10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

þ  QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 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)

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

(877) 647-5990

(Registrant’s telephone number, including area code)

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 definitions of "large accelerated filer," "accelerated filer" "smaller reporting company," and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one):

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 Exchange Act).

Yes ¨    No þ

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date: Common Stock, $0.01 Par Value: 373,103,190 shares outstanding at April 24, 2019.

NISOURCE INC.

FORM 10-Q QUARTERLY REPORT

FOR THE QUARTER ENDED MARCH 31, 2019

Table of Contents

			Page
	Defined Terms		3
PART I	FINANCIAL INFORMATION
	Item 1.	Financial Statements - unaudited
		Condensed Statements of Consolidated Income (unaudited)	7
		Condensed Statements of Consolidated Comprehensive Income (unaudited)	8
		Condensed Consolidated Balance Sheets (unaudited)	9
		Condensed Statements of Consolidated Cash Flows (unaudited)	11
		Condensed Statements of Consolidated Equity (unaudited)	12
		Notes to Condensed Consolidated Financial Statements (unaudited)	14
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	38
	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	52
	Item 4.	Controls and Procedures	52
PART II	OTHER INFORMATION
	Item 1.	Legal Proceedings	53
	Item 1A.	Risk Factors	53
	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	53
	Item 3.	Defaults Upon Senior Securities	53
	Item 4.	Mine Safety Disclosures	53
	Item 5.	Other Information	53
	Item 6.	Exhibits	54
	Signature		55

2

DEFINED TERMS
The following is a list of frequently used abbreviations or acronyms that are found 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.
NIPSCO	Northern Indiana Public Service Company LLC
NiSource ("we," "us" or “our”)	NiSource Inc.
Abbreviations and Other
ACE	Affordable Clean Energy
AFUDC	Allowance for funds used during construction
AMRP	Accelerated Main Replacement Program
AOCI	Accumulated Other Comprehensive Income (Loss)
ASC	Accounting Standards Codification
ASU	Accounting Standards Update
ATM	At-the-market
BTA	Build-transfer agreement
CAA	Clean Air Act
CCRs	Coal Combustion Residuals
CEP	Capital Expenditure Program
CERCLA	Comprehensive Environmental Response Compensation and Liability Act (also known as Superfund)
CO2	Carbon Dioxide
CPP	Clean Power Plan
DPU	Department of Public Utilities
EGUs	Electric Utility Generating Units
ELG	Effluent limitations guidelines
EPA	United States Environmental Protection Agency
EPS	Earnings per share
FAC	Fuel adjustment clause
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FMCA	Federally Mandated Cost Adjustment
GAAP	Generally Accepted Accounting Principles
GCA	Gas cost adjustment
GCR	Gas cost recovery
GHG	Greenhouse gases
GSEP	Gas System Enhancement Program
GWh	Gigawatt hours
IRP	Infrastructure Replacement Program
IT	Information technology
IURC	Indiana Utility Regulatory Commission

3

DEFINED TERMS
LIBOR	London InterBank Offered Rate
LIFO	Last In, First Out
MGP	Manufactured Gas Plant
MISO	Midcontinent Independent System Operator
MMDth	Million dekatherms
MW	Megawatts
NTSB	National Transportation Safety Board
NYMEX	New York Mercantile Exchange
OPEB	Other Postretirement Benefits
PHMSA	Pipeline and Hazardous Materials Safety Administration
PPA	Purchase power agreement
RCRA	Resource Conservation and Recovery Act
ROU	Right of use
SAVE	Steps to Advance Virginia's Energy Plan
SEC	Securities and Exchange Commission
STRIDE	Strategic Infrastructure Development Enhancement
TCJA	An Act to provide for reconciliation pursuant to titles II and V of the concurrent resolution on the budget for fiscal year 2018 (commonly known as the Tax Cuts and Jobs Act of 2017)
TDSIC	Transmission, Distribution and Storage System Improvement Charge
VSCC	Virginia State Corporation Commission
WCE	Whiting Clean Energy

Note regarding forward-looking statements

This Quarterly Report on Form 10-Q contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended 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 NiSource’s 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 Quarterly Report on Form 10-Q include, among other things, our debt obligations; any changes to the credit rating of our or 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; potential incidents and other operating risks associated with our business; our ability to obtain sufficient insurance coverage; 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 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; uncertainties related to the expected benefits of the Separation; our ability to manage new initiatives and organizational changes; the performance of third-party suppliers and service providers; and other matters in the “Risk Factors” section of this report and our Annual Report on Form 10-K for the fiscal year ended December 31, 2018, 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.

4

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

Index	Page
Condensed Statements of Consolidated Income (unaudited)	7
Condensed Statements of Consolidated Comprehensive Income (unaudited)	8
Condensed Consolidated Balance Sheets (unaudited)	9
Condensed Statements of Consolidated Cash Flows (unaudited)	11
Condensed Statements of Consolidated Equity (unaudited)	12
Notes to Condensed Consolidated Financial Statements (unaudited)	14
1. Basis of Accounting Presentation	14
2. Recent Accounting Pronouncements	14
3. Revenue Recognition	15
4. Earnings Per Share	17
5. Equity	17
6. Gas in Storage	18
7. Regulatory Matters	18
8. Risk Management Activities	20
9. Fair Value	22
10. Transfers of Financial Assets	24
11. Goodwill	24
12. Income Taxes	25
13. Pension and Other Postretirement Benefits	25
14. Long-Term Debt	25
15. Short-Term Borrowings	25
16. Leases	26
17. Other Commitments and Contingencies	29
18. Accumulated Other Comprehensive Loss	36
19. Other, Net	36
20. Business Segment Information	36

6

PART I

ITEM 1. FINANCIAL STATEMENTS

NiSource Inc.

Condensed Statements of Consolidated Income (unaudited)

	Three Months Ended March 31,
(in millions, except per share amounts)	2019			2018
Operating Revenues
Customer revenues	$	1,834.5		$	1,717.2
Other revenues	35.3			33.6
Total Operating Revenues	1,869.8			1,750.8
Operating Expenses
Cost of sales (excluding depreciation and amortization)	680.3			724.4
Operation and maintenance	552.4			402.5
Depreciation and amortization	175.1			144.7
Loss (Gain) on sale of assets and impairments, net	0.2			(0.3		)
Other taxes	87.6			78.9
Total Operating Expenses	1,495.6			1,350.2
Operating Income	374.2			400.6
Other Income (Deductions)
Interest expense, net	(95.6		)	(93.1		)
Other, net	(0.7		)	31.3
Total Other Deductions, Net	(96.3		)	(61.8		)
Income before Income Taxes	277.9			338.8
Income Taxes	59.0			62.7
Net Income	218.9			276.1
Preferred dividends	(13.8		)	—
Net Income Available to Common Shareholders	205.1			276.1
Earnings Per Share
Basic Earnings Per Share	$	0.55		$	0.82
Diluted Earnings Per Share	$	0.55		$	0.81
Basic Average Common Shares Outstanding	373.4			338.0
Diluted Average Common Shares	374.7			339.0

The accompanying Notes to Condensed Consolidated Financial Statements (unaudited) are an integral part of these statements.

7

Table of Contents

ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

Condensed Statements of Consolidated Comprehensive Income (unaudited)

	Three Months Ended March 31,
(in millions, net of taxes)	2019			2018
Net Income	$	218.9		$	276.1
Other comprehensive income (loss):
Net unrealized gain (loss) on available-for-sale securities(1)	2.8			(1.7		)
Net unrealized gain (loss) on cash flow hedges(2)	(19.3		)	35.4
Unrecognized pension and OPEB benefit(3)	0.9			0.2
Total other comprehensive income (loss)	(15.6		)	33.9
Comprehensive Income	$	203.3		$	310.0

⁽¹⁾ Net unrealized gain (loss) on available-for-sale securities, net of $0.7 million tax expense and $0.4 million tax benefit in the first quarter of 2019 and 2018, respectively.

⁽²⁾ Net unrealized gain (loss) on cash flow hedges, net of $6.5 million tax benefit and $11.7 million tax expense in the first quarter of 2019 and 2018, respectively.

⁽³⁾ Unrecognized pension and OPEB benefit, net of $0.4 million and $0.1 million tax expense in the first quarter of 2019 and 2018, respectively.

The accompanying Notes to Condensed Consolidated Financial Statements (unaudited) are an integral part of these statements.

8

Table of Contents

ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc. Condensed Consolidated Balance Sheets (unaudited)
(in millions)	March 31, 2019			December 31, 2018
ASSETS
Property, Plant and Equipment
Utility plant	$	23,079.7		$	22,780.8
Accumulated depreciation and amortization	(7,356.9		)	(7,257.9		)
Net utility plant	15,722.8			15,522.9
Other property, at cost, less accumulated depreciation	18.6			19.6
Net Property, Plant and Equipment	15,741.4			15,542.5
Investments and Other Assets
Unconsolidated affiliates	2.1			2.1
Other investments	208.5			204.0
Total Investments and Other Assets	210.6			206.1
Current Assets
Cash and cash equivalents	151.0			112.8
Restricted cash	9.8			8.3
Accounts receivable (less reserve of $31.4 and $21.1, respectively)	1,132.1			1,058.5
Gas inventory	75.1			286.8
Materials and supplies, at average cost	107.3			101.0
Electric production fuel, at average cost	33.3			34.7
Exchange gas receivable	72.1			88.4
Regulatory assets	190.9			235.4
Prepayments and other	144.2			129.5
Total Current Assets	1,915.8			2,055.4
Other Assets
Regulatory assets	1,979.4			2,002.1
Goodwill	1,690.7			1,690.7
Intangible assets, net	218.0			220.7
Deferred charges and other	134.0			86.5
Total Other Assets	4,022.1			4,000.0
Total Assets	$	21,889.9		$	21,804.0

The accompanying Notes to Condensed Consolidated Financial Statements (unaudited) are an integral part of these statements.

9

Table of Contents

ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc. Condensed Consolidated Balance Sheets (unaudited) (continued)
(in millions, except share amounts)	March 31, 2019			December 31, 2018
CAPITALIZATION AND LIABILITIES
Capitalization
Stockholders’ Equity
Common stock - $0.01 par value, 400,000,000 shares authorized; 373,002,671 and 372,363,656 shares outstanding, respectively	$	3.8		$	3.8
Preferred stock - $0.01 par value, 20,000,000 shares authorized; 440,000 shares outstanding	880.0			880.0
Treasury stock	(99.9		)	(99.9		)
Additional paid-in capital	6,406.5			6,403.5
Retained deficit	(1,358.0		)	(1,399.3		)
Accumulated other comprehensive loss	(52.8		)	(37.2		)
Total Stockholders’ Equity	5,779.6			5,750.9
Long-term debt, excluding amounts due within one year	7,110.1			7,105.4
Total Capitalization	12,889.7			12,856.3
Current Liabilities
Current portion of long-term debt	51.4			50.0
Short-term borrowings	2,080.0			1,977.2
Accounts payable	675.2			883.8
Dividends payable - common stock	74.6			—
Dividends payable - preferred stock	19.4			—
Customer deposits and credits	152.6			238.9
Taxes accrued	232.8			222.7
Interest accrued	93.7			90.7
Exchange gas payable	15.5			85.5
Regulatory liabilities	152.1			140.9
Legal and environmental	18.9			18.9
Accrued compensation and employee benefits	111.0			149.7
Claims accrued	258.5			114.7
Other accruals	79.5			63.8
Total Current Liabilities	4,015.2			4,036.8
Other Liabilities
Risk management liabilities	55.8			46.7
Deferred income taxes	1,391.6			1,330.5
Deferred investment tax credits	10.8			11.2
Accrued insurance liabilities	84.5			84.4
Accrued liability for postretirement and postemployment benefits	377.3			389.1
Regulatory liabilities	2,488.3			2,519.1
Asset retirement obligations	358.4			352.0
Other noncurrent liabilities	218.3			177.9
Total Other Liabilities	4,985.0			4,910.9
Commitments and Contingencies (Refer to Note 17, "Other Commitments and Contingencies")	—			—
Total Capitalization and Liabilities	$	21,889.9		$	21,804.0

The accompanying Notes to Condensed Consolidated Financial Statements (unaudited) are an integral part of these statements.

10

Table of Contents

ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc. Condensed Statements of Consolidated Cash Flows (unaudited)
Three Months Ended March 31, (in millions)	2019			2018
Operating Activities
Net Income	$	218.9		$	276.1
Adjustments to Reconcile Net Income to Net Cash from Operating Activities:
Depreciation and amortization	175.1			144.7
Deferred income taxes and investment tax credits	51.6			56.8
Other adjustments	6.5			(15.6		)
Changes in Assets and Liabilities:
Components of working capital	(27.2		)	(178.4		)
Regulatory assets/liabilities	0.4			117.1
Deferred charges and other noncurrent assets	(58.3		)	1.9
Other noncurrent liabilities	32.1			(14.4		)
Net Cash Flows from Operating Activities	399.1			388.2
Investing Activities
Capital expenditures	(353.7		)	(370.0		)
Cost of removal	(25.3		)	(19.0		)
Other investing activities	3.6			(9.9		)
Net Cash Flows used for Investing Activities	(375.4		)	(398.9		)
Financing Activities
Repayments of long-term debt and capital lease obligations	(2.3		)	(279.0		)
Premiums and other debt related costs	(4.0		)	—
Repayment of short-term debt (maturity > 90 days)	(350.0		)	—
Change in short-term borrowings, net (maturity ≤ 90 days)	452.8			361.6
Issuance of common stock	3.1			3.7
Acquisition of treasury stock	—			(3.6		)
Dividends paid - common stock	(74.5		)	(65.7		)
Dividends paid - preferred stock	(9.1		)	—
Net Cash Flows from Financing Activities	16.0			17.0
Change in cash, cash equivalents and restricted cash	39.7			6.3
Cash, cash equivalents and restricted cash at beginning of period	121.1			38.4
Cash, Cash Equivalents and Restricted Cash at End of Period	$	160.8		$	44.7

Supplemental Disclosures of Cash Flow Information

Three Months Ended March 31, (in millions)	2019		2018
Non-cash transactions:
Capital expenditures included in current liabilities	$	123.7	$	145.4
Dividends declared but not paid	94.0		65.8
Reclassification of other property to regulatory assets	—		142.3

The accompanying Notes to Condensed Consolidated Financial Statements (unaudited) are an integral part of these statements.

11

Table of Contents

ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

Condensed Statements of Consolidated Equity (unaudited)

(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, 2019	$	3.8	$	880.0	$	(99.9	)	$	6,403.5		$	(1,399.3	)	$	(37.2	)	$	5,750.9
Comprehensive Income:
Net Income	—		—		—			—			218.9			—			218.9
Other comprehensive loss, net of tax	—		—		—			—			—			(15.6		)	(15.6		)
Dividends:
Common stock ($0.40 per share)	—		—		—			—			(149.1		)	—			(149.1		)
Preferred stock (See Note 5)	—		—		—			—			(28.5		)	—			(28.5		)
Stock issuances:
Employee stock purchase plan	—		—		—			1.3			—			—			1.3
Long-term incentive plan	—		—		—			(2.7		)	—			—			(2.7		)
401(k) and profit sharing	—		—		—			4.4			—			—			4.4
Balance as of March 31, 2019	$	3.8	$	880.0	$	(99.9	)	$	6,406.5		$	(1,358.0	)	$	(52.8	)	$	5,779.6

⁽¹⁾Series A and Series B shares have an aggregate liquidation preference of $400M and $500M, respectively. See Note 5, "Equity" for additional information.

(in millions)	Common Stock		Treasury Stock			Additional Paid-In Capital		Retained Deficit			Accumulated Other Comprehensive Loss			Total
Balance as of January 1, 2018	$	3.4	$	(95.9	)	$	5,529.1	$	(1,073.1	)	$	(43.4	)	$	4,320.1
Comprehensive Income:
Net Income	—		—			—		276.1			—			276.1
Other comprehensive income, net of tax	—		—			—		—			33.9			33.9
Common stock dividends ($0.39 per share)	—		—			—		(131.7		)	—			(131.7		)
Treasury stock acquired	—		(3.6		)	—		—			—			(3.6		)
Cumulative effect of change in accounting principle	—		—			—		9.5			(9.5		)	—
Stock issuances:
Employee stock purchase plan	—		—			1.2		—			—			1.2
Long-term incentive plan	—		—			4.0		—			—			4.0
401(k) and profit sharing	—		—			6.2		—			—			6.2
Balance as of March 31, 2018	$	3.4	$	(99.5	)	$	5,540.5	$	(919.2	)	$	(19.0	)	$	4,506.2

12

Table of Contents

ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

Condensed Statements of Consolidated Equity (unaudited) (continued)

	Preferred	Common
Shares (in thousands)	Shares	Shares	Treasury		Outstanding
Balance as of January 1, 2019	420	376,326	(3,963	)	372,363
Issued:
Preferred stock	20
Employee stock purchase plan	—	50	—		50
Long-term incentive plan	—	426	—		426
401(k) and profit sharing	—	164	—		164
Balance as of March 31, 2019	440	376,966	(3,963	)	373,003

	Common
Shares (in thousands)	Shares	Treasury		Outstanding
Balance as of January 1, 2018	340,813	(3,797	)	337,016
Treasury Stock acquired		(149	)	(149	)
Issued:
Employee stock purchase plan	47	—		47
Long-term incentive plan	420	—		420
401(k) and profit sharing	264	—		264
Balance as of March 31, 2018	341,544	(3,946	)	337,598

The accompanying Notes to Condensed Consolidated Financial Statements (unaudited) are an integral part of these statements.

13

Table of Contents

ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

Notes to Condensed Consolidated Financial Statements (unaudited)

1.    Basis of Accounting Presentation

Our accompanying Condensed Consolidated Financial Statements (unaudited) reflect all normal recurring adjustments that are necessary, in the opinion of management, to present fairly the results of operations in accordance with GAAP in the United States of America. The accompanying financial statements contain our accounts and that of our majority-owned or controlled subsidiaries.

The accompanying financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2018. Income for interim periods may not be indicative of results for the calendar year due to weather variations and other factors.

The Condensed Consolidated Financial Statements (unaudited) have been prepared pursuant to the rules and regulations of the SEC. Certain information and note disclosures normally included in annual financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to those rules and regulations, although we believe that the disclosures made in this Quarterly Report on Form 10-Q are adequate to make the information herein not misleading.

2.    Recent Accounting Pronouncements

Recently Issued Accounting Pronouncements

We are currently evaluating the impact of certain ASUs on our Condensed Consolidated Financial Statements (unaudited) and Notes to Condensed Consolidated Financial Statements (unaudited), which are described below:

Standard	Description	Effective Date	Effect on the financial statements or other significant matters
ASU 2019-04, Codification Improvements to Topic 326, Financial Instruments-Credit Losses, Topic 815, Derivatives and Hedging, and Topic 825, Financial Instruments	The pronouncement clarifies and improves certain areas of guidance related to the recently issued standards on credit losses, hedging, and recognition and measurement. Topics 1, 2, and 5 of this update amends ASU 2016-13 as it relates to accrued interest, transfers between investment classifications, expected recoveries and reinsurance recoverables. Topic 3 improves guidance related to fair value hedges. Topic 4 of this update relates to codification improvements to ASU 2016-01.	Annual period ending after December 15, 2019, including interim periods therein. Early adoption is permitted.	We are currently evaluating the impact of codification improvements under Topics 1, 2, and 5 of this pronouncement, if any, on our Condensed Consolidated Financial Statements (unaudited) and Notes to Condensed Consolidated Financial Statements (unaudited). Topics 3 and 4 of this ASU are not material to us. We expect to adopt this ASU on its effective date.
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 Condensed Consolidated Financial Statements (unaudited). We expect to adopt this ASU on its effective date.

14

Table of Contents

ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

Standard	Description	Effective Date	Effect on the financial statements or other significant matters
ASU 2016-13,  Financial Instruments-Credit Losses (Topic 326)	The pronouncement changes the impairment model for most financial assets, replacing the current "incurred loss" model. ASU 2016-13 will require the use of an "expected loss" model for instruments measured at amortized cost. It will also require entities to record allowances for available-for-sale securities rather than impair the carrying amount of the securities. Subsequent improvements to the estimated credit losses of available-for-sale securities will be recognized immediately in earnings instead of over time as they are under historic guidance.	Annual periods beginning after December 15, 2019, including interim periods therein. Early adoption is permitted for annual or interim periods beginning after December 15, 2018.	We maintain investments in U.S. Treasury, corporate and mortgage-backed debt securities, which are pledged as collateral for trust accounts related to our wholly-owned insurance company. These debt securities are classified as available for sale. We also have recorded balances for trade receivables that fall within the scope of the standard. We are currently evaluating the impact of adoption, if any, on our Condensed Consolidated Financial Statements (unaudited) and Notes to Condensed Consolidated Financial Statements (unaudited). We 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)

3.    Revenue Recognition

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 tables below reconcile revenue disaggregation by customer class to segment revenue as well as to revenues reflected on the Condensed Statements of Consolidated Income (unaudited) for the three months ended March 31, 2019 and March 31, 2018:

15

Table of Contents

ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

Three Months Ended March 31, 2019 (in millions)	Gas Distribution Operations		Electric Operations		Corporate and Other		Total
Customer Revenues(1)
Residential	$	975.3	$	118.8	$	—	$	1,094.1
Commercial	330.5		119.3		—		449.8
Industrial	82.9		163.3		—		246.2
Off-system	20.1		—		—		20.1
Miscellaneous	17.2		6.9		0.2		24.3
Total Customer Revenues	$	1,426.0	$	408.3	$	0.2	$	1,834.5
Other Revenues	12.8		22.5		—		35.3
Total Operating Revenues	$	1,438.8	$	430.8	$	0.2	$	1,869.8

⁽¹⁾ Customer revenue amounts exclude intersegment revenues. See Note 20, "Business Segment Information," for discussion of intersegment revenues.

Three Months Ended March 31, 2018 (in millions)	Gas Distribution Operations		Electric Operations		Corporate and Other		Total
Customer Revenues(1)
Residential	$	893.6	$	114.5	$	—	$	1,008.1
Commercial	308.3		116.9		—		425.2
Industrial	74.6		162.5		—		237.1
Off-system	22.3		—		—		22.3
Miscellaneous	16.8		7.5		0.2		24.5
Total Customer Revenues	$	1,315.6	$	401.4	$	0.2	$	1,717.2
Other Revenues	11.7		21.9		—		33.6
Total Operating Revenues	$	1,327.3	$	423.3	$	0.2	$	1,750.8

⁽¹⁾ Customer revenue amounts exclude intersegment revenues. See Note 20, "Business Segment Information," for discussion of intersegment revenues.

Customer Accounts Receivable. Accounts receivable on our Condensed Consolidated Balance Sheets (unaudited) 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 three months ended March 31, 2019 are presented in the table below. We had no significant contract assets or liabilities during the period. Additionally, we have not incurred any significant costs to obtain or fulfill contracts.

(in millions)	Customer Accounts Receivable, Billed (less reserve)		Customer Accounts Receivable, Unbilled (less reserve)
Balance as of December 31, 2018	$	540.5	$	349.1
Balance as of March 31, 2019	692.2		284.6
Increase (Decrease)	$	151.7	$	(64.5	)

Utility revenues are billed to customers monthly on a cycle basis. We generally expect that substantially all customer accounts receivable will be collected within the month following customer billing, as this revenue consists primarily of monthly, tariff-based billings for service and usage. We maintain common utility credit risk mitigation practices, including requiring deposits and actively pursuing collection of past due amounts. 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. It is probable that substantially all of the consideration to which we are entitled from customers will be collected upon satisfaction of performance obligations.

16

Table of Contents

ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

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 would be dilutive (See Note 5 "Equity"). The computation of diluted average common shares is as follows:

	Three Months Ended
	March 31,
(in thousands)	2019	2018
Denominator
Basic average common shares outstanding	373,356	338,012
Dilutive potential common shares:
Shares contingently issuable under employee stock plans	1,062	715
Shares restricted under employee stock plans	133	264
Forward Agreements	105	—
Diluted Average Common Shares	374,656	338,991

5.    Equity

ATM Program and Forward Sale Agreement. On November 1, 2018, we entered into five separate equity distribution agreements, pursuant to which we may sell, from time to time, up to an aggregate value of $500.0 million of our common stock. The program expires on December 31, 2020.

