Stock Units (RSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted	166,031
Shares nonvested	302,606	178,678				302,606
Performance Shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted	552,389	514,338	660,750
Fair value of shares granted			$ 12.9
Shares nonvested	1,503,251	1,634,718				1,503,251
Shares vesting period, (years)						3 years
Performance Shares | NOEPS [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value of shares granted	$ 11.7	$ 9.2
Performance Shares | CVI [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value of shares granted	$ 2.5	$ 2.4
Omnibus Plan | Restricted Stock Units (RSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units issued	165,768
Director Plan | Non-Employee Director Award
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares nonvested	49,926					49,926
2019 Award | Restricted Stock Units (RSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted	166,031
Fair value of shares granted	$ 4.1
Shares nonvested	157,786					157,786
2019 Award | Performance Shares | NOEPS [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares nonvested	422,825					422,825
2019 Award | Performance Shares | CVI [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares nonvested	97,574					97,574
2018 Award | Restricted Stock Units (RSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted		158,689
Fair value of shares granted		$ 3.5
Shares nonvested	136,820					136,820
2018 Award | Performance Shares | NOEPS [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares nonvested	368,811					368,811
2018 Award | Performance Shares | CVI [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares nonvested	85,111					85,111
2017 Performance Awards | Performance Shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares nonvested	528,928					528,928
Subsequent Event | Restricted Stock Units (RSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares vesting period, (years)				3 years	3 years
Subsequent Event | Performance Shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares vesting period, (years)				3 years	3 years

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Income Taxes (Schedule Of Components Of Income Tax Expense) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Current
Federal	$ 0.0	$ 0.0	$ 0.0
State	5.2	8.2	7.8
Total Current	5.2	8.2	7.8
Deferred
Federal	110.7	(209.4)	302.7
State	9.0	22.2	5.0
Total Deferred	119.7	(187.2)	307.7
Deferred Investment Credits	(1.4)	(1.0)	(1.0)
Income Taxes	$ 123.5	$ (180.0)	$ 314.5

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Statements Of Consolidated Stockholders' Equity - USD ($) $ in Millions	Total		Common Stock	Preferred Stock		Treasury Stock	Additional Paid-in Capital	Retained Deficit	Accumulated Other Comprehensive Loss
Beginning Balance at Dec. 31, 2016	$ 4,071.2		$ 3.3	$ 0.0	[1]	$ (88.7)	$ 5,153.9	$ (972.2)	$ (25.1)
Comprehensive Income (Loss):
Net Income (Loss)	128.5		0.0	0.0	[1]	0.0	0.0	128.5	0.0
Other Comprehensive Income (Loss), Net of Tax	(18.3)	[2]	0.0	0.0	[1]	0.0	0.0	0.0	(18.3)
Dividends:
Common stock	(229.4)		0.0	0.0	[1]	0.0	0.0	(229.4)	0.0
Treasury stock acquired	(7.2)		0.0	0.0	[1]	(7.2)	0.0	0.0	0.0
Stock issuances:
Employee stock purchase plan	5.0		0.0	0.0	[1]	0.0	5.0	0.0	0.0
Long-term incentive plan	14.9		0.0	0.0	[1]	0.0	14.9	0.0	0.0
401(k) and profit sharing	34.3		0.0	0.0	[1]	0.0	34.3	0.0	0.0
Dividend reinvestment plan	6.4		0.0	0.0	[1]	0.0	6.4	0.0	0.0
ATM Program	314.7		0.1	0.0	[1]	0.0	314.6	0.0	0.0
Ending Balance at Dec. 31, 2017	4,320.1		3.4	0.0	[1]	(95.9)	5,529.1	(1,073.1)	(43.4)
Dividends:
Cumulative effect of change in accounting principle | Accounting Standards Update 2018-02	0.0		0.0	0.0	[1]	0.0	0.0	(9.5)	9.5
Net Income (Loss)	(50.6)		0.0	0.0	[1]	0.0	0.0	(50.6)	0.0
Other Comprehensive Income (Loss), Net of Tax	15.7	[2]	0.0	0.0	[1]	0.0	0.0	0.0	15.7
Common stock	(273.5)		0.0	0.0	[1]	0.0	0.0	(273.5)	0.0
Preferred stock	(11.6)		0.0	0.0	[1]	0.0	0.0	(11.6)	0.0
Treasury stock acquired	(4.0)		0.0	0.0	[1]	(4.0)	0.0	0.0	0.0
Stock issuances:
Common stock	599.6		0.3	0.0	[1]	0.0	599.3	0.0	0.0
Preferred stock	880.0		0.0	880.0	[1]	0.0	0.0	0.0	0.0
Employee stock purchase plan	5.5		0.0	0.0	[1]	0.0	5.5	0.0	0.0
Long-term incentive plan	15.4		0.0	0.0	[1]	0.0	15.4	0.0	0.0
401(k) and profit sharing	21.8		0.0	0.0		0.0	21.8	0.0	0.0
ATM Program	232.5		0.1	0.0	[1]	0.0	232.4	0.0	0.0
Ending Balance at Dec. 31, 2018	5,750.9		3.8	880.0	[1]	(99.9)	6,403.5	(1,399.3)	(37.2)
Comprehensive Income (Loss):
Net Income (Loss)	383.1		0.0	0.0	[1]	0.0	0.0	383.1	0.0
Other Comprehensive Income (Loss), Net of Tax	(55.4)	[2]	0.0	0.0	[1]	0.0	0.0	0.0	(55.4)
Dividends:
Common stock	(298.5)		0.0	0.0	[1]	0.0	0.0	(298.5)	0.0
Preferred stock	(56.1)		0.0	0.0	[1]	0.0	0.0	(56.1)	0.0
Stock issuances:
Employee stock purchase plan	5.6		0.0	0.0	[1]	0.0	5.6	0.0	0.0
Long-term incentive plan	10.4		0.0	0.0	[1]	0.0	10.4	0.0	0.0
401(k) and profit sharing	17.6		0.0	0.0	[1]	0.0	17.6	0.0	0.0
ATM Program	229.1		0.0	0.0	[1]	0.0	229.1	0.0	0.0
Ending Balance at Dec. 31, 2019	$ 5,986.7		$ 3.8	$ 880.0	[1]	$ (99.9)	$ 6,666.2	$ (1,370.8)	$ (92.6)

[1] Series A and Series B shares have an aggregate liquidation preference of $400M and $500M, respectively. See Note 12, "Equity" for additional information.

[2] All amounts are net of tax. Amounts in parentheses indicate debits.

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Pension and Other Postretirement Benefits (Schedule Of Changes In Plan Assets And Projected Benefit Obligations Recognized In Other Comprehensive Income) (Details) - USD ($) $ in Millions	3 Months Ended		12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Pension Plan
Net prior service cost/(credit)			$ 0.0	$ 0.2
Net actuarial (gain)/loss			(53.8)	127.5
Settlements	$ (9.5)	$ (18.5)	(9.5)	(18.5)	$ (13.7)
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)	(0.2)	0.4	(0.2)	0.4	0.7
Less: amortization of net actuarial (gain) loss	(45.2)	(40.6)	(45.2)	(40.6)	(52.9)
Total Recognized in Other Comprehensive Income or Regulatory Asset or Liability			(108.7)	69.0
Amount Recognized in Net Periodic Benefits Cost and Other Comprehensive Income or Regulatory Asset or Liability	(61.1)	83.8	(61.1)	83.8
Other Postretirement Benefits
Net prior service cost/(credit)			5.1	0.1
Net actuarial (gain)/loss			45.1	(5.0)
Settlements	0.0	0.0	0.0	0.0	0.0
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)	3.2	4.0	3.2	4.0	4.4
Less: amortization of net actuarial (gain) loss	(2.0)	(3.8)	(2.0)	(3.8)	$ (3.0)
Total Recognized in Other Comprehensive Income or Regulatory Asset or Liability			51.4	(4.7)
Amount Recognized in Net Periodic Benefits Cost and Other Comprehensive Income or Regulatory Asset or Liability	$ 61.4	$ 2.8	$ 61.4	$ 2.8

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Goodwill and Other Intangible Assets (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Goodwill And Other Intangible Assets [Line Items]
Goodwill	$ 1,485.9	$ 1,485.9	$ 1,690.7
Intangible Assets, Net (Excluding Goodwill)	0.0	0.0	220.7
Amortization			221.5
Amortization of Intangible Assets		$ 11.0	11.0	$ 11.0
Finite-Lived Intangible Asset, Useful Life		40 years
Finite-Lived Intangible Assets, Amortization End Date		2039
Gas Distribution Operations
Goodwill And Other Intangible Assets [Line Items]
Goodwill	1,485.9	$ 1,485.9	1,690.7
Electric Operations
Goodwill And Other Intangible Assets [Line Items]
Goodwill	0.0	0.0	0.0
Corporate and Other
Goodwill And Other Intangible Assets [Line Items]
Goodwill	0.0	$ 0.0	$ 0.0
Columbia Of Massachusetts
Goodwill And Other Intangible Assets [Line Items]
Impairment of Intangible Assets, Finite-lived	209.7
Goodwill, Impairment Loss	$ 204.8

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Long-Term Debt (Schedule of Consolidated Long-Term Debt (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Debt Instrument [Line Items]
Senior Notes	$ 7,581.6	$ 6,831.6
Medium-Term Notes	157.0	157.0
Capital Lease Obligations	201.5	194.3
Debt Instrument, Unamortized Discount (Premium) and Debt Issuance Costs, Net	(70.5)	(68.5)
Long-term Debt, Excluding Current Maturities	$ 7,869.6	7,155.4
NiSource | 4.45% Notes Due 2021
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Dec. 31, 2021
Debt, Weighted Average Interest Rate	4.45%
Senior Notes	$ 63.6	63.6
NiSource | 2.65% Notes Due 2022
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Nov. 30, 2022
Debt, Weighted Average Interest Rate	2.65%
Senior Notes	$ 500.0	500.0
NiSource | 3.85% Notes Due 2023
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Feb. 28, 2023
Debt, Weighted Average Interest Rate	3.85%
Senior Notes	$ 250.0	250.0
NiSource | 3.65% Notes Due 2023
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Jun. 30, 2023
Debt, Weighted Average Interest Rate	3.65%
Senior Notes	$ 350.0	350.0
NiSource | 5.89% Notes Due 2025
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Nov. 30, 2025
Debt, Weighted Average Interest Rate	5.89%
Senior Notes	$ 265.0	265.0
NiSource | 3.49% Notes due 2027
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	May 31, 2027
Debt, Weighted Average Interest Rate	3.49%
Senior Notes	$ 1,000.0	1,000.0
NiSource | 6.78% Notes Due 2027
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Dec. 31, 2027
Debt, Weighted Average Interest Rate	6.78%
Senior Notes	$ 3.0	3.0
NiSource | 2.95% Notes Due 2029
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Sep. 30, 2029
Debt, Weighted Average Interest Rate	2.95%
Senior Notes	$ 750.0	0.0
NiSource | 6.25% Notes Due 2040
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Dec. 31, 2040
Debt, Weighted Average Interest Rate	6.25%
Senior Notes	$ 250.0	250.0
NiSource | 5.95% Notes Due 2041
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Jun. 30, 2041
Debt, Weighted Average Interest Rate	5.95%
Senior Notes	$ 400.0	400.0
NiSource | 5.80% Notes Due 2042
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Feb. 28, 2042
Debt, Weighted Average Interest Rate	5.80%
Senior Notes	$ 250.0	250.0
NiSource | 5.25% Notes Due 2043
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Feb. 28, 2043
Debt, Weighted Average Interest Rate	5.25%
Senior Notes	$ 500.0	500.0
NiSource | 4.80% Notes due 2044
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Feb. 29, 2044
Debt, Weighted Average Interest Rate	4.80%
Senior Notes	$ 750.0	750.0
NiSource | 5.65% Notes Due 2045
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Feb. 28, 2045
Debt, Weighted Average Interest Rate	5.65%
Senior Notes	$ 500.0	500.0
NiSource | 4.375% Notes due 2047
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	May 31, 2047
Debt, Weighted Average Interest Rate	4.38%
Senior Notes	$ 1,000.0	1,000.0
NiSource | 3.95% Notes Due 2048
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Mar. 31, 2048
Debt, Weighted Average Interest Rate	3.95%
Senior Notes	$ 750.0	750.0
NiSource | 7.99% Notes Due 2027
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate	7.99%
Medium-Term Notes	$ 49.0	49.0
NiSource | 7.99% Notes Due 2027 | Maximum
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	May 31, 2027
NiSource | 7.99% Notes Due 2027 | Minimum
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Apr. 30, 2022
Columbia Of Massachusetts | 6.30% Notes Due 2028
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate	6.30%
Medium-Term Notes	$ 40.0	40.0
Columbia Of Massachusetts | 6.30% Notes Due 2028 | Maximum
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Feb. 28, 2028
Columbia Of Massachusetts | 6.30% Notes Due 2028 | Minimum
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Dec. 31, 2025
Columbia Of Massachusetts | 5.49% notes Due 2043
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate	5.49%
Capital Lease Obligations	$ 44.3	45.7
Columbia Of Massachusetts | 5.49% notes Due 2043 | Maximum
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Nov. 30, 2043
Columbia Of Massachusetts | 5.49% notes Due 2043 | Minimum
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Dec. 31, 2033
NIPSCO | 7.61% Notes Due 2027
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate	7.61%
Medium-Term Notes	$ 68.0	68.0
NIPSCO | 7.61% Notes Due 2027 | Maximum
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Aug. 31, 2027
NIPSCO | 7.61% Notes Due 2027 | Minimum
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Aug. 31, 2022
NIPSCO | 5.85% Notes Due 2019
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate	5.85%
Long-term Pollution Control Bond	$ 0.0	41.0
NIPSCO | 5.85% Notes Due 2019 | Maximum
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Apr. 30, 2019
Columbia Of Ohio | 6.16% Notes Due 2044
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate	6.16%
Capital Lease Obligations	$ 94.8	91.5
Columbia Of Ohio | 6.16% Notes Due 2044 | Maximum
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Mar. 31, 2044
Columbia Of Ohio | 6.16% Notes Due 2044 | Minimum
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Oct. 31, 2021
NiSource Corporate Services | 3.47% Notes Due 2023
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate	3.47%
Capital Lease Obligations	$ 22.3	11.6
NiSource Corporate Services | 3.47% Notes Due 2023 | Maximum
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Nov. 30, 2023
NiSource Corporate Services | 3.47% Notes Due 2023 | Minimum
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Jan. 31, 2020
Columbia Of Virginia | 6.31% Notes Due 2039
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate	6.31%
Capital Lease Obligations	$ 19.1	15.2
Columbia Of Virginia | 6.31% Notes Due 2039 | Maximum
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Nov. 30, 2039
Columbia Of Virginia | 6.31% Notes Due 2039 | Minimum
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Jul. 31, 2029
Columbia Of Kentucky | 3.79% Notes Due 2027
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	May 31, 2027
Debt, Weighted Average Interest Rate	3.79%
Capital Lease Obligations	$ 0.3	0.3
Columbia Of Pennsylvania | 5.67% Notes Due 2035
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate	5.67%
Capital Lease Obligations	$ 20.7	$ 30.0
Columbia Of Pennsylvania | 5.67% Notes Due 2035 | Maximum
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	May 31, 2035
Columbia Of Pennsylvania | 5.67% Notes Due 2035 | Minimum
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Aug. 31, 2027

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Statements of Consolidated Comprehensive Income (Loss) (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Other Comprehensive Income (Loss), Securities, Available-for-Sale, Unrealized Holding Gain (Loss) Arising During Period, Tax	$ 1.5	$ (0.6)	$ 0.4
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Tax	(21.2)	7.5	(13.9)
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, Tax	$ (1.6)	$ 1.5	$ (2.1)

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Revenue Recognition

12 Months Ended

Dec. 31, 2019

Revenue from Contract with Customer [Abstract]

Revenue from Contract with Customer

Revenue Recognition

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

The table below provides results for the years ended December 31, 2019 and 2018 as if it had been prepared under historic accounting guidance. We included operating revenue information for the year ended December 31, 2017 for comparability.

Year Ended December 31, (in millions)	2019		2018		2017
Operating Revenues
Gas Distribution	$	2,336.1	$	2,348.4	$	2,063.2
Gas Transportation	1,171.3		1,055.2		1,021.5
Electric	1,698.5		1,707.4		1,785.5
Other	3.0		3.5		4.4
Total Operating Revenues	$	5,208.9	$	5,114.5	$	4,874.6

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

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

Customers in certain of our jurisdictions participate in programs that allow for a fixed payment each month regardless of usage. Payments received that exceed the value of gas or electricity actually delivered are recorded as a liability and presented in "Customer Deposits and Credits" on the Consolidated Balance Sheets. Amounts in this account are reduced and revenue is recorded when customer usage begins to exceed 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. In general, revenue recognized from tariff-based sales is equivalent to the value of natural gas or electricity supplied and billed each period, in addition to an estimate for deliveries completed during the period but not yet billed to the customer.

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. 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, 2019 (in millions)	Gas Distribution Operations		Electric Operations		Corporate and Other		Total
Customer Revenues(1)
Residential	$	2,309.0	$	481.6	$	—	$	2,790.6
Commercial	771.3		486.6		—		1,257.9
Industrial	245.2		607.7		—		852.9
Off-system	77.7		—		—		77.7
Miscellaneous	52.0		21.5		0.8		74.3
Total Customer Revenues	$	3,455.2	$	1,597.4	$	0.8	$	5,053.4
Other Revenues	54.5		101.0		—		155.5
Total Operating Revenues	$	3,509.7	$	1,698.4	$	0.8	$	5,208.9

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

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

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, 2019 and 2018 are presented in the table below. We had no significant contract assets or liabilities during the period. Additionally, we have not incurred any significant costs to obtain or fulfill contracts.

(in millions)	Customer Accounts Receivable, Billed (less reserve)(1)			Customer Accounts Receivable, Unbilled (less reserve)
Balance as of December 31, 2018	$	540.5		$	349.1
Balance as of December 31, 2019	466.6			346.6
Decrease	$	(73.9	)	$	(2.5	)

⁽¹⁾ Customer billed receivables decreased due to decreased natural gas costs and warmer weather in 2019 compared to 2018.

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.

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 programs that allow for the adjustment of billings and revenue for certain broad, external factors, or for additional billings if the entity achieves certain objectives, such as a specified reduction of costs. We maintain a 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.

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Asset Retirement Obligations

12 Months Ended

Dec. 31, 2019

Asset Retirement Obligation [Abstract]

Asset Retirement Obligations

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 a significant obligation associated with the decommissioning of our two hydro facilities located in Indiana. These hydro facilities have an indeterminate life, and as such, no asset retirement obligation has been recorded.

Changes in our liability for asset retirement obligations for the years 2019 and 2018 are presented in the table below:

(in millions)	2019				2018
Beginning Balance	$	352.0			$	268.7
Accretion recorded as a regulatory asset/liability	15.7				11.1
Additions	—				63.3			(2)
Settlements	(5.4		)		(5.9		)
Change in estimated cash flows	54.6			(1)	14.8			(2)
Ending Balance	$	416.9			$	352.0

⁽¹⁾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.