On December 6, 2018, under the ATM program, we executed a forward agreement, which allows 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. We may settle this agreement in shares, cash, or net shares by December 6, 2019. Had we settled all the shares under the forward agreement at March 31, 2019, we would have received approximately $124.3 million, based on a net price of $26.40 per share.

As of March 31, 2019, the ATM program (including impacts of the forward sale agreement discussed above) had $309.4 million of equity available for issuance. We did not have any activity under the ATM program for the three months ended March 31, 2019.

Preferred Stock. As of March 31, 2019 we had 20,000,000 shares of preferred stock authorized for issuance, of which 440,000 shares of preferred stock were outstanding. The following table displays preferred dividends declared for the period by outstanding series of shares:

				Quarter Ended March 31, 2019		March 31, 2019		December 31, 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	$	28.25	$	393.9	$	393.9
6.500% Series B	$	25,000.00	20,000	$	862.15	$	486.1	$	486.1

In addition, 20,000 shares of Series B–1 Preferred Stock, par value $0.01 per share, were 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. Holders of Series B–1 Preferred Stock are not entitled to receive dividend payments and have no conversion rights. The Series B–1 Preferred Stock is paired with the Series B Preferred Stock and may not be transferred, redeemed or repurchased except in connection with the simultaneous transfer, redemption or repurchase of the underlying Series B Preferred Stock.

17

Table of Contents

ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

6.    Gas in Storage

We use both the LIFO inventory methodology and the weighted-average cost methodology to value natural gas in storage. Gas Distribution Operations prices natural gas storage injections at the average of the costs of natural gas supply purchased during the year. For interim periods, the difference between current projected replacement cost and the LIFO cost for quantities of gas temporarily withdrawn from storage is recorded as a temporary LIFO liquidation credit or debit within the Condensed Consolidated Balance Sheets (unaudited). Due to seasonality requirements, we expect interim variances in LIFO layers to be replenished by year end. We had a temporary LIFO liquidation debit of $21.5 million and zero as of March 31, 2019 and December 31, 2018, respectively, for certain gas distribution companies recorded within “Prepayments and other,” on the Condensed Consolidated Balance Sheets (unaudited).

7.    Regulatory Matters

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

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

18

Table of Contents

ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

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

(in millions)
Company	Program	Incremental Revenue			Incremental Capital Investment		Investment Period	Filed	Status	Rates Effective
Columbia of Ohio	IRP - 2018(1)	$	(1.6	)	$	207.3	1/17-12/17	February 27, 2018	Approved April 25, 2018	May 2018
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(1)	74.5			659.9		1/11-12/17	December 1, 2017	Approved November 28, 2018	December 2018
Columbia of Ohio	CEP - 2019	16.1			122.1		1/18-12/18	February 28, 2019	Order Expected August 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	FMCA 1(3)	9.9			1.5		11/17-9/18	November 30, 2018	Approved March 27, 2019	April 2019
Columbia of Massachusetts	GSEP - 2019	10.7			64.0		1/19-12/19	October 31, 2018	Approved April 30, 2019	May 2019
Columbia of Virginia	SAVE - 2019	2.4			36.0		1/19-12/19	August 17, 2018	Approved October 26, 2018	January 2019
Columbia of Kentucky	AMRP - 2019	3.6			30.1		1/19-12/19	October 15, 2018	Approved December 5, 2018	January 2019
Columbia of Maryland	STRIDE - 2019	1.2			15.9		1/19-12/19	November 1, 2018	Approved December 12, 2018	January 2019
NIPSCO - Electric	TDSIC - 4(1)	(11.8		)	72.2		12/17-5/18	July 31, 2018	Approved November 28, 2018	December 2018
NIPSCO - Electric	TDSIC - 5(1)	15.9			58.8		6/18-11/18	January 29, 2019	Order Expected Q2 2019	June 2019
NIPSCO - Electric	ECRM - 32	1.0			—		1/18-6/18	July 31, 2018	Approved October 31, 2018	November 2018
NIPSCO - Electric	FMCA - 9(3)	4.1			90.2		10/17-3/18	April 27, 2018	Approved July 25, 2018	August 2018
NIPSCO - Electric	FMCA - 10(3)	2.2			45.7		4/18-8/18	October 18, 2018	Approved January 29, 2019	February 2019
NIPSCO - Electric	FMCA - 11(3)	0.9			22.4		9/18-2/19	April 17, 2019	Order Expected July, 2019	August 2019

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

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

⁽³⁾Incremental revenue is inclusive of tracker eligible operations and maintenance expense.

19

Table of Contents

ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

Notes to Condensed Consolidated Financial Statements (unaudited) (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 or Settled Incremental Revenue			Filed	Status	Rates Effective
NIPSCO - Gas(1)	$	138.1	$	107.3		September 27, 2017	Approved September 19, 2018	October 2018
Columbia of Virginia(2)	$	14.2	$	1.3		August 28, 2018	Settlement filed April 19, 2019, Order expected Second half of 2019	February 2019
NIPSCO - Electric(3)	$	21.4	$	(45.0	)	October 31, 2018	Partial settlement filed April 26, 2019, Order expected Second half of 2019	Second half of 2019

⁽¹⁾Rates will be 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 will be effective on January 1, 2020. The IURC’s order also dismissed NIPSCO from phase 2 of the IURC’s TCJA investigation.

⁽²⁾Rates implemented subject to refund. An order of the settlement agreement, including refunds to be issued and resolution of outstanding TCJA impacts to rates, is currently pending before the VSCC.

⁽³⁾An order on the partial settlement agreement, including the resolution of outstanding TCJA impacts to rates is currently pending before the IURC. The as-filed request and partial settlement agreement also includes $83.6 million and $85.3 million, respectively, of reductions to the fuel component of base rates related to a proposed change in service structure.

Additional Regulatory Matters

Columbia of Massachusetts. On December 21, 2018, the Massachusetts DPU issued an order approving the pass back of approximately $95.8 million in excess deferred taxes associated with TCJA with new rates effective on February 1, 2019.

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.

8.    Risk Management Activities

We are exposed to certain risks relating to our ongoing business operations, namely commodity price risk and interest rate risk. We recognize that the prudent and selective use of derivatives may help to lower our cost of debt capital, manage our interest rate exposure and limit volatility in the price of natural gas.

20

Table of Contents

ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

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

(in millions)	March 31, 2019		December 31, 2018
Risk Management Assets - Current(1)
Interest rate risk programs	$	5.6	$	—
Commodity price risk programs	0.9		1.1
Total	$	6.5	$	1.1
Risk Management Assets - Noncurrent(2)
Interest rate risk programs	$	—	$	18.5
Commodity price risk programs	6.9		4.4
Total	$	6.9	$	22.9
Risk Management Liabilities - Current(3)
Interest rate risk programs	$	—	$	—
Commodity price risk programs	4.4		5.0
Total	$	4.4	$	5.0
Risk Management Liabilities - Noncurrent
Interest rate risk programs	$	22.4	$	9.5
Commodity price risk programs	33.4		37.2
Total	$	55.8	$	46.7

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

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

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

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 may range from five to ten years and is limited to 20 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 March 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 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 Condensed Statements of Consolidated Income (unaudited).

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

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

21

Table of Contents

ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

9.    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 Condensed Consolidated Balance Sheets (unaudited) on a recurring basis and their level within the fair value hierarchy as of March 31, 2019 and December 31, 2018:

 

Recurring Fair Value Measurements March 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 March 31, 2019
Assets
Risk management assets	$	—	$	13.4	$	—	$	13.4
Available-for-sale securities	—		138.2		—		138.2
Total	$	—	$	151.6	$	—	$	151.6
Liabilities
Risk management liabilities	$	—	$	60.2	$	—	$	60.2
Total	$	—	$	60.2	$	—	$	60.2

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 March 31, 2019 and December 31, 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

22

Table of Contents

ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

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 8, "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 8, “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 Condensed Consolidated Balance Sheets (unaudited). 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 March 31, 2019 and December 31, 2018 were: 

March 31, 2019 (in millions)	Amortized Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
Available-for-sale securities
U.S. Treasury debt securities	$	22.0	$	—	$	—		$	22.0
Corporate/Other debt securities	115.7		1.4		(0.9		)	116.2
Total	$	137.7	$	1.4	$	(0.9	)	$	138.2
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 three months ended March 31, 2019 and 2018.

The cost of maturities sold is based upon specific identification. At March 31, 2019, approximately $5.6 million of U.S. Treasury debt securities and approximately $3.6 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 three months ended March 31, 2019 and 2018.

Non-recurring Fair Value Measurements. There were no significant non-recurring fair value measurements recorded during the three months ended March 31, 2019.

B.    Other Fair Value Disclosures for Financial Instruments. The carrying amount of cash and cash equivalents, restricted cash, 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 three months ended March 31, 2019, there was no change in the method or significant assumptions used to estimate the fair value of long-term debt.

23

Table of Contents

ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

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

(in millions)	Carrying Amount as of March 31, 2019		Estimated Fair Value as of March 31, 2019		Carrying Amount as of Dec. 31, 2018		Estimated Fair Value as of Dec. 31, 2018
Long-term debt (including current portion)	$	7,161.5	$	7,533.6	$	7,155.4	$	7,228.3

10.    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 2019 and October 2019 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 Condensed Consolidated Balance Sheets (unaudited). As of March 31, 2019, the maximum amount of debt that could be recognized related to our accounts receivable programs is $500.0 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 March 31, 2019 and December 31, 2018:

 

(in millions)	March 31, 2019		December 31, 2018
Gross Receivables	$	742.7	$	694.4
Less: Receivables not transferred	242.7		295.2
Net receivables transferred	$	500.0	$	399.2
Short-term debt due to asset securitization	$	500.0	$	399.2

For the three months ended March 31, 2019 and 2018, $100.8 million and $176.7 million, respectively, 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 $0.8 million for the three months ended March 31, 2019 and 2018. We remain responsible for collecting on the receivables securitized, and the receivables cannot be transferred to another party.

11.    Goodwill

 The following presents our goodwill balance allocated by segment as of March 31, 2019:

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

We applied the qualitative "step 0" analysis to our reporting units for the annual impairment test performed as of May 1, 2018. For this test, we assessed various assumptions, events and circumstances that would have affected the estimated fair value of the reporting units as compared to their base line May 1, 2016 "step 1" fair value measurement. The results of this assessment indicated that it was not more likely than not that our reporting unit fair values were less than the reporting unit carrying values, accordingly, no "step 1" analysis was required.

24

Table of Contents

ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

12.    Income Taxes

Our interim effective tax rates reflect the estimated annual effective tax rates for 2019 and 2018, adjusted for tax expense associated with certain discrete items. The effective tax rates for the three months ended March 31, 2019 and 2018 were 21.2% and 18.5%, respectively. These effective tax rates differ from the federal statutory tax rate of 21% primarily due to the effects of tax credits, state income taxes, the amortization of excess deferred federal income tax liabilities, as specified in the TCJA and in utility ratemaking proceedings and other permanent book-to-tax differences.

The increase in the three month effective tax rate of 2.7% in 2019 compared to 2018 is primarily due to the relative impact of permanent differences on higher estimated pre-tax income in 2019 compared to 2018.

There were no material changes recorded in 2019 to our uncertain tax positions as of December 31, 2018.

13.    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. For most plans, cash contributions are remitted to grantor trusts.

For the three months ended March 31, 2019, we contributed $0.6 million to our pension plans and $5.7 million to our other postretirement benefit plans.

The following table provides the components of the plans’ actuarially determined net periodic benefit cost for the three months ended March 31, 2019 and 2018:

	Pension Benefits						Other Postretirement Benefits
Three Months Ended March 31, (in millions)	2019			2018			2019			2018
Components of Net Periodic Benefit (Income) Cost(1)
Service cost	$	7.3		$	7.9		$	1.3		$	1.3
Interest cost	18.2			16.6			4.8			4.4
Expected return on assets	(27.2		)	(36.3		)	(3.3		)	(3.7		)
Amortization of prior service credit	—			(0.1		)	(0.8		)	(1.0		)
Recognized actuarial loss	11.4			10.2			0.5			0.9
Total Net Periodic Benefit (Income) Cost	$	9.7		$	(1.7	)	$	2.5		$	1.9

⁽¹⁾The service cost component, and all non-service cost components, of net periodic benefit cost are presented in "Operation and maintenance" and "Other, net", respectively, on the Condensed Statements of Consolidated Income (unaudited).

14.    Long-Term Debt

On April 1, 2019, NIPSCO redeemed $41.0 million of 5.85% pollution control bonds at maturity.

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 March 31, 2019 and December 31, 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 $980.0 million and $978.0 million of commercial paper outstanding as of March 31, 2019 and December 31, 2018, respectively.

25

Table of Contents

ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

Transfers of accounts receivable are accounted for as secured borrowings resulting in the recognition of short-term borrowings on the Condensed Consolidated Balance Sheets (unaudited). We had $500.0 million in transfers as of March 31, 2019 and $399.2 million as of December 31, 2018. Refer to Note 10, "Transfers of Financial Assets," for additional information.

Short-term borrowings were as follows: 

(in millions)	March 31, 2019		December 31, 2018
Commercial paper weighted-average interest rate of 2.90% and 2.96% at March 31, 2019 and December 31, 2018, respectively	$	980.0	$	978.0
Accounts receivable securitization facility borrowings	500.0		399.2
Term loan weighted-average interest rate of 3.00% and 3.07% at March 31, 2019 and December 31, 2018, respectively	600.0		600.0
Total Short-Term Borrowings	$	2,080.0	$	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 Condensed Statements of Consolidated Cash Flows (unaudited) as their maturities are less than 90 days.

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.

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 Condensed Consolidated Balance Sheets (unaudited) as of January 1, 2019. The standard had no material impact on our Condensed Statements of Consolidated Income (unaudited) or our Condensed Statements of Consolidated Cash Flows (unaudited).

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 25 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

26

Table of Contents

ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

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 Condensed Consolidated Balance Sheets (unaudited) do not include obligations for possible fleet vehicle lease renewals beyond the initial lease term. While we have the ability to renew these leases beyond the initial term, we are not reasonably certain to do so.

We lease the majority of our IT assets under 4 year lease terms. Ownership of leased IT assets is transferred to us at the end of the lease term. We have not provided material residual value guarantees for our leases, nor do our leases contain material restrictions or covenants. Lease contracts containing renewal and termination options are mostly exercisable at our sole discretion. Certain of our real estate and railcar leases include renewal periods in the measurement of the lease obligation if we have deemed the renewals reasonably certain to be exercised.

With respect to service contracts involving the use of assets, if we have the right to direct the use of the asset and obtain substantially all economic benefits from the use of an asset, we account for the service contract as a lease. Unless specifically provided to us by the lessor, we utilize NiSource's collateralized incremental borrowing rate commensurate to the lease term as the discount rate for all of our leases.

The components of lease expense are presented in the following lines on the Condensed Statements of Consolidated Income (unaudited):

Three Months Ended March 31, (in millions)	Income Statement Classification	2019
Finance lease cost
Amortization of right-of-use assets	Depreciation and amortization	$	3.7
Interest on lease liabilities	Interest expense, net	2.9
Total finance lease cost(1)		6.6
Operating lease cost(2)	Operation and maintenance	3.7
Short-term lease cost	Operation and maintenance	0.7
Total lease cost		$	11.0

⁽¹⁾Total finance lease cost includes $0.6 million in costs that have been capitalized into Net Property, Plant and Equipment.

⁽²⁾Operating lease cost includes $0.3 million in costs that have been capitalized into Net Property, Plant and Equipment.

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

Three Months Ended March 31, (in millions)	Balance Sheet Classification	2019
Assets
Finance leases	Net Property, Plant and Equipment	$	179.8
Operating leases	Deferred charges and other	53.8
Total leased assets		233.6
Liabilities
Current
Finance leases	Current portion of long-term debt	10.4
Operating leases	Other accruals	9.3
Noncurrent
Finance leases	Long-term debt, excluding amounts due within one year	188.5
Operating leases	Other noncurrent liabilities	44.5
Total lease liabilities		$	252.7

27

Table of Contents

ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

Other pertinent information related to leases was as follows:

Three Months Ended March 31, (in millions)	2019
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows from finance leases	$	3.0
Operating cash flows from operating leases	3.7
Financing cash flows from finance leases	2.4
Right-of-use assets obtained in exchange for lease obligations
Finance leases	6.6
Operating leases	$	0.1

	March 31, 2019
Weighted-average remaining lease term (years)
Finance leases	15.8
Operating leases	10.1
Weighted-average discount rate
Finance leases	5.8	%
Operating leases	4.4	%

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

As of March 31, 2019, (in millions)	Total			Finance Leases			Operating Leases
Year 1	$	35.5		$	24.0		$	11.5
Year 2	31.8			23.7			8.1
Year 3	31.0			23.9			7.1
Year 4	28.8			22.7			6.1
Year 5	25.8			20.1			5.7
Thereafter	246.7			217.7			29.0
Total lease payments	399.6			332.1			67.5
Less: Imputed interest	(125.2		)	(111.5		)	(13.7		)
Less: Leases not yet commenced(1)	(21.7		)	(21.7		)	—
Total	252.7			198.9			53.8
Reported as of March 31, 2019
Short-term lease liabilities	19.7			10.4			9.3
Long-term lease liabilities	233.0			188.5			44.5
Total lease liabilities	$	252.7		$	198.9		$	53.8

⁽¹⁾ Expected payments include obligations for leases not yet commenced of approximately $21.7 million for interconnection facilities. The facilities will have a lease term of 10 years, with an estimated commencement in the second quarter of 2019.

28

Table of Contents

ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

Disclosures Related to Periods Prior to Adoption of ASC 842.

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.    Other Commitments and Contingencies

A. Guarantees and Indemnities. We and certain of our subsidiaries enter into various agreements providing financial or performance assurance to third parties on behalf of certain subsidiaries as a 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. As of March 31, 2019 and December 31, 2018, we had issued stand-by letters of credit of $10.2 million.  

 B. 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 service for approximately 7,500 gas meters, the majority of which serve residences and approximately 700 of which serve 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 “ - D. Other Matters - Greater Lawrence Pipeline Replacement” below for more information.

We are subject to inquiries by federal and state government authorities and regulatory agencies regarding the Greater Lawrence Incident. The NTSB, the U.S Attorney’s office and the SEC have pending investigations related to the Greater Lawrence Incident, as described below. We are also subject to inquiries from the Massachusetts DPU and the Massachusetts Attorney General’s Office. We are cooperating with all inquiries and investigations. The outcomes and impacts of the current investigations and any future investigations that may be commenced related to such inquiries are uncertain at this time.

NTSB Investigation. As noted above, the NTSB is investigating the Greater Lawrence Incident. The parties to the investigation include the PHMSA, the Massachusetts DPU, Columbia of Massachusetts, and the Massachusetts State Police. We are cooperating with the NTSB and have provided information to assist in its ongoing investigation into relevant facts related to the event, the probable cause, and its development of safety recommendations.

According to the preliminary public report that the NTSB issued on October 11, 2018, an over-pressurization of a low-pressure gas distribution system occurred that was related to work being done on behalf of Columbia of Massachusetts on a pipeline replacement project in Lawrence. According to the report, sensing lines detected a drop in pressure in a portion of mainline that was being abandoned, causing a regulator to open up and increase pressure in the system to a level that exceeded the maximum allowable operating pressure of the distribution system.

On November 14, 2018, the NTSB issued an urgent safety recommendation report regarding natural gas distribution system project development and review. In its report, the NTSB identified certain factors that it believes contributed to the Greater Lawrence Incident and made safety recommendations. The NTSB recommended that the Commonwealth of Massachusetts eliminate the

29

Table of Contents

ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

professional engineer licensure exemption for public utility work and require a professional engineer’s seal on public utility engineering drawings, which is now law in Massachusetts. The NTSB also made recommendations to us related to engineering plan and constructability review processes, records and documentation, management of change processes, and control procedures during modifications to gas mains. We are in the process of implementing these recommendations. The NTSB investigation is ongoing. While the NTSB investigation is pending, we are prohibited from disclosing information related to the investigation without approval from the NTSB.

Since the Greater Lawrence Incident, we have identified, and moved ahead with, new steps to enhance system safety and reliability and to safeguard against over-pressurization. Some of these measures have already been completed and others are in process. These Company-wide safety measures will include enhanced measures as called for in the NTSB’s recommendations. We have committed to a program to install over-pressurization protection devices on all of our low-pressure systems, which is described in “ - D. Other Matters.”

Massachusetts Regulatory and Legislative Matters. Under Massachusetts law, the DPU is authorized to investigate potential violations of pipeline safety regulations and to assess a civil penalty of up to $209,000 for a violation of federal pipeline safety regulations. A separate violation occurs for each day of violation up to $2.1 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, 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. The timing and outcome of any such investigations are uncertain at this time.

The Massachusetts DPU has 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 will direct all natural gas distribution companies operating in the Commonwealth to fund the statewide examination. The statewide examination is underway and we have responded to the evaluator’s information requests. The independent evaluator is expected to produce a report with recommendations. The examination is expected to complement, but not duplicate, the NTSB’s investigation.

On November 30, 2018, Columbia of Massachusetts entered into a consent order with the Massachusetts DPU in connection with a notice of probable violation issued in March 2018, stemming from a 2016 report. The Division found that Columbia of Massachusetts violated certain pipeline safety regulations related to pressure limiting and regulating stations in Taunton, Massachusetts. As part of the consent order, Columbia of Massachusetts was fined $75,000 and entered into a compliance agreement under which it agreed to take several actions related to its pressure regulator stations within various timeframes, including the adoption of a Pipeline Safety Management System ("SMS"), the American Petroleum Institute’s (API) Recommended Practice 1173. Columbia of Massachusetts is complying with the order.

On December 18, 2018, the Massachusetts DPU issued an order requiring Columbia of Massachusetts to enter into an agreement with a Massachusetts-based engineering firm to monitor Columbia of Massachusetts’ remaining restoration and recovery work in the Greater Lawrence area. The order requires Columbia of Massachusetts to take measures to ensure that adequate heat and hot water and gas appliances are provided to all affected properties, repave all affected streets, roadways, sidewalks and other areas in accordance with applicable DPU standards and precedents, consult with the affected communities and discuss plans for restoring affected hard or soft surfaces, and replace all gas boilers and furnaces and other gas-fired equipment at affected residences. Under the order, all restoration work beginning in 2019 is required to be completed no later than October 31, 2019, unless an earlier or later date is agreed to with any of the affected communities. We have agreed to complete the work by September 15, 2019. Also, under the order, Columbia of Massachusetts will be required to maintain quantitative measures, which must be verified by officials of the affected communities, to track its progress in completing all of the remaining work. Estimates for the cost of this work are included in the estimated ranges of loss noted below, which is discussed in “- D. Other Matters - Greater Lawrence Incident Restoration" and " - Greater Lawrence Pipeline Replacement” below. Our failure to adhere to any of the requirements in the order may result in penalties of up to $1 million per violation.

In December 2018, the President of Columbia of Massachusetts testified before a joint state legislative committee on telecommunications, utilities and energy with other industry officials about gas system safety in Massachusetts and regulatory oversight. Increased scrutiny related to these matters, including additional legislative oversight hearings and new legislative proposals, is expected to continue during the current two-year legislative session.

On December 31, 2018, the Massachusetts Governor signed into law legislation requiring a certified professional engineer to review and approve gas pipeline work that could pose a “material risk” to public safety, consistent with the NTSB’s recommendation.

30

Table of Contents

ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

The Massachusetts DPU has issued interim guidelines and the existing moratorium has been lifted. The DPU issued an Order Opening Inquiry (Notice of Inquiry) on March 18, 2019, and Columbia of Massachusetts has submitted comments.

U.S. Department of Justice Investigation. 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 for the District of Massachusetts. The initial grand jury subpoenas were served on the Company and Columbia of Massachusetts on September 24, 2018. The Company and Columbia of Massachusetts are cooperating with the investigation. We are unable to estimate the amount (or range of amounts) of reasonably possible losses associated with any civil or criminal penalties that could be imposed on the Company or Columbia of Massachusetts.