⁽²⁾In 2018, $59.8 million of additions and $17.7 million of the change in estimated cash flows are attributed to costs associated with refining the CCR compliance plan. See Note 19-D, "Environmental Matters," for additional information on CCRs.

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.

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Recent Accounting Pronouncements (Tables)

12 Months Ended

Dec. 31, 2019

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

Description of New Accounting Pronouncements Not yet Adopted [Text Block]

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 2018-14, Compensation—Retirement Benefits—Defined Benefit Plans—General (Subtopic 715-20): Disclosure Framework—Changes to the Disclosure Requirements for Defined Benefit Plans	The pronouncement modifies the disclosure requirements for defined benefit pension 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 and must be applied on a retrospective basis to all periods presented.	Annual periods ending after December 15, 2020. Early adoption is permitted.	We are currently evaluating the effects of this pronouncement on our Notes to Consolidated Financial Statements. We expect to adopt this ASU on its effective date.
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.	Annual periods beginning after December 15, 2020. Early adoption is permitted.	We are currently evaluating the effects of this pronouncement on our Consolidated Financial Statements and Notes to Consolidated Financial Statements. We tentatively expect to adopt this ASU on its effective date.

Schedule of New Accounting Pronouncements and Changes in Accounting Principles [Table Text Block]

Recently Adopted Accounting Pronouncements

Standard	Adoption
ASU 2019-01, Leases (Topic 842): Codification Improvements	See Note 16, "Leases," for our discussion of the effects of implementing these standards.
ASU 2018-11, Leases (Topic 842): Targeted Improvements
ASU 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842
ASU 2016-02, Leases (Topic 842)
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 that revised the guidance on the impairment of most financial assets and certain other instruments that are not measured at fair value through net income. This ASU replaces the current "incurred loss" model with an "expected loss" model for instruments measured at amortized cost. It also requires entities to record allowances for available-for-sale securities rather than impair the carrying amount of the securities. Subsequent improvements to the estimated credit losses of available-for-sale securities will be recognized immediately in earnings instead of over time as they are under historic guidance. We adopted this ASU effective January 1, 2020, using a modified retrospective method. Adoption of this standard did not have a material impact on our Consolidated Financial Statements. No material adjustments were made to January 1, 2020 opening balances as a result of adoption. For our investments that are classified as available for sale debt securities, we will recognize impairment using an allowance approach instead of an 'other than temporary' impairment (OTTI) model. Since we do not have amounts previously recognized in other comprehensive income related to previous OTTI charges, provisions of this ASU are adopted prospectively. In regards to our recorded balances of trade receivables that fall within the scope of this ASU, the ASU did not result in any significant modifications to our policies related to recognizing an allowance on our trade receivables. Based on shared risk characteristics, we segregate our trade receivables into separate pools. We will apply separate models to calculate reserves for uncollectible receivables, as well as consider factors other than time to determine whether a credit loss exists. ASC 326 also prescribes additional presentation and disclosure requirements. For reporting periods beginning after January 1, 2020, we will include additional disclosures in our Notes to Consolidated Financial Statements based on qualitative and quantitative assessment of materiality.
ASU 2016-13,  Financial Instruments-Credit Losses (Topic 326)

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Quarterly Financial Data

12 Months Ended

Dec. 31, 2019

Quarterly Financial Data [Abstract]

Quarterly Financial Data (Unaudited)

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)
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	)
2018
Operating Revenues	$	1,750.8		$	1,007.0		$	895.0		$	1,461.7
Operating Income (Loss)	400.6			118.4			(315.9		)	(78.4		)
Net Income (Loss)	276.1			24.5			(339.5		)	(11.7		)
Preferred Dividends	—			(1.3		)	(5.6		)	(8.1		)
Net Income (Loss) Available to Common Shareholders	276.1			23.2			(345.1		)	(19.8		)
Earnings (Loss) Per Share
Basic Earnings (Loss) Per Share	$	0.82		$	0.07		$	(0.95	)	$	(0.05	)
Diluted Earnings (Loss) Per Share	$	0.81		$	0.07		$	(0.95	)	$	(0.05	)

⁽¹⁾ 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 19-E, "Other Matters" for additional information.

⁽²⁾ 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 19-E, "Other Matters" for additional information.

⁽³⁾ Net loss for the third quarter of 2018 was impacted by approximately $462 million in expenses (pretax) related to the Greater Lawrence Incident restoration and a $33.0 million loss (pretax) on an early extinguishment of long-term debt. See Note 19-E, "Other Matters" and Note 14, "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 6, "Goodwill and Other Intangible Assets."

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Accumulated Other Comprehensive Loss

12 Months Ended

Dec. 31, 2019

Components of Accumulated Other Comprehensive Income (Loss) [Abstract]

Accumulated Other Comprehensive Loss

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, 2017	$	(0.6	)	$	(6.9	)	$	(17.6	)	$	(25.1	)
Other comprehensive income (loss) before reclassifications	0.6			(24.2		)	1.9			(21.7		)
Amounts reclassified from accumulated other comprehensive loss	0.2			1.7			1.5			3.4
Net current-period other comprehensive income (loss)	0.8			(22.5		)	3.4			(18.3		)
Balance as of December 31, 2017	$	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	)

 

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

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Pension and Other Postretirement Benefits

12 Months Ended

Dec. 31, 2019

Pension and Other Postretirement Benefits Cost (Reversal of Cost) [Abstract]

Pension and Other Postretirement Benefits

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. We employ a liability-driven investing strategy for the pension plan, as noted below. A mix of equities and fixed income investments are used to maximize the long-term return of plan assets and hedge the liabilities at a prudent level of risk. We utilize a total return investment approach for the other postretirement benefit plans. Risk tolerance is established through careful consideration of plan liabilities, plan funded status, and asset class volatility. The investment portfolio contains a diversified blend of equity and fixed income investments. Furthermore, equity investments are diversified across U.S. and non-U.S. stocks, as well as growth, value, small and large capitalizations. Other assets such as private equity funds are used judiciously to enhance long-term returns while improving portfolio diversification. Derivatives may be used to gain market exposure in an efficient and timely manner; however, derivatives may not be used to leverage the portfolio beyond the market value of the underlying assets. Investment risk is measured and monitored on an ongoing basis through quarterly investment portfolio reviews, annual liability measurements, and periodic asset/liability studies.

We utilize a building block approach with proper consideration of diversification and rebalancing in determining the long-term rate of return for plan assets. Historical markets are studied and long-term historical relationships between equities and fixed income are analyzed to ensure that they are consistent with the widely accepted capital market principle that assets with higher volatility generate greater return over the long run. Current market factors, such as inflation and interest rates, are evaluated before long-term capital market assumptions are determined. Peer data and historical returns are reviewed to check for reasonability and appropriateness.

The most important component of an investment strategy is the portfolio asset mix, or the allocation between the various classes of securities available to the pension and other postretirement benefit plans for investment purposes. The asset mix and acceptable minimum and maximum ranges established for our plan assets represents a long-term view and are listed in the table below.

In 2012, a dynamic asset allocation policy for the pension fund was approved. This 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 above 90% (as measured by the market value of qualified pension plan assets divided by the projected benefit obligations of the qualified pension plans). A new asset-liability study was completed in 2018 resulting in a more conservative glide path and an increase in the allocation to liability-hedging assets held in the portfolio.

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 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%
Short-Term Investments/Other	0%	15%	0%	10%

As of December 31, 2018, 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%
Short-Term Investments/Other	0%	15%	0%	10%

Pension Plan and Postretirement Plan Asset Mix at December 31, 2019 and December 31, 2018:

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

The categorization of investments into the asset classes in the table 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 Master Trust and other postretirement benefits investment assets at fair value as of December 31, 2019 and 2018. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Total Master Trust and other postretirement benefits investment assets at fair value classified within Level 3 were $0 million and $86.1 million as of December 31, 2019 and December 31, 2018, respectively. Such amounts were approximately 0% and 4% of the Master Trust and other postretirement benefits’ total investments as reported on the statement of net assets available for benefits at fair value as of December 31, 2019 and 2018, respectively.

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, 2019, there were no significant changes to valuation techniques to determine the fair value of our pension and other postretirement benefits' assets.

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.

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		)	—
Distressed opportunities	2.4		(2.4		)	—
Real estate	52.7		(52.7		)	—
Total	$	86.1	$	(86.1	)	$	—

⁽¹⁾ Level 3 assets from the prior year were reclassified in the current year 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	1 day
International equities	168.2		Monthly	10-30 days
Fixed income	351.8		Daily	3 days
Total	$	860.5

Fair Value Measurements at December 31, 2018: 

(in millions)	December 31, 2018			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	$	9.2		$	8.8	$	0.4		$	—
Equity securities
U.S. equities	0.2			0.2		—			—
Fixed income securities
Government	250.2			—		250.2			—
Corporate	442.8			—		442.8			—
Mutual Funds
U.S. multi-strategy	110.3			110.3		—			—
International equities	43.2			43.2		—			—
Fixed income	166.8			166.8		—			—
Private equity limited partnerships
U.S. multi-strategy(1)	18.5			—		—			18.5
International multi-strategy(2)	12.5			—		—			12.5
Distressed opportunities	2.4			—		—			2.4
Real Estate	52.7			—		—			52.7
Commingled funds(3)
Short-term money markets	18.3			—		—			—
U.S. equities	245.2			—		—			—
International equities	122.3			—		—			—
Fixed income	365.7			—		—			—
Pension plan assets subtotal	1,860.3			329.3		693.4			86.1
Other postretirement benefit plan assets:
Mutual funds
U.S. equities	68.4			68.4		—			—
International equities	17.5			17.5		—			—
Fixed income	114.8			114.8		—			—
Commingled funds(3)
Short-term money markets	5.2			—		—			—
U.S. equities	10.4			—		—			—
Other postretirement benefit plan assets subtotal	216.3			200.7		—			—
Due to brokers, net(4)	(1.1		)	—		(1.1		)	—
Accrued investment income/dividends	8.6			8.6		—			—
Total pension and other postretirement benefit plan assets	$	2,084.1		$	538.6	$	692.3		$	86.1

⁽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 a 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.

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, 2018:

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

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, 2018:

(in millions)	Fair Value		Redemption Frequency	Redemption Notice Period
Commingled Funds
Short-term money markets	$	23.5	Daily	1 day
U.S. equities	255.6		Monthly	3 days
International equities	122.3		Monthly	10-30 days
Fixed income	365.7		Monthly	3 days
Total	$	767.1

 

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)	2019			2018			2019			2018
Change in projected benefit obligation(1)
Benefit obligation at beginning of year	$	1,981.3		$	2,192.6		$	492.5		$	556.3
Service cost	29.2			31.3			5.1			5.0
Interest cost	72.3			67.1			19.2			17.6
Plan participants’ contributions	—			—			4.8			5.7
Plan amendments	—			0.2			5.1			0.1
Actuarial (gain) loss	204.3			(103.9		)	88.8			(51.7		)
Settlement loss	—			0.8			—			—
Benefits paid	(156.6		)	(206.8		)	(39.5		)	(41.1		)
Estimated benefits paid by incurred subsidy	—			—			0.5			0.6
Projected benefit obligation at end of year	$	2,130.5		$	1,981.3		$	576.5		$	492.5
Change in plan assets
Fair value of plan assets at beginning of year	$	1,867.7		$	2,160.0		$	216.3		$	262.5
Actual (loss) return on plan assets	366.8			(88.4		)	56.9			(31.8		)
Employer contributions	2.9			2.9			23.0			21.0
Plan participants’ contributions	—			—			4.7			5.7
Benefits paid	(156.5		)	(206.8		)	(39.5		)	(41.1		)
Fair value of plan assets at end of year	$	2,080.9		$	1,867.7		$	261.4		$	216.3
Funded Status at end of year	$	(49.6	)	$	(113.6	)	$	(315.1	)	$	(276.2	)
Amounts recognized in the statement of financial position consist of:
Noncurrent assets	8.2			—			—			—
Current liabilities	(3.0		)	(3.0		)	(0.8		)	(0.8		)
Noncurrent liabilities	(54.8		)	(110.6		)	(314.3		)	(275.4		)
Net amount recognized at end of year(2)	$	(49.6	)	$	(113.6	)	$	(315.1	)	$	(276.2	)
Amounts recognized in accumulated other comprehensive income or regulatory asset/liability(3)
Unrecognized prior service credit	$	3.0		$	3.2		$	(10.7	)	$	(19.0	)
Unrecognized actuarial loss	652.8			761.2			118.4			75.3
Net amount recognized at end of year	$	655.8		$	764.4		$	107.7		$	56.3

⁽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⁾ 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 $739.1 million and $0.1 million, respectively, as of December 31, 2019, and $798.3 million and $0.1 million, respectively, as of December 31, 2018 that would otherwise have been recorded to accumulated other comprehensive loss.

Our accumulated benefit obligation for our pension plans was $2,111.5 million and $1,965.6 million as of December 31, 2019 and 2018, respectively. The accumulated benefit obligation as of a 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 the pension and postretirement benefit plans on the Consolidated Balance Sheet. The funded status of the plans is measured as the difference between the plan assets' fair value and the projected benefit obligation. We present the noncurrent aggregate of all underfunded plans within "Accrued liability for postretirement and postemployment benefits." The portion of the amount by which the actuarial present value of benefits included in the projected benefit obligation

exceeds the fair value of plan assets, payable in the next 12 months, is reflected in "Accrued compensation and other benefits." We present the aggregate of all overfunded plans within "Deferred charges and other."

Information for pension plans with a projected benefit obligation in excess of plan assets:

	December 31,
	2019			2018
Accumulated Benefit Obligation	$	1,473.9		$	1,965.6
Funded Status
Projected Benefit Obligation	1,492.9			1,981.3
Fair Value of Plan Assets	1,435.1			1,867.7
Funded Status of Underfunded Pension Plans at End of Year	$	(57.8	)	$	(113.6	)

Information for pension plans with plan assets in excess of the projected benefit obligation:

	December 31,
	2019		2018
Accumulated Benefit Obligation	$	637.6	$	—
Funded Status
Projected Benefit Obligation	637.6		—
Fair Value of Plan Assets	645.8		—
Funded Status of Overfunded Pension Plans at End of Year	$	8.2	$	—

Our pension plans were underfunded, in aggregate, by $49.6 million at December 31, 2019 compared to being underfunded by $113.6 million at December 31, 2018. 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 2019 and 2018.

Our other postretirement benefit plans were underfunded by $315.1 million at December 31, 2019 compared to being underfunded by $276.2 million at December 31, 2018. The decline in funded status was primarily due to a decrease in discount rates offset by favorable asset returns. We contributed $23.0 million and $21.0 million to our other postretirement benefit plans in 2019 and 2018, respectively.

No amounts of our pension or other postretirement benefit plans’ assets are expected to be returned to us or any of our subsidiaries in 2019.

In 2019 and 2018, 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 $9.5 million and $18.5 million in 2019 and 2018, respectively. Net periodic pension benefit cost for 2019 was decreased by $0.7 million as a result of the interim remeasurement.

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
	2019		2018		2019		2018
Weighted-average assumptions to Determine Benefit Obligation
Discount Rate	3.12	%	4.26	%	3.21	%	4.31	%
Rate of Compensation Increases	4.00	%	4.00	%	—		—
Health Care Trend Rates
Trend for Next Year	—		—		6.68	%	8.48	%
Ultimate Trend	—		—		4.50	%	4.50	%
Year Ultimate Trend Reached	—		—		2028		2026

Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects:

(in millions)	1% point increase		1% point decrease
Effect on service and interest components of net periodic cost	$	1.2	$	(1.1	)
Effect on accumulated postretirement benefit obligation	30.1		(26.3		)

We expect to make contributions of approximately $3.0 million to our pension plans and approximately $24.0 million to our postretirement medical and life plans in 2020.

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)
2020	$	178.8	$	38.1	$	0.5
2021	177.8		38.6		0.4
2022	175.8		38.4		0.4
2023	168.5		38.1		0.4
2024	164.4		37.9		0.4
2025-2029	723.7		181.0		1.5

The following table provides the components of the plans’ actuarially determined net periodic benefits cost for each of the three years ended December 31, 2019, 2018 and 2017:

	Pension Benefits									Other Postretirement Benefits
(in millions)	2019			2018			2017			2019			2018			2017
Components of Net Periodic Benefit Cost(1)
Service cost	$	29.2		$	31.3		$	30.0		$	5.1		$	5.0		$	4.8
Interest cost	72.3			67.1			68.3			19.2			17.6			17.8
Expected return on assets	(108.8		)	(142.3		)	(123.1		)	(13.1		)	(14.9		)	(15.9		)
Amortization of prior service cost (credit)	0.2			(0.4		)	(0.7		)	(3.2		)	(4.0		)	(4.4		)
Recognized actuarial loss	45.2			40.6			52.9			2.0			3.8			3.0
Settlement loss	9.5			18.5			13.7			—			—			—
Total Net Periodic Benefits Cost	$	47.6		$	14.8		$	41.1		$	10.0		$	7.5		$	5.3

⁽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."

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
	2019		2018		2017		2019		2018		2017
Weighted-average Assumptions to Determine Net Periodic Benefit Cost
Discount rate - service cost(1)	4.48	%	3.79	%	4.40	%	4.59	%	3.89	%	4.58	%
Discount rate - interest cost(1)	3.84	%	3.15	%	3.31	%	3.94	%	3.27	%	3.48	%
Expected Long-Term Rate of Return on Plan Assets	6.10	%	7.00	%	7.25	%	5.83	%	5.80	%	6.99	%
Rate of Compensation Increases	4.00	%	4.00	%	4.00	%	—		—		—

⁽¹⁾  In January 2017, we changed the method used to estimate the service and interest components of net periodic benefit cost for pension and other postretirement benefits. This change, compared to the previous method, resulted in a decrease in the actuarially-determined service and interest cost components. Historically, we estimated service and interest cost utilizing a single weighted-average discount rate derived from the yield curve used to measure the benefit obligation at the beginning of the period. For fiscal 2017 and beyond, we now utilize a full yield curve approach to estimate these components by applying the specific spot rates along the yield curve used in the determination of the benefit obligation to the relevant projected cash flows.

We believe it is appropriate to assume a 6.10% and 5.83% rate of return on pension and other postretirement plan assets, respectively, for our calculation of 2019 pension benefits cost. These rates are primarily based on asset mix and historical rates of return and were adjusted in the current year 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)	2019			2018			2019			2018
Other Changes in Plan Assets and Projected Benefit Obligations Recognized in Other Comprehensive Income or Regulatory Asset or Liability
Net prior service cost	$	—		$	0.2		$	5.1		$	0.1
Net actuarial loss (gain)	(53.8		)	127.5			45.1			(5.0		)
Settlements	(9.5		)	(18.5		)	—			—
Less: amortization of prior service cost	(0.2		)	0.4			3.2			4.0
Less: amortization of net actuarial loss	(45.2		)	(40.6		)	(2.0		)	(3.8		)
Total Recognized in Other Comprehensive Income or Regulatory Asset or  Liability	$	(108.7	)	$	69.0		$	51.4		$	(4.7	)
Amount Recognized in Net Periodic Benefits Cost and Other Comprehensive Income or Regulatory Asset or Liability	$	(61.1	)	$	83.8		$	61.4		$	2.8

Based on a December 31 measurement date, the estimated net unrecognized actuarial loss, unrecognized prior service cost, and unrecognized transition obligation that will be amortized into net periodic benefit cost during 2020 for the pension plans are $34.7 million, $0.8 million and zero, respectively, and for other postretirement benefit plans are $4.9 million, $(1.8) million and zero, respectively.

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Short-Term Borrowings

12 Months Ended

Dec. 31, 2019

Short-term Debt [Abstract]

Short-Term Borrowings

Short-Term Borrowings

We generate short-term borrowings from our revolving credit facility, commercial paper program, accounts receivable transfer programs and term loan borrowings. Each of these borrowing sources is described further below.

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, 2019 and 2018, 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 $570.0 million and $978.0 million of commercial paper outstanding as of December 31, 2019 and 2018, 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 $353.2 million and $399.2 million in transfers as of December 31, 2019 and 2018, respectively. Refer to Note 18, "Transfers of Financial Assets," for additional information.

On April 17, 2019, we amended our existing term loan agreement with a syndicate of banks, with MUFG Bank Ltd. as the Administrative Agent, Sole Lead Arranger and Sole Bookrunner. The amendment increased the amount of our term loan from $600.0 million to $850.0 million and extended the maturity date to April 16, 2020. Interest charged on borrowings depends on the variable rate structure we elect at the time of each borrowing. The available variable rate structures from which we may choose are defined in the term loan agreement. Under the agreement, we borrowed $850.0 million on April 17, 2019 with an interest rate of LIBOR plus 60 basis points.

Short-term borrowings were as follows: 

At December 31, (in millions)	2019		2018
Commercial Paper weighted-average interest rate of 2.03% and 2.96% at December 31, 2019 and 2018, respectively	$	570.0	$	978.0
Accounts receivable securitization facility borrowings	353.2		399.2
Term loan weighted-average interest rate of 2.40% and 3.07% at December 31, 2019 and 2018, respectively	850.0		$	600.0
Total Short-Term Borrowings	$	1,773.2	$	1,977.2

Other than for the term loan 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.

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Other Commitments And Contingencies

12 Months Ended

Dec. 31, 2019

Commitments and Contingencies Disclosure [Abstract]

Other Commitments And Contingencies

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, 2019 and their maturities were:

(in millions)	Total		2020		2021		2022		2023		2024		After
Long-term debt (1)	$	7,738.6	$	—	$	63.6	$	530.0	$	600.0	$	—	$	6,545.0
Interest payments on long-term debt	6,214.2		342.0		340.7		337.1		311.1		299.9		4,583.4
Finance leases(2)	325.9		27.2		27.3		26.8		23.1		19.9		201.6
Operating leases(3)	79.1		15.6		9.4		8.2		7.6		6.6		31.7
Energy commodity contracts(4)	95.9		65.5		30.4		—		—		—		—
Service obligations:
Pipeline service obligations	3,450.7		605.0		590.1		546.8		357.2		237.5		1,114.1
IT service obligations	153.2		63.6		49.4		38.0		1.1		1.1		—
Other service obligations(5)	59.8		45.8		14.0		—		—		—		—
Other liabilities	27.3		27.3		—		—		—		—		—
Total contractual obligations	$	18,144.7	$	1,192.0	$	1,124.9	$	1,486.9	$	1,300.1	$	565.0	$	12,475.8

⁽¹⁾ Long-term debt balance excludes unamortized issuance costs and discounts of $70.5 million.

⁽²⁾ Finance lease payments shown above are inclusive of interest totaling $108.3 million.

⁽³⁾ Operating lease payments shown above are inclusive of interest totaling $14.3 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. If we were to continue the fleet vehicle leases outstanding at December 31, 2019, payments would be $34.5 million in 2020, $28.3 million in 2021, $23.4 million in 2022, $19.9 million in 2023, $15.2 million in 2024 and $15.2 million thereafter.  

⁽⁴⁾In January 2020, NIPSCO signed new coal contract commitments of $14.4 million for 2020. These contracts are not included above.  

⁽⁵⁾In February 2020, NIPSCO signed a new railcar coal transportation contract commitment of $12.0 million for 2020. This contract is not included above.

Operating and Finance Lease Commitments. We lease assets in several areas of our operations including corporate and field offices, railcars, fleet vehicles and certain IT assets. Payments made in connection with operating and month-to-month leases were $52.5 million in 2019, $49.1 million in 2018 and $49.5 million in 2017, and are primarily charged to operation and maintenance expense as incurred. See Note 16, "Leases" for additional details.

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 minimum quantities 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, 2019.

In July 2008, the IURC issued an order approving NIPSCO’s purchase power agreements with subsidiaries of Iberdrola Renewables, Buffalo Ridge I LLC and Barton Windpower LLC. These agreements provide NIPSCO the opportunity and obligation to purchase up to 100 MW of wind power generated commencing in early 2009. The contracts extend 15 and 20 years, representing 50 MW of wind power each. 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 any termination of the agreements by NIPSCO for any reason (other than material breach by Buffalo Ridge I LLC or Barton Windpower LLC), 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. NIPSCO began purchasing wind power in April 2009.

We have pipeline service agreements that provide for pipeline capacity, transportation and storage services. These agreements, which have expiration dates ranging from 2020 to 2045, 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 2024.

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, 2019 and 2018, we had issued stand-by letters of credit of $10.2 million for the benefit of third parties.

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.

We are 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 described below. We are cooperating with all inquiries and investigations. In addition, 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, as described below.

NTSB Investigation. As previously disclosed, the NTSB concluded its investigation into the Greater Lawrence Incident, and we are implementing the one remaining safety recommendation resulting from the investigation.

Massachusetts Investigations. Under Massachusetts law, the DPU is authorized to investigate potential violations of pipeline safety regulations and to assess a civil penalty of up to $218,647 for a violation of federal pipeline safety regulations. A separate violation occurs for each day of violation up to $2.2 million for a related series of violations. The Massachusetts DPU also is authorized to investigate potential violations of the Columbia of Massachusetts emergency response plan and to assess penalties of up to $250,000 per violation per day, or up to $20 million per related series of violations. Further, as a result of the declaration of emergency by the Governor, the DPU is authorized to investigate potential violations of the DPU's operational directives during the restoration efforts and assess penalties of up to $1 million per violation. Pursuant to these authorities, the DPU is investigating Columbia of Massachusetts as described below. Columbia of Massachusetts will likely be subject to potential compliance actions related to the Greater Lawrence Incident and the restoration work following the incident, the timing and outcomes of which are uncertain at this time.

After the Greater Lawrence Incident, the Massachusetts DPU retained an independent evaluator to conduct a statewide examination of the safety of the natural gas distribution system and the operational and maintenance functions of natural gas companies in the Commonwealth of Massachusetts. Through authority granted by the Massachusetts Governor under the state of emergency, the Chair of the Massachusetts DPU has directed all natural gas distribution companies operating in the Commonwealth to fund the statewide examination. The statewide examination is complete. The Phase I report, which was issued in May 2019, included a program level assessment and evaluation of natural gas distribution companies. The Phase I report's conclusions were statewide and contained no specific conclusions about Columbia of Massachusetts. Phase II, which was focused on field assessments of each Massachusetts gas company, concluded in December 2019. The Phase II report made several observations about and recommendations to Massachusetts gas companies, including Columbia of Massachusetts, with regard to safety culture and assets. The final report was issued in late January 2020, and the DPU directed each natural gas distribution company operating in Massachusetts to submit a plan in response to the report no later than February 28, 2020.

On September 11, 2019, the Massachusetts DPU issued an order directing Columbia of Massachusetts to take several specific actions to address concerns related to service lines abandoned during the restoration work following the Greater Lawrence Incident and to furnish certain information and periodic reports to the DPU.

On October 1, 2019, the Massachusetts DPU issued four orders to Columbia of Massachusetts in connection with the service lines abandoned during the Greater Lawrence Incident restoration, which require: (1) the submission of a detailed work plan to the DPU, (2) the completion of quality control work on certain abandoned services, (3) the payment for a third-party independent audit, to be contracted through the DPU, of all gas pipeline work completed as part of the incident restoration effort, and (4) prompt and full response to any requests for information by the third-party auditor. The Massachusetts DPU retained an independent evaluator to conduct this audit, and that third party is currently evaluating compliance with Massachusetts and federal law, as well as any other operational or safety risks that may be posed by the pipeline work. The audit scope also includes Columbia of Massachusetts' operations in the Lawrence Division and other service territories as appropriate.

Also in October 2019, the Massachusetts DPU issued three additional orders requiring: (1) daily leak surveillance and reporting in areas where abandoned services are located, (2) completion by November 15, 2019 of the work plan previously submitted describing how Columbia of Massachusetts would address the estimated 2,200 locations at which an inside meter set was moved outside the property as part of the abandoned service work completed during the Greater Lawrence Incident restoration, and (3) submission of a report by December 2, 2019 showing any patterns, trends or correlations among the non-compliant work related to the abandonment of service lines, gate boxes and curb boxes during the incident restoration.

On October 3, 2019, the Massachusetts DPU notified Columbia of Massachusetts that, absent DPU approval, it is currently allowed to perform only emergency work on its gas distribution system throughout its service territories in Massachusetts. The restrictions do not apply to Columbia of Massachusetts’ work to address the previously identified issues with abandoned service lines and valve boxes in the Greater Lawrence, Massachusetts area. Columbia of Massachusetts is subject to daily monitoring by the DPU on any work that Columbia of Massachusetts conducts in Massachusetts. Such restrictions on work remain in place until modified by the DPU.

On October 25, 2019, the Massachusetts DPU issued two orders opening public investigations into Columbia of Massachusetts with respect to the Greater Lawrence Incident. The Massachusetts DPU opened the first investigation under its authority to determine compliance with federal and state pipeline safety laws and regulations, and to investigate Columbia of Massachusetts’ responsibility for and response to the Greater Lawrence Incident and its restoration efforts following the incident. The Massachusetts DPU opened the second investigation under its authority to determine whether a gas distribution company has violated established standards regarding acceptable performance for emergency preparedness and restoration of service to investigate efforts by Columbia of Massachusetts to prepare for and restore service following the Greater Lawrence Incident. Separate penalties are applicable under each exercise of authority.

On December 23, 2019, the Massachusetts DPU issued an order defining the scope of its investigation into the response of Columbia of Massachusetts related to the Greater Lawrence Incident. The DPU identified three distinct time frames in which Columbia of Massachusetts handled emergency response and restoration directly: (1) September 13-14, 2018, (2) September 21 through December 16, 2018 (the Phase I restoration), and (3) September 27, 2019 through completion of restoration of outages resulting from the gas release event in Lawrence, Massachusetts that occurred on September 27, 2019. The DPU determined that it is appropriate to investigate separately, for each time period described above, the areas of response, recovery and restoration for which Columbia of Massachusetts was responsible. The DPU noted that it also may investigate the continued restoration and related repair work that took place after December 16, 2018 and, depending on the outcome of that investigation, may deem it appropriate to consider that period of restoration as an additional separate time period.

The DPU also noted that its investigation into all of the above described time periods is ongoing and that if the DPU determines, based on its investigation, that it is appropriate to treat the separate time frames as separate emergency events, it may impose up to the maximum statutory penalty for each event, pursuant to Mass. G.L. c. 164 Section 1J. This provision authorizes the DPU to investigate potential violations of the Columbia of Massachusetts emergency response plan and to assess penalties of up to $250,000 per violation per day, or up to $20 million per related series of violations. The DPU noted that at this preliminary stage of the investigation, it does not have the factual basis to make those determinations.

In connection with its investigation related to the Greater Lawrence Incident, on February 4, 2020, the Massachusetts Attorney General's Office issued a request for documents primarily focused on the restoration work following the incident.

Columbia of Massachusetts is cooperating with the investigations set forth above as well as other inquiries resulting from an increased amount of enforcement activity, for all of which the outcomes are uncertain at this time.

Massachusetts Legislative Matters. On November 12, 2019, the Joint Committee on Telecommunications, Utilities and Energy held a hearing that focused on gas safety, but the Committee has not taken action on any bills. Increased scrutiny related to gas system safety and regulatory oversight in Massachusetts, including additional legislative oversight hearings and new legislative proposals, is expected to continue during the current two-year legislative session that ends in December 2020.

U.S. Department of Justice Investigation. As previously disclosed, the Company and Columbia of Massachusetts are subject to a criminal investigation related to the Greater Lawrence Incident that is being conducted under the supervision of the U.S. Attorney's Office. The initial grand jury subpoenas were served on the Company and Columbia of Massachusetts on September 24, 2018.

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 DPA.

Under the Plea Agreement, which must be approved by the Court, Columbia of Massachusetts will be subject to the following terms, among others: (i) a criminal fine in the amount of $53,030,116 paid within 30 days of sentencing; (ii) a three year probationary period that will early terminate 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; (iii) compliance with each of the NTSB recommendations stemming from the Greater Lawrence Incident; and (iv) employment of an in-house monitor during the term of the probationary period.

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. 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 Gas of Massachusetts or its gas distribution business, a fine equal to the total amount of any profit or gain 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’ guilty plea is not accepted by the Court or is withdrawn for any reason, 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.

U.S. Congressional Activity. On September 30, 2019, the U.S. Pipeline Safety Act expired. There is no effect on PHMSA's authority. Action on past re-authorization bills has extended past the expiration date and action on this re-authorization is expected to continue well into 2020. Pipeline safety jurisdiction resides with the U.S. Senate Commerce Committee, and is divided between two committees in the U.S. House of Representatives (Energy and Commerce, and Transportation and Infrastructure). Legislative proposals are currently in various stages of committee development and the timing of further action is uncertain. Certain legislative proposals, if enacted into law, may increase costs for natural gas industry companies, including the Company and Columbia of Massachusetts.

SEC Investigation. On November 27, 2019, the SEC staff notified the Company that it concluded its investigation related to disclosures made by the Company prior to the Greater Lawrence Incident and, based on the information provided as of such date, it does not intend to recommend an enforcement action against the Company.

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. A special judge has been appointed to hear all pending and future cases and the class actions have been consolidated into one class action. On January 14, 2019, the special judge granted the parties’ joint motion to stay all cases until

April 30, 2019 to allow mediation, and the parties subsequently agreed to extend the stay until July 25, 2019. The class action lawsuits allege varying causes of action, including those for strict liability for ultra-hazardous activity, negligence, private nuisance, public nuisance, premises liability, trespass, breach of warranty, breach of contract, failure to warn, unjust enrichment, consumer protection act claims, negligent, reckless and intentional infliction of emotional distress and gross negligence, and seek actual compensatory damages, plus treble damages, and punitive damages.

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 proposed settlement is subject to final court approval, and a hearing occurred on February 27, 2020. The court took the matter under advisement.

Many residents and business owners have submitted individual damage claims to Columbia of Massachusetts. Most of the wrongful death and bodily injury claims that have been asserted have been settled, and we continue to discuss potential settlements with plaintiffs asserting such claims. In addition, the Commonwealth of Massachusetts is seeking reimbursement from Columbia of Massachusetts for its expenses incurred in connection with the Greater Lawrence Incident. The outcomes and impacts of such private actions are uncertain at this time.

Financial Impact. Since the Greater Lawrence Incident, we have recorded expenses of approximately $1,041 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 $1,041 million to $1,065 million, depending on the number, nature, final outcome and value of third-party claims and the final outcome of government investigations. 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, nor do they include non-claims related and government investigation-related legal expenses resulting from the incident and the capital cost of the pipeline replacement, which are set forth in " - E. Other Matters - Greater Lawrence Incident Restoration" and "- Greater Lawrence Incident Pipeline Replacement," respectively, below.

The process for estimating costs associated with third-party claims and fines, penalties, and settlements associated with government investigations 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, including additional information regarding ongoing investigations, 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 have 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 that we are in substantial compliance with the environmental regulations currently applicable to our operations.

It is management's continued intent to address environmental issues in cooperation with regulatory authorities in such a manner as to achieve mutually acceptable compliance plans. However, there can be no assurance that fines and penalties will not be incurred. Management expects a significant portion of environmental assessment, improvement and remediation costs to be recoverable through rates for certain of our companies.

As of December 31, 2019 and 2018, we had recorded a liability of $104.4 million and $101.2 million, respectively, to cover environmental remediation at various sites. The current portion of this liability is included in "Legal and environmental" 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.

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 coal-fired units at NIPSCO’s R.M. Schahfer Generating Station and Michigan City Generating Station are potentially affected sources, and compliance requirements for these units which NIPSCO plans to retire by 2023 and 2028, respectively, will be determined by future Indiana rulemaking. The ACE rule notes that states have “broad flexibility in setting standards of performance for designated facilities” and that a state may set a “business as usual” standard for sources that have a remaining useful life “so short that imposing any costs on the electric generating unit is unreasonable.” State plans are due by 2022, and the EPA will have six months to determine completeness and then one additional year to determine whether to approve the submitted plan. States have the discretion to determine the compliance period for each source. As a result, NIPSCO will continue to monitor this matter and cannot estimate its impact at this time.

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 63 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, 2019. Our total estimated liability related to the facilities subject to remediation was $102.2 million and $97.5 million at December 31, 2019 and 2018, 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 to modify its infrastructure and manage CCRs during 2019. 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 has filed initial CCR closure plans for R.M. Schahfer Generating Station and Michigan City Generating Station with the Indiana Department of Environmental Management.

Water

ELG. On November 3, 2015, the EPA issued a final rule to amend the ELG and standards for the Steam Electric Power Generating category. Based upon a study performed in 2016 of the final rule, capital compliance costs were expected to be approximately $170.0 million. The EPA has proposed revisions to the final rule, and public comments were due on January 21, 2020. NIPSCO does not anticipate material ELG compliance costs based on the preferred option announced as part of NIPSCO's 2018 Integrated Resource Plan (discussed below).

E.         Other Matters.

NIPSCO 2018 Integrated Resource Plan. Multiple factors, but primarily economic ones, including low natural gas prices, advancing cost effective renewable technology and increasing capital and operating costs associated with existing coal plants, have led NIPSCO to conclude in its October 2018 Integrated Resource Plan submission that NIPSCO’s current fleet of coal generation facilities will be retired earlier than previous Integrated Resource 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 R.M. Schahfer Generating Station (Units 14, 15, 17, and 18) by 2023 and Michigan City Generating Station (Unit 12) by 2028. These units represent 2,080 MW of generating capacity, equal to 72% of NIPSCO’s remaining generating capacity (and 100% of NIPSCO's remaining coal-fired generating capacity) after the retirement of Bailly Units 7 and 8 on May 31, 2018.

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.

In January 2019, NIPSCO executed two 20 year PPAs to purchase 100% of the output from renewable generation facilities at a fixed price per MWh. NIPSCO submitted the PPAs to the IURC for approval in February 2019 and the IURC approved the PPAs on June 5, 2019. Payments under the PPAs will not begin until the associated generation facilities are constructed by the owner / seller which is currently scheduled to be complete by the end of 2020 for one facility. NIPSCO has filed a notice with the IURC of its intention not to move forward with one of its approved PPAs due to the failure to meet a condition precedent in the agreement as a result of local zoning restrictions.