U.S. Congressional Hearing. In November 2018, executives of the Company and Columbia of Massachusetts testified at a U.S. Senate hearing regarding the Greater Lawrence Incident and natural gas pipeline safety. Increased scrutiny related to these matters, including additional federal congressional hearings and new legislative proposals, is expected to continue through 2019.

SEC Investigation. On February 11, 2019, the SEC notified the Company that it is conducting an investigation of the Company related to disclosures made prior to the Greater Lawrence Incident. We are cooperating with the investigation.

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 will be 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 May 13. 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. Many residents and business owners have submitted individual damage claims to Columbia of Massachusetts. We also have received notice from three parties indicating an intent to assert wrongful death claims. In Massachusetts, punitive damages are available in a wrongful death action upon proof of gross negligence or willful or reckless conduct causing the death. In addition, the Commonwealth of Massachusetts and the municipalities of Lawrence, Andover and North Andover are seeking reimbursement from Columbia of Massachusetts for their respective expenses incurred in connection with the Greater Lawrence Incident. The outcomes and impacts of the private actions are uncertain at this time. We are discussing potential settlements with the affected municipalities and certain of the wrongful death and bodily injury plaintiffs. On April 25, 2019, we entered into a settlement agreement with certain of these plaintiffs involving bodily injury claims, subject to certain conditions, including court approval.

Financial Impact. During the quarter ended March 31, 2019, we expensed approximately $204 million for estimated third-party claims related to the Greater Lawrence Incident, including, but not limited to, personal injury and property damage claims, damage to infrastructure and mutual aid payments to other utilities assisting with the restoration effort. Including the $757 million recorded during 2018, we estimate that total costs related to third-party claims resulting from the incident will range from $961 million to $1,010 million, depending on the final outcome of ongoing reviews and the number, nature, and value of third-party claims. The amounts set forth above do not include costs of certain third party claims that we are not able to estimate, non-claims related expenses resulting from the incident or the estimated capital cost of the pipeline replacement, which is set forth in " - D. Other Matters - Greater Lawrence Incident Restoration" and " - Greater Lawrence Pipeline Replacement," respectively, below.

The process for estimating costs associated with third-party claims relating to the Greater Lawrence Incident requires management to exercise significant judgment based on a number of assumptions and subjective factors. As more information becomes known, including additional information resulting from the NTSB investigation and private actions, management’s estimates and assumptions regarding the financial impact of the Greater Lawrence Incident may change. The increase in estimated total costs related to third-party claims from those disclosed in our Form 10-K for the year ended December 31, 2018 resulted primarily from receiving additional information regarding legal claims and the required scope of the restoration work inside the affected homes.

Expenses described above are presented within “Operation and maintenance” in our Statements of Consolidated Income.

We believe that it is reasonably possible that the total amount of the financial loss will be greater than the amount recorded, but we are unable to reasonably estimate the additional loss and the upper end of the range for the class action lawsuits and certain other private action claims because there are a number of unknown facts and legal considerations that may impact the amount of any potential liability, including the total scope and nature of claims that may be asserted against NiSource and Columbia of Massachusetts, whether certain claims can be brought as a class action, and the number of plaintiffs who may bring such claims.

31

Table of Contents

ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

We will continue to review the available information and other information as it becomes available, including evidence from or held by other parties, claims that have not yet been submitted, and additional information about the nature and extent of personal and business property damage and losses, the nature, number and severity of personal injuries, and information made available through the discovery process.

In addition, it is not possible at this timesub to reasonably estimate the total amount of any expenses associated with government investigations and fines, penalties or settlements with certain governmental authorities, including the Massachusetts DPU and other regulators, that we may incur in connection with the Greater Lawrence Incident. Therefore, the foregoing amounts do not include estimates of the total amount that we may incur for any such fines, penalties or settlements.

We maintain liability insurance for damages in the approximate amount of $800 million and property insurance for gas pipelines and other applicable property in the approximate amount of $300 million. Total expenses related to the incident have exceeded the total amount of insurance coverage available under our policies. While we believe that a substantial amount of expenses related to the Greater Lawrence Incident will be covered by insurance, insurers providing property and liability insurance to the Company or Columbia of Massachusetts are raising defenses to coverage under the terms and conditions of the respective insurance policies which contain various exclusions and conditions that could limit the amount of insurance proceeds to the Company or Columbia of Massachusetts. We are not able to estimate the amount of expenses that will not be covered by insurance, but these amounts are material to our financial statements. Certain types of damages, expenses or claimed costs, such as fines or penalties, may be excluded under the policies. An amount of $100 million for insurance recoveries was recorded during the quarter ended March 31, 2019 in addition to the $135 million of insurance recoveries that were recorded during 2018. As of March 31, 2019, $113 million had been collected, of which $108 million was collected during the three months ended March 31, 2019. Additional collections of insurance proceeds in the amount of $22 million were received subsequent to the March 31, 2019 balance sheet date. The remaining insurance receivable balance of $122 million as of March 31, 2019 is presented within “Accounts receivable.” To the extent that we are not successful in obtaining insurance recoveries in the amount recorded for such recoveries as of March 31, 2019, it could result in a charge against "Operation and maintenance" expense. We are currently unable to predict the timing of additional future insurance recoveries.

In addition, we are party to certain other claims and legal proceedings arising in the ordinary course of business, 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 or proceeding related to the Greater Lawrence Incident or otherwise would not have a material adverse effect on our results of operations, financial position or liquidity. If one or more of such 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.

C. 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 and remediation costs to be recoverable through rates for certain of our companies.

As of March 31, 2019 and December 31, 2018, we had recorded a liability of $99.7 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 Condensed Consolidated Balance Sheets (unaudited). 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.

32

Table of Contents

ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

Electric Operations' compliance estimates disclosed below are reflective of NIPSCO's Integrated Resource Plan submitted to the IURC on October 31, 2018. See section D, "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 increase methane leak detection, require emission reductions or impose additional requirements for natural gas facilities could restrict GHG emissions and impose additional costs. We carefully monitor all GHG reduction proposals and regulations.

CPP and ACE Rules. On October 23, 2015, the EPA issued the CPP to regulate CO₂ emissions from existing fossil-fuel EGUs under section 111(d) of the CAA. The U.S. Supreme Court has stayed implementation of the CPP until litigation is decided on its merits, and the EPA under the current administration has proposed to repeal the CPP. On August 31, 2018, the EPA published a proposal to replace the CPP with the ACE rule, which establishes guidelines for states to use when developing plans to reduce CO₂ emissions from existing coal-fired EGUs. The proposal would provide states three years after a final rule is issued to develop state-specific plans, and the EPA would have 12 months to act on a complete state plan submittal. Within two years after a finding of failure to submit a complete plan, or disapproval of a state plan, the EPA would issue a federal plan. 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 Condensed Consolidated Financial Statements (unaudited).

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, 2018. Our total estimated liability related to the facilities subject to remediation was $96.4 million and $97.5 million at March 31, 2019 and December 31, 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.

The publication of the CCR rule 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 compliance strategies that will be used and the preliminary nature of available data used to estimate costs. In addition, to comply with the rule, NIPSCO incurred capital expenditures to modify its infrastructure and manage CCRs. As allowed by the EPA, 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 filed a petition on November 1, 2016 with the IURC seeking approval of the projects and recovery of the costs associated with CCR compliance. On June 9, 2017, NIPSCO filed with the IURC a settlement reached with certain parties regarding the CCR projects and treatment of associated costs. The IURC approved the settlement in an order on December 13, 2017. Capital compliance costs totaled approximately $193 million, with the projects being substantially complete and in service as of March 31, 2019.

33

Table of Contents

ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

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. The final rule became effective January 4, 2016. Based upon a preliminary study of the November 3, 2015 final rule, capital compliance costs were expected to be approximately $170 million. The EPA is expected to release a draft ELG reconsideration rule in 2019. However, 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).

D. 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 Plan’s had indicated.

The Integrated Resource Plan evaluated demand-side and supply-side resource alternatives to reliably and cost effectively meet NIPSCO customers' future energy requirements over the ensuing 20 years. The preferred option within the Integrated Resource Plan retires R.M. Schahfer Generating Station (Units 14, 15, 17, and 18) by 2023 and Michigan City Generating Station (Unit 12) by 2028. These units represent 2,080 MW of generating capacity, equal to 72% of NIPSCO’s remaining 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 MW. The facilities supplying the energy will have a combined nameplate capacity of approximately 700 MW. NIPSCO's purchase requirement under the PPAs is dependent on satisfactory approval of the PPAs by the IURC. NIPSCO submitted the PPAs to the IURC for approval in February 2019. An IURC order is anticipated in the third quarter of 2019. If approved by the IURC, payments under the PPAs will not begin until the associated generation facilities are constructed by the owner / seller which is expected to be complete by the end of 2020.

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 partnership owned by NIPSCO, the developer and an unrelated tax equity partner. The aforementioned partnership structure will result in full NIPSCO ownership 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 and timely completion of construction. The estimated procedural timeline for receiving an IURC order is the same as the aforementioned PPAs with required FERC filings occurring after receiving the IURC order. Construction of the facility is expected to be complete by the end of 2020.

Greater Lawrence Incident Restoration. In addition to the amounts recorded for third-party claims (described above in " - B. Legal Proceedings"), we expensed approximately $32 million for other incident-related costs during the three months ended March 31, 2019. These expenses include certain consulting costs, claims center costs and labor and related expenses incurred in connection with the incident. Including the $266 million recorded during 2018, we expect to incur a total of $360 million to $370 million in such incident-related costs, depending on the incurrence of future restoration work. The amounts set forth above do not include the estimated capital cost of the pipeline replacement, which is set forth below. The increase in estimated total incident-related expenses from those disclosed in our Form 10-K for the year ended December 31, 2018 resulted primarily from receiving additional information regarding the extended period of time over which the restoration work would take place, higher than anticipated costs from vendors and increased estimates for consultants and claim center costs.

We maintain liability insurance for damages in the approximate amount of $800 million and property insurance for gas pipelines and other applicable property in the approximate amount of $300 million. Total expenses related to the incident have exceeded the total amount of insurance coverage available under our policies. While we believe that a substantial amount of expenses related to the Greater Lawrence Incident will be covered by insurance, insurers providing property and liability insurance to the Company or Columbia of Massachusetts are raising defenses to coverage under the terms and conditions of the respective insurance policies which contain various exclusions and conditions that could limit the amount of insurance proceeds to the Company or Columbia of Massachusetts. We are not able to estimate the amount of expenses that will not be covered by insurance, but these amounts are material to our financial statements. Certain types of damages, expenses or claimed costs, such as fines or penalties, may be excluded under the policies. As discussed above in “- B. Legal Proceedings,” $100 million for insurance recoveries was recorded during the quarter ended March 31, 2019 in addition to the $135 million of insurance recoveries that were recorded during 2018.

34

Table of Contents

ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

As of March 31, 2019, $113 million had been collected, of which $108 million was collected during the three months ended March 31, 2019. Additional collections of insurance proceeds in the amount of $22 million were received subsequent to the March 31, 2019 balance sheet date. We are currently unable to predict the timing of future insurance recoveries. To the extent that we are not successful in obtaining insurance recoveries in the amount recorded for such recoveries as of March 31, 2019, it could result in a charge against “Operation and maintenance” expense.

Substantially all of the $346 million liability for third-party claims and other incident-related costs remaining as of March 31, 2019 is presented within "Current liabilities" in our Condensed Consolidated Balance Sheets (unaudited). The remaining insurance receivable balance of $122 million as of March 31, 2019 is presented within “Accounts receivable.”

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. At the request of the Massachusetts DPU, which was instructed by the Massachusetts Governor through his executive authority under a state of emergency, Columbia of Massachusetts hired an outside contractor to serve as the Chief Recovery Officer for the Greater Lawrence Incident, responsible for command, control and communications. Columbia of Massachusetts restored gas service to nearly all homes and workplaces in December 2018. With the restoration and recovery efforts now substantially complete, the service of the Chief Recovery Officer is complete and the next phase of the effort is being managed by Columbia of Massachusetts under the third party oversight of a Massachusetts-based engineering firm as set forth above under “ - B. Legal Proceedings.”

Since the Greater Lawrence Incident and through March 31, 2019, we have incurred approximately $177 million of capital spend for the pipeline replacement, of which approximately $10 million was incurred in 2019. We estimate this replacement work will cost between $240 million and $250 million in total. Columbia of Massachusetts has provided notice to its property insurer of the Greater Lawrence Incident and discussions around the claim and recovery have commenced. The recovery of any capital investment not reimbursed through insurance will be addressed in a future regulatory proceeding. The outcome of such a proceeding is uncertain. In accordance with ASC 980-360, if it becomes probable that a portion of the pipeline replacement cost will not be recoverable through customer rates and an amount can be reasonably estimated, we will reduce our regulated plant balance for the amount of the probable disallowance and record an associated charge to earnings. This could result in a material adverse effect to our financial condition, results of operations and cash flows. Additionally, if a rate order is received allowing recovery of the investment with no or reduced return on investment, a loss on disallowance may be required.

In addition, we have committed to a capital investment program to install over-pressurization protection devices on all of our low-pressure systems as described above in “-B. Legal Proceedings.” These devices operate like circuit-breakers, so that if operating pressure is too high or too low, regardless of the cause, they are designed to immediately shut down the supply of gas to the system. The program also includes installing remote monitoring devices on all low-pressure systems, enabling gas control centers to continuously monitor pressure at regulator stations. In addition, we have conducted a field survey of all regulator stations and initiated an engineering review of those regulator stations; we are verifying and enhancing our maps and records of low-pressure regulator stations; and we initiated a process so that our personnel will be present whenever excavation work is being done in close proximity to a regulator station.

35

Table of Contents

ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

18.    Accumulated Other Comprehensive Loss

The following tables display the components of Accumulated Other Comprehensive Loss:

	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, 2019	$	(2.4	)	$	(13.0	)	$	(21.8	)	$	(37.2	)
Other comprehensive income (loss) before reclassifications	2.7			(19.3		)	0.5			(16.1		)
Amounts reclassified from accumulated other comprehensive loss	0.1			—			0.4			0.5
Net current-period other comprehensive income (loss)	2.8			(19.3		)	0.9			(15.6		)
Balance as of March 31, 2019	$	0.4		$	(32.3	)	$	(20.9	)	$	(52.8	)

	Gains and Losses on Securities(1)			Gains and Losses on Cash Flow Hedges(1)			Pension and OPEB Items(1)			Accumulated Other Comprehensive Loss(1)
Balance as of January 1, 2018	$	0.2		$	(29.4	)	$	(14.2	)	$	(43.4	)
Other comprehensive income (loss) before reclassifications	(1.9		)	51.1			(0.6		)	48.6
Amounts reclassified from accumulated other comprehensive loss	0.2			(15.7		)	0.8			(14.7		)
Net current-period other comprehensive income (loss)	(1.7		)	35.4			0.2			33.9
Reclassification due to adoption of ASU 2018-02	—			(6.3		)	(3.2		)	(9.5		)
Balance as of March 31, 2018	$	(1.5	)	$	(0.3	)	$	(17.2	)	$	(19.0	)

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

19.    Other, Net

Three Months Ended March 31, (in millions)	2019			2018
Interest Income	$	2.1		$	1.7
AFUDC Equity	1.7			3.7
Pension and other postretirement non-service cost	(2.8		)	6.2
Interest rate swap settlement gain	—			21.2
Miscellaneous	(1.7		)	(1.5		)
Total Other, net	$	(0.7	)	$	31.3

20.    Business Segment Information

At March 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.

36

Table of Contents

ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

The following table provides information about our business 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.

 

	Three Months Ended March 31,
(in millions)	2019			2018
Operating Revenues
Gas Distribution Operations
Unaffiliated	$	1,438.8		$	1,327.3
Intersegment	3.3			3.3
Total	1,442.1			1,330.6
Electric Operations
Unaffiliated	430.8			423.3
Intersegment	0.2			0.2
Total	431.0			423.5
Corporate and Other
Unaffiliated	0.2			0.2
Intersegment	111.1			114.1
Total	111.3			114.3
Eliminations	(114.6		)	(117.6		)
Consolidated Operating Revenues	$	1,869.8		$	1,750.8
Operating Income
Gas Distribution Operations	$	275.4		$	321.7
Electric Operations	95.0			83.1
Corporate and Other	3.8			(4.2		)
Consolidated Operating Income	$	374.2		$	400.6

37

Table of Contents

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

NiSource Inc.

Index	Page
Executive Summary	39
Summary of Consolidated Financial Results	40
Results and Discussion of Segment Operations	41
Gas Distribution Operations	42
Electric Operations	45
Liquidity and Capital Resources	48
Off Balance Sheet Arrangements	50
Market Risk Disclosures	50
Other Information	51

38

Table of Contents

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)

NiSource Inc.

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 Annual Report on Form 10-K for the fiscal year ended December 31, 2018.

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 of our Annual Report on Form 10-K for the fiscal year ended December 31, 2018 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, 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. 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.

Greater Lawrence Incident: The Greater Lawrence Incident occurred on September 13, 2018. During the quarter ended March 31, 2019, we recorded a loss of approximately $204 million for third-party claims and approximately $32 million for other incident-related expenses in connection with the Greater Lawrence Incident. The amounts set forth above do not include the estimated capital cost of the pipeline replacement described below and as set forth in Note 17- D, "Other Matters - Greater Lawrence Pipeline Replacement," in the Notes to Condensed Consolidated Financial Statements (unaudited).

Including the $757 million recorded during 2018, we estimate that total costs related to third-party claims as set forth in Note 17, "Other Commitments and Contingencies - B. Legal Proceedings," will range from $961 million to $1,010 million, depending on the final outcome of ongoing reviews and the number, nature and value of third-party claims. We expect to incur a total of $360 million to $370 million in other incident-related costs, inclusive of the $266 million recorded during 2018.

We also expect to incur expenses for which we cannot estimate the amounts of or the timing at this time, including expenses associated with government investigations and fines, penalties or settlements with governmental authorities in connection with the Greater Lawrence Incident.

Columbia of Massachusetts recorded $100 million to accounts receivable for insurance recoveries during the first quarter of 2019 in addition to the $135 million recorded during 2018. As of March 31, 2019, $113 million had been collected, of which $108 million was collected during the three months ended March 31, 2019. Additional collections of insurance proceeds in the amount of $22 million were received subsequent to the March 31, 2019 balance sheet date. We are currently unable to predict the amount and timing of future insurance recoveries. To the extent that we are not successful in collecting reimbursement in the amount recorded for such recoveries as of March 31, 2019, it could result in a charge to earnings.

Since the Greater Lawrence Incident and through March 31, 2019, we have incurred approximately $177 million of capital spend for the pipeline replacement, of which approximately $10 million was incurred in 2019. We estimate this replacement work will cost between $240 million and $250 million in total. Columbia of Massachusetts has provided notice to its property insurer of the Greater Lawrence Incident and discussions around the claim and recovery have commenced. The recovery of any capital investment not reimbursed through insurance will be addressed in a future regulatory proceeding. The outcome of such a proceeding is uncertain. If at any point Columbia of Massachusetts concludes it is probable that any portion of this capital investment is not recoverable through customer rates, that portion of the capital investment, if estimable, would be immediately charged to earnings.

Refer to Note 17-B and D, "Legal Proceedings" and "Other Matters," in the Notes to Condensed Consolidated Financial Statements (unaudited), "Summary of Consolidated Financial Results," "Results and Discussion of Segment Operation - Gas Distribution

39

Table of Contents

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)

NiSource Inc.

Operations," and "Liquidity and Capital Resources" in this Management's Discussion for additional information related to the Greater Lawrence Incident.

Summary of Consolidated Financial Results

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 are not necessarily comparable to similarly titled measures reported by other companies.

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

	Three Months Ended March 31,
(in millions)	2019		2018		2019 vs. 2018
Operating Income	$	374.2	$	400.6	$	(26.4	)

	Three Months Ended March 31,
(in millions, except per share amounts)	2019			2018			2019 vs. 2018
Operating Revenues	$	1,869.8		$	1,750.8		$	119.0
Cost of Sales (excluding depreciation and amortization)	680.3			724.4			(44.1		)
Total Net Revenues	1,189.5			1,026.4			163.1
Other Operating Expenses	815.3			625.8			189.5
Operating Income	374.2			400.6			(26.4		)
Total Other Deductions, net	(96.3		)	(61.8		)	(34.5		)
Income Taxes	59.0			62.7			(3.7		)
Net Income	218.9			276.1			(57.2		)
Preferred dividends	(13.8		)	—			(13.8		)
Net Income Available to Common Shareholders	205.1			276.1			(71.0		)
Basic Earnings Per Share	$	0.55		$	0.82		$	(0.27	)
Basic Average Common Shares Outstanding	373.4			338.0			35.4

On a consolidated basis, we reported net income available to common shareholders of $205.1 million, or $0.55 per basic share for the three months ended March 31, 2019, compared to net income available to common shareholders of $276.1 million, or $0.82 per basic share for the same period in 2018. The decrease in income available to common shareholders during 2019 was primarily due to greater operating expenses related to the Greater Lawrence Incident, an interest rate swap settlement gain in 2018 and dilution resulting from preferred stock dividend commitments, partially offset by new rates from base rate proceedings and infrastructure replacement programs.

Operating Income

For the three months ended March 31, 2019, we reported operating income of $374.2 million compared to operating income of $400.6 million for the same period in 2018. The decrease in operating income was primarily due to expenses related to the Greater Lawrence Incident and increased depreciation and amortization expense. These decreases were partially offset by new rates from base rate proceedings and infrastructure replacement programs along with favorable effects on revenue from year-over-year weather variations.

40

Table of Contents

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)

NiSource Inc.

Other Deductions, net

Other deductions, net reduced income by $96.3 million in the first quarter of 2019 compared to a reduction in income of $61.8 million in the prior year. This change is primarily due to an interest rate swap settlement gain of $21.2 million recognized in the first quarter of 2018.

Income Taxes

The decrease in income tax expense from 2018 to 2019 is primarily attributable to the decreased income before income taxes in the first quarter of 2019, partially offset by a higher effective tax rate in 2019 due to the relative impact of permanent differences on higher estimated pre-tax income in 2019 compared to 2018.

Refer to Note 12, "Income Taxes," in the Notes to Condensed Consolidated Financial Statements (unaudited) for information on income taxes and the change in the effective tax rate.

Capital Investment

For the three months ended March 31, 2019, we invested $353.7 million in capital expenditures across our 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 a total of approximately $1.6 to $1.7 billion in capital during 2019 to continue to modernize and improve our system across all seven states.

Liquidity

The enactment of the TCJA has and will continue to have an unfavorable impact on our liquidity in 2019; however, 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 and our ability to access the capital markets, we believe there is adequate capital available to fund our operating activities, capital expenditures and the effects of the Greater Lawrence Incident in 2019 and beyond. As of March 31, 2019 and December 31, 2018, we had $1,010.8 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

During the quarter ended March 31, 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 7, "Regulatory Matters" and Note 17-D "Other Matters," in the Notes to Condensed Consolidated Financial Statements (unaudited) for a complete discussion of key regulatory developments that have 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.

41

Table of Contents

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)

NiSource Inc.