Also in January 2019, NIPSCO executed a BTA with a developer to construct a renewable generation facility with a nameplate capacity of approximately 100 MW. Once complete, ownership of the facility would be transferred to a joint venture owned by NIPSCO, the developer and an unrelated tax equity partner. The aforementioned joint venture is expected to be fully owned by NIPSCO after the PTC are monetized from the project (approximately 10 years after the facility goes into service). NIPSCO's purchase requirement under the BTA 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 submitted the BTA to the IURC for approval

in February 2019 and the IURC approved the BTA on August 7, 2019. Required FERC filings occurred after receiving the IURC order and the related approvals were received. Construction of the facility is expected to be completed by the end of 2020.

On October 1, 2019, NIPSCO announced the opening of its next round of RFP to consider potential resources to meet the future electric needs of its customers. The RFP closed on November 20, 2019, and NIPSCO continues to evaluate the results. NIPSCO is considering all sources in the RFP process.

In October 2019, NIPSCO executed a BTA with a developer to construct an additional renewable generation facility with a nameplate capacity of approximately 300 MW. Once complete, ownership of the facility would be transferred to a joint venture owned by NIPSCO, the developer and an unrelated tax equity partner. The aforementioned joint venture is expected to be fully owned by NIPSCO after the PTC are monetized from the project (approximately 10 years after the facility goes into service). NIPSCO's purchase requirement under the BTA 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 submitted the BTA to the IURC for approval on October 22, 2019, and the IURC approved the BTA on February 19, 2020. Required FERC filings are expected to be filed by the end of June 2020. Construction of the facility is expected to be completed by the end of 2021.

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, since the Greater Lawrence Incident, we have recorded expenses of approximately $420 million for other incident-related costs. We estimate that total other incident-related costs will range from $450 million to $460 million, depending on the incurrence of costs associated with resolving outstanding inquiries and investigations discuss above in " - C. Legal Proceedings." 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. The amounts set forth above do not include the capital cost of the pipeline replacement, which is set forth below, or any estimates for fines and penalties, which are discussed above in " - C. Legal Proceedings."

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. We have collected the entire $800 million as of December 31, 2019. Expenses related to the incident have exceeded the total amount of insurance coverage available under our policies.

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).

	Year Ended			Year Ended
(in millions)	December 31, 2018			December 31, 2019			Incident to Date
Third-party claims and government fines, penalties and settlements	$	757		$	284		$	1,041
Other incident-related costs	266			154			420
Total	1,023			438			1,461
Insurance recoveries recorded	(135		)	(665		)	(800		)
Loss (benefit) to income before income taxes	$	888		$	(227	)	$	661

The following table presents activity related to our Greater Lawrence Incident insurance recovery, which we have recovered in full as of December 31, 2019.

(in millions)	Insurance receivable(1)
Balance, December 31, 2018	$	130
Insurance recoveries recorded in first quarter of 2019	100
Cash collected from insurance recoveries in the first quarter of 2019	(108		)
Balance, March 31, 2019	122
Insurance recoveries recorded in the second quarter of 2019	435
Cash collected from insurance recoveries in the second quarter of 2019	(297		)
Balance, June 30, 2019	$	260
Insurance recoveries recorded in third quarter of 2019	—
Cash collected from insurance recoveries in the third quarter of 2019	(260		)
Balance, September 30, 2019	$	—
Insurance recoveries recorded in the fourth quarter of 2019	130
Cash collected from insurance recoveries in the fourth quarter of 2019	(130		)
Balance, December 31, 2019	$	—

⁽¹⁾$5 million of insurance recoveries were collected during 2018.

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 45-mile cast iron and bare steel pipeline system that delivers gas to approximately 7,500 gas meters, the majority of which serve residences and approximately 700 of which serve businesses impacted in the Greater Lawrence Incident. This system was replaced with plastic distribution mains and service lines, as well as enhanced safety features such as pressure regulation and excess flow valves at each premise.

Since the Greater Lawrence Incident and through December 31, 2019, we have 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 full cost of 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. The recovery of any capital investment not reimbursed through insurance will be addressed in a future regulatory proceeding; a future regulatory proceeding is dependent on the outcome of the sale of the Massachusetts Business. The outcome of such a proceeding (if any) is uncertain. In accordance with ASC 980-360, if it becomes probable that a portion of the pipeline replacement cost will not be recoverable through customer rates and an amount can be reasonably estimated, we will reduce our regulated plant balance for the amount of the probable disallowance and record an associated charge to earnings. This could result in a material adverse effect to our financial condition, results of operations and cash flows. Additionally, if a rate order is received allowing recovery of the investment with no or reduced return on investment, a loss on disallowance may be required.

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 is expected to review the application within nine months from the date of filing, and we believe it is reasonably possible that the application will be accepted, or an alternative method proposed.

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Equity (Tables)

12 Months Ended

Dec. 31, 2019

Equity [Abstract]

Schedule Of Stock Offering Program

The following table summarizes our activity under the ATM program:

Year Ending December 31,	2019		2018		2017
Number of shares issued	8,422,498		8,883,014		11,931,376
Average price per share	$	27.75	$	26.85	$	26.58
Proceeds, net of fees (in millions)	$	229.1	$	232.5	$	314.7

Schedule of Stock by Class - Preferred

The following table summarizes preferred stock by outstanding series of shares:

				Year ended December 31,						December 31,		December 31,
				2019		2018		2017		2019		2018
(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	$	28.88	$	—	$	393.9	$	393.9
6.500% Series B	$	25,000.00	20,000	$	1,674.65	$	—	$	—	$	486.1	$	486.1

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Regulatory Matters (Tables)

12 Months Ended

Dec. 31, 2019

Regulatory Assets and Liabilities Disclosure [Abstract]

Regulatory Assets

Regulatory assets were comprised of the following items: 

At December 31, (in millions)	2019		2018
Regulatory Assets
Unrecognized pension and other postretirement benefit costs (see Note 11)	$	739.1	$	798.3
Deferred pension and other postretirement benefit costs (see Note 11)	91.3		74.1
Environmental costs (see Note 19-D)	73.4		61.5
Regulatory effects of accounting for income taxes (see Note 1-N and Note 10)	234.0		233.1
Under-recovered gas and fuel costs (see Note 1-J)	3.9		34.7
Depreciation	210.7		209.6
Post-in-service carrying charges	219.8		206.6
Safety activity costs	118.6		91.7
DSM programs	50.1		45.5
Bailly Generating Station	221.8		244.3
Other	276.9		238.1
Total Regulatory Assets	$	2,239.6	$	2,237.5

Regulatory Liabilities

Regulatory liabilities were comprised of the following items: 

At December 31, (in millions)	2019		2018
Regulatory Liabilities
Over-recovered gas and fuel costs (see Note 1-J)	$	42.6	$	32.0
Cost of removal (see Note 7)	1,047.5		1,076.0
Regulatory effects of accounting for income taxes (see Note 1-N and Note 10)	1,307.0		1,428.3
Deferred pension and other postretirement benefit costs (see Note 11)	64.7		62.7
Other	50.4		61.0
Total Regulatory Liabilities	$	2,512.2	$	2,660.0

Schedule of Regulatory Programs

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	Filed	Status	Rates Effective
Columbia of Ohio	IRP - 2019(1)	$	18.2		$	199.6	1/18-12/18	February 28, 2019	Approved April 24, 2019	May 2019
Columbia of Ohio	CEP - 2018	$	74.5		$	659.9	1/11-12/17	December 1, 2017	Approved November 28, 2018	December 2018
Columbia of Ohio	CEP - 2019	$	15.0		$	121.7	1/18-12/18	February 28, 2019	Approved August 28, 2019	September 2019
NIPSCO - Gas	TDSIC 9(1)(2)	$	(10.6	)	$	54.4	1/18-6/18	August 28, 2018	Approved December 27, 2018	January 2019
NIPSCO - Gas	TDSIC 10(3)	$	1.6		$	12.4	7/18-4/19	June 25, 2019	Approved October 16, 2019	November 2019
NIPSCO - Gas	TDSIC 11(4)	$	(1.7	)	$	38.7	5/19-12/19	February 25, 2020	Order Expected June 2020	July 2020
NIPSCO - Gas	FMCA 1(5)	$	9.9		$	1.5	11/17-9/18	November 30, 2018	Approved March 27, 2019	April 2019
NIPSCO - Gas	FMCA 2(5)	$	(3.5	)	$	1.8	10/18-3/19	May 29, 2019	Approved September 25, 2019	October 2019
NIPSCO - Gas	FMCA 3(5)	$	0.3		$	43.0	4/19-9/19	November 26, 2019	Order Expected March 2020	April 2020
Columbia of Massachusetts	GSEP - 2019(6)	$	9.6		$	36.0	1/19-12/19	October 31, 2018	Approved April 30, 2019	May 2019
Columbia of Massachusetts	GSEP - 2020(6)(7)	$	2.4		$	75.0	1/20-12/20	October 31, 2019	Order Expected April 2020	May 2020
Columbia of Virginia	SAVE - 2019	$	2.4		$	36.0	1/19-12/19	August 17, 2018	Approved October 26, 2018	January 2019
Columbia of Virginia	SAVE - 2020	$	3.8		$	50.0	1/20-12/20	August 15, 2019	Approved December 6, 2019	January 2020
Columbia of Kentucky	AMRP - 2019	$	3.6		$	30.1	1/19-12/19	October 15, 2018	Approved December 5, 2018	January 2019
Columbia of Kentucky	SMRP - 2020	$	4.2		$	40.4	1/20-12/20	October 15, 2019	Approved December 20, 2019	January 2020
Columbia of Maryland	STRIDE - 2019	$	1.2		$	19.7	1/19-12/19	November 1, 2018	Approved December 12, 2018	January 2019
Columbia of Maryland	STRIDE - 2020	$	1.3		$	15.0	1/20-12/20	January 29, 2020	Approved February 19, 2020	February 2020
NIPSCO - Electric	TDSIC - 5(1)	$	15.9		$	58.8	6/18-11/18	January 29, 2019	Approved June 12, 2019	June 2019
NIPSCO - Electric	TDSIC - 6	$	28.1		$	131.1	12/18-6/19	August 21, 2019	Approved December 18, 2019	January 2020
NIPSCO - Electric	FMCA - 11(5)	$	0.9		$	22.4	9/18-2/19	April 17, 2019	Approved July 29, 2019	August 2019
NIPSCO - Electric	FMCA - 12(5)	$	1.6		$	4.7	3/19-8/19	October 18, 2019	Approved January 29, 2020	February 2020

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

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

⁽³⁾Incremental capital and revenue are net of amounts included in the step 2 rates.

⁽⁴⁾Incremental revenue is net of amounts included in the step 2 rates and reflects a more typical filing period.

⁽⁵⁾Incremental revenue is inclusive of tracker eligible operations and maintenance expense.

⁽⁶⁾Due to an order from the Massachusetts DPU on October 3, 2019 imposing work restrictions on Columbia of Massachusetts, Columbia of Massachusetts did not meet the approved projected 2019 GSEP spend of $64 million and associated incremental revenue of $10.7 million. In the 2020 GSEP, Columbia of Massachusetts reduced the projected capital spend for calendar year 2019 to $36 million and the associated incremental revenue in 2019 GSEP to $9.6 million.

⁽⁷⁾Incremental capital investment is anticipated to be lower than $75 million in 2020 due to the Massachusetts DPU imposed work restrictions.

Rate Case Action

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

(in millions)
Company	Requested Incremental Revenue		Approved Incremental Revenue			Filed	Status	Rates Effective
NIPSCO - Gas(1)	$	138.1	$	105.6		September 27, 2017	Approved September 19, 2018	October 2018
Columbia of Virginia(2)	$	14.2	$	1.3		August 28, 2018	Approved June 12, 2019	February 2019
NIPSCO - Electric(3)	$	21.4	$	(53.5	)	October 31, 2018	Approved December 4, 2019	January 2020
Columbia of Maryland	$	2.5	$	(0.1	)	May 22, 2019	Approved December 18, 2019	December 2019

⁽¹⁾Rates were implemented in three steps, with implementation of step 1 rates effective October 1, 2018. Step 2 rates were effective on March 1, 2019, and step 3 rates were effective on January 1, 2020. The step 3 increase was approved based on actual information and revised from $107.3 million to $105.6 million. The IURC’s order also dismissed NIPSCO from phase 2 of the IURC’s TCJA investigation.

⁽²⁾Rates, as originally filed, were implemented in February 2019 on an interim basis, subject to refund. The final approved rates, which replaced interim rates, were implemented in July 2019.

⁽³⁾An order was received on December 4, 2019, which included the resolution of outstanding TCJA impacts to rates. Incremental revenues decreased due to a reduction in fuel costs associated with the new industrial service structure. Rates will be implemented in two steps, with implementation of step 1 rates effective January 2, 2020 and step 2 rates effective March 2, 2020.

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Valuation and Qualifying Accounts (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Reserve For Accounts Receivable [Member]
SEC Schedule, 12-09, Valuation and Qualifying Accounts Disclosure [Line Items]
Beginning Balance		$ 21.1	$ 18.3	$ 23.3
Valuation Allowances and Reserves, Charged to Cost and Expense		21.6	20.2	14.8
Valuation Allowances and Reserves, Charged to Other Accounts	[1]	41.3	43.7	39.1
Deductions for Purposes for which Reserves were Created		64.8	61.1	58.9
Ending Balance		19.2	21.1	18.3
Reserve For Other Investments [Member]
SEC Schedule, 12-09, Valuation and Qualifying Accounts Disclosure [Line Items]
Beginning Balance		3.0	3.0	3.0
Valuation Allowances and Reserves, Charged to Cost and Expense		0.0	0.0	0.0
Valuation Allowances and Reserves, Charged to Other Accounts	[1]	0.0	0.0	0.0
Deductions for Purposes for which Reserves were Created		0.0	0.0	0.0
Ending Balance		$ 3.0	$ 3.0	$ 3.0

[1] Charged to Other Accounts reflects the deferral of bad debt expense to a regulatory asset.

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Quarterly Financial Data (Narrative) (Details) - USD ($) $ in Millions		3 Months Ended								6 Months Ended	12 Months Ended				16 Months Ended
	Jul. 16, 2018	Dec. 31, 2019		Sep. 30, 2019	[1]	Jun. 30, 2019	[1]	Mar. 31, 2019	[1]	Jun. 30, 2018	Dec. 31, 2019		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2019
Quarterly Financial Data [Line Items]
Proceeds From Insurance Settlement		$ 130.0	[1]	$ 260.0		$ 297.0		$ 108.0							$ 800.0
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Amount											$ 0.0		$ 0.0	$ 161.1
Increase (Decrease) in Income Taxes													120.7
Loss on early extinguishment of long-term debt	$ 33.0									$ 12.5	0.0		(45.5)	$ (111.5)
Goodwill		1,485.9									1,485.9		1,690.7		1,485.9
Intangible Assets, Net (Excluding Goodwill)		0.0									0.0		220.7		$ 0.0
Interest Rate Swap Settled
Quarterly Financial Data [Line Items]
Derivative, Gain (Loss) on Derivative, Net											$ 0.0	[2]	$ 46.2
Columbia Of Massachusetts
Quarterly Financial Data [Line Items]
Expenses Related to Third Party Claims and Other Expenses		462.0
Goodwill, Impairment Loss		204.8
Impairment of Intangible Assets, Finite-lived		$ 209.7

[1] $5 million of insurance recoveries were collected during 2018.

[2] ⁽³⁾ See Note 9, "Risk Management Activities" for additional information.

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Earnings Per Share (Tables)

12 Months Ended

Dec. 31, 2019

Earnings Per Share [Abstract]

Schedule of Weighted Average Number of Shares

The computation of diluted average common shares is as follows:

Year Ended December 31, (in thousands)	2019	2018	2017
Denominator
Basic average common shares outstanding	374,650	356,491	329,388
Dilutive potential common shares:
Shares contingently issuable under employee stock plans	929	—	547
Shares restricted under stock plans	154	—	821
Forward agreements	253	—	—
Diluted Average Common Shares	375,986	356,491	330,756

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Fair Value (Available-For-Sale Securities) (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Fair Value Disclosure [Line Items]
Amortized Cost	$ 150.1	$ 141.3
Gross Unrealized Gains	4.3	0.5
Gross Unrealized Losses	0.2	3.5
Fair Value	154.2	138.3
U.S. Treasury debt securities
Fair Value Disclosure [Line Items]
Amortized Cost	31.4	23.6
Gross Unrealized Gains	0.1	0.1
Gross Unrealized Losses	0.1	0.1
Fair Value	31.4	23.6
Corporate/Other debt securities
Fair Value Disclosure [Line Items]
Amortized Cost	118.7	117.7
Gross Unrealized Gains	4.2	0.4
Gross Unrealized Losses	0.1	3.4
Fair Value	$ 122.8	$ 114.7

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Nature of Operations And Summary of Significant Accounting Policies (Narrative) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019 USD ($)	Dec. 31, 2018 USD ($)	Dec. 31, 2017
Basis Of Accounting Presentation [Line Items]
Number of customers	4,000,000
Unbilled revenue, less reserves	$ 350.5	$ 324.2
Other than Temporary Impairment Losses, Investments	$ 0.0	$ 0.0
Pre-tax rate for allowance for funds used during construction	3.00%	3.50%	4.00%
Inventory valued using LIFO	$ 47.2	$ 47.5
Excess of replacement over LIFO value	(25.5)	(12.2)
Inventory valued using the weighted average cost methodology	$ 203.7	$ 239.3

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Leases (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Jan. 01, 2019
Lessee, Lease, Description [Line Items]
Operating Lease, Right-of-Use Asset	$ 64.2			$ 57.0
Lessee, Lease Renewal Term	25 years
Lessee, Operating Lease, Renewal Term	1 year
Lessee, Finance Lease, Term of Contract	4 years
Payments made in connection with operating leases	$ 52.5	$ 49.1	$ 49.5
Fleet Lease
Lessee, Lease, Description [Line Items]
Lessee, Finance Lease, Term of Contract	1 year
Minimum
Lessee, Lease, Description [Line Items]
Lessee, Operating Lease, Term of Contract	1 year
Minimum | Office Lease
Lessee, Lease, Description [Line Items]
Remaining Lease Term	1 year
Maximum
Lessee, Lease, Description [Line Items]
Lessee, Operating Lease, Term of Contract	3 years
Maximum | Office Lease
Lessee, Lease, Description [Line Items]
Remaining Lease Term	24 years

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Pension and Other Postretirement Benefits (Schedule Of Reconciliation Of The Plans Funded Status And Amounts Reflected) (Details) - USD ($) $ in Millions		3 Months Ended			12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018		Dec. 31, 2019	Dec. 31, 2018		Dec. 31, 2017
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at beginning of year					$ 2,084.1
Fair value of plan assets at end of year		$ 2,342.3	$ 2,084.1		2,342.3	$ 2,084.1
Noncurrent liabilities		(314.3)	(275.4)		(314.3)	(275.4)
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation at beginning of year	[1]				1,981.3	2,192.6
Service cost		29.2	31.3		29.2	31.3		$ 30.0
Interest cost		72.3	67.1		72.3	67.1		68.3
Plan participants' contributions					0.0	0.0
Plan amendments					0.0	0.2
Actuarial loss (gain)					204.3	(103.9)
Settlement Loss					0.0	0.8
Defined Benefit Plan, Benefit Obligation, Benefits Paid					156.6	206.8
Benefits paid					(156.5)	(206.8)
Estimated benefits paid by incurred subsidy					0.0	0.0
Projected benefit obligation at end of year		2,130.5	1,981.3	[1]	2,130.5	1,981.3	[1]	2,192.6	[1]
Fair value of plan assets at beginning of year					1,867.7	2,160.0
Actual return on plan assets					366.8	(88.4)
Employer contributions					2.9	2.9
Defined Benefit Plan, Plan Assets, Contributions by Plan Participant					0.0	0.0
Fair value of plan assets at end of year		2,080.9	1,867.7		2,080.9	1,867.7		2,160.0
Defined Benefit Plan, Funded (Unfunded) Status of Plan		(49.6)	(113.6)		(49.6)	(113.6)
Noncurrent assets		8.2	0.0		8.2	0.0
Current liabilities		(3.0)	(3.0)		(3.0)	(3.0)
Noncurrent liabilities		(54.8)	(110.6)		(54.8)	(110.6)
Net amount recognized at end of year	[2]	(49.6)	(113.6)		(49.6)	(113.6)
Unrecognized prior service cost	[3]	3.0	3.2		3.0	3.2
Unrecognized actuarial loss	[3]	652.8	761.2		652.8	761.2
Defined Benefit Plan Amounts Recognized In Other Comprehensive Income Or Regulatory Asset Or Liability	[3]	655.8	764.4		655.8	764.4
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation at beginning of year	[1]				492.5	556.3
Service cost		5.1	5.0		5.1	5.0		4.8
Interest cost		19.2	17.6		19.2	17.6		17.8
Plan participants' contributions					4.8	5.7
Plan amendments					5.1	0.1
Actuarial loss (gain)					88.8	(51.7)
Settlement Loss					0.0	0.0
Defined Benefit Plan, Benefit Obligation, Benefits Paid					39.5	41.1
Benefits paid					(39.5)	(41.1)
Estimated benefits paid by incurred subsidy					0.5	0.6
Projected benefit obligation at end of year		576.5	492.5	[1]	576.5	492.5	[1]	556.3	[1]
Fair value of plan assets at beginning of year					216.3	262.5
Actual return on plan assets					56.9	(31.8)
Employer contributions					23.0	21.0
Defined Benefit Plan, Plan Assets, Contributions by Plan Participant					4.7	5.7
Fair value of plan assets at end of year		261.4	216.3		261.4	216.3		$ 262.5
Defined Benefit Plan, Funded (Unfunded) Status of Plan		(315.1)	(276.2)		(315.1)	(276.2)
Noncurrent assets		0.0	0.0		0.0	0.0
Current liabilities		(0.8)	(0.8)		(0.8)	(0.8)
Net amount recognized at end of year	[2]	(315.1)	(276.2)		(315.1)	(276.2)
Unrecognized prior service cost	[3]	(10.7)	(19.0)		(10.7)	(19.0)
Unrecognized actuarial loss	[3]	118.4	75.3		118.4	75.3
Defined Benefit Plan Amounts Recognized In Other Comprehensive Income Or Regulatory Asset Or Liability	[3]	$ 107.7	$ 56.3		$ 107.7	$ 56.3

[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] 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] 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 $739.1 million and $0.1 million, respectively, as of December 31, 2019, and $798.3 million and $0.1 million, respectively, as of December 31, 2018 that would otherwise have been recorded to accumulated other comprehensive loss.

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Leases (Lease Maturity) (Details) - USD ($) $ in Millions		Dec. 31, 2019	Dec. 31, 2018
Lease Maturity [Line Items]
Total Future Minimum Lease Payments Due, Next Twelve Months		$ 42.8	$ 34.0
Total Future Minimum Lease Payments, Due in Two Years		36.7	29.8
Total Future Minimum Lease Payments, Due in Three Years		35.0	28.7
Total Future Minimum Lease Payments, Due in Four Years		30.7	26.3
Total Future Minimum Lease Payments, Due in Five Years		26.5	22.6
Total Future Minimum Lease Payments, Due Thereafter		233.3	226.9
Total Future Minimum Lease Payments Due		405.0	$ 368.3
Undiscounted Excess Amount		(116.6)
Total Lease Liability		266.3
Short-term Lease Liability		26.6
Long-term Lease Liability		239.7
Finance Leases, Future Minimum Payments Due, Next Twelve Months	[1]	27.2
Finance Leases, Future Minimum Payments Due in Two Years	[1]	27.3
Finance Leases, Future Minimum Payments Due in Three Years	[1]	26.8
Finance Leases, Future Minimum Payments Due in Four Years	[1]	23.1
Finance Leases, Future Minimum Payments Due in Five Years	[1]	19.9
Finance Leases, Future Minimum Payments Due Thereafter	[1]	201.6
Finance Lease, Liability, Payment, Due	[1]	325.9
Finance Lease, Liability, Current		13.4
Finance Lease, Liability, Noncurrent		188.1
Operating Leases, Future Minimum Payments Due, Next Twelve Months	[2]	15.6
Operating Leases, Future Minimum Payments, Due in Two Years	[2]	9.4
Operating Leases, Future Minimum Payments, Due in Three Years	[2]	8.2
Operating Leases, Future Minimum Payments, Due in Four Years	[2]	7.6
Operating Leases, Future Minimum Payments, Due in Five Years	[2]	6.6
Operating Leases, Future Minimum Payments, Due Thereafter	[2]	31.7
Lessee, Operating Lease, Liability, Payments, Due	[2]	79.1
Leases Not Yet Commenced	[3]	(22.1)
Operating Lease, Liability, Current		13.2
Operating Lease, Liability, Noncurrent		51.6
Interconnection facilities
Lease Maturity [Line Items]
Leases Not Yet Commenced		(22.1)
Finance Lease
Lease Maturity [Line Items]
Finance Leases, Future Minimum Payments Due, Next Twelve Months		27.2
Finance Leases, Future Minimum Payments Due in Two Years		27.3
Finance Leases, Future Minimum Payments Due in Three Years		26.8
Finance Leases, Future Minimum Payments Due in Four Years		23.1
Finance Leases, Future Minimum Payments Due in Five Years		19.9
Finance Leases, Future Minimum Payments Due Thereafter		201.6
Finance Lease, Liability, Payment, Due		325.9
Finance Lease, Liability, Undiscounted Excess Amount		(102.3)
Finance Lease, Liability		201.5
Finance Lease, Liability, Current		13.4
Finance Lease, Liability, Noncurrent		188.1
Leases Not Yet Commenced	[3]	(22.1)
Operating Lease
Lease Maturity [Line Items]
Operating Leases, Future Minimum Payments Due, Next Twelve Months		15.6
Operating Leases, Future Minimum Payments, Due in Two Years		9.4
Operating Leases, Future Minimum Payments, Due in Three Years		8.2
Operating Leases, Future Minimum Payments, Due in Four Years		7.6
Operating Leases, Future Minimum Payments, Due in Five Years		6.6
Operating Leases, Future Minimum Payments, Due Thereafter		31.7
Lessee, Operating Lease, Liability, Payments, Due		79.1
Lessee, Operating Lease, Liability, Undiscounted Excess Amount		(14.3)
Leases Not Yet Commenced	[3]	0.0
Operating Lease, Liability		64.8
Operating Lease, Liability, Current		13.2
Operating Lease, Liability, Noncurrent		$ 51.6
Maximum
Lease Maturity [Line Items]
Lessee, Finance Lease, Lease Not yet Commenced, Term of Contract		20 years
Minimum
Lease Maturity [Line Items]
Lessee, Finance Lease, Lease Not yet Commenced, Term of Contract		4 years

[1] Finance lease payments shown above are inclusive of interest totaling $108.3 million.

[2] Operating lease payments shown above are inclusive of interest totaling $14.3 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. If we were to continue the fleet vehicle leases outstanding at December 31, 2019, payments would be $34.5 million in 2020, $28.3 million in 2021, $23.4 million in 2022, $19.9 million in 2023, $15.2 million in 2024 and $15.2 million thereafter.

[3] Expected payments include obligations for leases not yet commenced of approximately $22.1 million for IT assets and interconnection facilities. These leases have terms between 4 years and 20 years, with estimated commencements in the first quarter of 2020 and in the third quarter of 2020.

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Pension and Other Postretirement Benefits (Schedule Of Expected Payments To Participants In Pension Plan) (Details) $ in Millions	Dec. 31, 2019 USD ($)
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
2017	$ 178.8
2018	177.8
2019	175.8
2020	168.5
2021	164.4
2022-2026	723.7
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
2017	38.1
2018	38.6
2019	38.4
2020	38.1
2021	37.9
2022-2026	181.0
Postretirement Health Coverage [Member]
Defined Benefit Plan Disclosure [Line Items]
2017	0.5
2018	0.4
2019	0.4
2020	0.4
2021	0.4
2022-2026	$ 1.5

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Revenue Recognition (Customer Accounts Receivable) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018
Revenue Recognition [Abstract]
Customer Accounts Receivable, Billed (Less Reserve)	[1]	$ 466.6	$ 540.5
Customer Accounts Receivable, Unbilled (Less Reserve)		346.6	$ 349.1
Increase (Decrease) in Customer Accounts Receivable, Billed (Less Reserve)	[1]	(73.9)
Increase (Decrease) in Customer Accounts Receivable, Unbilled (Less Reserve)		$ (2.5)

[1] Customer billed receivables decreased due to decreased natural gas costs and warmer weather in 2019 compared to 2018

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Transfers Of Financial Assets

12 Months Ended

Dec. 31, 2019

Transfers and Servicing [Abstract]

Transfers Of Financial Assets

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 2020 and October 2020 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, 2019, the maximum amount of debt that could be recognized related to our accounts receivable programs is $465.0 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, 2019 and 2018:

At December 31, (in millions)	2019		2018
Gross receivables	$	569.1	$	694.4
Less: receivables not transferred	215.9		295.2
Net receivables transferred	$	353.2	$	399.2
Short-term debt due to asset securitization	$	353.2	$	399.2

During 2019, $46.0 million was recorded as cash flows used for financing activities related to the change in short-term borrowings due to securitization transactions. During 2018, $62.5 million was recorded as cash flows from financing activities related to the change in short-term borrowings due to securitization transactions. Fees associated with the securitization transactions were $2.6 million, $2.6 million and $2.5 million for the years ended December 31, 2019, 2018 and 2017, respectively. Columbia of Ohio, NIPSCO and Columbia of Pennsylvania remain responsible for collecting on the receivables securitized, and the receivables cannot be transferred to another party.

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Income Taxes

12 Months Ended

Dec. 31, 2019

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

Income Tax Expense

The components of income tax expense (benefit) were as follows: 

Year Ended December 31, (in millions)	2019			2018			2017
Income Taxes
Current
Federal	$	—		$	—		$	—
State	5.2			8.2			7.8
Total Current	5.2			8.2			7.8
Deferred
Federal	110.7			(209.4		)	302.7
State	9.0			22.2			5.0
Total Deferred	119.7			(187.2		)	307.7
Deferred Investment Credits	(1.4		)	(1.0		)	(1.0		)
Income Taxes	$	123.5		$	(180.0	)	$	314.5

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)	2019					2018					2017
Book income (loss) before income taxes	$	506.6				$	(230.6	)			$	443.0
Tax expense (benefit) at statutory federal income tax rate	106.5			21.0	%	(48.4		)	21.0	%	155.0			35.0	%
Increases (reductions) in taxes resulting from:
State income taxes, net of federal income tax benefit	10.1			2.0		24.7			(10.7	)	6.9			1.5
Amortization of regulatory liabilities	(29.4		)	(5.8	)	(29.3		)	12.7		(2.4		)	(0.5	)
Goodwill impairment	43.0			8.5		—			—		—			—
Fines and penalties	11.5			2.3		0.2			(0.1	)	2.8			0.6
Charitable contribution carryover	(2.5		)	(0.5	)	—			—		(1.2		)	(0.3	)
State regulatory proceedings	(9.5		)	(1.9	)	(127.8		)	55.4		—			—
Remeasurement due to TCJA	—			—		—			—		161.1			36.4
Employee stock ownership plan dividends and other compensation	(2.0		)	(0.4	)	(2.2		)	1.0		(6.5		)	(1.5	)
Other adjustments	(4.2		)	(0.8	)	2.8			(1.2	)	(1.2		)	(0.2	)
Income Taxes	$	123.5		24.4	%	$	(180.0	)	78.1	%	$	314.5		71.0	%

The effective income tax rates were 24.4%, 78.1% and 71.0% in 2019, 2018 and 2017, respectively. 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 6, "Goodwill and Other Intangible Assets" for additional information)

and non-deductible fines and penalties related to the Greater Lawrence Incident (see Note 19, "Legal Proceedings" for additional information). The rate is also impacted by the relative impact of permanent differences on higher pre-tax income.

The 7.1% increase in the overall effective tax rate in 2018 versus 2017 was primarily the result of state regulatory proceedings which resulted in a $127.8 million decrease in federal income taxes offset by a related increase in state income taxes of $7.1 million. Additionally, the increase was driven by a $26.9 million decrease in income taxes related to amortization of the regulatory liability primarily associated with excess deferred taxes.

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)	2019		2018
Deferred tax liabilities
Accelerated depreciation and other property differences	$	2,516.9	$	2,458.0
Other regulatory assets	381.5		375.4
Total Deferred Tax Liabilities	2,898.4		2,833.4
Deferred tax assets
Other regulatory liabilities and deferred investment tax credits (including TCJA)	336.1		365.5
Pension and other postretirement/postemployment benefits	152.1		157.5
Net operating loss carryforward and AMT credit carryforward	765.9		849.8
Environmental liabilities	25.4		24.4
Other accrued liabilities	35.3		37.5
Other, net	98.3		68.2
Total Deferred Tax Assets	1,413.1		1,502.9
Net Deferred Tax Liabilities	$	1,485.3	$	1,330.5

At December 31, 2019, we had $657.1 million of federal net operating loss carryforwards. The federal net operating loss carryforwards are available to offset taxable income and will begin to expire in 2028. We also have $1.6 million of federal alternative minimum tax credit carryforwards which do not expire. In addition, we have $1.4 million in charitable contribution carryforwards to offset future taxable income, which begin to expire in 2023. We also have $107.2 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 we will realize the benefit from the state net operating loss carryforwards.

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)	2019			2018			2017
Unrecognized Tax Benefits - Opening Balance	$	1.2		$	1.4		$	2.6
Gross decreases - tax positions in prior period	(0.6		)	(0.4		)	(1.4		)
Gross increases - current period tax positions	22.6			0.2			0.2
Unrecognized Tax Benefits - Ending Balance	$	23.2		$	1.2		$	1.4
Offset for net operating loss carryforwards	(22.6		)	—			—
Balance - Less Net Operating Loss Carryforwards	$	0.6		$	1.2		$	1.4

In 2019, we resolved prior unrecognized tax benefits of $0.6 million and established new unrecognized tax benefits related to state matters of $22.6 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, 2019, 2018 and 2017, and there were no balances for accrued penalties recorded on the Consolidated Balance Sheets as of December 31, 2019 and 2018.

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

We participate in the IRS CAP which provides the opportunity to resolve tax matters with the IRS before filing each year's consolidated federal income tax return. As of December 31, 2019, tax years through 2018 have been audited and are effectively closed to further assessment. The audit of tax year 2019 under the CAP program is expected to be completed in 2020.

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, 2019, there were no state income tax audits in progress that would have a material impact on the consolidated financial statements.

In December 22, 2017, the TCJA was signed into law. As a result of the implementation of the TCJA, we remeasured deferred taxes and recognized $161.1 million of income tax expense in our Consolidated Statements of Income (Loss) for the year ended December 31, 2017. The result of this remeasurement was a reduction in the net deferred tax liability of approximately $1.3 billion, including approximately $0.4 billion of regulatory "gross up" to account for over collection of past taxes from customers. Offsetting the reduction in net deferred tax liabilities was an increase in regulatory liabilities of approximately $1.5 billion as of December 31, 2017. In 2018, we received regulatory orders on the treatment of excess deferred taxes from the jurisdictions in which we operate. As a result of these orders, we reduced our regulatory liability related to excess deferred income taxes by $120.7 million (net of tax). This adjustment is reflected in "Income Taxes" on our Consolidated Statements of Income (Loss) for the year ended December 31, 2018.

As of December 31, 2019, we received approval from regulators to return excess deferred taxes in all of our jurisdictions in accordance with regulatory proceedings.

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

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Long-Term Debt

12 Months Ended

Dec. 31, 2019

Long-term Debt, Current and Noncurrent [Abstract]

Long-Term Debt

Long-Term Debt

Our long-term debt as of December 31, 2019 and 2018 is as follows:

Long-term debt type	Maturity as of December 31, 2019	Weighted average interest rate (%)		Outstanding balance as of December 31, (in millions)
				2019			2018
Senior notes:
NiSource	December 2021	4.45	%	63.6			63.6
NiSource	November 2022	2.65	%	500.0			500.0
NiSource	February 2023	3.85	%	250.0			250.0
NiSource	June 2023	3.65	%	350.0			350.0
NiSource	November 2025	5.89	%	265.0			265.0
NiSource	May 2027	3.49	%	1,000.0			1,000.0
NiSource	December 2027	6.78	%	3.0			3.0
NiSource	September 2029	2.95	%	750.0			—
NiSource	December 2040	6.25	%	250.0			250.0
NiSource	June 2041	5.95	%	400.0			400.0
NiSource	February 2042	5.80	%	250.0			250.0
NiSource	February 2043	5.25	%	500.0			500.0
NiSource	February 2044	4.80	%	750.0			750.0
NiSource	February 2045	5.65	%	500.0			500.0
NiSource	May 2047	4.38	%	1,000.0			1,000.0
NiSource	March 2048	3.95	%	750.0			750.0
Total senior notes				$	7,581.6		$	6,831.6
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	December 2025 to February 2028	6.30	%	40.0			40.0
Total medium term notes				$	157.0		$	157.0
Finance leases:
NiSource Corporate Services	January 2020 to November 2023	3.47	%	22.3			11.6
Columbia of Ohio	October 2021 to March 2044	6.16	%	94.8			91.5
Columbia of Virginia	July 2029 to November 2039	6.31	%	19.1			15.2
Columbia of Kentucky	May 2027	3.79	%	0.3			0.3
Columbia of Pennsylvania	August 2027 to May 2035	5.67	%	20.7			30.0
Columbia of Massachusetts	December 2033 to November 2043	5.49	%	44.3			45.7
Total finance leases				201.5			194.3
Pollution control bonds - NIPSCO	April 2019	5.85	%	—			41.0
Unamortized issuance costs and discounts				(70.5		)	$	(68.5	)
Total Long-Term Debt				$	7,869.6		$	7,155.4

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 closed our placement 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.

Details of our 2018 long-term debt related activity are summarized below:

• On March 15, 2018, we redeemed $275.1 million of 6.40% senior unsecured notes at maturity.