Gas Distribution Operations

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

	Three Months Ended March 31,
(in millions)	2019		2018	2019 vs. 2018
Operating Income	$	275.4	321.7	$	(46.3	)

	Three Months Ended March 31,
(in millions)	2019			2018			2019 vs. 2018
Net Revenues
Operating Revenues	$	1,442.1		$	1,330.6		$	111.5
Less: Cost of sales (excluding depreciation and amortization)	550.1			591.8			(41.7		)
Net Revenues	892.0			738.8			153.2
Operating Expenses
Operation and maintenance	451.3			287.2			164.1
Depreciation and amortization	97.4			70.7			26.7
Other taxes	67.9			59.2			8.7
Total Operating Expenses	616.6			417.1			199.5
Operating Income	$	275.4		$	321.7		$	(46.3	)
Revenues
Residential	$	976.0		$	893.0		$	83.0
Commercial	331.6			308.9			22.7
Industrial	83.0			74.7			8.3
Off-System	20.1			22.3			(2.2		)
Other	31.4			31.7			(0.3		)
Total	$	1,442.1		$	1,330.6		$	111.5
Sales and Transportation (MMDth)
Residential	140.7			135.1			5.6
Commercial	86.0			82.2			3.8
Industrial	148.1			145.5			2.6
Off-System	7.2			7.6			(0.4		)
Other	0.2			0.1			0.1
Total	382.2			370.5			11.7
Heating Degree Days	2,897			2,823			74
Normal Heating Degree Days	2,864			2,892			(28		)
% Colder (Warmer) than Normal	1		%	(2		)%
Gas Distribution Customers
Residential	3,206,016			3,179,647			26,369
Commercial	282,616			281,503			1,113
Industrial	6,035			6,244			(209		)
Other	3			5			(2		)
Total	3,494,670			3,467,399			27,271

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.

42

Table of Contents

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)

NiSource Inc.

Gas Distribution Operations

Three Months Ended March 31, 2019 vs. March 31, 2018 Operating Income

For the three months ended March 31, 2019, Gas Distribution Operations reported operating income of $275.4 million, a decrease of $46.3 million from the comparable 2018 period.

Net revenues for the three months ended March 31, 2019 were $892.0 million, an increase of $153.2 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 $100.1 million.

• Higher regulatory, tax and depreciation trackers, which are offset in operating expense, of $25.2 million.

• Higher revenues of $5.1 million from the effects of colder weather in 2019 as well as a decrease in the weather-related normal heating degree day methodology resulting in an favorable variance of $4.7 million, as discussed below.

• Increased customer growth and usage of $6.6 million.

• Adjustments to the revenue reserve for the probable future refund of certain collections from customers as a result of the lower income tax rate from the TCJA of $6.1 million.

Operating expenses were $199.5 million higher for the three months ended March 31, 2019 compared to the same period in 2018. This change was primarily driven by:

• Expenses related to third-party claims and other costs following the Greater Lawrence Incident of $135.6 million, net of insurance recoveries recorded.

• Increased depreciation of $26.7 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 $25.2 million.

• Increased property taxes of $5.9 million due to higher capital expenditures placed in service and increased amortization of property taxes previously deferred as a regulatory asset.

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 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 the first quarter of 2019 was about 1% colder than normal and about 3% colder than 2018, leading to increased net revenues of $9.8 million for the quarter ended March 31, 2019 compared to the same period in 2018 in total. The change in weather-related net revenues was primarily driven by:

• The effects of colder weather in 2019 of $5.1 million.

• A decrease in the weather-related normal heating degree day methodology resulting in a favorable variance of $4.7 million, as discussed above.

Throughput

Total volumes sold and transported for the three months ended March 31, 2019 were 382.2 MMDth, compared to 370.5 MMDth for the same period in 2018. This 3% increase is primarily attributable to the effects of colder weather and increased industrial usage due to energy production from electric generating customers in 2019.

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

43

Table of Contents

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)

NiSource Inc.

Gas Distribution Operations

recorded on the Condensed Consolidated Balance Sheets (unaudited) as under-recovered or over-recovered gas cost to be included in future customer billings.

Certain Gas Distribution Operations companies continue to offer choice opportunities, where customers can choose to purchase gas from a third-party supplier, through regulatory initiatives in their respective jurisdictions. These programs serve to further reduce our exposure to gas prices.

44

Table of Contents

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)

NiSource Inc.

Electric Operations

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

	Three Months Ended March 31,
(in millions)	2019		2018		2019 vs. 2018
Operating Income	$	95.0	$	83.1	$	11.9

	Three Months Ended March 31,
(in millions)	2019		2018		2019 vs. 2018
Net Revenues
Operating revenues	$	431.0	$	423.5	$	7.5
Less: Cost of sales (excluding depreciation and amortization)	130.1		132.7		(2.6		)
Net Revenues	300.9		290.8		10.1
Operating Expenses
Operation and maintenance	121.7		126.2		(4.5		)
Depreciation and amortization	68.2		65.5		2.7
Other taxes	16.0		16.0		—
Total Operating Expenses	205.9		207.7		(1.8		)
Operating Income	$	95.0	$	83.1	$	11.9
Revenues
Residential	$	118.8	$	114.5	$	4.3
Commercial	119.3		116.9		2.4
Industrial	163.5		162.7		0.8
Wholesale	2.7		4.7		(2.0		)
Other	26.7		24.7		2.0
Total	$	431.0	$	423.5	$	7.5
Sales (Gigawatt Hours)
Residential	792.4		788.4		4.0
Commercial	894.4		905.7		(11.3		)
Industrial	2,215.7		2,333.8		(118.1		)
Wholesale	6.5		50.8		(44.3		)
Other	34.5		33.2		1.3
Total	3,943.5		4,111.9		(168.4		)
Electric Customers
Residential	412,739		409,962		2,777
Commercial	56,703		56,175		528
Industrial	2,281		2,300		(19		)
Wholesale	732		739		(7		)
Other	2		2		—
Total	472,457		469,178		3,279

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.

45

Table of Contents

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)

NiSource Inc.

Electric Operations

Three Months Ended March 31, 2019 vs. March 31, 2018 Operating Income

For the three months ended March 31, 2019, Electric Operations reported operating income of $95.0 million, an increase of $11.9 million from the comparable 2018 period.

Net revenues for the three months ended March 31, 2019 were $300.9 million, an increase of $10.1 million from the same period in 2018. The change in net revenues was primarily driven by:

• Higher rates driven by incremental capital spend on infrastructure replacement of $4.3 million.

• Decreased fuel handling costs of $3.4 million.

• Higher regulatory and depreciation trackers, which are offset in operating expense, of $2.7 million.

• The effects of colder weather of $2.5 million.

Partially offset by:

• Decreased residential and industrial usage of $4.4 million.

Operating expenses were $1.8 million lower for the three months ended March 31, 2019 compared to the same period in 2018. This change was primarily driven by:

• Decreased employee and administrative costs of $4.9 million.

• Lower outside service costs of $3.5 million primarily related to the retirement of Bailly Generating Station Units 7 and 8 on May 31, 2018.

Partially offset by:

• Higher regulatory and depreciation trackers, which are offset in net revenues, of $2.7 million.

• Increased depreciation of $1.4 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 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 the first quarter of 2019 was about 2% colder than normal and about 4% colder than in 2018, resulting in increased net revenues of $2.5 million for the quarter ended March 31, 2019 compared to the same period in 2018.

Sales

Electric Operations sales for the first quarter of 2019 were 3943.5 gwh, a decrease of 168.4 gwh compared to the same period in 2018. This decrease was primarily attributable to higher internal generation from large industrial customers during the first quarter of 2019.

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 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,

46

Table of Contents

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)

NiSource Inc.

Electric Operations

2019. Refer to Note 7, "Regulatory Matters," in the Notes to Condensed Consolidated Financial Statements (unaudited) 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 Condensed Consolidated Balance Sheets (unaudited) as under-recovered or over-recovered fuel cost to be included in future customer billings.

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.

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 17-D, "Other Matters," in the Notes to Condensed Consolidated Financial Statements (unaudited) for additional information on the NIPSCO Integrated Resource Plan.

47

Table of Contents

ITEM 2. 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 "Executive Summary" and Note 17, “Other Commitments and Contingencies,” we have recorded losses 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 and Note 17 referenced earlier in this paragraph we may incur additional expenses and liabilities in excess of our recorded liabilities and estimated additional costs associated with the Greater Lawrence Incident. The timing and amount of future financing needs, if any, will depend on the ultimate timing and amount of payments made to third parties in connection with the Greater Lawrence Incident and the timing and amount of associated insurance recoveries. 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 and our ability to access the capital markets, we believe there is adequate capital available to fund these expenditures.

Operating Activities

Net cash from operating activities for the three months ended March 31, 2019 was $399.1 million, an increase of $10.9 million compared to the three months ended March 31, 2018. This increase was driven by decreased compensation and employee benefit payments as well as decreased debt interest payments. The increase was also a result of higher revenue due to colder weather during the 2019 winter heating season compared to 2018 and increased rates from infrastructure replacement programs. Offsetting these cash inflows are a year-over-year increase in net payments made related to the Greater Lawrence Incident. During 2019, we paid approximately $73 million, net of insurance recoveries, in operating cash flow related to the Greater Lawrence Incident. Refer to Note 17-D "Other Matters" in the Notes to Condensed Consolidated Financial Statements (unaudited) for further information.

Investing Activities

Net cash used for investing activities for the three months ended March 31, 2019 was $375.4 million, a decrease of $23.5 million compared to the three months ended March 31, 2018. This decrease was mostly attributable to lower capital expenditures in 2019.

Our capital expenditures for the three months ended March 31, 2019 were $353.7 million compared to $370.0 million for the comparable period in 2018. The decrease was driven by a decrease in planned capital expenditures in the current year and the timing of payments through March 2019 compared to March 2018. We project total 2019 capital expenditures to be approximately $1.6 to $1.7 billion.

Financing Activities

Common Stock and Preferred Stock. Refer to Note 5, “Equity,” in the Notes to Condensed Consolidated Financial Statements (unaudited) for information on common and preferred stock activity.

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

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

Net Available Liquidity. As of March 31, 2019, an aggregate of $1,010.8 million of net liquidity was available, including cash and credit available under the revolving credit facility and accounts receivable securitization programs.

48

Table of Contents

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)

NiSource Inc.

The following table displays our liquidity position as of March 31, 2019 and December 31, 2018:

(in millions)	March 31, 2019		December 31, 2018
Current Liquidity
Revolving Credit Facility	$	1,850.0	$	1,850.0
Accounts Receivable Program(1)	500.0		399.2
Less:
Commercial Paper	980.0		978.0
Accounts Receivable Program Utilized	500.0		399.2
Letters of Credit Outstanding Under Credit Facility	10.2		10.2
Add:
Cash and Cash Equivalents	151.0		112.8
Net Available Liquidity	$	1,010.8	$	974.6

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

Debt Covenants. We are subject to financial covenants 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 March 31, 2019, the ratio was 61.5%.

Sale of Trade Accounts Receivables. Refer to Note 10, “Transfers of Financial Assets,” in the Notes to Condensed Consolidated Financial Statements (unaudited) 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 March 31, 2019. There were no changes to the below credit ratings or outlooks since December 31, 2018.

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 rating 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 March 31, 2019, the collateral requirement that would be required in the event of a downgrade below the ratings trigger levels would amount to approximately $59.8 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 420,000,000 shares, $0.01 par value, of which 400,000,000 are common stock and 20,000,000 are preferred stock. As of March 31, 2019, 373,002,671 shares of common stock and 440,000 shares of preferred stock were outstanding.

Contractual Obligations. Aside from the previously referenced repayments of long-term debt and payments associated with the Greater Lawrence Incident, there were no material changes recorded during the three months ended March 31, 2019 to our contractual obligations as of December 31, 2018.

49

Table of Contents

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)

NiSource Inc.

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 17, “Other Commitments and Contingencies,” in the Notes to Condensed Consolidated Financial Statements (unaudited) for additional information about such arrangements.

With the adoption of ASC 842, Leases, on January 1, 2019, all operating leases with terms greater than one year are now recorded on the balance sheet. Refer to Note 2, "Recent Accounting Pronouncements," for additional information.

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 ratemaking 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 ratemaking 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 8, "Risk Management Activities," in the Notes to Condensed Consolidated Financial Statements (unaudited) for further information on our commodity price risk assets and liabilities as of March 31, 2019 or December 31, 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, accounts receivable programs and term loan, which have interest rates that are indexed to short-term market interest rates. Based upon average borrowings and debt obligations subject to fluctuations in short-term market interest rates, an increase (or decrease) in short-term interest rates of 100 basis points (1%) would have increased (or decreased) interest expense by $4.9 million and $3.0 million for the three months ended March 31, 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 8, "Risk Management Activities," in the Notes to Condensed Consolidated Financial Statements (unaudited) for further information on our interest rate risk assets and liabilities as of March 31, 2019 and December 31, 2018. 

50

Table of Contents

ITEM 2. 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 Estimates

Refer to Note 17, "Other Commitments and Contingencies," in the Notes to Condensed Consolidated Financial Statements (unaudited) for additional information about management judgment used in the development of estimates related to the Greater Lawrence Incident.

Recently Issued Accounting Pronouncements

Refer to Note 2, "Recent Accounting Pronouncements," in the Notes to Condensed Consolidated Financial Statements (unaudited) for additional information about recently issued and adopted accounting pronouncements.

51

Table of Contents

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

NiSource Inc.

For a discussion regarding quantitative and qualitative disclosures about market risk see “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Market Risk Disclosures.”

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Our chief executive officer and our chief financial officer are responsible for evaluating the effectiveness of our 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 us in reports that we file or submit under the Exchange Act is accumulated and communicated to our 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, our disclosure controls and procedures were effective to provide reasonable assurance that financial information was processed, recorded and reported accurately.

Changes in Internal Controls

There have been no changes in our internal control over financial reporting during the fiscal quarter covered by this report that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

52

PART II

ITEM 1. LEGAL PROCEEDINGS

NiSource Inc.

For a description of our legal proceedings, see Note 17-B, "Legal Proceedings," in the Notes to Condensed Consolidated Financial Statements (unaudited).

ITEM 1A. RISK FACTORS

Our operations and financial results are subject to various risks and uncertainties, including those disclosed in our most recent Annual Report on Form 10-K for the year ended December 31, 2018. There have been no material changes to such risk factors.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5. OTHER INFORMATION

None.

53

ITEM 6. EXHIBITS

NiSource Inc.

(10.1)	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).
(10.2)	Amended and Restated NiSource Inc. Employee Stock Purchase Plan adopted as of February 1, 2019 (incorporated by reference to Exhibit C to the NiSource Inc. Definitive Proxy Statement to Stockholders for the Annual Meeting to be held on May 7, 2019, filed on April 1, 2019).
(10.3)	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).
(31.1)	Certification of Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.*
(31.2)	Certification of Chief Financial Officer pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.*
(32.1)	Certification of Chief Executive Officer pursuant to 18. U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith).*
(32.2)	Certification of Chief Financial Officer pursuant to 18. U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith).*
(101.INS)	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)	XBRL Schema Document
(101.CAL)	XBRL Calculation Linkbase Document
(101.LAB)	XBRL Labels Linkbase Document
(101.PRE)	XBRL Presentation Linkbase Document
(101.DEF)	XBRL Definition Linkbase Document
*	Exhibit filed herewith.

54

SIGNATURE

NiSource Inc.

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

			NiSource Inc.
			(Registrant)
Date:	May 1, 2019	By:	/s/ Joseph W. Mulpas
			Joseph W. Mulpas
			Vice President, Chief Accounting Officer and Controller (Principal Accounting Officer)

55

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 Quarterly Report of NiSource Inc. on Form 10-Q for the quarter ended March 31, 2019;

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(s) 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:	May 1, 2019	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 Quarterly Report of NiSource Inc. on Form 10-Q for the quarter ended March 31, 2019;

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(s) 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:	May 1, 2019	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 Quarterly Report of NiSource Inc. (the “Company”) on Form 10-Q for the quarter ending March 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 results of operations of the Company.

		/s/ Joseph Hamrock
		Joseph Hamrock
		President and Chief Executive Officer
Date:	May 1, 2019

EX-32.2

Exhibit 32.2

Certification Pursuant to

Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the Quarterly Report of NiSource Inc. (the “Company”) on Form 10-Q for the quarter ending March 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 results of operations of the Company.

		/s/ Donald E. Brown
		Donald E. Brown
		Executive Vice President and Chief Financial Officer
Date:	May 1, 2019

XML

Document And Entity Information - shares	3 Months Ended
	Mar. 31, 2019	Apr. 24, 2019
Document Information [Line Items]
Document Type	10-Q
Amendment Flag	false
Entity Emerging Growth Company	false
Entity Small Business	false
Document Period End Date	Mar. 31, 2019
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	Q1
Entity Registrant Name	NISOURCE INC/DE
Entity Central Index Key	0001111711
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		373,103,190

XML

Statements Of Consolidated Income - USD ($) shares in Thousands, $ in Millions		3 Months Ended
		Mar. 31, 2019	Mar. 31, 2018
Operating Revenues
Customer revenues	[1]	$ 1,834.5	$ 1,717.2
Other revenues		35.3	33.6
Total Operating Revenues		1,869.8	1,750.8
Operating Expenses
Cost of Sales (excluding depreciation and amortization)		680.3	724.4
Operation and maintenance		552.4	402.5
Depreciation and amortization		175.1	144.7
Loss (Gain) on sale of assets and impairments, net		0.2	(0.3)
Other taxes		87.6	78.9
Total Operating Expenses		1,495.6	1,350.2
Operating Income		374.2	400.6
Other Income (Deductions)
Interest expense, net		(95.6)	(93.1)
Other, net		(0.7)	31.3
Total Other Deductions, Net		(96.3)	(61.8)
Income before Income Taxes		277.9	338.8
Income Taxes		59.0	62.7
Net Income		218.9	276.1
Preferred dividends		(13.8)	0.0
Net Income Available to Common Shareholders		$ 205.1	$ 276.1
Earnings Per Share
Basic Earnings Per Share		$ 0.55	$ 0.82
Diluted Earnings Per Share		$ 0.55	$ 0.81
Basic Average Common Shares Outstanding		373,356	338,012
Diluted Average Common Shares		374,656	338,991

[1] Customer revenue amounts exclude intersegment revenues. See Note 20, "Business Segment Information," for discussion of intersegment revenues.

XML

Statements of Consolidated Comprehensive Income - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2019	Mar. 31, 2018
Net Income		$ 218.9	$ 276.1
Other comprehensive income (loss):
Net unrealized gain (loss) on available-for-sale securities	[1]	2.8	(1.7)
Net unrealized gain (loss) on cash flow hedges	[2]	(19.3)	35.4
Unrecognized pension and OPEB benefit	[3]	0.9	0.2
Total other comprehensive income (loss)	[4]	(15.6)	33.9
Comprehensive Income		$ 203.3	$ 310.0

[1] Net unrealized gain (loss) on available-for-sale securities, net of $0.7 million tax expense and $0.4 million tax benefit in the first quarter of 2019 and 2018, respectively.

[2] Net unrealized gain (loss) on cash flow hedges, net of $6.5 million tax benefit and $11.7 million tax expense in the first quarter of 2019 and 2018, respectively.

[3] Unrecognized pension and OPEB benefit, net of $0.4 million and $0.1 million tax expense in the first quarter of 2019 and 2018, respectively.

[4] All amounts are net of tax. Amounts in parentheses indicate debits.

XML

Statements of Consolidated Comprehensive Income (Parenthetical) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Other Comprehensive Income (Loss), Securities, Available-for-Sale, Unrealized Holding Gain (Loss) Arising During Period, Tax	$ (0.7)	$ 0.4
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Tax	6.5	(11.7)
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, Tax	$ (0.4)	$ (0.1)

XML

Statements of Consolidated Balance Sheets - USD ($) $ in Millions		Mar. 31, 2019	Dec. 31, 2018
Property, Plant and Equipment
Utility Plant		$ 23,079.7	$ 22,780.8
Accumulated depreciation and amortization		(7,356.9)	(7,257.9)
Net utility plant		15,722.8	15,522.9
Other property, at cost, less accumulated depreciation		18.6	19.6
Net Property, Plant and Equipment		15,741.4	15,542.5
Investments and Other Assets
Unconsolidated affiliates		2.1	2.1
Other investments		208.5	204.0
Total Investments and Other Assets		210.6	206.1
Current Assets
Cash and cash equivalents		151.0	112.8
Restricted Cash		9.8	8.3
Accounts receivable (less reserve of $31.4 and $21.1, respectively)		1,132.1	1,058.5
Gas inventory		75.1	286.8
Materials and supplies, at average cost		107.3	101.0
Electric production fuel, at average cost		33.3	34.7
Exchange gas receivable		72.1	88.4
Regulatory assets		190.9	235.4
Prepayments and other		144.2	129.5
Total Current Assets		1,915.8	2,055.4
Other Assets
Regulatory assets		1,979.4	2,002.1
Goodwill		1,690.7	1,690.7
Intangible assets, net		218.0	220.7
Deferred charges and other		134.0	86.5
Total Other Assets		4,022.1	4,000.0
Total Assets		21,889.9	21,804.0
Stockholders' Equity
Common stock - $0.01 par value, 400,000,000 shares authorized; 373,002,671 and 372,363,656 shares outstanding, respectively		3.8	3.8
Preferred stock - $0.01 par value, 20,000,000 shares authorized; 440,000 shares outstanding		880.0	880.0
Treasury stock		(99.9)	(99.9)
Additional paid-in capital		6,406.5	6,403.5
Retained deficit		(1,358.0)	(1,399.3)
Accumulated other comprehensive loss	[1]	(52.8)	(37.2)
Total Stockholders' Equity		5,779.6	5,750.9
Long-term debt, excluding amounts due within one year		7,110.1	7,105.4
Total Capitalization		12,889.7	12,856.3
Current Liabilities
Current portion of long-term debt		51.4	50.0
Short-term borrowings		2,080.0	1,977.2
Accounts payable		675.2	883.8
Dividends payable - common stock		74.6	0.0
Dividends payable - preferred stock		19.4	0.0
Customer deposits and credits		152.6	238.9
Taxes accrued		232.8	222.7
Interest accrued		93.7	90.7
Exchange gas payable		15.5	85.5
Regulatory liabilities		152.1	140.9
Legal and environmental		18.9	18.9
Accrued compensation and employee benefits		111.0	149.7
Claims accrued		258.5	114.7
Other accruals		79.5	63.8
Total Current Liabilities		4,015.2	4,036.8
Other Liabilities
Risk management liabilities		55.8	46.7
Deferred income taxes		1,391.6	1,330.5
Deferred investment tax credits		10.8	11.2
Accrued insurance liabilities		84.5	84.4
Accrued liability for postretirement and postemployment benefits		377.3	389.1
Regulatory liabilities		2,488.3	2,519.1
Asset retirement obligations		358.4	352.0
Other noncurrent liabilities		218.3	177.9
Total Other Liabilities		4,985.0	4,910.9
Commitments and Contingencies		0.0	0.0
Total Capitalization and Liabilities		$ 21,889.9	$ 21,804.0

[1] All amounts are net of tax. Amounts in parentheses indicate debits.