• In June 2018, we executed a tender offer for $209.0 million of outstanding notes consisting of a combination of our 6.80% notes due 2019, 5.45% notes due 2020, and 6.125% notes due 2022. In conjunction with the debt retired, we recorded a $12.5 million loss on early extinguishment of long-term debt, primarily attributable to early redemption premiums.

• On June 11, 2018, we closed our private placement of $350.0 million of 3.65% senior unsecured notes maturing in 2023 which resulted in approximately $346.6 million of net proceeds after deducting commissions and expenses. We used the net proceeds from this private placement to pay a portion of the redemption price for the notes subject to the tender offer described above.

• In July 2018, we redeemed $551.1 million of outstanding notes representing the remainder of our 6.80% notes due 2019, 5.45% notes due 2020 and 6.125% notes due 2022. During the third quarter of 2018, we recorded a $33.0 million loss on early extinguishment of long-term debt, primarily attributable to early redemption premiums.

See Note 19-A, "Contractual Obligations," for the outstanding long-term debt maturities at December 31, 2019.

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 and term loan agreement which requires us to maintain a debt to capitalization ratio that does not exceed 70%. A similar covenant in a 2005 private placement note purchase agreement requires us to maintain a debt to capitalization ratio that does not exceed 75%. As of December 31, 2019, the ratio was 61.7%.

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.

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Risk Management Activities (Tables)

12 Months Ended

Dec. 31, 2019

Risk Management Activities [Abstract]

Schedule of Derivative Instruments in Statement of Financial Position, Fair Value

Risk management assets and liabilities on our derivatives are presented on the Consolidated Balance Sheets as shown below:

December 31, (in millions)	2019		2018
Risk Management Assets - Current(1)
Interest rate risk programs	$	—	$	—
Commodity price risk programs	0.6		1.1
Total	$	0.6	$	1.1
Risk Management Assets - Noncurrent(2)
Interest rate risk programs	$	—	$	18.5
Commodity price risk programs	3.8		4.4
Total	$	3.8	$	22.9
Risk Management Liabilities - Current(3)
Interest rate risk programs	$	—	$	—
Commodity price risk programs	12.6		5.0
Total	$	12.6	$	5.0
Risk Management Liabilities - Noncurrent
Interest rate risk programs	$	76.2	$	9.5
Commodity price risk programs	57.8		37.2
Total	$	134.0	$	46.7

⁽¹⁾Presented in "Prepayments and other" on the Consolidated Balance Sheets.

⁽²⁾Presented in "Deferred charges and other" on the Consolidated Balance Sheets.

⁽³⁾Presented in "Other accruals" on the Consolidated Balance Sheets.

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Quarterly Financial Data (Schedule Of Quarterly Financial Data) (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended													12 Months Ended
	Dec. 31, 2019		Sep. 30, 2019		Jun. 30, 2019	Mar. 31, 2019		Dec. 31, 2018		Sep. 30, 2018	Jun. 30, 2018		Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Quarterly Financial Data [Abstract]
Operating Revenues	$ 1,397.2		$ 931.5		$ 1,010.4	$ 1,869.8		$ 1,461.7		$ 895.0	$ 1,007.0		$ 1,750.8	$ 5,208.9	$ 5,114.5	$ 4,874.6
Operating Income (Loss)	(38.0)		91.0		463.5	374.2		(78.4)		(315.9)	118.4		400.6	890.7	124.7	921.2
Net Income (Loss)	(139.3)	[1]	6.6	[2]	296.9	218.9	[3]	(11.7)		(339.5)	24.5			383.1	(50.6)	128.5
Preferred Dividends	(13.7)		(13.8)		(13.8)	(13.8)		(8.1)		(5.6)	(1.3)		0.0	(55.1)	(15.0)	0.0
Net Income (Loss) Available to Common Stockholders	$ (153.0)	[1]	$ (7.2)	[2]	$ 283.1	$ 205.1	[3]	$ (19.8)	[1]	$ (345.1)	$ 23.2	[4]	$ 276.1	$ 328.0	$ (65.6)	$ 128.5
Basic Earnings (Loss) Per Share	$ (0.41)		$ (0.02)		$ 0.76	$ 0.55		$ (0.05)		$ (0.95)	$ 0.07		$ 0.82	$ 0.88	$ (0.18)	$ 0.39
Diluted Earnings (Loss) Per Share	$ (0.41)		$ (0.02)		$ 0.75	$ 0.55		$ (0.05)		$ (0.95)	$ 0.07		$ 0.81	$ 0.87	$ (0.18)	$ 0.39

[1] ⁽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 6, "Goodwill and Other Intangible Assets."

[2] Net loss for the third quarter of 2018 was impacted by approximately $462 million in expenses (pretax) related to the Greater Lawrence Incident restoration and a $33.0 million loss (pretax) on an early extinguishment of long-term debt. See Note 19-E, "Other Matters" and Note 14, "Long-Term Debt" for additional information.

[3] ⁽¹⁾ 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 19-E, "Other Matters" for additional information.

[4] 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 19-E, "Other Matters" for additional information.

XML

Property, Plant And Equipment (Tables)

12 Months Ended

Dec. 31, 2019

Property, Plant and Equipment [Abstract]

Schedule Of Property, Plant And Equipment

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

At December 31, (in millions)	2019			2018
Property, Plant and Equipment
Gas Distribution Utility(1)	$	14,989.7		$	13,776.0
Electric Utility(1)	8,902.3			8,374.2
Corporate	153.3			155.8
Construction Work in Process	457.3			474.8
Non-Utility and Other	39.3			38.7
Total Property, Plant and Equipment	$	24,541.9		$	22,819.5
Accumulated Depreciation and Amortization
Gas Distribution Utility(1)	$	(3,556.0	)	$	(3,373.8	)
Electric Utility(1)	(3,973.8		)	(3,809.5		)
Corporate	(79.5		)	(74.6		)
Non-Utility and Other	(20.4		)	(19.1		)
Total Accumulated Depreciation and Amortization	$	(7,629.7	)	$	(7,277.0	)
Net Property, Plant and Equipment	$	16,912.2		$	15,542.5

⁽¹⁾NIPSCO’s common utility plant and associated accumulated depreciation and amortization are allocated between Gas Distribution Utility and Electric Utility Property, Plant and Equipment.

Schedule Of Depreciation Provisions For Utility Plant As A Percentage Of The Original Cost

The weighted average depreciation provisions for utility plant, as a percentage of the original cost, for the periods ended December 31, 2019, 2018 and 2017 were as follows:

	2019		2018		2017
Electric Operations(1)	2.8	%	2.9	%	3.4	%
Gas Distribution Operations	2.5	%	2.2	%	2.1	%

XML

Share-Based Compensation (Tables)

12 Months Ended

Dec. 31, 2019

Restricted Stock Units (RSUs)

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Schedule Of Transactions Of Share Based Compensation Other Than Stock Options

(shares)	Restricted Stock Units		Weighted Average Award Date Fair  Value Per Unit ($)
Non-vested at December 31, 2018	178,678		21.82
Granted	166,031		24.93
Forfeited	(21,547	)	22.99
Vested	(20,556	)	21.08
Non-vested at December 31, 2019	302,606		23.49

Performance Shares

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Schedule Of Transactions Of Share Based Compensation Other Than Stock Options

(shares)	Performance Awards		Weighted Average Grant Date Fair  Value Per Unit ($)(1)
Non-vested at December 31, 2018	1,634,718		20.45
Granted	552,389		25.77
Forfeited	(156,700	)	26.72
Vested	(527,156	)	28.11
Non-vested at December 31, 2019	1,503,251		22.74

XML

Valuation and Qualifying Accounts (Tables)

12 Months Ended

Dec. 31, 2019

SEC Schedule, 12-09, Valuation and Qualifying Accounts [Abstract]

Schedule of Valuation and Qualifying Accounts Disclosure

NISOURCE INC.

SCHEDULE II – VALUATION AND QUALIFYING ACCOUNTS

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
Twelve months ended December 31, 2017
			Additions
($ in millions)	Balance Jan. 1, 2017		Charged to Costs and Expenses		Charged to Other Account (1)		Deductions for Purposes for which Reserves were Created		Balance Dec. 31, 2017
Reserves Deducted in Consolidated Balance Sheet from Assets to Which They Apply:
Reserve for accounts receivable	$	23.3	$	14.8	$	39.1	$	58.9	$	18.3
Reserve for other investments	3.0		—		—		—		3.0

⁽¹⁾ Charged to Other Accounts reflects the deferral of bad debt expense to a regulatory asset.

XML

Short-Term Borrowings (Schedule Of Short-Term Borrowings) (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Short-term Debt [Line Items]
Commercial Paper weighted-average interest rate of 2.03% and 2.96% at December 31, 2019 and 2018, respectively	$ 570.0	$ 978.0
Accounts receivable securitization facility borrowings	353.2	399.2
Total short-term borrowings	$ 1,773.2	$ 1,977.2
Commercial Paper
Short-term Debt [Line Items]
Commercial Paper/credit facilities borrowings, weighted average interest rate	2.03%	2.96%
Term Loan
Short-term Debt [Line Items]
Term loan weighted-average interest rate of 2.40% and 3.07% at December 31, 2019 and 2018, respectively	$ 850.0	$ 600.0
Commercial Paper/credit facilities borrowings, weighted average interest rate	2.40%	3.07%

XML

Pension and Other Postretirement Benefits (Schedule of Net Asset Value Per Share) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Defined Benefit Plan Disclosure [Line Items]
Net Asset Value Excluded From Fair Value By Input	$ 860.5	$ 767.1
Commingled Funds | Short-Term Money Markets
Defined Benefit Plan Disclosure [Line Items]
Net Asset Value Excluded From Fair Value By Input	$ 22.5	$ 23.5
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Investment Redemption, Frequency	Daily	Daily
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Investment Redemption, Notice Period	1 day	1 day
Commingled Funds | United States Equities
Defined Benefit Plan Disclosure [Line Items]
Net Asset Value Excluded From Fair Value By Input	$ 318.0	$ 255.6
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Investment Redemption, Frequency	Monthly	Monthly
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Investment Redemption, Notice Period	3 days	3 days
Commingled Funds | International Equities
Defined Benefit Plan Disclosure [Line Items]
Net Asset Value Excluded From Fair Value By Input	$ 168.2	$ 122.3
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Investment Redemption, Frequency	Monthly	Monthly
Commingled Funds | Fixed Income Funds
Defined Benefit Plan Disclosure [Line Items]
Net Asset Value Excluded From Fair Value By Input	$ 351.8	$ 365.7
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Investment Redemption, Frequency	Daily	Monthly
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Investment Redemption, Notice Period	3 days	3 days
Minimum | Commingled Funds | International Equities
Defined Benefit Plan Disclosure [Line Items]
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Investment Redemption, Notice Period	10 days	14 days
Maximum | Commingled Funds | International Equities
Defined Benefit Plan Disclosure [Line Items]
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Investment Redemption, Notice Period	30 days	30 days

XML

Leases (Lease Information) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019 USD ($) Rate
Leases [Abstract]
Finance Lease, Interest Payment on Liability	$ 11.3
Operating Lease, Payments	17.9
Finance Lease, Principal Payments	10.6
Right-of-Use Asset Obtained in Exchange for Finance Lease Liability	26.4
Right-of-Use Asset Obtained in Exchange for Operating Lease Liability	$ 13.4
Finance Lease, Weighted Average Remaining Lease Term	14 years 9 months 18 days
Operating Lease, Weighted Average Remaining Lease Term	9 years 2 months 12 days
Finance Lease, Weighted Average Discount Rate, Percent | Rate	5.90%
Operating Lease, Weighted Average Discount Rate, Percent | Rate	4.30%

XML

Pension and Other Postretirement Benefits (Schedule Of One-Percentage-Point Change In Assumed Health Care Cost Trend Rates) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019 USD ($)
Defined Benefit Plan Disclosure [Line Items]
Effect on service and interest components of net periodic cost, 1% point increase	$ 1.2
Effect on service and interest components of net periodic cost, 1% point decrease	(1.1)
Effect on accumulated postretirement benefit obligation, 1% point increase	30.1
Effect on accumulated postretirement benefit obligation, 1% point decrease	$ (26.3)

XML

Revenue Recognition (Disaggregation of Revenue) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2019		Dec. 31, 2018		Dec. 31, 2017
Disaggregation of Revenue [Line Items]
Customer revenues		$ 5,053.4	[1]	$ 4,991.1	[1]	$ 4,730.2
Other revenues		155.5		123.4		144.4
Total Operating Revenues		5,208.9		5,114.5		$ 4,874.6
Gas Distribution Operations
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	3,455.2		3,372.0
Other revenues		54.5		34.4
Total Operating Revenues		3,509.7		3,406.4
Electric Operations
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	1,597.4		1,618.4
Other revenues		101.0		89.0
Total Operating Revenues		1,698.4		1,707.4
Corporate and Other
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	0.8		0.7
Other revenues		0.0		0.0
Total Operating Revenues		0.8		0.7
Residential
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	2,790.6		2,744.7
Residential | Gas Distribution Operations
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	2,309.0		2,250.0
Residential | Electric Operations
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	481.6		494.7
Residential | Corporate and Other
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	0.0		0.0
Commercial
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	1,257.9		1,244.6
Commercial | Gas Distribution Operations
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	771.3		751.9
Commercial | Electric Operations
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	486.6		492.7
Commercial | Corporate and Other
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	0.0		0.0
Industrial
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	852.9		841.6
Industrial | Gas Distribution Operations
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	245.2		228.0
Industrial | Electric Operations
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	607.7		613.6
Industrial | Corporate and Other
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	0.0		0.0
Off-system
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	77.7		92.4
Off-system | Gas Distribution Operations
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	77.7		92.4
Off-system | Electric Operations
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	0.0		0.0
Off-system | Corporate and Other
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	0.0		0.0
Miscellaneous
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	74.3		67.8
Miscellaneous | Gas Distribution Operations
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	52.0		49.7
Miscellaneous | Electric Operations
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	21.5		17.4
Miscellaneous | Corporate and Other
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	$ 0.8		$ 0.7

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

XML

Fair Value (Fair Value Of Financial Assets And Liabilities Measured On A Recurring Basis) (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Fair Value Assets And Liabilities Measured On Recurring Basis [Line Items]
Risk management assets	$ 4.4	$ 24.0
Available-for-sale securities	154.2	138.3
Total	158.6	162.3
Risk management liabilities	146.6	51.7
Total	146.6	51.7
Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Fair Value Assets And Liabilities Measured On Recurring Basis [Line Items]
Risk management assets	0.0	0.0
Available-for-sale securities	0.0	0.0
Total	0.0	0.0
Risk management liabilities	0.0	0.0
Total	0.0	0.0
Significant Other Observable Inputs (Level 2) [Member]
Fair Value Assets And Liabilities Measured On Recurring Basis [Line Items]
Risk management assets	4.4	24.0
Available-for-sale securities	154.2	138.3
Total	158.6	162.3
Risk management liabilities	146.6	51.7
Total	146.6	51.7
Significant Unobservable Inputs (Level 3) [Member]
Fair Value Assets And Liabilities Measured On Recurring Basis [Line Items]
Risk management assets	0.0	0.0
Available-for-sale securities	0.0	0.0
Total	0.0	0.0
Risk management liabilities	0.0	0.0
Total	$ 0.0	$ 0.0

XML

Interest Expense, Net (Tables)

12 Months Ended

Dec. 31, 2019

Interest Expense [Abstract]

Schedule Of Interest Expense, Net

Year Ended December 31, (in millions)	2019			2018			2017
Interest on long-term debt	$	327.7		$	342.2		$	354.8
Interest on short-term borrowings	50.8			31.8			14.9
Debt discount/cost amortization	8.3			7.7			7.2
Accounts receivable securitization fees	2.6			2.6			2.5
Allowance for borrowed funds used and interest capitalized during construction	(7.5		)	(9.1		)	(6.2		)
Debt-based post-in-service carrying charges	(18.7		)	(35.0		)	(36.4		)
Other	15.7			13.1			16.4
Total Interest Expense, net	$	378.9		$	353.3		$	353.2

XML

Long-Term Debt (Tables)

12 Months Ended

Dec. 31, 2019

Long-term Debt, Current and Noncurrent [Abstract]

Schedule of Long-Term Debt

Our long-term debt as of December 31, 2019 and 2018 is as follows:

Long-term debt type	Maturity as of December 31, 2019	Weighted average interest rate (%)		Outstanding balance as of December 31, (in millions)
				2019			2018
Senior notes:
NiSource	December 2021	4.45	%	63.6			63.6
NiSource	November 2022	2.65	%	500.0			500.0
NiSource	February 2023	3.85	%	250.0			250.0
NiSource	June 2023	3.65	%	350.0			350.0
NiSource	November 2025	5.89	%	265.0			265.0
NiSource	May 2027	3.49	%	1,000.0			1,000.0
NiSource	December 2027	6.78	%	3.0			3.0
NiSource	September 2029	2.95	%	750.0			—
NiSource	December 2040	6.25	%	250.0			250.0
NiSource	June 2041	5.95	%	400.0			400.0
NiSource	February 2042	5.80	%	250.0			250.0
NiSource	February 2043	5.25	%	500.0			500.0
NiSource	February 2044	4.80	%	750.0			750.0
NiSource	February 2045	5.65	%	500.0			500.0
NiSource	May 2047	4.38	%	1,000.0			1,000.0
NiSource	March 2048	3.95	%	750.0			750.0
Total senior notes				$	7,581.6		$	6,831.6
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	December 2025 to February 2028	6.30	%	40.0			40.0
Total medium term notes				$	157.0		$	157.0
Finance leases:
NiSource Corporate Services	January 2020 to November 2023	3.47	%	22.3			11.6
Columbia of Ohio	October 2021 to March 2044	6.16	%	94.8			91.5
Columbia of Virginia	July 2029 to November 2039	6.31	%	19.1			15.2
Columbia of Kentucky	May 2027	3.79	%	0.3			0.3
Columbia of Pennsylvania	August 2027 to May 2035	5.67	%	20.7			30.0
Columbia of Massachusetts	December 2033 to November 2043	5.49	%	44.3			45.7
Total finance leases				201.5			194.3
Pollution control bonds - NIPSCO	April 2019	5.85	%	—			41.0
Unamortized issuance costs and discounts				(70.5		)	$	(68.5	)
Total Long-Term Debt				$	7,869.6		$	7,155.4

XML

Transfers Of Financial Assets (Schedule Of Gross And Net Receivables Transferred As Well As Short-Term Borrowings Related To The Securitization Transactions) (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Transfers and Servicing [Abstract]
Gross Receivables interest	$ 569.1	$ 694.4
Less: Receivables not transferred	215.9	295.2
Net receivables transferred	353.2	399.2
Accounts receivable securitization agreements outstanding	$ 353.2	$ 399.2

XML

Other Commitments And Contingencies Other Commitments and Contingencies (Insurance Recoveries and Cash Collected) (Details) - USD ($) $ in Millions		3 Months Ended								4 Months Ended	12 Months Ended	16 Months Ended
		Dec. 31, 2019		Sep. 30, 2019		Jun. 30, 2019		Mar. 31, 2019		Dec. 31, 2018	Dec. 31, 2019	Dec. 31, 2019
Commitments and Contingencies Disclosure [Abstract]
Insurance Settlements Receivable	[1]	$ 0.0		$ 0.0		$ 260.0		$ 122.0		$ 130.0	$ 0.0	$ 0.0
Insurance recoveries recorded		130.0	[1]	0.0	[1]	435.0	[1]	100.0	[1]	$ 135.0	$ 665.0	800.0
Cash collected from insurance recoveries		$ (130.0)	[1]	$ (260.0)	[1]	$ (297.0)	[1]	$ (108.0)	[1]			$ (800.0)

[1] $5 million of insurance recoveries were collected during 2018.