XML

Statements of Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Mar. 31, 2019	Dec. 31, 2018
Accounts receivable less reserve	$ 31.4	$ 21.1
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	400,000,000	400,000,000
Common Stock, Shares, Outstanding	373,002,671	372,363,656
Preferred Stock, Par or Stated Value Per Share	$ 0.01
Preferred Stock, Shares Authorized	20,000,000
Preferred Stock, Shares Outstanding	440,000

XML

Statements Of Consolidated Cash Flows - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Operating Activities
Net Income	$ 218.9	$ 276.1
Adjustments to Reconcile Net Income to Net Cash from Operating Activities:
Depreciation and amortization	175.1	144.7
Deferred income taxes and investment tax credits	51.6	56.8
Other adjustments	6.5	(15.6)
Changes in Assets and Liabilities:
Components of working capital	(27.2)	(178.4)
Regulatory assets/liabilities	0.4	117.1
Deferred charges and other noncurrent assets	(58.3)	1.9
Other noncurrent liabilities	32.1	(14.4)
Net Cash Flows from Operating Activities	399.1	388.2
Investing Activities
Capital expenditures	(353.7)	(370.0)
Cost of removal	(25.3)	(19.0)
Other investing activities	3.6	(9.9)
Net Cash Flows used for Investing Activities	(375.4)	(398.9)
Financing Activities
Repayments of long-term debt and capital lease obligations	(2.3)	(279.0)
Premiums and other debt related costs	(4.0)	0.0
Repayment of Short-term Debt (maturity greater than 90 days)	(350.0)	0.0
Change in short-term borrowings, net (maturity ≤ 90 days)	452.8	361.6
Issuance of common stock	3.1	3.7
Acquisition of treasury stock	0.0	(3.6)
Dividends paid - common stock	(74.5)	(65.7)
Dividends paid - preferred stock	9.1	0.0
Net Cash Flows from Financing Activities	16.0	17.0
Change in cash, cash equivalents and restricted cash	39.7	6.3
Cash, cash equivalents and restricted cash at beginning of period	121.1	38.4
Cash, Cash Equivalents and Restricted Cash at End of Period	$ 160.8	$ 44.7

XML

Statements Of Consolidated Cash Flows (Supplemental Disclosures of Cash Flow Information) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Supplemental Cash Flow [Abstract]
Capital Expenditures Incurred but Not yet Paid	$ 123.7	$ 145.4
Dividends declared but not paid	94.0	65.8
Reclassification of other property to regulatory assets	$ 0.0	$ 142.3

XML

Statements Of Consolidated 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, 2017	$ 4,320.1	$ 3.4			$ (95.9)	$ 5,529.1	$ (1,073.1)	$ (43.4)
Comprehensive Income:
Net Income	276.1	0.0			0.0	0.0	276.1	0.0
Other comprehensive loss, net of tax	33.9	0.0			0.0	0.0	0.0	33.9
Dividends:
Common stock	(131.7)	0.0			0.0	0.0	(131.7)	0.0
Treasury stock acquired	(3.6)	0.0			(3.6)	0.0	0.0	0.0
Stock Issuances:
Employee stock purchase plan	1.2	0.0			0.0	1.2	0.0	0.0
Long-term incentive plan	4.0	0.0			0.0	4.0	0.0	0.0
401(k) and profit sharing	6.2	0.0			0.0	6.2	0.0	0.0
Ending balance at Mar. 31, 2018	4,506.2	3.4			(99.5)	5,540.5	(919.2)	(19.0)
Dividends:
Cumulative Effect of New Accounting Principle in Period of Adoption | Accounting Standards Update 2018-02	0.0	0.0			0.0	0.0	(9.5)	9.5
Beginning balance at Dec. 31, 2018	5,750.9	3.8	$ 880.0		(99.9)	6,403.5	(1,399.3)	(37.2)
Comprehensive Income:
Net Income	218.9	0.0	0.0	[1]	0.0	0.0	218.9	0.0
Other comprehensive loss, net of tax	(15.6)	0.0	0.0	[1]	0.0	0.0	0.0	(15.6)
Dividends:
Common stock	(149.1)	0.0	0.0	[1]	0.0	0.0	(149.1)	0.0
Preferred stock	(28.5)	0.0	0.0	[1]	0.0	0.0	(28.5)	0.0
Stock Issuances:
Employee stock purchase plan	1.3	0.0	0.0	[1]	0.0	1.3	0.0	0.0
Long-term incentive plan	(2.7)	0.0	0.0	[1]	0.0	(2.7)	0.0	0.0
401(k) and profit sharing	4.4	0.0	0.0	[1]	0.0	4.4	0.0	0.0
Ending balance at Mar. 31, 2019	$ 5,779.6	$ 3.8	$ 880.0	[1]	$ (99.9)	$ 6,406.5	$ (1,358.0)	$ (52.8)

[1] Series A and Series B shares have an aggregate liquidation preference of $400M and $500M, respectively. See Note 5, "Equity" for additional information.

XML

Statements of Consolidated Equity (Shares) (Parenthetical) - shares shares in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Beginning balance	(372,363)	(337,016)
Treasury Stock acquired		(149)
Issued:
Employee stock purchase plan	50	47
Long-term incentive plan	426	420
401(k) and profit sharing	164	264
Ending balance	(373,003)	(337,598)
Preferred Stock
Beginning balance	(420)
Issued:
Preferred stock	20
Employee stock purchase plan	0
Long-term incentive plan	0
401(k) and profit sharing	0
Ending balance	(440)
Common Stock
Beginning balance	(376,326)	(340,813)
Issued:
Employee stock purchase plan	50	47
Long-term incentive plan	426	420
401(k) and profit sharing	164	264
Ending balance	(376,966)	(341,544)
Treasury Stock
Beginning balance	(3,963)	(3,797)
Treasury Stock acquired		(149)
Issued:
Employee stock purchase plan	0	0
Long-term incentive plan	0	0
401(k) and profit sharing	0	0
Ending balance	(3,963)	(3,946)

XML

Statements Of Consolidated Equity (Parenthetical) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Dividends Declared Per Share - Common	$ 0.400	$ 0.390
Series A Preferred Stock
Preferred Stock, Liquidation Preference, Value	$ 400
Series B Preferred Stock
Preferred Stock, Liquidation Preference, Value	$ 500

XML

Basis of Accounting Presentation

3 Months Ended

Mar. 31, 2019

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Basis of Accounting Presentation

Basis of Accounting Presentation

Our accompanying Condensed Consolidated Financial Statements (unaudited) reflect all normal recurring adjustments that are necessary, in the opinion of management, to present fairly the results of operations in accordance with GAAP in the United States of America. The accompanying financial statements contain our accounts and that of our majority-owned or controlled subsidiaries.

The accompanying financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2018. Income for interim periods may not be indicative of results for the calendar year due to weather variations and other factors.

The Condensed Consolidated Financial Statements (unaudited) have been prepared pursuant to the rules and regulations of the SEC. Certain information and note disclosures normally included in annual financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to those rules and regulations, although we believe that the disclosures made in this Quarterly Report on Form 10-Q are adequate to make the information herein not misleading.

XML

Recent Accounting Pronouncements

3 Months Ended

Mar. 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 Condensed Consolidated Financial Statements (unaudited) and Notes to Condensed Consolidated Financial Statements (unaudited), which are described below:

Standard	Description	Effective Date	Effect on the financial statements or other significant matters
ASU 2019-04, Codification Improvements to Topic 326, Financial Instruments-Credit Losses, Topic 815, Derivatives and Hedging, and Topic 825, Financial Instruments	The pronouncement clarifies and improves certain areas of guidance related to the recently issued standards on credit losses, hedging, and recognition and measurement. Topics 1, 2, and 5 of this update amends ASU 2016-13 as it relates to accrued interest, transfers between investment classifications, expected recoveries and reinsurance recoverables. Topic 3 improves guidance related to fair value hedges. Topic 4 of this update relates to codification improvements to ASU 2016-01.	Annual period ending after December 15, 2019, including interim periods therein. Early adoption is permitted.	We are currently evaluating the impact of codification improvements under Topics 1, 2, and 5 of this pronouncement, if any, on our Condensed Consolidated Financial Statements (unaudited) and Notes to Condensed Consolidated Financial Statements (unaudited). Topics 3 and 4 of this ASU are not material to us. We expect to adopt this ASU on its effective date.
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 Condensed Consolidated Financial Statements (unaudited). We expect to adopt this ASU on its effective date.

Standard	Description	Effective Date	Effect on the financial statements or other significant matters
ASU 2016-13,  Financial Instruments-Credit Losses (Topic 326)	The pronouncement changes the impairment model for most financial assets, replacing the current "incurred loss" model. ASU 2016-13 will require the use of an "expected loss" model for instruments measured at amortized cost. It will also require entities to record allowances for available-for-sale securities rather than impair the carrying amount of the securities. Subsequent improvements to the estimated credit losses of available-for-sale securities will be recognized immediately in earnings instead of over time as they are under historic guidance.	Annual periods beginning after December 15, 2019, including interim periods therein. Early adoption is permitted for annual or interim periods beginning after December 15, 2018.	We maintain investments in U.S. Treasury, corporate and mortgage-backed debt securities, which are pledged as collateral for trust accounts related to our wholly-owned insurance company. These debt securities are classified as available for sale. We also have recorded balances for trade receivables that fall within the scope of the standard. We are currently evaluating the impact of adoption, if any, on our Condensed Consolidated Financial Statements (unaudited) and Notes to Condensed Consolidated Financial Statements (unaudited). We 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)

XML

Revenue Recognition

3 Months Ended

Mar. 31, 2019

Revenue from Contract with Customer [Abstract]

Revenue from Contract with Customer

Revenue Recognition

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 tables below reconcile revenue disaggregation by customer class to segment revenue as well as to revenues reflected on the Condensed Statements of Consolidated Income (unaudited) for the three months ended March 31, 2019 and March 31, 2018:

Three Months Ended March 31, 2019 (in millions)	Gas Distribution Operations		Electric Operations		Corporate and Other		Total
Customer Revenues(1)
Residential	$	975.3	$	118.8	$	—	$	1,094.1
Commercial	330.5		119.3		—		449.8
Industrial	82.9		163.3		—		246.2
Off-system	20.1		—		—		20.1
Miscellaneous	17.2		6.9		0.2		24.3
Total Customer Revenues	$	1,426.0	$	408.3	$	0.2	$	1,834.5
Other Revenues	12.8		22.5		—		35.3
Total Operating Revenues	$	1,438.8	$	430.8	$	0.2	$	1,869.8

⁽¹⁾ Customer revenue amounts exclude intersegment revenues. See Note 20, "Business Segment Information," for discussion of intersegment revenues.

Three Months Ended March 31, 2018 (in millions)	Gas Distribution Operations		Electric Operations		Corporate and Other		Total
Customer Revenues(1)
Residential	$	893.6	$	114.5	$	—	$	1,008.1
Commercial	308.3		116.9		—		425.2
Industrial	74.6		162.5		—		237.1
Off-system	22.3		—		—		22.3
Miscellaneous	16.8		7.5		0.2		24.5
Total Customer Revenues	$	1,315.6	$	401.4	$	0.2	$	1,717.2
Other Revenues	11.7		21.9		—		33.6
Total Operating Revenues	$	1,327.3	$	423.3	$	0.2	$	1,750.8

⁽¹⁾ Customer revenue amounts exclude intersegment revenues. See Note 20, "Business Segment Information," for discussion of intersegment revenues.

Customer Accounts Receivable. Accounts receivable on our Condensed Consolidated Balance Sheets (unaudited) 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 three months ended March 31, 2019 are presented in the table below. We had no significant contract assets or liabilities during the period. Additionally, we have not incurred any significant costs to obtain or fulfill contracts.

(in millions)	Customer Accounts Receivable, Billed (less reserve)		Customer Accounts Receivable, Unbilled (less reserve)
Balance as of December 31, 2018	$	540.5	$	349.1
Balance as of March 31, 2019	692.2		284.6
Increase (Decrease)	$	151.7	$	(64.5	)

Utility revenues are billed to customers monthly on a cycle basis. We generally expect that substantially all customer accounts receivable will be collected within the month following customer billing, as this revenue consists primarily of monthly, tariff-based billings for service and usage. We maintain common utility credit risk mitigation practices, including requiring deposits and actively pursuing collection of past due amounts. 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. It is probable that substantially all of the consideration to which we are entitled from customers will be collected upon satisfaction of performance obligations.

XML

Earnings Per Share

3 Months Ended

Mar. 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 would be dilutive (See Note 5 "Equity"). The computation of diluted average common shares is as follows:

	Three Months Ended
	March 31,
(in thousands)	2019	2018
Denominator
Basic average common shares outstanding	373,356	338,012
Dilutive potential common shares:
Shares contingently issuable under employee stock plans	1,062	715
Shares restricted under employee stock plans	133	264
Forward Agreements	105	—
Diluted Average Common Shares	374,656	338,991

XML

Equity

3 Months Ended

Mar. 31, 2019

Equity [Abstract]

Equity

Equity

ATM Program and Forward Sale Agreement. On November 1, 2018, we entered into five separate equity distribution agreements, pursuant to which we may sell, from time to time, up to an aggregate value of $500.0 million of our common stock. The program expires on December 31, 2020.

On December 6, 2018, under the ATM program, we executed a forward agreement, which allows 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. We may settle this agreement in shares, cash, or net shares by December 6, 2019. Had we settled all the shares under the forward agreement at March 31, 2019, we would have received approximately $124.3 million, based on a net price of $26.40 per share.

As of March 31, 2019, the ATM program (including impacts of the forward sale agreement discussed above) had $309.4 million of equity available for issuance. We did not have any activity under the ATM program for the three months ended March 31, 2019.

Preferred Stock. As of March 31, 2019 we had 20,000,000 shares of preferred stock authorized for issuance, of which 440,000 shares of preferred stock were outstanding. The following table displays preferred dividends declared for the period by outstanding series of shares:

				Quarter Ended March 31, 2019		March 31, 2019		December 31, 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	$	28.25	$	393.9	$	393.9
6.500% Series B	$	25,000.00	20,000	$	862.15	$	486.1	$	486.1

In addition, 20,000 shares of Series B–1 Preferred Stock, par value $0.01 per share, were 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. Holders of Series B–1 Preferred Stock are not entitled to receive dividend payments and have no conversion rights. The Series B–1 Preferred Stock is paired with the Series B Preferred Stock and may not be transferred, redeemed or repurchased except in connection with the simultaneous transfer, redemption or repurchase of the underlying Series B Preferred Stock.

XML

Gas in Storage	3 Months Ended
	Mar. 31, 2019
Gas in Storage [Abstract]
Inventory Disclosure [Text Block]	Gas in StorageWe use both the LIFO inventory methodology and the weighted-average cost methodology to value natural gas in storage. Gas Distribution Operations prices natural gas storage injections at the average of the costs of natural gas supply purchased during the year. For interim periods, the difference between current projected replacement cost and the LIFO cost for quantities of gas temporarily withdrawn from storage is recorded as a temporary LIFO liquidation credit or debit within the Condensed Consolidated Balance Sheets (unaudited). Due to seasonality requirements, we expect interim variances in LIFO layers to be replenished by year end. We had a temporary LIFO liquidation debit of $21.5 million and zero as of March 31, 2019 and December 31, 2018, respectively, for certain gas distribution companies recorded within “Prepayments and other,” on the Condensed Consolidated Balance Sheets (unaudited).

XML

Regulatory Matters

3 Months Ended

Mar. 31, 2019

Regulatory Assets and Liabilities Disclosure [Abstract]

Regulatory Matters

Regulatory Matters

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

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

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

(in millions)
Company	Program	Incremental Revenue			Incremental Capital Investment		Investment Period	Filed	Status	Rates Effective
Columbia of Ohio	IRP - 2018(1)	$	(1.6	)	$	207.3	1/17-12/17	February 27, 2018	Approved April 25, 2018	May 2018
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(1)	74.5			659.9		1/11-12/17	December 1, 2017	Approved November 28, 2018	December 2018
Columbia of Ohio	CEP - 2019	16.1			122.1		1/18-12/18	February 28, 2019	Order Expected August 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	FMCA 1(3)	9.9			1.5		11/17-9/18	November 30, 2018	Approved March 27, 2019	April 2019
Columbia of Massachusetts	GSEP - 2019	10.7			64.0		1/19-12/19	October 31, 2018	Approved April 30, 2019	May 2019
Columbia of Virginia	SAVE - 2019	2.4			36.0		1/19-12/19	August 17, 2018	Approved October 26, 2018	January 2019
Columbia of Kentucky	AMRP - 2019	3.6			30.1		1/19-12/19	October 15, 2018	Approved December 5, 2018	January 2019
Columbia of Maryland	STRIDE - 2019	1.2			15.9		1/19-12/19	November 1, 2018	Approved December 12, 2018	January 2019
NIPSCO - Electric	TDSIC - 4(1)	(11.8		)	72.2		12/17-5/18	July 31, 2018	Approved November 28, 2018	December 2018
NIPSCO - Electric	TDSIC - 5(1)	15.9			58.8		6/18-11/18	January 29, 2019	Order Expected Q2 2019	June 2019
NIPSCO - Electric	ECRM - 32	1.0			—		1/18-6/18	July 31, 2018	Approved October 31, 2018	November 2018
NIPSCO - Electric	FMCA - 9(3)	4.1			90.2		10/17-3/18	April 27, 2018	Approved July 25, 2018	August 2018
NIPSCO - Electric	FMCA - 10(3)	2.2			45.7		4/18-8/18	October 18, 2018	Approved January 29, 2019	February 2019
NIPSCO - Electric	FMCA - 11(3)	0.9			22.4		9/18-2/19	April 17, 2019	Order Expected July, 2019	August 2019

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

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

⁽³⁾Incremental revenue is inclusive of tracker eligible operations and maintenance expense.

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 or Settled Incremental Revenue			Filed	Status	Rates Effective
NIPSCO - Gas(1)	$	138.1	$	107.3		September 27, 2017	Approved September 19, 2018	October 2018
Columbia of Virginia(2)	$	14.2	$	1.3		August 28, 2018	Settlement filed April 19, 2019, Order expected Second half of 2019	February 2019
NIPSCO - Electric(3)	$	21.4	$	(45.0	)	October 31, 2018	Partial settlement filed April 26, 2019, Order expected Second half of 2019	Second half of 2019

⁽¹⁾Rates will be 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 will be effective on January 1, 2020. The IURC’s order also dismissed NIPSCO from phase 2 of the IURC’s TCJA investigation.

⁽²⁾Rates implemented subject to refund. An order of the settlement agreement, including refunds to be issued and resolution of outstanding TCJA impacts to rates, is currently pending before the VSCC.

⁽³⁾An order on the partial settlement agreement, including the resolution of outstanding TCJA impacts to rates is currently pending before the IURC. The as-filed request and partial settlement agreement also includes $83.6 million and $85.3 million, respectively, of reductions to the fuel component of base rates related to a proposed change in service structure.

Additional Regulatory Matters

Columbia of Massachusetts. On December 21, 2018, the Massachusetts DPU issued an order approving the pass back of approximately $95.8 million in excess deferred taxes associated with TCJA with new rates effective on February 1, 2019.

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.

XML

Risk Management Activities

3 Months Ended

Mar. 31, 2019

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Risk Management Activities

Risk Management Activities

We are exposed to certain risks relating to our ongoing business operations, namely commodity price risk and interest rate risk. We recognize that the prudent and selective use of derivatives may help to lower our cost of debt capital, manage our interest rate exposure and limit volatility in the price of natural gas.

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

(in millions)	March 31, 2019		December 31, 2018
Risk Management Assets - Current(1)
Interest rate risk programs	$	5.6	$	—
Commodity price risk programs	0.9		1.1
Total	$	6.5	$	1.1
Risk Management Assets - Noncurrent(2)
Interest rate risk programs	$	—	$	18.5
Commodity price risk programs	6.9		4.4
Total	$	6.9	$	22.9
Risk Management Liabilities - Current(3)
Interest rate risk programs	$	—	$	—
Commodity price risk programs	4.4		5.0
Total	$	4.4	$	5.0
Risk Management Liabilities - Noncurrent
Interest rate risk programs	$	22.4	$	9.5
Commodity price risk programs	33.4		37.2
Total	$	55.8	$	46.7

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

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

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

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 may range from five to ten years and is limited to 20 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 March 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 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 Condensed Statements of Consolidated Income (unaudited).

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

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

XML

Fair Value

3 Months Ended

Mar. 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 Condensed Consolidated Balance Sheets (unaudited) on a recurring basis and their level within the fair value hierarchy as of March 31, 2019 and December 31, 2018:

 

Recurring Fair Value Measurements March 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 March 31, 2019
Assets
Risk management assets	$	—	$	13.4	$	—	$	13.4
Available-for-sale securities	—		138.2		—		138.2
Total	$	—	$	151.6	$	—	$	151.6
Liabilities
Risk management liabilities	$	—	$	60.2	$	—	$	60.2
Total	$	—	$	60.2	$	—	$	60.2

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 March 31, 2019 and December 31, 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 8, "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 8, “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 Condensed Consolidated Balance Sheets (unaudited). 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 March 31, 2019 and December 31, 2018 were: 

March 31, 2019 (in millions)	Amortized Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
Available-for-sale securities
U.S. Treasury debt securities	$	22.0	$	—	$	—		$	22.0
Corporate/Other debt securities	115.7		1.4		(0.9		)	116.2
Total	$	137.7	$	1.4	$	(0.9	)	$	138.2
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 three months ended March 31, 2019 and 2018.

The cost of maturities sold is based upon specific identification. At March 31, 2019, approximately $5.6 million of U.S. Treasury debt securities and approximately $3.6 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 three months ended March 31, 2019 and 2018.

Non-recurring Fair Value Measurements. There were no significant non-recurring fair value measurements recorded during the three months ended March 31, 2019.

B.    Other Fair Value Disclosures for Financial Instruments. The carrying amount of cash and cash equivalents, restricted cash, 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 three months ended March 31, 2019, 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: 

(in millions)	Carrying Amount as of March 31, 2019		Estimated Fair Value as of March 31, 2019		Carrying Amount as of Dec. 31, 2018		Estimated Fair Value as of Dec. 31, 2018
Long-term debt (including current portion)	$	7,161.5	$	7,533.6	$	7,155.4	$	7,228.3

XML

Transfers Of Financial Assets

3 Months Ended

Mar. 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 2019 and October 2019 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 Condensed Consolidated Balance Sheets (unaudited). As of March 31, 2019, the maximum amount of debt that could be recognized related to our accounts receivable programs is $500.0 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 March 31, 2019 and December 31, 2018:

 

(in millions)	March 31, 2019		December 31, 2018
Gross Receivables	$	742.7	$	694.4
Less: Receivables not transferred	242.7		295.2
Net receivables transferred	$	500.0	$	399.2
Short-term debt due to asset securitization	$	500.0	$	399.2

For the three months ended March 31, 2019 and 2018, $100.8 million and $176.7 million, respectively, 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 $0.8 million for the three months ended March 31, 2019 and 2018. We remain responsible for collecting on the receivables securitized, and the receivables cannot be transferred to another party.

XML

Goodwill

3 Months Ended

Mar. 31, 2019

Goodwill and Intangible Assets Disclosure [Abstract]

Goodwill

Goodwill

 The following presents our goodwill balance allocated by segment as of March 31, 2019:

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

We applied the qualitative "step 0" analysis to our reporting units for the annual impairment test performed as of May 1, 2018. For this test, we assessed various assumptions, events and circumstances that would have affected the estimated fair value of the reporting units as compared to their base line May 1, 2016 "step 1" fair value measurement. The results of this assessment indicated that it was not more likely than not that our reporting unit fair values were less than the reporting unit carrying values, accordingly, no "step 1" analysis was required.

XML

Income Taxes

3 Months Ended

Mar. 31, 2019

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

Our interim effective tax rates reflect the estimated annual effective tax rates for 2019 and 2018, adjusted for tax expense associated with certain discrete items. The effective tax rates for the three months ended March 31, 2019 and 2018 were 21.2% and 18.5%, respectively. These effective tax rates differ from the federal statutory tax rate of 21% primarily due to the effects of tax credits, state income taxes, the amortization of excess deferred federal income tax liabilities, as specified in the TCJA and in utility ratemaking proceedings and other permanent book-to-tax differences.

The increase in the three month effective tax rate of 2.7% in 2019 compared to 2018 is primarily due to the relative impact of permanent differences on higher estimated pre-tax income in 2019 compared to 2018.

There were no material changes recorded in 2019 to our uncertain tax positions as of December 31, 2018.

XML

Pension And Other Postretirement Benefits

3 Months Ended

Mar. 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. For most plans, cash contributions are remitted to grantor trusts.

For the three months ended March 31, 2019, we contributed $0.6 million to our pension plans and $5.7 million to our other postretirement benefit plans.

The following table provides the components of the plans’ actuarially determined net periodic benefit cost for the three months ended March 31, 2019 and 2018:

	Pension Benefits						Other Postretirement Benefits
Three Months Ended March 31, (in millions)	2019			2018			2019			2018
Components of Net Periodic Benefit (Income) Cost(1)
Service cost	$	7.3		$	7.9		$	1.3		$	1.3
Interest cost	18.2			16.6			4.8			4.4
Expected return on assets	(27.2		)	(36.3		)	(3.3		)	(3.7		)
Amortization of prior service credit	—			(0.1		)	(0.8		)	(1.0		)
Recognized actuarial loss	11.4			10.2			0.5			0.9
Total Net Periodic Benefit (Income) Cost	$	9.7		$	(1.7	)	$	2.5		$	1.9

⁽¹⁾The service cost component, and all non-service cost components, of net periodic benefit cost are presented in "Operation and maintenance" and "Other, net", respectively, on the Condensed Statements of Consolidated Income (unaudited).