XML

Transfers Of Financial Assets (Tables)

12 Months Ended

Dec. 31, 2019

Transfers and Servicing [Abstract]

Schedule of Assets and Associated Liabilities Accounted for as Secured Borrowings

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, 2019 and 2018:

At December 31, (in millions)	2019		2018
Gross receivables	$	569.1	$	694.4
Less: receivables not transferred	215.9		295.2
Net receivables transferred	$	353.2	$	399.2
Short-term debt due to asset securitization	$	353.2	$	399.2

XML

Short-Term Borrowings (Narrative) (Details) - USD ($) $ in Millions	Apr. 17, 2019	Dec. 31, 2019	Dec. 31, 2018
Short-term Debt [Line Items]
Commercial paper outstanding		$ 570.0	$ 978.0
Line of Credit Facility, Amount Outstanding		0.0	0.0
Accounts receivable securitization facility borrowings		353.2	399.2
Commercial Paper
Short-term Debt [Line Items]
Revolving credit facility, maximum		1,500.0
Revolving Credit Facility
Short-term Debt [Line Items]
Revolving credit facility, maximum		1,850.0
Term Loan
Short-term Debt [Line Items]
Debt Instrument, Basis Spread on Variable Rate	0.60%
Term Loan		$ 850.0	600.0
Maximum | Term Loan
Short-term Debt [Line Items]
Term Loan	$ 850.0		$ 600.0
Debt Outstanding | Term Loan
Short-term Debt [Line Items]
Term Loan	$ 850.0

XML

Document And Entity Information - USD ($)

12 Months Ended

Dec. 31, 2019

Feb. 18, 2020

Jun. 28, 2019

Document Information [Line Items]

Document Type

10-K

Document Annual Report

true

Document Period End Date

Dec. 31, 2019

Document Transition Report

false

Entity File Number

001-16189

Entity Registrant Name

NiSource Inc.

Entity Incorporation, State or Country Code

DE

Entity Tax Identification Number

35-2108964

Entity Address, Address Line One

801 East 86th Avenue

Entity Address, City or Town

Merrillville,

Entity Address, State or Province

IN

Entity Address, Postal Zip Code

46410

City Area Code

(877)

Local Phone Number

647-5990

Entity Well-known Seasoned Issuer

Yes

Entity Voluntary Filers

No

Entity Current Reporting Status

Yes

Entity Interactive Data Current

Yes

Entity Filer Category

Large Accelerated Filer

Entity Emerging Growth Company

false

Entity Small Business

false

Entity Shell Company

false

Entity Public Float

$ 10,713,311,150

Entity Common Stock, Shares Outstanding

382,263,348

Entity Central Index Key

0001111711

Current Fiscal Year End Date

--12-31

Document Fiscal Year Focus

2019

Document Fiscal Period Focus

FY

Amendment Flag

false

Documents Incorporated by Reference [Text Block]

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 19, 2020.

Common Stock

Document Information [Line Items]

Title of 12(b) Security

Common Stock, par value $0.01 per share

Trading Symbol

NI

Security Exchange Name

NYSE

Preferred Stock

Document Information [Line Items]

Title of 12(b) Security

Depositary Shares, each representing a 1/1,000th ownership interest in a share of 6.50% Series B

Trading Symbol

NI PR B

Security Exchange Name

NYSE

XML

Consolidated Balance Sheets - USD ($) $ in Millions		Dec. 31, 2019	Dec. 31, 2018
Property, Plant and Equipment
Utility Plant		$ 24,502.6	$ 22,780.8
Accumulated depreciation and amortization		(7,609.3)	(7,257.9)
Net utility plant		16,893.3	15,522.9
Other property, at cost, less accumulated depreciation		18.9	19.6
Net Property, Plant and Equipment		16,912.2	15,542.5
Investments and Other Assets
Unconsolidated affiliates		1.3	2.1
Other investments		228.9	204.0
Total Investments and Other Assets		230.2	206.1
Current Assets
Cash and cash equivalents		139.3	112.8
Restricted cash		9.1	8.3
Accounts receivable (less reserve of $19.2 and $21.1, respectively)		856.9	1,058.5
Gas inventory		250.9	286.8
Materials and supplies, at average cost		120.2	101.0
Electric production fuel, at average cost		53.6	34.7
Exchange gas receivable		48.5	88.4
Regulatory assets		225.7	235.4
Prepayments and other		149.7	129.5
Total Current Assets		1,853.9	2,055.4
Other Assets
Regulatory assets		2,013.9	2,002.1
Goodwill		1,485.9	1,690.7
Intangible assets		0.0	220.7
Deferred charges and other		163.7	86.5
Total Other Assets		3,663.5	4,000.0
Total Assets		22,659.8	21,804.0
Common Stockholders' Equity
Common stock - $0.01 par value, 600,000,000 shares authorized; 382,135,680 and 372,363,656 shares outstanding, respectively		3.8	3.8
Preferred stock - $0.01 par value, 20,000,000 shares authorized; 440,000 and 420,000 shares outstanding, respectively		880.0	880.0
Treasury stock		(99.9)	(99.9)
Additional paid-in capital		6,666.2	6,403.5
Retained deficit		(1,370.8)	(1,399.3)
Accumulated other comprehensive loss	[1]	(92.6)	(37.2)
Total Common Stockholders' Equity		5,986.7	5,750.9
Long-term debt, excluding amounts due within one year		7,856.2	7,105.4
Total Capitalization		13,842.9	12,856.3
Current Liabilities
Current portion of long-term debt		13.4	50.0
Short-term borrowings		1,773.2	1,977.2
Accounts payable		666.0	883.8
Customer deposits and credits		256.4	238.9
Taxes accrued		231.6	222.7
Interest accrued		99.4	90.7
Exchange gas payable		59.7	85.5
Regulatory liabilities		160.2	140.9
Legal and environmental		20.1	18.9
Accrued compensation and employee benefits		156.3	149.7
Claims accrued		165.4	114.7
Other accruals		144.1	63.8
Total Current Liabilities		3,745.8	4,036.8
Other Liabilities
Risk management liabilities		134.0	46.7
Deferred income taxes		1,485.3	1,330.5
Deferred investment tax credits		9.7	11.2
Accrued insurance liabilities		81.5	84.4
Accrued liability for postretirement and postemployment benefits		373.2	389.1
Regulatory liabilities		2,352.0	2,519.1
Asset retirement obligations		416.9	352.0
Other noncurrent liabilities		218.5	177.9
Total Other Liabilities		5,071.1	4,910.9
Commitments and Contingencies (Refer to Note 19, Other Commitments and Contingencies)		0.0	0.0
Total Capitalization and Liabilities		$ 22,659.8	$ 21,804.0

[1] All amounts are net of tax. Amounts in parentheses indicate debits.

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Regulatory Matters (Schedule of Regulatory Programs) (Details) - USD ($) $ in Millions		Feb. 25, 2020	Jan. 29, 2020	Nov. 26, 2019	Oct. 31, 2019	Oct. 18, 2019	Oct. 15, 2019	Aug. 21, 2019	Aug. 15, 2019	Jun. 25, 2019	May 29, 2019	May 22, 2019	Apr. 17, 2019	Feb. 28, 2019	Jan. 29, 2019	Nov. 30, 2018	Nov. 01, 2018	Oct. 31, 2018	Oct. 15, 2018	Aug. 28, 2018	Aug. 17, 2018	Dec. 01, 2017	Sep. 27, 2017
Regulatory Matters [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Adjustment																				$ 5.2
NIPSCO - Gas
Regulatory Matters [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount																							$ 105.6
Public Utilities, Requested Rate Increase (Decrease), Amount																							$ 138.1
Columbia Of Virginia
Regulatory Matters [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount																				1.3
Public Utilities, Requested Rate Increase (Decrease), Amount																				14.2
Columbia Of Maryland
Regulatory Matters [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount											$ (0.1)
Public Utilities, Requested Rate Increase (Decrease), Amount												$ 2.5
NIPSCO - Electric
Regulatory Matters [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount																		$ (53.5)
Public Utilities, Requested Rate Increase (Decrease), Amount																		21.4
2019 IRP | Columbia Of Ohio
Regulatory Matters [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount	[1]													$ 18.2
Regulatory Net Capital Expenditures Included In Filing	[1]													199.6
2018 CEP | Columbia Of Ohio
Regulatory Matters [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount																						$ 74.5
Regulatory Net Capital Expenditures Included In Filing																						$ 659.9
2019 CEP | Columbia Of Ohio
Regulatory Matters [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount														15.0
Regulatory Net Capital Expenditures Included In Filing														$ 121.7
TDSIC 9 | NIPSCO - Gas
Regulatory Matters [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount	[1],[2]																			(10.6)
Regulatory Net Capital Expenditures Included In Filing	[1],[2]																			$ 54.4
TDSIC 10 | NIPSCO - Gas
Regulatory Matters [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount	[3]									$ 1.6
Regulatory Net Capital Expenditures Included In Filing	[3]									$ 12.4
FMCA 1 | NIPSCO - Gas
Regulatory Matters [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount	[4]															$ 9.9
Regulatory Net Capital Expenditures Included In Filing	[4]															$ 1.5
FMCA 2 | NIPSCO - Gas
Regulatory Matters [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount	[4]										(3.5)
Regulatory Net Capital Expenditures Included In Filing	[4]										$ 1.8
FMCA 3 | NIPSCO - Gas
Regulatory Matters [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount	[4]			$ 0.3
Regulatory Net Capital Expenditures Included In Filing	[4]			$ 43.0
2019 GSEP | Columbia Of Massachusetts
Regulatory Matters [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount	[5]																	9.6
Regulatory Net Capital Expenditures Included In Filing	[5]																	$ 36.0
2020 GSEP | Columbia Of Massachusetts
Regulatory Matters [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount	[5],[6]				$ 2.4
Regulatory Net Capital Expenditures Included In Filing	[5],[6]				$ 75.0
2019 SAVE | Columbia Of Virginia
Regulatory Matters [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount																					$ 2.4
Regulatory Net Capital Expenditures Included In Filing																					$ 36.0
2020 SAVE | Columbia Of Virginia
Regulatory Matters [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount									$ 3.8
Regulatory Net Capital Expenditures Included In Filing									$ 50.0
2019 AMRP | Columbia Of Kentucky
Regulatory Matters [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount																			$ 3.6
Regulatory Net Capital Expenditures Included In Filing																			$ 30.1
2020 SMRP | Columbia Of Kentucky
Regulatory Matters [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount							$ 4.2
Regulatory Net Capital Expenditures Included In Filing							$ 40.4
2019 STRIDE | Columbia Of Maryland
Regulatory Matters [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount																	$ 1.2
Regulatory Net Capital Expenditures Included In Filing																	$ 19.7
TDSIC 5 | NIPSCO - Electric
Regulatory Matters [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount	[1]														$ 15.9
Regulatory Net Capital Expenditures Included In Filing	[1]														$ 58.8
TDSIC 6 | NIPSCO - Electric
Regulatory Matters [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount								$ 28.1
Regulatory Net Capital Expenditures Included In Filing								$ 131.1
FMCA 11 | NIPSCO - Electric
Regulatory Matters [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount	[4]												$ 0.9
Regulatory Net Capital Expenditures Included In Filing	[4]												$ 22.4
FMCA 12 | NIPSCO - Electric
Regulatory Matters [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount	[4]					$ 1.6
Regulatory Net Capital Expenditures Included In Filing	[4]					$ 4.7
Subsequent Event | TDSIC 11 | NIPSCO - Gas
Regulatory Matters [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount	[7]	$ (1.7)
Regulatory Net Capital Expenditures Included In Filing	[7]	$ 38.7
Subsequent Event | 2020 STRIDE | Columbia Of Maryland
Regulatory Matters [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount			$ 1.3
Regulatory Net Capital Expenditures Included In Filing			$ 15.0

[1] Incremental revenue is net of amounts due back to customers as a result of the TCJA.

[2] Incremental revenue is net of $5.2 million of adjustments in the TDSIC-9 settlement.

[3] ⁽³⁾Incremental capital and revenue are net of amounts included in the step 2 rates.

[4] ⁽⁵⁾Incremental revenue is inclusive of tracker eligible operations and maintenance expense.

[5] ⁽⁶⁾Due to an order from the Massachusetts DPU on October 3, 2019 imposing work restrictions on Columbia of Massachusetts, Columbia of Massachusetts did not meet the approved projected 2019 GSEP spend of $64 million and associated incremental revenue of $10.7 million. In the 2020 GSEP, Columbia of Massachusetts reduced the projected capital spend for calendar year 2019 to $36 million and the associated incremental revenue in 2019 GSEP to $9.6 million.

[6] ⁽⁷⁾Incremental capital investment is anticipated to be lower than $75 million in 2020 due to the Massachusetts DPU imposed work restrictions.

[7] ⁽⁴⁾Incremental revenue is net of amounts included in the step 2 rates and reflects a more typical filing period.

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Pension and Other Postretirement Benefits (Schedule Of Portfolio Asset Mix) (Details)	Dec. 31, 2019	Dec. 31, 2018
Minimum | Domestic Equities | Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	12.00%	12.00%
Minimum | Domestic Equities | Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	0.00%	0.00%
Minimum | International Equities | Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	6.00%	6.00%
Minimum | International Equities | Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	0.00%	0.00%
Minimum | Fixed Income | Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	59.00%
Minimum | Fixed Income | Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	20.00%
Minimum | Real Estate [Member] | Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	0.00%
Minimum | Real Estate [Member] | Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	0.00%
Minimum | Real Estate | Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage		0.00%
Minimum | Real Estate | Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage		0.00%
Minimum | Short-Term Investments/Other | Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	0.00%	0.00%
Minimum | Short-Term Investments/Other | Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	0.00%	0.00%
Maximum | Domestic Equities | Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	32.00%	32.00%
Maximum | Domestic Equities | Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	55.00%	55.00%
Maximum | International Equities | Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	16.00%	16.00%
Maximum | International Equities | Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	25.00%	25.00%
Maximum | Fixed Income | Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	71.00%
Maximum | Fixed Income | Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	100.00%
Maximum | Real Estate [Member] | Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	7.00%
Maximum | Real Estate [Member] | Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	0.00%
Maximum | Real Estate | Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage		7.00%
Maximum | Real Estate | Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage		0.00%
Maximum | Short-Term Investments/Other | Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	15.00%	15.00%
Maximum | Short-Term Investments/Other | Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	10.00%	10.00%

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Share-Based Compensation (Schedule Of Transactions Of Restricted Stock Unit) (Details) - Restricted Stock Units (RSUs)	12 Months Ended
	Dec. 31, 2019 $ / shares shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Nonvested, Other Than Options | shares	178,678
Nonvested, Weighted Average Grant Date Fair Value | $ / shares	$ 21.82
Granted, Other Than Options | shares	166,031
Granted, Weighted Average Grant Date Fair Value | $ / shares	$ 24.93
Forfeited, Other Than Options | shares	(21,547)
Forfeited, Weighted Average Grant Date Fair Value | $ / shares	$ 22.99
Vested, Other Than Options | shares	(20,556)
Vested, Weighted Average Grant Date Fair Value | $ / shares	$ 21.08
Nonvested, Other Than Options | shares	302,606
Nonvested, Weighted Average Grant Date Fair Value | $ / shares	$ 23.49

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Statements Of Consolidated Stockholders' Equity (Shares) - shares shares in Thousands	Total	Common Stock	Treasury Stock	Preferred Stock
Beginning Balance at Dec. 31, 2016	323,160	326,664	3,504	0
Treasury stock acquired	(293)	0	(293)	0
Issued:
Employee stock purchase plan	207	207	0	0
Long-term incentive plan	351	351	0	0
401(k) and profit sharing plan	1,396	1,396	0	0
Dividend reinvestment plan	264	264	0	0
ATM Program	11,931	11,931	0	0
Ending Balance at Dec. 31, 2017	337,016	340,813	3,797	0
Treasury stock acquired	(166)	0	(166)	0
Issued:
Common stock - private placement	24,964	24,964	0	0
Preferred	0	0	0	420
Employee stock purchase plan	223	223	0	0
Long-term incentive plan	561	561	0	0
401(k) and profit sharing plan	882	882	0	0
ATM Program	8,883	8,883	0	0
Ending Balance at Dec. 31, 2018	372,363	376,326	3,963	420
Issued:
Preferred	0	0	0	20	[1]
Employee stock purchase plan	201	201	0	0
Long-term incentive plan	518	518	0	0
401(k) and profit sharing plan	631	631	0	0
ATM Program	8,423	8,423	0	0
Ending Balance at Dec. 31, 2019	382,136	386,099	3,963	440

[1] See Note 12, "Equity," for additional information.