XML

Long-Term Debt	3 Months Ended
	Mar. 31, 2019
Long-term Debt, Current and Noncurrent [Abstract]
Long-term Debt	Long-Term DebtOn April 1, 2019, NIPSCO redeemed $41.0 million of 5.85% pollution control bonds at maturity.

XML

Short-Term Borrowings

3 Months Ended

Mar. 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 March 31, 2019 and December 31, 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 $980.0 million and $978.0 million of commercial paper outstanding as of March 31, 2019 and December 31, 2018, respectively.

Transfers of accounts receivable are accounted for as secured borrowings resulting in the recognition of short-term borrowings on the Condensed Consolidated Balance Sheets (unaudited). We had $500.0 million in transfers as of March 31, 2019 and $399.2 million as of December 31, 2018. Refer to Note 10, "Transfers of Financial Assets," for additional information.

Short-term borrowings were as follows: 

(in millions)	March 31, 2019		December 31, 2018
Commercial paper weighted-average interest rate of 2.90% and 2.96% at March 31, 2019 and December 31, 2018, respectively	$	980.0	$	978.0
Accounts receivable securitization facility borrowings	500.0		399.2
Term loan weighted-average interest rate of 3.00% and 3.07% at March 31, 2019 and December 31, 2018, respectively	600.0		600.0
Total Short-Term Borrowings	$	2,080.0	$	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 Condensed Statements of Consolidated Cash Flows (unaudited) as their maturities are less than 90 days.

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.

XML

Leases

3 Months Ended

Mar. 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 Condensed Consolidated Balance Sheets (unaudited) as of January 1, 2019. The standard had no material impact on our Condensed Statements of Consolidated Income (unaudited) or our Condensed Statements of Consolidated Cash Flows (unaudited).

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 25 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 Condensed Consolidated Balance Sheets (unaudited) do not include obligations for possible fleet vehicle lease renewals beyond the initial lease term. While we have the ability to renew these leases beyond the initial term, we are not reasonably certain to do so.

We lease the majority of our IT assets under 4 year lease terms. Ownership of leased IT assets is transferred to us at the end of the lease term. We have not provided material residual value guarantees for our leases, nor do our leases contain material restrictions or covenants. Lease contracts containing renewal and termination options are mostly exercisable at our sole discretion. Certain of our real estate and railcar leases include renewal periods in the measurement of the lease obligation if we have deemed the renewals reasonably certain to be exercised.

With respect to service contracts involving the use of assets, if we have the right to direct the use of the asset and obtain substantially all economic benefits from the use of an asset, we account for the service contract as a lease. Unless specifically provided to us by the lessor, we utilize NiSource's collateralized incremental borrowing rate commensurate to the lease term as the discount rate for all of our leases.

The components of lease expense are presented in the following lines on the Condensed Statements of Consolidated Income (unaudited):

Three Months Ended March 31, (in millions)	Income Statement Classification	2019
Finance lease cost
Amortization of right-of-use assets	Depreciation and amortization	$	3.7
Interest on lease liabilities	Interest expense, net	2.9
Total finance lease cost(1)		6.6
Operating lease cost(2)	Operation and maintenance	3.7
Short-term lease cost	Operation and maintenance	0.7
Total lease cost		$	11.0

⁽¹⁾Total finance lease cost includes $0.6 million in costs that have been capitalized into Net Property, Plant and Equipment.

⁽²⁾Operating lease cost includes $0.3 million in costs that have been capitalized into Net Property, Plant and Equipment.

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

Three Months Ended March 31, (in millions)	Balance Sheet Classification	2019
Assets
Finance leases	Net Property, Plant and Equipment	$	179.8
Operating leases	Deferred charges and other	53.8
Total leased assets		233.6
Liabilities
Current
Finance leases	Current portion of long-term debt	10.4
Operating leases	Other accruals	9.3
Noncurrent
Finance leases	Long-term debt, excluding amounts due within one year	188.5
Operating leases	Other noncurrent liabilities	44.5
Total lease liabilities		$	252.7

Other pertinent information related to leases was as follows:

Three Months Ended March 31, (in millions)	2019
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows from finance leases	$	3.0
Operating cash flows from operating leases	3.7
Financing cash flows from finance leases	2.4
Right-of-use assets obtained in exchange for lease obligations
Finance leases	6.6
Operating leases	$	0.1

	March 31, 2019
Weighted-average remaining lease term (years)
Finance leases	15.8
Operating leases	10.1
Weighted-average discount rate
Finance leases	5.8	%
Operating leases	4.4	%

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

As of March 31, 2019, (in millions)	Total			Finance Leases			Operating Leases
Year 1	$	35.5		$	24.0		$	11.5
Year 2	31.8			23.7			8.1
Year 3	31.0			23.9			7.1
Year 4	28.8			22.7			6.1
Year 5	25.8			20.1			5.7
Thereafter	246.7			217.7			29.0
Total lease payments	399.6			332.1			67.5
Less: Imputed interest	(125.2		)	(111.5		)	(13.7		)
Less: Leases not yet commenced(1)	(21.7		)	(21.7		)	—
Total	252.7			198.9			53.8
Reported as of March 31, 2019
Short-term lease liabilities	19.7			10.4			9.3
Long-term lease liabilities	233.0			188.5			44.5
Total lease liabilities	$	252.7		$	198.9		$	53.8

⁽¹⁾ Expected payments include obligations for leases not yet commenced of approximately $21.7 million for interconnection facilities. The facilities will have a lease term of 10 years, with an estimated commencement in the second quarter of 2019.

Disclosures Related to Periods Prior to Adoption of ASC 842.

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.

XML

Other Commitments And Contingencies

3 Months Ended

Mar. 31, 2019

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Other Commitments and Contingencies

A. Guarantees and Indemnities. We and certain of our subsidiaries enter into various agreements providing financial or performance assurance to third parties on behalf of certain subsidiaries as a 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. As of March 31, 2019 and December 31, 2018, we had issued stand-by letters of credit of $10.2 million.  

 B. 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 service for approximately 7,500 gas meters, the majority of which serve residences and approximately 700 of which serve 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 “ - D. Other Matters - Greater Lawrence Pipeline Replacement” below for more information.

We are subject to inquiries by federal and state government authorities and regulatory agencies regarding the Greater Lawrence Incident. The NTSB, the U.S Attorney’s office and the SEC have pending investigations related to the Greater Lawrence Incident, as described below. We are also subject to inquiries from the Massachusetts DPU and the Massachusetts Attorney General’s Office. We are cooperating with all inquiries and investigations. The outcomes and impacts of the current investigations and any future investigations that may be commenced related to such inquiries are uncertain at this time.

NTSB Investigation. As noted above, the NTSB is investigating the Greater Lawrence Incident. The parties to the investigation include the PHMSA, the Massachusetts DPU, Columbia of Massachusetts, and the Massachusetts State Police. We are cooperating with the NTSB and have provided information to assist in its ongoing investigation into relevant facts related to the event, the probable cause, and its development of safety recommendations.

According to the preliminary public report that the NTSB issued on October 11, 2018, an over-pressurization of a low-pressure gas distribution system occurred that was related to work being done on behalf of Columbia of Massachusetts on a pipeline replacement project in Lawrence. According to the report, sensing lines detected a drop in pressure in a portion of mainline that was being abandoned, causing a regulator to open up and increase pressure in the system to a level that exceeded the maximum allowable operating pressure of the distribution system.

On November 14, 2018, the NTSB issued an urgent safety recommendation report regarding natural gas distribution system project development and review. In its report, the NTSB identified certain factors that it believes contributed to the Greater Lawrence Incident and made safety recommendations. The NTSB recommended that the Commonwealth of Massachusetts eliminate the

professional engineer licensure exemption for public utility work and require a professional engineer’s seal on public utility engineering drawings, which is now law in Massachusetts. The NTSB also made recommendations to us related to engineering plan and constructability review processes, records and documentation, management of change processes, and control procedures during modifications to gas mains. We are in the process of implementing these recommendations. The NTSB investigation is ongoing. While the NTSB investigation is pending, we are prohibited from disclosing information related to the investigation without approval from the NTSB.

Since the Greater Lawrence Incident, we have identified, and moved ahead with, new steps to enhance system safety and reliability and to safeguard against over-pressurization. Some of these measures have already been completed and others are in process. These Company-wide safety measures will include enhanced measures as called for in the NTSB’s recommendations. We have committed to a program to install over-pressurization protection devices on all of our low-pressure systems, which is described in “ - D. Other Matters.”

Massachusetts Regulatory and Legislative Matters. Under Massachusetts law, the DPU is authorized to investigate potential violations of pipeline safety regulations and to assess a civil penalty of up to $209,000 for a violation of federal pipeline safety regulations. A separate violation occurs for each day of violation up to $2.1 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, 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. The timing and outcome of any such investigations are uncertain at this time.

The Massachusetts DPU has 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 will direct all natural gas distribution companies operating in the Commonwealth to fund the statewide examination. The statewide examination is underway and we have responded to the evaluator’s information requests. The independent evaluator is expected to produce a report with recommendations. The examination is expected to complement, but not duplicate, the NTSB’s investigation.

On November 30, 2018, Columbia of Massachusetts entered into a consent order with the Massachusetts DPU in connection with a notice of probable violation issued in March 2018, stemming from a 2016 report. The Division found that Columbia of Massachusetts violated certain pipeline safety regulations related to pressure limiting and regulating stations in Taunton, Massachusetts. As part of the consent order, Columbia of Massachusetts was fined $75,000 and entered into a compliance agreement under which it agreed to take several actions related to its pressure regulator stations within various timeframes, including the adoption of a Pipeline Safety Management System ("SMS"), the American Petroleum Institute’s (API) Recommended Practice 1173. Columbia of Massachusetts is complying with the order.

On December 18, 2018, the Massachusetts DPU issued an order requiring Columbia of Massachusetts to enter into an agreement with a Massachusetts-based engineering firm to monitor Columbia of Massachusetts’ remaining restoration and recovery work in the Greater Lawrence area. The order requires Columbia of Massachusetts to take measures to ensure that adequate heat and hot water and gas appliances are provided to all affected properties, repave all affected streets, roadways, sidewalks and other areas in accordance with applicable DPU standards and precedents, consult with the affected communities and discuss plans for restoring affected hard or soft surfaces, and replace all gas boilers and furnaces and other gas-fired equipment at affected residences. Under the order, all restoration work beginning in 2019 is required to be completed no later than October 31, 2019, unless an earlier or later date is agreed to with any of the affected communities. We have agreed to complete the work by September 15, 2019. Also, under the order, Columbia of Massachusetts will be required to maintain quantitative measures, which must be verified by officials of the affected communities, to track its progress in completing all of the remaining work. Estimates for the cost of this work are included in the estimated ranges of loss noted below, which is discussed in “- D. Other Matters - Greater Lawrence Incident Restoration" and " - Greater Lawrence Pipeline Replacement” below. Our failure to adhere to any of the requirements in the order may result in penalties of up to $1 million per violation.

In December 2018, the President of Columbia of Massachusetts testified before a joint state legislative committee on telecommunications, utilities and energy with other industry officials about gas system safety in Massachusetts and regulatory oversight. Increased scrutiny related to these matters, including additional legislative oversight hearings and new legislative proposals, is expected to continue during the current two-year legislative session.

On December 31, 2018, the Massachusetts Governor signed into law legislation requiring a certified professional engineer to review and approve gas pipeline work that could pose a “material risk” to public safety, consistent with the NTSB’s recommendation.

The Massachusetts DPU has issued interim guidelines and the existing moratorium has been lifted. The DPU issued an Order Opening Inquiry (Notice of Inquiry) on March 18, 2019, and Columbia of Massachusetts has submitted comments.

U.S. Department of Justice Investigation. 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 for the District of Massachusetts. The initial grand jury subpoenas were served on the Company and Columbia of Massachusetts on September 24, 2018. The Company and Columbia of Massachusetts are cooperating with the investigation. We are unable to estimate the amount (or range of amounts) of reasonably possible losses associated with any civil or criminal penalties that could be imposed on the Company or Columbia of Massachusetts.

U.S. Congressional Hearing. In November 2018, executives of the Company and Columbia of Massachusetts testified at a U.S. Senate hearing regarding the Greater Lawrence Incident and natural gas pipeline safety. Increased scrutiny related to these matters, including additional federal congressional hearings and new legislative proposals, is expected to continue through 2019.

SEC Investigation. On February 11, 2019, the SEC notified the Company that it is conducting an investigation of the Company related to disclosures made prior to the Greater Lawrence Incident. We are cooperating with the investigation.

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 will be 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 May 13. 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. Many residents and business owners have submitted individual damage claims to Columbia of Massachusetts. We also have received notice from three parties indicating an intent to assert wrongful death claims. In Massachusetts, punitive damages are available in a wrongful death action upon proof of gross negligence or willful or reckless conduct causing the death. In addition, the Commonwealth of Massachusetts and the municipalities of Lawrence, Andover and North Andover are seeking reimbursement from Columbia of Massachusetts for their respective expenses incurred in connection with the Greater Lawrence Incident. The outcomes and impacts of the private actions are uncertain at this time. We are discussing potential settlements with the affected municipalities and certain of the wrongful death and bodily injury plaintiffs. On April 25, 2019, we entered into a settlement agreement with certain of these plaintiffs involving bodily injury claims, subject to certain conditions, including court approval.

Financial Impact. During the quarter ended March 31, 2019, we expensed approximately $204 million for estimated third-party claims related to the Greater Lawrence Incident, including, but not limited to, personal injury and property damage claims, damage to infrastructure and mutual aid payments to other utilities assisting with the restoration effort. Including the $757 million recorded during 2018, we estimate that total costs related to third-party claims resulting from the incident will range from $961 million to $1,010 million, depending on the final outcome of ongoing reviews and the number, nature, and value of third-party claims. The amounts set forth above do not include costs of certain third party claims that we are not able to estimate, non-claims related expenses resulting from the incident or the estimated capital cost of the pipeline replacement, which is set forth in " - D. Other Matters - Greater Lawrence Incident Restoration" and " - Greater Lawrence Pipeline Replacement," respectively, below.

The process for estimating costs associated with third-party claims relating to the Greater Lawrence Incident requires management to exercise significant judgment based on a number of assumptions and subjective factors. As more information becomes known, including additional information resulting from the NTSB investigation and private actions, management’s estimates and assumptions regarding the financial impact of the Greater Lawrence Incident may change. The increase in estimated total costs related to third-party claims from those disclosed in our Form 10-K for the year ended December 31, 2018 resulted primarily from receiving additional information regarding legal claims and the required scope of the restoration work inside the affected homes.

Expenses described above are presented within “Operation and maintenance” in our Statements of Consolidated Income.

We believe that it is reasonably possible that the total amount of the financial loss will be greater than the amount recorded, but we are unable to reasonably estimate the additional loss and the upper end of the range for the class action lawsuits and certain other private action claims because there are a number of unknown facts and legal considerations that may impact the amount of any potential liability, including the total scope and nature of claims that may be asserted against NiSource and Columbia of Massachusetts, whether certain claims can be brought as a class action, and the number of plaintiffs who may bring such claims.

We will continue to review the available information and other information as it becomes available, including evidence from or held by other parties, claims that have not yet been submitted, and additional information about the nature and extent of personal and business property damage and losses, the nature, number and severity of personal injuries, and information made available through the discovery process.

In addition, it is not possible at this timesub to reasonably estimate the total amount of any expenses associated with government investigations and fines, penalties or settlements with certain governmental authorities, including the Massachusetts DPU and other regulators, that we may incur in connection with the Greater Lawrence Incident. Therefore, the foregoing amounts do not include estimates of the total amount that we may incur for any such fines, penalties or settlements.

We maintain liability insurance for damages in the approximate amount of $800 million and property insurance for gas pipelines and other applicable property in the approximate amount of $300 million. Total expenses related to the incident have exceeded the total amount of insurance coverage available under our policies. While we believe that a substantial amount of expenses related to the Greater Lawrence Incident will be covered by insurance, insurers providing property and liability insurance to the Company or Columbia of Massachusetts are raising defenses to coverage under the terms and conditions of the respective insurance policies which contain various exclusions and conditions that could limit the amount of insurance proceeds to the Company or Columbia of Massachusetts. We are not able to estimate the amount of expenses that will not be covered by insurance, but these amounts are material to our financial statements. Certain types of damages, expenses or claimed costs, such as fines or penalties, may be excluded under the policies. An amount of $100 million for insurance recoveries was recorded during the quarter ended March 31, 2019 in addition to the $135 million of insurance recoveries that were recorded during 2018. As of March 31, 2019, $113 million had been collected, of which $108 million was collected during the three months ended March 31, 2019. Additional collections of insurance proceeds in the amount of $22 million were received subsequent to the March 31, 2019 balance sheet date. The remaining insurance receivable balance of $122 million as of March 31, 2019 is presented within “Accounts receivable.” To the extent that we are not successful in obtaining insurance recoveries in the amount recorded for such recoveries as of March 31, 2019, it could result in a charge against "Operation and maintenance" expense. We are currently unable to predict the timing of additional future insurance recoveries.

In addition, we are party to certain other claims and legal proceedings arising in the ordinary course of business, 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 or proceeding related to the Greater Lawrence Incident or otherwise would not have a material adverse effect on our results of operations, financial position or liquidity. If one or more of such 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.

C. 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 and remediation costs to be recoverable through rates for certain of our companies.

As of March 31, 2019 and December 31, 2018, we had recorded a liability of $99.7 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 Condensed Consolidated Balance Sheets (unaudited). 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 D, "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 increase methane leak detection, require emission reductions or impose additional requirements for natural gas facilities could restrict GHG emissions and impose additional costs. We carefully monitor all GHG reduction proposals and regulations.

CPP and ACE Rules. On October 23, 2015, the EPA issued the CPP to regulate CO₂ emissions from existing fossil-fuel EGUs under section 111(d) of the CAA. The U.S. Supreme Court has stayed implementation of the CPP until litigation is decided on its merits, and the EPA under the current administration has proposed to repeal the CPP. On August 31, 2018, the EPA published a proposal to replace the CPP with the ACE rule, which establishes guidelines for states to use when developing plans to reduce CO₂ emissions from existing coal-fired EGUs. The proposal would provide states three years after a final rule is issued to develop state-specific plans, and the EPA would have 12 months to act on a complete state plan submittal. Within two years after a finding of failure to submit a complete plan, or disapproval of a state plan, the EPA would issue a federal plan. 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 Condensed Consolidated Financial Statements (unaudited).

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, 2018. Our total estimated liability related to the facilities subject to remediation was $96.4 million and $97.5 million at March 31, 2019 and December 31, 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.

The publication of the CCR rule 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 compliance strategies that will be used and the preliminary nature of available data used to estimate costs. In addition, to comply with the rule, NIPSCO incurred capital expenditures to modify its infrastructure and manage CCRs. As allowed by the EPA, 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 filed a petition on November 1, 2016 with the IURC seeking approval of the projects and recovery of the costs associated with CCR compliance. On June 9, 2017, NIPSCO filed with the IURC a settlement reached with certain parties regarding the CCR projects and treatment of associated costs. The IURC approved the settlement in an order on December 13, 2017. Capital compliance costs totaled approximately $193 million, with the projects being substantially complete and in service as of March 31, 2019.

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. The final rule became effective January 4, 2016. Based upon a preliminary study of the November 3, 2015 final rule, capital compliance costs were expected to be approximately $170 million. The EPA is expected to release a draft ELG reconsideration rule in 2019. However, 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).

D. 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 Plan’s had indicated.

The Integrated Resource Plan evaluated demand-side and supply-side resource alternatives to reliably and cost effectively meet NIPSCO customers' future energy requirements over the ensuing 20 years. The preferred option within the Integrated Resource Plan retires R.M. Schahfer Generating Station (Units 14, 15, 17, and 18) by 2023 and Michigan City Generating Station (Unit 12) by 2028. These units represent 2,080 MW of generating capacity, equal to 72% of NIPSCO’s remaining 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 MW. The facilities supplying the energy will have a combined nameplate capacity of approximately 700 MW. NIPSCO's purchase requirement under the PPAs is dependent on satisfactory approval of the PPAs by the IURC. NIPSCO submitted the PPAs to the IURC for approval in February 2019. An IURC order is anticipated in the third quarter of 2019. If approved by the IURC, payments under the PPAs will not begin until the associated generation facilities are constructed by the owner / seller which is expected to be complete by the end of 2020.

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 partnership owned by NIPSCO, the developer and an unrelated tax equity partner. The aforementioned partnership structure will result in full NIPSCO ownership 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 and timely completion of construction. The estimated procedural timeline for receiving an IURC order is the same as the aforementioned PPAs with required FERC filings occurring after receiving the IURC order. Construction of the facility is expected to be complete by the end of 2020.

Greater Lawrence Incident Restoration. In addition to the amounts recorded for third-party claims (described above in " - B. Legal Proceedings"), we expensed approximately $32 million for other incident-related costs during the three months ended March 31, 2019. These expenses include certain consulting costs, claims center costs and labor and related expenses incurred in connection with the incident. Including the $266 million recorded during 2018, we expect to incur a total of $360 million to $370 million in such incident-related costs, depending on the incurrence of future restoration work. The amounts set forth above do not include the estimated capital cost of the pipeline replacement, which is set forth below. The increase in estimated total incident-related expenses from those disclosed in our Form 10-K for the year ended December 31, 2018 resulted primarily from receiving additional information regarding the extended period of time over which the restoration work would take place, higher than anticipated costs from vendors and increased estimates for consultants and claim center costs.

We maintain liability insurance for damages in the approximate amount of $800 million and property insurance for gas pipelines and other applicable property in the approximate amount of $300 million. Total expenses related to the incident have exceeded the total amount of insurance coverage available under our policies. While we believe that a substantial amount of expenses related to the Greater Lawrence Incident will be covered by insurance, insurers providing property and liability insurance to the Company or Columbia of Massachusetts are raising defenses to coverage under the terms and conditions of the respective insurance policies which contain various exclusions and conditions that could limit the amount of insurance proceeds to the Company or Columbia of Massachusetts. We are not able to estimate the amount of expenses that will not be covered by insurance, but these amounts are material to our financial statements. Certain types of damages, expenses or claimed costs, such as fines or penalties, may be excluded under the policies. As discussed above in “- B. Legal Proceedings,” $100 million for insurance recoveries was recorded during the quarter ended March 31, 2019 in addition to the $135 million of insurance recoveries that were recorded during 2018.

As of March 31, 2019, $113 million had been collected, of which $108 million was collected during the three months ended March 31, 2019. Additional collections of insurance proceeds in the amount of $22 million were received subsequent to the March 31, 2019 balance sheet date. We are currently unable to predict the timing of future insurance recoveries. To the extent that we are not successful in obtaining insurance recoveries in the amount recorded for such recoveries as of March 31, 2019, it could result in a charge against “Operation and maintenance” expense.

Substantially all of the $346 million liability for third-party claims and other incident-related costs remaining as of March 31, 2019 is presented within "Current liabilities" in our Condensed Consolidated Balance Sheets (unaudited). The remaining insurance receivable balance of $122 million as of March 31, 2019 is presented within “Accounts receivable.”

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. At the request of the Massachusetts DPU, which was instructed by the Massachusetts Governor through his executive authority under a state of emergency, Columbia of Massachusetts hired an outside contractor to serve as the Chief Recovery Officer for the Greater Lawrence Incident, responsible for command, control and communications. Columbia of Massachusetts restored gas service to nearly all homes and workplaces in December 2018. With the restoration and recovery efforts now substantially complete, the service of the Chief Recovery Officer is complete and the next phase of the effort is being managed by Columbia of Massachusetts under the third party oversight of a Massachusetts-based engineering firm as set forth above under “ - B. Legal Proceedings.”

Since the Greater Lawrence Incident and through March 31, 2019, we have incurred approximately $177 million of capital spend for the pipeline replacement, of which approximately $10 million was incurred in 2019. We estimate this replacement work will cost between $240 million and $250 million in total. Columbia of Massachusetts has provided notice to its property insurer of the Greater Lawrence Incident and discussions around the claim and recovery have commenced. The recovery of any capital investment not reimbursed through insurance will be addressed in a future regulatory proceeding. The outcome of such a proceeding is uncertain. In accordance with ASC 980-360, if it becomes probable that a portion of the pipeline replacement cost will not be recoverable through customer rates and an amount can be reasonably estimated, we will reduce our regulated plant balance for the amount of the probable disallowance and record an associated charge to earnings. This could result in a material adverse effect to our financial condition, results of operations and cash flows. Additionally, if a rate order is received allowing recovery of the investment with no or reduced return on investment, a loss on disallowance may be required.

In addition, we have committed to a capital investment program to install over-pressurization protection devices on all of our low-pressure systems as described above in “-B. Legal Proceedings.” These devices operate like circuit-breakers, so that if operating pressure is too high or too low, regardless of the cause, they are designed to immediately shut down the supply of gas to the system. The program also includes installing remote monitoring devices on all low-pressure systems, enabling gas control centers to continuously monitor pressure at regulator stations. In addition, we have conducted a field survey of all regulator stations and initiated an engineering review of those regulator stations; we are verifying and enhancing our maps and records of low-pressure regulator stations; and we initiated a process so that our personnel will be present whenever excavation work is being done in close proximity to a regulator station.

XML

Accumulated Other Comprehensive Loss

3 Months Ended

Mar. 31, 2019

Other Comprehensive Income (Loss), Tax [Abstract]

Accumulated Other Comprehensive Loss

Accumulated Other Comprehensive Loss

The following tables display the components of Accumulated Other Comprehensive Loss:

	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, 2019	$	(2.4	)	$	(13.0	)	$	(21.8	)	$	(37.2	)
Other comprehensive income (loss) before reclassifications	2.7			(19.3		)	0.5			(16.1		)
Amounts reclassified from accumulated other comprehensive loss	0.1			—			0.4			0.5
Net current-period other comprehensive income (loss)	2.8			(19.3		)	0.9			(15.6		)
Balance as of March 31, 2019	$	0.4		$	(32.3	)	$	(20.9	)	$	(52.8	)

	Gains and Losses on Securities(1)			Gains and Losses on Cash Flow Hedges(1)			Pension and OPEB Items(1)			Accumulated Other Comprehensive Loss(1)
Balance as of January 1, 2018	$	0.2		$	(29.4	)	$	(14.2	)	$	(43.4	)
Other comprehensive income (loss) before reclassifications	(1.9		)	51.1			(0.6		)	48.6
Amounts reclassified from accumulated other comprehensive loss	0.2			(15.7		)	0.8			(14.7		)
Net current-period other comprehensive income (loss)	(1.7		)	35.4			0.2			33.9
Reclassification due to adoption of ASU 2018-02	—			(6.3		)	(3.2		)	(9.5		)
Balance as of March 31, 2018	$	(1.5	)	$	(0.3	)	$	(17.2	)	$	(19.0	)

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

XML

Other, Net

3 Months Ended

Mar. 31, 2019

Other, Net [Abstract]

Other Income and Other Expense Disclosure [Text Block]

Other, Net

Three Months Ended March 31, (in millions)	2019			2018
Interest Income	$	2.1		$	1.7
AFUDC Equity	1.7			3.7
Pension and other postretirement non-service cost	(2.8		)	6.2
Interest rate swap settlement gain	—			21.2
Miscellaneous	(1.7		)	(1.5		)
Total Other, net	$	(0.7	)	$	31.3

XML

Business Segment Information

3 Months Ended

Mar. 31, 2019

Segment Reporting [Abstract]

Business Segment Information

Business Segment Information

At March 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 business 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.

 

	Three Months Ended March 31,
(in millions)	2019			2018
Operating Revenues
Gas Distribution Operations
Unaffiliated	$	1,438.8		$	1,327.3
Intersegment	3.3			3.3
Total	1,442.1			1,330.6
Electric Operations
Unaffiliated	430.8			423.3
Intersegment	0.2			0.2
Total	431.0			423.5
Corporate and Other
Unaffiliated	0.2			0.2
Intersegment	111.1			114.1
Total	111.3			114.3
Eliminations	(114.6		)	(117.6		)
Consolidated Operating Revenues	$	1,869.8		$	1,750.8
Operating Income
Gas Distribution Operations	$	275.4		$	321.7
Electric Operations	95.0			83.1
Corporate and Other	3.8			(4.2		)
Consolidated Operating Income	$	374.2		$	400.6

XML

Recent Accounting Pronouncements (Tables)

3 Months Ended

Mar. 31, 2019

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

Description of New Accounting Pronouncements Not yet Adopted

Recently Issued Accounting Pronouncements

We are currently evaluating the impact of certain ASUs on our Condensed Consolidated Financial Statements (unaudited) and Notes to Condensed Consolidated Financial Statements (unaudited), which are described below:

Standard	Description	Effective Date	Effect on the financial statements or other significant matters
ASU 2019-04, Codification Improvements to Topic 326, Financial Instruments-Credit Losses, Topic 815, Derivatives and Hedging, and Topic 825, Financial Instruments	The pronouncement clarifies and improves certain areas of guidance related to the recently issued standards on credit losses, hedging, and recognition and measurement. Topics 1, 2, and 5 of this update amends ASU 2016-13 as it relates to accrued interest, transfers between investment classifications, expected recoveries and reinsurance recoverables. Topic 3 improves guidance related to fair value hedges. Topic 4 of this update relates to codification improvements to ASU 2016-01.	Annual period ending after December 15, 2019, including interim periods therein. Early adoption is permitted.	We are currently evaluating the impact of codification improvements under Topics 1, 2, and 5 of this pronouncement, if any, on our Condensed Consolidated Financial Statements (unaudited) and Notes to Condensed Consolidated Financial Statements (unaudited). Topics 3 and 4 of this ASU are not material to us. We expect to adopt this ASU on its effective date.
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 Condensed Consolidated Financial Statements (unaudited). We expect to adopt this ASU on its effective date.

Standard	Description	Effective Date	Effect on the financial statements or other significant matters
ASU 2016-13,  Financial Instruments-Credit Losses (Topic 326)	The pronouncement changes the impairment model for most financial assets, replacing the current "incurred loss" model. ASU 2016-13 will require the use of an "expected loss" model for instruments measured at amortized cost. It will also require entities to record allowances for available-for-sale securities rather than impair the carrying amount of the securities. Subsequent improvements to the estimated credit losses of available-for-sale securities will be recognized immediately in earnings instead of over time as they are under historic guidance.	Annual periods beginning after December 15, 2019, including interim periods therein. Early adoption is permitted for annual or interim periods beginning after December 15, 2018.	We maintain investments in U.S. Treasury, corporate and mortgage-backed debt securities, which are pledged as collateral for trust accounts related to our wholly-owned insurance company. These debt securities are classified as available for sale. We also have recorded balances for trade receivables that fall within the scope of the standard. We are currently evaluating the impact of adoption, if any, on our Condensed Consolidated Financial Statements (unaudited) and Notes to Condensed Consolidated Financial Statements (unaudited). We expect to adopt this ASU on its effective date.

Schedule of Prospective Adoption of New Accounting Pronouncements

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)

XML

Revenue Recognition (Tables)

3 Months Ended

Mar. 31, 2019

Revenue from Contract with Customer [Abstract]

Disaggregation of Revenue

The tables below reconcile revenue disaggregation by customer class to segment revenue as well as to revenues reflected on the Condensed Statements of Consolidated Income (unaudited) for the three months ended March 31, 2019 and March 31, 2018:

Three Months Ended March 31, 2019 (in millions)	Gas Distribution Operations		Electric Operations		Corporate and Other		Total
Customer Revenues(1)
Residential	$	975.3	$	118.8	$	—	$	1,094.1
Commercial	330.5		119.3		—		449.8
Industrial	82.9		163.3		—		246.2
Off-system	20.1		—		—		20.1
Miscellaneous	17.2		6.9		0.2		24.3
Total Customer Revenues	$	1,426.0	$	408.3	$	0.2	$	1,834.5
Other Revenues	12.8		22.5		—		35.3
Total Operating Revenues	$	1,438.8	$	430.8	$	0.2	$	1,869.8

⁽¹⁾ Customer revenue amounts exclude intersegment revenues. See Note 20, "Business Segment Information," for discussion of intersegment revenues.

Three Months Ended March 31, 2018 (in millions)	Gas Distribution Operations		Electric Operations		Corporate and Other		Total
Customer Revenues(1)
Residential	$	893.6	$	114.5	$	—	$	1,008.1
Commercial	308.3		116.9		—		425.2
Industrial	74.6		162.5		—		237.1
Off-system	22.3		—		—		22.3
Miscellaneous	16.8		7.5		0.2		24.5
Total Customer Revenues	$	1,315.6	$	401.4	$	0.2	$	1,717.2
Other Revenues	11.7		21.9		—		33.6
Total Operating Revenues	$	1,327.3	$	423.3	$	0.2	$	1,750.8

⁽¹⁾ Customer revenue amounts exclude intersegment revenues. See Note 20, "Business Segment Information," for discussion of intersegment revenues.

Customer Accounts Receivable

The opening and closing balances of customer receivables for the three months ended March 31, 2019 are presented in the table below. We had no significant contract assets or liabilities during the period. Additionally, we have not incurred any significant costs to obtain or fulfill contracts.

(in millions)	Customer Accounts Receivable, Billed (less reserve)		Customer Accounts Receivable, Unbilled (less reserve)
Balance as of December 31, 2018	$	540.5	$	349.1
Balance as of March 31, 2019	692.2		284.6
Increase (Decrease)	$	151.7	$	(64.5	)

XML

Earnings Per Share (Tables)

3 Months Ended

Mar. 31, 2019

Earnings Per Share [Abstract]

Computation Of Diluted Average Common Shares

The computation of diluted average common shares is as follows:

	Three Months Ended
	March 31,
(in thousands)	2019	2018
Denominator
Basic average common shares outstanding	373,356	338,012
Dilutive potential common shares:
Shares contingently issuable under employee stock plans	1,062	715
Shares restricted under employee stock plans	133	264
Forward Agreements	105	—
Diluted Average Common Shares	374,656	338,991

XML

Equity (Tables)

3 Months Ended

Mar. 31, 2019

Equity [Abstract]

Schedule of Stock by Class [Table Text Block]

The following table displays preferred dividends declared for the period by outstanding series of shares:

				Quarter Ended March 31, 2019		March 31, 2019		December 31, 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	$	28.25	$	393.9	$	393.9
6.500% Series B	$	25,000.00	20,000	$	862.15	$	486.1	$	486.1

XML

Regulatory Matters (Tables)

3 Months Ended

Mar. 31, 2019

Regulatory Assets and Liabilities Disclosure [Abstract]

Schedule of Regulatory Programs

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

(in millions)
Company	Program	Incremental Revenue			Incremental Capital Investment		Investment Period	Filed	Status	Rates Effective
Columbia of Ohio	IRP - 2018(1)	$	(1.6	)	$	207.3	1/17-12/17	February 27, 2018	Approved April 25, 2018	May 2018
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(1)	74.5			659.9		1/11-12/17	December 1, 2017	Approved November 28, 2018	December 2018
Columbia of Ohio	CEP - 2019	16.1			122.1		1/18-12/18	February 28, 2019	Order Expected August 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	FMCA 1(3)	9.9			1.5		11/17-9/18	November 30, 2018	Approved March 27, 2019	April 2019
Columbia of Massachusetts	GSEP - 2019	10.7			64.0		1/19-12/19	October 31, 2018	Approved April 30, 2019	May 2019
Columbia of Virginia	SAVE - 2019	2.4			36.0		1/19-12/19	August 17, 2018	Approved October 26, 2018	January 2019
Columbia of Kentucky	AMRP - 2019	3.6			30.1		1/19-12/19	October 15, 2018	Approved December 5, 2018	January 2019
Columbia of Maryland	STRIDE - 2019	1.2			15.9		1/19-12/19	November 1, 2018	Approved December 12, 2018	January 2019
NIPSCO - Electric	TDSIC - 4(1)	(11.8		)	72.2		12/17-5/18	July 31, 2018	Approved November 28, 2018	December 2018
NIPSCO - Electric	TDSIC - 5(1)	15.9			58.8		6/18-11/18	January 29, 2019	Order Expected Q2 2019	June 2019
NIPSCO - Electric	ECRM - 32	1.0			—		1/18-6/18	July 31, 2018	Approved October 31, 2018	November 2018
NIPSCO - Electric	FMCA - 9(3)	4.1			90.2		10/17-3/18	April 27, 2018	Approved July 25, 2018	August 2018
NIPSCO - Electric	FMCA - 10(3)	2.2			45.7		4/18-8/18	October 18, 2018	Approved January 29, 2019	February 2019
NIPSCO - Electric	FMCA - 11(3)	0.9			22.4		9/18-2/19	April 17, 2019	Order Expected July, 2019	August 2019

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

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

⁽³⁾Incremental revenue is inclusive of tracker eligible operations and maintenance expense.

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 or Settled Incremental Revenue			Filed	Status	Rates Effective
NIPSCO - Gas(1)	$	138.1	$	107.3		September 27, 2017	Approved September 19, 2018	October 2018
Columbia of Virginia(2)	$	14.2	$	1.3		August 28, 2018	Settlement filed April 19, 2019, Order expected Second half of 2019	February 2019
NIPSCO - Electric(3)	$	21.4	$	(45.0	)	October 31, 2018	Partial settlement filed April 26, 2019, Order expected Second half of 2019	Second half of 2019

⁽¹⁾Rates will be 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 will be effective on January 1, 2020. The IURC’s order also dismissed NIPSCO from phase 2 of the IURC’s TCJA investigation.

⁽²⁾Rates implemented subject to refund. An order of the settlement agreement, including refunds to be issued and resolution of outstanding TCJA impacts to rates, is currently pending before the VSCC.

XML

Risk Management Activities (Tables)

3 Months Ended

Mar. 31, 2019

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block]

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

(in millions)	March 31, 2019		December 31, 2018
Risk Management Assets - Current(1)
Interest rate risk programs	$	5.6	$	—
Commodity price risk programs	0.9		1.1
Total	$	6.5	$	1.1
Risk Management Assets - Noncurrent(2)
Interest rate risk programs	$	—	$	18.5
Commodity price risk programs	6.9		4.4
Total	$	6.9	$	22.9
Risk Management Liabilities - Current(3)
Interest rate risk programs	$	—	$	—
Commodity price risk programs	4.4		5.0
Total	$	4.4	$	5.0
Risk Management Liabilities - Noncurrent
Interest rate risk programs	$	22.4	$	9.5
Commodity price risk programs	33.4		37.2
Total	$	55.8	$	46.7

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

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

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

XML

Fair Value (Tables)

3 Months Ended

Mar. 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 Condensed Consolidated Balance Sheets (unaudited) on a recurring basis and their level within the fair value hierarchy as of March 31, 2019 and December 31, 2018:

 

Recurring Fair Value Measurements March 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 March 31, 2019
Assets
Risk management assets	$	—	$	13.4	$	—	$	13.4
Available-for-sale securities	—		138.2		—		138.2
Total	$	—	$	151.6	$	—	$	151.6
Liabilities
Risk management liabilities	$	—	$	60.2	$	—	$	60.2
Total	$	—	$	60.2	$	—	$	60.2

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

Schedule of Available-For-Sale Securities

The amortized cost, gross unrealized gains and losses and fair value of available-for-sale securities at March 31, 2019 and December 31, 2018 were: 

March 31, 2019 (in millions)	Amortized Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
Available-for-sale securities
U.S. Treasury debt securities	$	22.0	$	—	$	—		$	22.0
Corporate/Other debt securities	115.7		1.4		(0.9		)	116.2
Total	$	137.7	$	1.4	$	(0.9	)	$	138.2
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: 

(in millions)	Carrying Amount as of March 31, 2019		Estimated Fair Value as of March 31, 2019		Carrying Amount as of Dec. 31, 2018		Estimated Fair Value as of Dec. 31, 2018
Long-term debt (including current portion)	$	7,161.5	$	7,533.6	$	7,155.4	$	7,228.3

XML

Transfers Of Financial Assets (Tables)

3 Months Ended

Mar. 31, 2019

Transfers and Servicing [Abstract]

Schedule Of Gross And Net Receivables Transferred As Well As Short-Term Borrowings Related To The Securitization Transactions

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 March 31, 2019 and December 31, 2018: 

(in millions)	March 31, 2019		December 31, 2018
Gross Receivables	$	742.7	$	694.4
Less: Receivables not transferred	242.7		295.2
Net receivables transferred	$	500.0	$	399.2
Short-term debt due to asset securitization	$	500.0	$	399.2

XML

Goodwill (Tables)

3 Months Ended

Mar. 31, 2019

Goodwill and Intangible Assets Disclosure [Abstract]

Schedule of Goodwill

The following presents our goodwill balance allocated by segment as of March 31, 2019:

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

XML

Pension And Other Postretirement Benefits (Tables)

3 Months Ended

Mar. 31, 2019

Pension and Other Postretirement Benefits Cost (Reversal of Cost) [Abstract]

Components Of The Plans' Net Periodic Benefits Cost

The following table provides the components of the plans’ actuarially determined net periodic benefit cost for the three months ended March 31, 2019 and 2018:

	Pension Benefits						Other Postretirement Benefits
Three Months Ended March 31, (in millions)	2019			2018			2019			2018
Components of Net Periodic Benefit (Income) Cost(1)
Service cost	$	7.3		$	7.9		$	1.3		$	1.3
Interest cost	18.2			16.6			4.8			4.4
Expected return on assets	(27.2		)	(36.3		)	(3.3		)	(3.7		)
Amortization of prior service credit	—			(0.1		)	(0.8		)	(1.0		)
Recognized actuarial loss	11.4			10.2			0.5			0.9
Total Net Periodic Benefit (Income) Cost	$	9.7		$	(1.7	)	$	2.5		$	1.9

⁽¹⁾The service cost component, and all non-service cost components, of net periodic benefit cost are presented in "Operation and maintenance" and "Other, net", respectively, on the Condensed Statements of Consolidated Income (unaudited).

XML

Short-Term Borrowings (Tables)

3 Months Ended

Mar. 31, 2019

Short-term Debt [Abstract]

Schedule Of Short-Term Borrowings

Short-term borrowings were as follows: 

(in millions)	March 31, 2019		December 31, 2018
Commercial paper weighted-average interest rate of 2.90% and 2.96% at March 31, 2019 and December 31, 2018, respectively	$	980.0	$	978.0
Accounts receivable securitization facility borrowings	500.0		399.2
Term loan weighted-average interest rate of 3.00% and 3.07% at March 31, 2019 and December 31, 2018, respectively	600.0		600.0
Total Short-Term Borrowings	$	2,080.0	$	1,977.2

XML

Leases (Tables)

3 Months Ended

Mar. 31, 2019

Leases [Abstract]

Lease Cost

The components of lease expense are presented in the following lines on the Condensed Statements of Consolidated Income (unaudited):

Three Months Ended March 31, (in millions)	Income Statement Classification	2019
Finance lease cost
Amortization of right-of-use assets	Depreciation and amortization	$	3.7
Interest on lease liabilities	Interest expense, net	2.9
Total finance lease cost(1)		6.6
Operating lease cost(2)	Operation and maintenance	3.7
Short-term lease cost	Operation and maintenance	0.7
Total lease cost		$	11.0

⁽¹⁾Total finance lease cost includes $0.6 million in costs that have been capitalized into Net Property, Plant and Equipment.

⁽²⁾Operating lease cost includes $0.3 million in costs that have been capitalized into Net Property, Plant and Equipment.

Right-of-Use Assets and Liabilities

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

Three Months Ended March 31, (in millions)	Balance Sheet Classification	2019
Assets
Finance leases	Net Property, Plant and Equipment	$	179.8
Operating leases	Deferred charges and other	53.8
Total leased assets		233.6
Liabilities
Current
Finance leases	Current portion of long-term debt	10.4
Operating leases	Other accruals	9.3
Noncurrent
Finance leases	Long-term debt, excluding amounts due within one year	188.5
Operating leases	Other noncurrent liabilities	44.5
Total lease liabilities		$	252.7

Lease Information

Other pertinent information related to leases was as follows:

Three Months Ended March 31, (in millions)	2019
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows from finance leases	$	3.0
Operating cash flows from operating leases	3.7
Financing cash flows from finance leases	2.4
Right-of-use assets obtained in exchange for lease obligations
Finance leases	6.6
Operating leases	$	0.1

	March 31, 2019
Weighted-average remaining lease term (years)
Finance leases	15.8
Operating leases	10.1
Weighted-average discount rate
Finance leases	5.8	%
Operating leases	4.4	%

Lease Maturity

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

As of March 31, 2019, (in millions)	Total			Finance Leases			Operating Leases
Year 1	$	35.5		$	24.0		$	11.5
Year 2	31.8			23.7			8.1
Year 3	31.0			23.9			7.1
Year 4	28.8			22.7			6.1
Year 5	25.8			20.1			5.7
Thereafter	246.7			217.7			29.0
Total lease payments	399.6			332.1			67.5
Less: Imputed interest	(125.2		)	(111.5		)	(13.7		)
Less: Leases not yet commenced(1)	(21.7		)	(21.7		)	—
Total	252.7			198.9			53.8
Reported as of March 31, 2019
Short-term lease liabilities	19.7			10.4			9.3
Long-term lease liabilities	233.0			188.5			44.5
Total lease liabilities	$	252.7		$	198.9		$	53.8

⁽¹⁾ Expected payments include obligations for leases not yet commenced of approximately $21.7 million for interconnection facilities. The facilities will have a lease term of 10 years, with an estimated commencement in the second quarter of 2019.

XML

Accumulated Other Comprehensive Loss (Tables)

3 Months Ended

Mar. 31, 2019

Other Comprehensive Income (Loss), Tax [Abstract]

Components Of Accumulated Other Comprehensive Loss

The following tables display the components of Accumulated Other Comprehensive Loss:

	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, 2019	$	(2.4	)	$	(13.0	)	$	(21.8	)	$	(37.2	)
Other comprehensive income (loss) before reclassifications	2.7			(19.3		)	0.5			(16.1		)
Amounts reclassified from accumulated other comprehensive loss	0.1			—			0.4			0.5
Net current-period other comprehensive income (loss)	2.8			(19.3		)	0.9			(15.6		)
Balance as of March 31, 2019	$	0.4		$	(32.3	)	$	(20.9	)	$	(52.8	)

	Gains and Losses on Securities(1)			Gains and Losses on Cash Flow Hedges(1)			Pension and OPEB Items(1)			Accumulated Other Comprehensive Loss(1)
Balance as of January 1, 2018	$	0.2		$	(29.4	)	$	(14.2	)	$	(43.4	)
Other comprehensive income (loss) before reclassifications	(1.9		)	51.1			(0.6		)	48.6
Amounts reclassified from accumulated other comprehensive loss	0.2			(15.7		)	0.8			(14.7		)
Net current-period other comprehensive income (loss)	(1.7		)	35.4			0.2			33.9
Reclassification due to adoption of ASU 2018-02	—			(6.3		)	(3.2		)	(9.5		)
Balance as of March 31, 2018	$	(1.5	)	$	(0.3	)	$	(17.2	)	$	(19.0	)

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

XML

Other, Net (Tables)

3 Months Ended

Mar. 31, 2019

Other, Net [Abstract]

Schedule of Other Nonoperating Income (Expense)

Three Months Ended March 31, (in millions)	2019			2018
Interest Income	$	2.1		$	1.7
AFUDC Equity	1.7			3.7
Pension and other postretirement non-service cost	(2.8		)	6.2
Interest rate swap settlement gain	—			21.2
Miscellaneous	(1.7		)	(1.5		)
Total Other, net	$	(0.7	)	$	31.3

XML

Business Segment Information (Tables)

3 Months Ended

Mar. 31, 2019

Segment Reporting [Abstract]

Schedule Of Operating Income Derived From Revenues And Expenses By Segment

At March 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 business 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.