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Income Taxes (Schedule Of Reasons Behind Differences In Computation Of Total Income Taxes) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2019	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2017	Dec. 31, 2017
Schedule of Reasons Behind Differences in Computation of Total Income Taxes [Line Items]
Book income (loss) before income taxes		$ 506.6			$ (230.6)			$ 443.0
Tax expense (benefit) at statutory federal income tax rate, value		106.5			(48.4)			155.0
Tax expense (benefit) at statutory federal income tax rate, rate	21.00%			21.00%			35.00%
Increases (reductions) in taxes resulting from:
State income taxes, net of federal income tax benefit, value		10.1			24.7			6.9
State income taxes, net of federal income tax benefit, rate	2.00%			(10.70%)			1.50%
Amortization of regulatory liabilities, value		(29.4)			(29.3)			(2.4)
Amortization of regulatory liabilities, rate	(5.80%)			12.70%			(0.50%)
Goodwill impairment, value		43.0			0.0			0.0
Goodwill impairment, rate	8.50%			0.00%			0.00%
Fines and penalties, value		11.5			0.2			2.8
Fines and penalties, rate	2.30%			(0.10%)			0.60%
Charitable contribution carryover, value		(2.5)			0.0			(1.2)
Charitable contribution carryover, rate	(0.50%)			0.00%			(0.30%)
State regulatory proceedings, value		(9.5)			(127.8)			0.0
State regulatory proceedings, rate	(1.90%)			55.40%			0.00%
Remeasurement due to TCJA, value		0.0			0.0			161.1
Remeasurement due to TCJA, rate	0.00%			0.00%			36.40%
Employee stock ownership plan dividends and other compensation, value		(2.0)			(2.2)			(6.5)
Employee stock ownership plan dividends and other compensation, rate	(0.40%)			1.00%			(1.50%)
Other adjustments, value		(4.2)			2.8			(1.2)
Other adjustments, rate	(0.80%)			(1.20%)			(0.20%)
Income Taxes		$ 123.5			$ (180.0)			$ 314.5
Income Taxes, rate	24.40%		24.40%	78.10%		78.10%	71.00%		71.00%

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Equity (Narrative) (Details) $ / shares in Units, $ in Millions											1 Months Ended	3 Months Ended	12 Months Ended
	Feb. 20, 2020 $ / shares	Dec. 11, 2019 USD ($) $ / shares	Nov. 21, 2019 USD ($) $ / shares	Aug. 01, 2019	Dec. 10, 2018 $ / shares shares	Nov. 06, 2018 USD ($) $ / shares	Nov. 01, 2018 USD ($)	Jun. 11, 2018 USD ($)	May 04, 2018 USD ($) $ / shares shares	May 03, 2017 USD ($)	Dec. 31, 2018 USD ($) $ / shares shares	Dec. 31, 2019 USD ($) $ / shares shares	Dec. 31, 2019 USD ($) $ / shares shares	Dec. 31, 2018 USD ($) $ / shares shares	Dec. 31, 2017 USD ($) $ / shares shares	Jun. 15, 2023 $ / shares	Dec. 05, 2018 shares	Dec. 31, 2016 shares
Forward Contract Indexed to Issuer's Equity [Line Items]
Common stock, shares authorized | shares											400,000,000	600,000,000	600,000,000	400,000,000
Preferred Stock, Shares Authorized | shares											20,000,000	20,000,000	20,000,000	20,000,000
Common Stock, Shares, Outstanding | shares											372,363,656	382,135,680	382,135,680	372,363,656
Preferred Stock, Shares Outstanding | shares											420,000	440,000	440,000	420,000
Common Stock, Dividends, Per Share, Declared													$ 0.80	$ 0.78	$ 0.70
Shares, Issued | shares											372,363,000	382,136,000	382,136,000	372,363,000	337,016,000			323,160,000
Common stock, par value											$ 0.01	$ 0.01	$ 0.01	$ 0.01
Proceeds from Issuance of Preferred Stock and Preference Stock | $													$ 0.0	$ 880.0	$ 0.0
Preferred Stock, Par or Stated Value Per Share											$ 0.01	$ 0.01	$ 0.01	$ 0.01
Dividends Payable, Date to be Paid													Feb. 20, 2020
Dividends Payable, Date of Record													Feb. 11, 2020
Series A Preferred Stock
Forward Contract Indexed to Issuer's Equity [Line Items]
Preferred Stock, Shares Outstanding | shares												400,000	400,000
Preferred Stock, Shares Issued | shares												400,000	400,000
Preferred Stock, Dividend Rate, Percentage								5.65%
Preferred Stock, Liquidation Preference Per Share												$ 1,000	$ 1,000
Preferred Stock, Dividend Rate, Initial Margin								2.843%
Preferred Stock, Dividend Rate, Initial Margin Plus 1.000%								1.00%
Preferred Stock, Amount of Preferred Dividends in Arrears | $													$ 1.0
Preferred Stock, Per Share Amounts of Preferred Dividends in Arrears													$ 2.51
Preferred Stock, Liquidation Preference, Value | $												$ 400.0	$ 400.0
Series B Preferred Stock
Forward Contract Indexed to Issuer's Equity [Line Items]
Preferred Stock, Shares Outstanding | shares												20,000	20,000
Preferred Stock, Dividend Rate, Percentage											6.50%
Preferred Stock, Liquidation Preference Per Share												$ 25,000.00	$ 25,000.00
Preferred Stock, Dividend Rate, Initial Margin											3.632%
Preferred Stock, Dividend Rate, Initial Margin Plus 1.000%											1.00%
Preferred Stock, Amount of Preferred Dividends in Arrears | $													$ 1.4	$ 2.4
Preferred Stock, Per Share Amounts of Preferred Dividends in Arrears													$ 72.23	$ 121.88
Preferred Stock Depositary Shares Issued | shares																	20,000,000
Preferred Stock, Liquidation Preference, Value | $												$ 500.0	$ 500.0
Depositary Stock Liquidation Preference												$ 25	$ 25
Series B-1 Preferred Stock
Forward Contract Indexed to Issuer's Equity [Line Items]
Preferred Stock, Shares Issued | shares												20,000	20,000
Gross Proceeds | Series A Preferred Stock
Forward Contract Indexed to Issuer's Equity [Line Items]
Proceeds from Issuance of Preferred Stock and Preference Stock | $								$ 400.0
Gross Proceeds | Series B Preferred Stock
Forward Contract Indexed to Issuer's Equity [Line Items]
Proceeds from Issuance of Preferred Stock and Preference Stock | $											$ 500.0
Common Stock
Forward Contract Indexed to Issuer's Equity [Line Items]
Shares, Issued | shares									24,964,163		376,326,000	386,099,000	386,099,000	376,326,000	340,813,000			326,664,000
Common stock, par value									$ 0.01
Sale of Stock, Price Per Share									$ 24.28
Common Stock | Gross Proceeds
Forward Contract Indexed to Issuer's Equity [Line Items]
Proceeds from Issuance of Private Placement | $									$ 606.0
Common Stock | Net Proceeds
Forward Contract Indexed to Issuer's Equity [Line Items]
Proceeds from Issuance of Private Placement | $									$ 599.6
At The Market Program
Forward Contract Indexed to Issuer's Equity [Line Items]
Number Of Equity Distribution Agreements				4			5			4
Common Stock Aggregate Sale Price | $							$ 500.0			$ 500.0		$ 434.4	$ 434.4
Derivative, Forward Price					$ 26.55
Forward Contract Indexed to Issuer's Equity, Shares | shares					4,708,098
ATM Program Equity Remaining Available for Issuance | $													$ 200.7
Forward Agreement
Forward Contract Indexed to Issuer's Equity [Line Items]
Derivative, Forward Price		$ 28.83	$ 26.01			$ 26.43
Forward Contract Indexed to Issuer's Equity, Settlement Alternatives, Cash, at Fair Value | $		$ 107.1	$ 122.5			$ 167.7
Forward Agreement 19
Forward Contract Indexed to Issuer's Equity [Line Items]
Derivative, Forward Price												$ 29.26
Forward Contract Indexed to Issuer's Equity, Shares | shares												3,714,400
Preferred Stock
Forward Contract Indexed to Issuer's Equity [Line Items]
Shares, Issued | shares											420,000	440,000	440,000	420,000	0			0
Preferred Stock | Series A Preferred Stock
Forward Contract Indexed to Issuer's Equity [Line Items]
Proceeds from Issuance of Preferred Stock and Preference Stock | $								$ 393.9
Preferred Stock | Net Proceeds | Series B Preferred Stock
Forward Contract Indexed to Issuer's Equity [Line Items]
Proceeds from Issuance of Preferred Stock and Preference Stock | $											$ 486.1
Subsequent Event
Forward Contract Indexed to Issuer's Equity [Line Items]
Common Stock, Dividends, Per Share, Declared	$ 0.21
Subsequent Event | Series A Preferred Stock
Forward Contract Indexed to Issuer's Equity [Line Items]
Preferred Stock, Liquidation Preference Per Share																$ 1,000

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Asset Retirement Obligations (Changes In Company's Liability For Asset Retirement Obligations) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019		Dec. 31, 2018
Beginning Balance	$ 352.0		$ 268.7
Accretion recorded as a regulatory asset	15.7		11.1
Additions	0.0		63.3	[1]
Settlements	(5.4)		(5.9)
Change in estimated cash flows	54.6	[2]	14.8	[1]
Ending Balance	416.9		$ 352.0
CCR
Additions	59.8
Change in estimated cash flows	$ 17.7

[1] In 2018, $59.8 million of additions and $17.7 million of the change in estimated cash flows are attributed to costs associated with refining the CCR compliance plan. See Note 19-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.

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Recent Accounting Pronouncements

12 Months Ended

Dec. 31, 2019

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

New Accounting Pronouncements and Changes in Accounting Principles

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 2018-14, Compensation—Retirement Benefits—Defined Benefit Plans—General (Subtopic 715-20): Disclosure Framework—Changes to the Disclosure Requirements for Defined Benefit Plans	The pronouncement modifies the disclosure requirements for defined benefit pension 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 and must be applied on a retrospective basis to all periods presented.	Annual periods ending after December 15, 2020. Early adoption is permitted.	We are currently evaluating the effects of this pronouncement on our Notes to Consolidated Financial Statements. We expect to adopt this ASU on its effective date.
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.	Annual periods beginning after December 15, 2020. Early adoption is permitted.	We are currently evaluating the effects of this pronouncement on our Consolidated Financial Statements and Notes to Consolidated Financial Statements. We tentatively expect to adopt this ASU on its effective date.

Recently Adopted Accounting Pronouncements

Standard	Adoption
ASU 2019-01, Leases (Topic 842): Codification Improvements	See Note 16, "Leases," for our discussion of the effects of implementing these standards.
ASU 2018-11, Leases (Topic 842): Targeted Improvements
ASU 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842
ASU 2016-02, Leases (Topic 842)
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 that revised the guidance on the impairment of most financial assets and certain other instruments that are not measured at fair value through net income. This ASU replaces the current "incurred loss" model with an "expected loss" model for instruments measured at amortized cost. It also requires entities to record allowances for available-for-sale securities rather than impair the carrying amount of the securities. Subsequent improvements to the estimated credit losses of available-for-sale securities will be recognized immediately in earnings instead of over time as they are under historic guidance. We adopted this ASU effective January 1, 2020, using a modified retrospective method. Adoption of this standard did not have a material impact on our Consolidated Financial Statements. No material adjustments were made to January 1, 2020 opening balances as a result of adoption. For our investments that are classified as available for sale debt securities, we will recognize impairment using an allowance approach instead of an 'other than temporary' impairment (OTTI) model. Since we do not have amounts previously recognized in other comprehensive income related to previous OTTI charges, provisions of this ASU are adopted prospectively. In regards to our recorded balances of trade receivables that fall within the scope of this ASU, the ASU did not result in any significant modifications to our policies related to recognizing an allowance on our trade receivables. Based on shared risk characteristics, we segregate our trade receivables into separate pools. We will apply separate models to calculate reserves for uncollectible receivables, as well as consider factors other than time to determine whether a credit loss exists. ASC 326 also prescribes additional presentation and disclosure requirements. For reporting periods beginning after January 1, 2020, we will include additional disclosures in our Notes to Consolidated Financial Statements based on qualitative and quantitative assessment of materiality.
ASU 2016-13,  Financial Instruments-Credit Losses (Topic 326)

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Goodwill and Other Intangible Assets

12 Months Ended

Dec. 31, 2019

Goodwill and Intangible Assets Disclosure [Abstract]

Goodwill And Other Intangible Assets

Goodwill and Other Intangible Assets

Intangible and Other Long-Lived Assets Impairment. Our intangible assets, apart from goodwill, consist 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. 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.

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. While there was no single determinative event or factor, the consideration in totality of several factors that developed during the fourth quarter of 2019 led us to conclude that it was more likely than not that the fair value of the Columbia of Massachusetts reporting unit and the value of its long-lived assets was below

its carrying value. These factors included: (i) increased Massachusetts DPU regulatory enforcement activity related to Columbia of Massachusetts during the fourth quarter, including (a) an order imposing work restrictions on Columbia of Massachusetts, impacting Columbia of Massachusetts' infrastructure replacement program, (b) two orders opening public investigations into Columbia of Massachusetts related to the Greater Lawrence Incident and restoration efforts following the incident, and (c) an order defining the scope of the Massachusetts DPU's investigation into the preparation and response of Columbia of Massachusetts related to the incident; (ii) increased uncertainty as to the ability of Columbia of Massachusetts to execute its growth strategy, including utility infrastructure investments, and to obtain timely regulatory outcomes with reasonable rates of return; (iii) further damage to Columbia of Massachusetts' reputation as a result of concerns related to service lines abandoned during the restoration work following the Greater Lawrence Incident and the gas release event in Lawrence, Massachusetts on September 27, 2019; and (iv) the potential sale of the Massachusetts Business. See Note 19, "Other Commitments and Contingencies - C. Legal Proceedings" for more information regarding Massachusetts DPU regulatory enforcement activity. See Note 26, "Subsequent Event" for more information on the potential sale of the Massachusetts Business.

As a result, we performed a year-end impairment test of the 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. This 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.

We also considered if any regulatory assets or ROU assets were probable of disallowance and determined no disallowances were probable. All of Columbia of Massachusetts' regulatory assets represent incurred costs probable of recovery.

As of December 31, 2019 and 2018, the carrying amount of the franchise rights was $0.0 million and $220.7 million (net of accumulated amortization of $221.5 million), respectively. We recorded amortization expense of $11.0 million in 2019, 2018 and 2017 related to our franchise rights intangible asset.

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, 2019 and 2018:

(in millions)	2019		2018
Gas Distribution Operations	$	1,485.9	$	1,690.7
Electric Operations	—		—
Corporate and Other	—		—
Total	$	1,485.9	$	1,690.7

For our annual goodwill impairment analysis performed as of May 1, 2019, we completed a qualitative "step 0" analysis for all reporting units other than our Columbia of Massachusetts reporting unit. In the step 0 analysis, we assessed various assumptions, events and circumstances that would have affected the estimated fair value of the applicable reporting units as compared to their baseline May 1, 2016 "step 1" fair value measurement. The results of this assessment indicated that it was not more likely than not that the fair values of these reporting units were less than their respective carrying values, accordingly, no "step 1" analysis was required.

The results of our Columbia of Massachusetts reporting unit were negatively impacted by the Greater Lawrence Incident (see Note 19-C, "Legal Proceedings"). As a result, we completed a quantitative "step 1" analysis for the May 1, 2019 goodwill analysis for this reporting unit. This analysis considered the progress Columbia of Massachusetts had made with its restoration efforts related to the Greater Lawrence Incident, including the replacement of previously repaired equipment and the settlement agreement with the three impacted municipalities, as well as the ability for Columbia of Massachusetts to sustain its infrastructure replacement growth strategy through GSEP and timely rate cases with reasonable rates of return. Consistent with our historical impairment testing of goodwill, fair value of the Columbia of Massachusetts reporting unit 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. These approaches also incorporate the latest available cash flow projections reflecting the estimated ongoing impacts of the Greater Lawrence Incident on Columbia of Massachusetts’ operations. 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 the Columbia of Massachusetts reporting unit exceeds its carrying value. As a result, no impairment charge was recorded as of the May 1, 2019 test date.

Although our annual impairment test is performed during the second quarter, we continue to monitor changes in circumstances that may indicate that it is more likely than not that the fair value of our reporting units is less than the reporting unit carrying value. During the fourth quarter of 2019, in connection with the preparation of the year-end financial statements, we assessed the matters related to Columbia of Massachusetts. These factors were the same fourth quarter circumstances outlined in the intangible and other long-lived assets impairment above.

As a result, a new impairment analysis was required for our Columbia of Massachusetts reporting unit. Consistent with the May 1, 2019 test, 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 updated cash flow projections. While certain assumptions, such as market multiples, remained unchanged in the year-end test, our cash flow projections, return on equity and rate case assumptions were all unfavorably updated at year-end compared to the May 1, 2019 test. The effects of these unfavorable developments were greater than the favorable change in weighted average cost of capital between the two tests. The 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.

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Supplemental Cash Flow Information

12 Months Ended

Dec. 31, 2019

Supplemental Cash Flow Information [Abstract]

Supplemental Cash Flow Information

Supplemental Cash Flow Information

The following table provides additional information regarding our Consolidated Statements of Cash Flows for the years ended December 31, 2019, 2018 and 2017:

Year Ended December 31, (in millions)	2019		2018		2017
Supplemental Disclosures of Cash Flow Information
Non-cash transactions:
Capital expenditures included in current liabilities	$	223.6	$	152.0	$	173.0
Assets acquired under a finance lease	26.4		54.6		11.5
Assets acquired under an operating lease	13.4		—		—
Reclassification of other property to regulatory assets(1)	—		245.3		—
Assets recorded for asset retirement obligations(2)	54.6		78.1		11.4
Schedule of interest and income taxes paid:
Cash paid for interest, net of interest capitalized amounts	$	349.7	$	354.2	$	339.9
Cash paid for income taxes, net of refunds	10.8		3.3		5.5

⁽¹⁾See Note 8 "Regulatory Matters" for additional information.

⁽²⁾See Note 7 "Asset Retirement Obligations" for additional information.

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Other, Net

12 Months Ended

Dec. 31, 2019

Other Nonoperating Income (Expense) [Abstract]

Other, Net

Other, Net

Year Ended December 31, (in millions)	2019			2018			2017
Interest income	$	7.7		$	6.6		$	4.6
AFUDC equity	8.0			14.2			12.6
Charitable contributions(1)	(5.1		)	(45.3		)	(19.9		)
Pension and other postretirement non-service cost(2)	(16.5		)	18.0			(10.6		)
Interest rate swap settlement gain(3)	—			46.2			—
Miscellaneous	0.7			3.8			(0.2		)
Total Other, net	$	(5.2	)	$	43.5		$	(13.5	)

⁽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 19, "Other Commitments and Contingencies" for additional information on the Greater Lawrence Incident.

⁽²⁾ See Note 11, "Pension and Other Postretirement Benefits" for additional information.

⁽³⁾ See Note 9, "Risk Management Activities" for additional information.

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Revenue Recognition (Tables)

12 Months Ended

Dec. 31, 2019

Revenue from Contract with Customer [Abstract]

Revenue Recognition Under Previous Guidance

The table below provides results for the years ended December 31, 2019 and 2018 as if it had been prepared under historic accounting guidance. We included operating revenue information for the year ended December 31, 2017 for comparability.

Year Ended December 31, (in millions)	2019		2018		2017
Operating Revenues
Gas Distribution	$	2,336.1	$	2,348.4	$	2,063.2
Gas Transportation	1,171.3		1,055.2		1,021.5
Electric	1,698.5		1,707.4		1,785.5
Other	3.0		3.5		4.4
Total Operating Revenues	$	5,208.9	$	5,114.5	$	4,874.6

Disaggregation of Revenue

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, 2019 (in millions)	Gas Distribution Operations		Electric Operations		Corporate and Other		Total
Customer Revenues(1)
Residential	$	2,309.0	$	481.6	$	—	$	2,790.6
Commercial	771.3		486.6		—		1,257.9
Industrial	245.2		607.7		—		852.9
Off-system	77.7		—		—		77.7
Miscellaneous	52.0		21.5		0.8		74.3
Total Customer Revenues	$	3,455.2	$	1,597.4	$	0.8	$	5,053.4
Other Revenues	54.5		101.0		—		155.5
Total Operating Revenues	$	3,509.7	$	1,698.4	$	0.8	$	5,208.9

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

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

Customer Accounts Receivable

The opening and closing balances of customer receivables for the years ended December 31, 2019 and 2018 are presented in the table below. We had no significant contract assets or liabilities during the period. Additionally, we have not incurred any significant costs to obtain or fulfill contracts.

(in millions)	Customer Accounts Receivable, Billed (less reserve)(1)			Customer Accounts Receivable, Unbilled (less reserve)
Balance as of December 31, 2018	$	540.5		$	349.1
Balance as of December 31, 2019	466.6			346.6
Decrease	$	(73.9	)	$	(2.5	)

⁽¹⁾ Customer billed receivables decreased due to decreased natural gas costs and warmer weather in 2019 compared to 2018.