 

	Three Months Ended March 31,
(in millions)	2019			2018
Operating Revenues
Gas Distribution Operations
Unaffiliated	$	1,438.8		$	1,327.3
Intersegment	3.3			3.3
Total	1,442.1			1,330.6
Electric Operations
Unaffiliated	430.8			423.3
Intersegment	0.2			0.2
Total	431.0			423.5
Corporate and Other
Unaffiliated	0.2			0.2
Intersegment	111.1			114.1
Total	111.3			114.3
Eliminations	(114.6		)	(117.6		)
Consolidated Operating Revenues	$	1,869.8		$	1,750.8
Operating Income
Gas Distribution Operations	$	275.4		$	321.7
Electric Operations	95.0			83.1
Corporate and Other	3.8			(4.2		)
Consolidated Operating Income	$	374.2		$	400.6

XML

Revenue Recognition (Narrative) (Details)	3 Months Ended
	Mar. 31, 2019
Revenue from Contract with Customer [Abstract]
Service Area By County	20

XML

Revenue Recognition (Disaggregation of Revenue) (Details) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2019	Mar. 31, 2018
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	$ 1,834.5	$ 1,717.2
Other revenues		35.3	33.6
Total Operating Revenues		1,869.8	1,750.8
Gas Distribution Operations
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	1,426.0	1,315.6
Other revenues		12.8	11.7
Total Operating Revenues		1,438.8	1,327.3
Electric Operations
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	408.3	401.4
Other revenues		22.5	21.9
Total Operating Revenues		430.8	423.3
Corporate and Other
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	0.2	0.2
Other revenues		0.0	0.0
Total Operating Revenues		0.2	0.2
Residential
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	1,094.1	1,008.1
Residential | Gas Distribution Operations
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	975.3	893.6
Residential | Electric Operations
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	118.8	114.5
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]	449.8	425.2
Commercial | Gas Distribution Operations
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	330.5	308.3
Commercial | Electric Operations
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	119.3	116.9
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]	246.2	237.1
Industrial | Gas Distribution Operations
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	82.9	74.6
Industrial | Electric Operations
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	163.3	162.5
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]	20.1	22.3
Off-system | Gas Distribution Operations
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	20.1	22.3
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]	24.3	24.5
Miscellaneous | Gas Distribution Operations
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	17.2	16.8
Miscellaneous | Electric Operations
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	6.9	7.5
Miscellaneous | Corporate and Other
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	$ 0.2	$ 0.2

[1] Customer revenue amounts exclude intersegment revenues. See Note 20, "Business Segment Information," for discussion of intersegment revenues.

XML

Revenue Recognition (Customer Accounts Receivable) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Dec. 31, 2018
Revenue from Contract with Customer [Abstract]
Customer Accounts Receivable, Billed (Less Reserve)	$ 692.2	$ 540.5
Customer Accounts Receivable, Unbilled (Less Reserve)	284.6	$ 349.1
Increase (Decrease) in Customer Accounts Receivable, Billed (Less Reserve)	151.7
Increase (Decrease) in Customer Accounts Receivable, Unbilled (Less Reserve)	$ (64.5)

XML

Earnings Per Share (Details) - shares shares in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Denominator
Basic Average Common Shares Outstanding	373,356	338,012
Dilutive potential common shares
Shares contingently issuable under employee stock plans	1,062	715
Shares restricted under stock plans	133	264
Forward agreements	105	0
Diluted Average Common Shares	374,656	338,991

XML

Equity (Narrative) (Details) $ / shares in Units, $ in Millions	3 Months Ended
	Mar. 31, 2019 USD ($) $ / shares shares	Dec. 31, 2018 $ / shares shares
Preferred Stock, Shares Authorized	20,000,000
Preferred Stock, Shares Outstanding	440,000
Preferred Stock, Par or Stated Value Per Share | $ / shares	$ 0.01
At The Market Program [Member]
Number Of Equity Distribution Agreements	5
Common Stock Aggregate Sale Price | $	$ 500.0
ATM Program Equity Remaining Available for Issuance | $	$ 309.4
Forward Agreement [Member]
Forward Contract Indexed to Issuer's Equity, Shares		4,708,098
Forward Contract Indexed to Issuer's Equity, Forward Rate Per Share | $ / shares	$ 26.40	$ 26.55
Forward Contract Indexed to Issuer's Equity, Settlement Alternatives, Shares, at Fair Value | $	$ 124.3
Series A Preferred Stock
Preferred Stock, Shares Outstanding	400,000
Series B Preferred Stock
Preferred Stock, Shares Outstanding	20,000
Series B-1 Preferred Stock
Preferred Stock, Shares Outstanding	20,000

XML

Equity Schedule of Stock by Class - Preferred (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended
	Mar. 31, 2019		Dec. 31, 2018	Mar. 31, 2018	Dec. 31, 2017
Class of Stock [Line Items]
Preferred Stock, Shares Outstanding	440,000
Stockholders' Equity Attributable to Parent	$ 5,779.6		$ 5,750.9	$ 4,506.2	$ 4,320.1
Series A Preferred Stock
Class of Stock [Line Items]
Preferred Stock, Liquidation Preference Per Share	$ 1,000.00
Preferred Stock, Shares Outstanding	400,000
Dividends Declared Per Share	$ 28.25
Series B Preferred Stock
Class of Stock [Line Items]
Preferred Stock, Liquidation Preference Per Share	$ 25,000.00
Preferred Stock, Shares Outstanding	20,000
Dividends Declared Per Share	$ 862.15
Series B-1 Preferred Stock
Class of Stock [Line Items]
Preferred Stock, Shares Outstanding	20,000
Preferred Stock
Class of Stock [Line Items]
Stockholders' Equity Attributable to Parent	$ 880.0	[1]	880.0
Preferred Stock | Series A Preferred Stock
Class of Stock [Line Items]
Stockholders' Equity Attributable to Parent	393.9		393.9
Preferred Stock | Series B Preferred Stock
Class of Stock [Line Items]
Stockholders' Equity Attributable to Parent	$ 486.1		$ 486.1

[1] Series A and Series B shares have an aggregate liquidation preference of $400M and $500M, respectively. See Note 5, "Equity" for additional information.

XML

Gas in Storage Gas in Storage (Details) - USD ($) $ in Millions	Mar. 31, 2019	Dec. 31, 2018
Gas in Storage [Abstract]
LIFO Inventory Amount	$ 21.5	$ 0.0

XML

Regulatory Matters (Narrative) (Details) - USD ($) $ in Millions	Oct. 31, 2018	Oct. 09, 2018	Aug. 28, 2018
Regulatory Matters [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Adjustment			$ 5.2
NIPSCO - Electric
Regulatory Matters [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Adjustment	$ 83.6
Public Utilities, Approved Rate Increase (Decrease), Adjustment	$ 85.3
Columbia Of Massachusetts
Regulatory Matters [Line Items]
Public Utilities, Customer Refund for Tax Rate Change Due to TCJA		$ 95.8

XML

Regulatory Matters Regulatory Matters (Schedule of Regulatory Programs) (Details) - USD ($) $ in Millions		Apr. 17, 2019	Feb. 28, 2019	Jan. 29, 2019	Nov. 30, 2018	Nov. 01, 2018	Oct. 31, 2018	Oct. 18, 2018	Oct. 15, 2018	Aug. 28, 2018	Aug. 17, 2018	Jul. 31, 2018	Apr. 27, 2018	Feb. 27, 2018	Dec. 01, 2017	Sep. 27, 2017
Columbia Of Ohio | 2018 IRP
Regulatory Matters [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount	[1]													$ (1.6)
Regulatory Net Capital Expenditures Included In Filing	[1]													$ 207.3
Columbia Of Ohio | 2019 IRP
Regulatory Matters [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount	[1]		$ 18.2
Regulatory Net Capital Expenditures Included In Filing	[1]		199.6
Columbia Of Ohio | 2018 CEP
Regulatory Matters [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount	[1]														$ 74.5
Regulatory Net Capital Expenditures Included In Filing	[1]														$ 659.9
Columbia Of Ohio | 2019 CEP
Regulatory Matters [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount			16.1
Regulatory Net Capital Expenditures Included In Filing			$ 122.1
NIPSCO - Gas
Regulatory Matters [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount																$ 107.3
Public Utilities, Requested Rate Increase (Decrease), Amount																$ 138.1
NIPSCO - Gas | TDSIC-9
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
NIPSCO - Gas | FMCA 1
Regulatory Matters [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount	[3]				$ 9.9
Regulatory Net Capital Expenditures Included In Filing	[3]				$ 1.5
Columbia Of Massachusetts | 2019 GSEP
Regulatory Matters [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount	[4]						$ 10.7
Regulatory Net Capital Expenditures Included In Filing	[4]						64.0
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 Virginia | 2019 SAVE
Regulatory Matters [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount											$ 2.4
Regulatory Net Capital Expenditures Included In Filing											$ 36.0
Columbia Of Kentucky | 2019 AMRP
Regulatory Matters [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount									$ 3.6
Regulatory Net Capital Expenditures Included In Filing									$ 30.1
Columbia Of Maryland | 2019 STRIDE
Regulatory Matters [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount						$ 1.2
Regulatory Net Capital Expenditures Included In Filing						$ 15.9
NIPSCO - Electric
Regulatory Matters [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount							(45.0)
Public Utilities, Requested Rate Increase (Decrease), Amount							$ 21.4
NIPSCO - Electric | TDSIC-4
Regulatory Matters [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount	[1]											$ (11.8)
Regulatory Net Capital Expenditures Included In Filing	[1]											72.2
NIPSCO - Electric | TDSIC 5
Regulatory Matters [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount	[1]			$ 15.9
Regulatory Net Capital Expenditures Included In Filing	[1]			$ 58.8
NIPSCO - Electric | ECRM 32
Regulatory Matters [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount												1.0
Regulatory Net Capital Expenditures Included In Filing												$ 0.0
NIPSCO - Electric | FMCA 9
Regulatory Matters [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount	[3]												$ 4.1
Regulatory Net Capital Expenditures Included In Filing	[3]												$ 90.2
NIPSCO - Electric | FMCA 10
Regulatory Matters [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount	[3]							$ 2.2
Regulatory Net Capital Expenditures Included In Filing	[3]							$ 45.7
Subsequent Event | NIPSCO - Electric | FMCA 11
Regulatory Matters [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount	[3]	$ 0.9
Regulatory Net Capital Expenditures Included In Filing	[3]	$ 22.4

[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 revenue is inclusive of tracker eligible operations and maintenance expense.

[4]

XML

Regulatory Matters Regulatory Matters (Rate Case Action) (Details) - USD ($) $ in Millions	Oct. 31, 2018	Aug. 28, 2018	Sep. 27, 2017
NIPSCO - Gas
Rate Case Action [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount			$ 138.1
Public Utilities, Approved Rate Increase (Decrease), Amount			$ 107.3
Columbia Of Virginia
Rate Case Action [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount		$ 14.2
Public Utilities, Approved Rate Increase (Decrease), Amount		$ 1.3
NIPSCO - Electric
Rate Case Action [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount	$ 21.4
Public Utilities, Approved Rate Increase (Decrease), Amount	$ (45.0)

XML

Risk Management Activities (Narrative) (Details) $ in Millions	Mar. 31, 2019 USD ($)
Interest Rate Swap
Derivative [Line Items]
Derivative, Notional Amount	$ 500.0

XML

Risk Management Activities (Schedule of Derivative Instruments in Statement of Financial Position, Fair Value) (Details) - USD ($) $ in Millions		Mar. 31, 2019		Dec. 31, 2018
Risk Management Assets Current
Derivatives, Fair Value [Line Items]
Derivative Asset	[1]	$ 6.5		$ 1.1
Risk Management Assets Noncurrent
Derivatives, Fair Value [Line Items]
Derivative Asset	[2]	6.9		22.9
Risk Management Liabilities Current
Derivatives, Fair Value [Line Items]
Derivative Liability		4.4	[3]	5.0
Risk Management Liabilities Noncurrent
Derivatives, Fair Value [Line Items]
Derivative Liability		55.8		46.7
Interest Rate Risk | Risk Management Assets Current
Derivatives, Fair Value [Line Items]
Derivative Asset	[1]	5.6		0.0
Interest Rate Risk | Risk Management Assets Noncurrent
Derivatives, Fair Value [Line Items]
Derivative Asset	[2]	0.0		18.5
Interest Rate Risk | Risk Management Liabilities Current
Derivatives, Fair Value [Line Items]
Derivative Liability		0.0	[3]	0.0
Interest Rate Risk | Risk Management Liabilities Noncurrent
Derivatives, Fair Value [Line Items]
Derivative Liability		22.4		9.5
Commodity Price Risk Programs | Risk Management Assets Current
Derivatives, Fair Value [Line Items]
Derivative Asset	[1]	0.9		1.1
Commodity Price Risk Programs | Risk Management Assets Noncurrent
Derivatives, Fair Value [Line Items]
Derivative Asset	[2]	6.9		4.4
Commodity Price Risk Programs | Risk Management Liabilities Current
Derivatives, Fair Value [Line Items]
Derivative Liability		4.4	[3]	5.0
Commodity Price Risk Programs | Risk Management Liabilities Noncurrent
Derivatives, Fair Value [Line Items]
Derivative Liability		$ 33.4		$ 37.2

[1] Presented in "Prepayments and other" on the Condensed Consolidated Balance Sheets (unaudited).

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

[3] Presented in "Other accruals" on the Condensed Consolidated Balance Sheets (unaudited).

XML

Fair Value (Narrative) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Fair Value Disclosure [Line Items]
Transfers between Fair Value Hierarchies	$ 0.0	$ 0.0
Material Level 3 Changes	0.0	$ 0.0
Fair Value, Assets and Liabilities Measured on a Non-Recurring Basis	0.0
U.S. Treasury debt securities
Fair Value Disclosure [Line Items]
Available-for-sale Securities, Maturities, Next Twelve Months, Fair Value	5.6
Corporate/Other debt securities
Fair Value Disclosure [Line Items]
Available-for-sale Securities, Maturities, Next Twelve Months, Fair Value	$ 3.6

XML

Fair Value (Fair Value Of Financial Assets And Liabilities Measured On A Recurring Basis) (Details) - USD ($) $ in Millions	Mar. 31, 2019	Dec. 31, 2018
Fair Value Assets And Liabilities Measured On Recurring Basis [Line Items]
Assets, Fair Value Disclosure	$ 151.6	$ 162.3
Total	60.2	51.7
Fair Value, Inputs, Level 1
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
Assets, Fair Value Disclosure	0.0	0.0
Risk management liabilities	0.0	0.0
Total	0.0	0.0
Significant Other Observable Inputs (Level 2)
Fair Value Assets And Liabilities Measured On Recurring Basis [Line Items]
Risk management assets	13.4	24.0
Available-for-sale securities	138.2	138.3
Assets, Fair Value Disclosure	151.6	162.3
Risk management liabilities	60.2	51.7
Total	60.2	51.7
Significant Unobservable Inputs (Level 3)
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
Assets, Fair Value Disclosure	0.0	0.0
Risk management liabilities	0.0	0.0
Total	0.0	0.0
Available-for-sale Securities
Fair Value Assets And Liabilities Measured On Recurring Basis [Line Items]
Available-for-sale securities	138.2	138.3
Risk management assets
Fair Value Assets And Liabilities Measured On Recurring Basis [Line Items]
Risk management assets	13.4	24.0
Risk management liabilities	$ 60.2	$ 51.7

XML

Fair Value (Available-For-Sale Securities) (Details) - USD ($) $ in Millions	Mar. 31, 2019	Dec. 31, 2018
Fair Value Disclosure [Line Items]
Amortized Cost	$ 137.7	$ 141.3
Gross Unrealized Gains	1.4	0.5
Gross Unrealized Losses	0.9	3.5
Fair Value	138.2	138.3
U.S. Treasury debt securities
Fair Value Disclosure [Line Items]
Amortized Cost	22.0	23.6
Gross Unrealized Gains	0.0	0.1
Gross Unrealized Losses	0.0	0.1
Fair Value	22.0	23.6
Corporate/Other debt securities
Fair Value Disclosure [Line Items]
Amortized Cost	115.7	117.7
Gross Unrealized Gains	1.4	0.4
Gross Unrealized Losses	0.9	3.4
Fair Value	$ 116.2	$ 114.7

XML

Fair Value (Carrying Amount And Estimated Fair Values Of Financial Instruments) (Details) - USD ($) $ in Millions	Mar. 31, 2019	Dec. 31, 2018
Fair Value Disclosures [Abstract]
Long-term Debt (including current portion), Carrying Amount	$ 7,161.5	$ 7,155.4
Long-term debt (including current portion), Estimated Fair Value	$ 7,533.6	$ 7,228.3

XML

Transfers Of Financial Assets (Narrative) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Assets and Associated Liabilities of Transfers Accounted for as Secured Borrowings [Line Items]
Cash From Financing Activities Related To The Change In Short-Term Borrowings Due To The Securitization Transactions	$ 100.8	$ 176.7
Securitization Transaction Fees	0.8	$ 0.8
Accounts Receivable Program
Assets and Associated Liabilities of Transfers Accounted for as Secured Borrowings [Line Items]
Seasonal Limit	$ 500.0

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	Mar. 31, 2019	Dec. 31, 2018
Gross Receivables	$ 742.7	$ 694.4
Less: Receivables not transferred	242.7	295.2
Net receivables transferred	500.0	399.2
Accounts receivable securitization facility borrowings	$ 500.0	$ 399.2

XML

Goodwill (Details) - USD ($) $ in Millions	Mar. 31, 2019	Dec. 31, 2018
Goodwill [Line Items]
Goodwill	$ 1,690.7	$ 1,690.7
Gas Distribution Operations
Goodwill [Line Items]
Goodwill	1,690.7
Electric Operations
Goodwill [Line Items]
Goodwill	0.0
Corporate and Other
Goodwill [Line Items]
Goodwill	$ 0.0

XML

Income Taxes (Narrative) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Income Tax Disclosure [Abstract]
Effective income tax rates	21.20%	18.50%
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate	21.00%
Increase (Decrease) in Effective Tax Rate	2.70%
Changes to Liability for Uncertain Tax Positions	$ 0.0

XML

Pension And Other Postretirement Benefits (Narrative) (Details) $ in Millions	3 Months Ended
	Mar. 31, 2019 USD ($)
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Employer contributions	$ 0.6
Other Postretirement Benefit Plan
Defined Benefit Plan Disclosure [Line Items]
Employer contributions	$ 5.7

XML

Pension And Other Postretirement Benefits (Components Of The Plans' Net Periodic Benefits Cost) (Details) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2019	Mar. 31, 2018
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Service Cost	[1]	$ 7.3	$ 7.9
Interest cost	[1]	18.2	16.6
Expected return on assets	[1]	(27.2)	(36.3)
Amortization of prior service credit	[1]	0.0	(0.1)
Recognized actuarial loss	[1]	11.4	10.2
Total Net Periodic Benefits Cost		9.7	(1.7)
Other Postretirement Benefit Plan
Defined Benefit Plan Disclosure [Line Items]
Service Cost	[1]	1.3	1.3
Interest cost	[1]	4.8	4.4
Expected return on assets	[1]	(3.3)	(3.7)
Amortization of prior service credit	[1]	(0.8)	(1.0)
Recognized actuarial loss	[1]	0.5	0.9
Total Net Periodic Benefits Cost		$ 2.5	$ 1.9

[1] The service cost component, and all non-service cost components, of net periodic benefit cost are presented in "Operation and maintenance" and "Other, net", respectively, on the Condensed Statements of Consolidated Income (unaudited).

XML

Long-Term Debt (Narrative) (Details) $ in Millions	Apr. 01, 2019 USD ($) Rate
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage | Rate	5.85%
Senior Note Redeemed 2019 Note 1 | Senior Notes
Debt Instrument [Line Items]
Debt Instrument, Repurchase Amount | $	$ 41.0

XML

Short-Term Borrowings (Narrative) (Details) - USD ($) $ in Millions	Apr. 17, 2019	Mar. 31, 2019	Dec. 31, 2018
Short-term Debt [Line Items]
Commercial paper outstanding		$ 980.0	$ 978.0
Accounts receivable securitization facility borrowings		500.0	399.2
Revolving Credit Facility
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity		1,850.0
Long-term Line of Credit		0.0
Commercial Paper
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity		1,500.0
Standby Letters of Credit
Short-term Debt [Line Items]
Long-term Line of Credit		10.2
Term Loan
Short-term Debt [Line Items]
Term Loan		$ 600.0	600.0
Maximum | Term Loan
Short-term Debt [Line Items]
Term Loan			$ 600.0
Subsequent Event | Term Loan
Short-term Debt [Line Items]
Debt Instrument, Basis Spread on Variable Rate	0.60%
Subsequent Event | Term Loan | Debt Oustanding
Short-term Debt [Line Items]
Term Loan	$ 850.0
Subsequent Event | Maximum | Term Loan
Short-term Debt [Line Items]
Term Loan	$ 850.0

XML

Short-Term Borrowings (Schedule Of Short-Term Borrowings) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Apr. 17, 2019	Dec. 31, 2018	Mar. 31, 2018
Short-term Debt [Line Items]
Document Period End Date	Mar. 31, 2019
Commercial paper weighted-average interest rate of 2.90% and 2.96% at March 31, 2019 and December 31, 2018, respectively	$ 980.0		$ 978.0
Accounts receivable securitization facility borrowings	500.0		399.2
Total short-term borrowings	$ 2,080.0		$ 1,977.2
Commercial Paper
Short-term Debt [Line Items]
Short-term Debt, Weighted Average Interest Rate, at Point in Time	2.90%		2.96%
Term Loan
Short-term Debt [Line Items]
Term loan weighted-average interest rate of 3.00% and 3.07% at March 31, 2019 and December 31, 2018, respectively	$ 600.0		$ 600.0
Short-term Debt, Weighted Average Interest Rate, at Point in Time	3.00%			3.07%
Maximum | Term Loan
Short-term Debt [Line Items]
Term loan weighted-average interest rate of 3.00% and 3.07% at March 31, 2019 and December 31, 2018, respectively			$ 600.0
Subsequent Event | Maximum | Term Loan
Short-term Debt [Line Items]
Term loan weighted-average interest rate of 3.00% and 3.07% at March 31, 2019 and December 31, 2018, respectively		$ 850.0

XML

Leases (Narrative) (Details) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2019	Jan. 01, 2019	Dec. 31, 2018
Lessee, Lease, Description [Line Items]
Leases Not Yet Commenced	[1]	$ 21.7
Lessee, Finance Lease, Lease Not yet Commenced, Term of Contract		10 years
Capital Leases, Future Minimum Payments, Interest Included in Payments				$ 114.6
Lessee, Finance Lease, Term of Contract		4 years
Operating Lease, Right-of-Use Asset		$ 53.8	$ 57.0
Lessee, Lease Renewal Term		25 years
Lessee, Operating Lease, Renewal Term		1 year
Operating Leases, Future Minimum Payments Due, Next Twelve Months				11.0
Operating Leases, Future Minimum Payments, Due in Two Years				7.3
Operating Leases, Future Minimum Payments, Due in Three Years				6.1
Operating Leases, Future Minimum Payments, Due in Four Years				4.2
Operating Leases, Future Minimum Payments, Due in Five Years				2.8
Operating Leases, Future Minimum Payments, Due Thereafter				14.5
Fleet Lease
Lessee, Lease, Description [Line Items]
Lessee, Operating Lease, Term of Contract		1 year
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
Interconnection facilities
Lessee, Lease, Description [Line Items]
Leases Not Yet Commenced	[1]	$ (21.7)
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		25 years

[1] Expected payments include obligations for leases not yet commenced of approximately $21.7 million for interconnection facilities. The facilities will have a lease term of 10 years, with an estimated commencement in the second quarter of 2019.

XML

Leases (Lease Cost) (Details) $ in Millions	3 Months Ended
	Mar. 31, 2019 USD ($)
Leases [Abstract]
Finance Lease, Right-of-Use Asset, Amortization	$ 3.7
Finance Lease, Interest Expense	2.9
Finance Lease, Cost Total	6.6	[1]
Operating Lease, Cost	3.7	[2]
Short-term Lease, Cost	0.7
Lease, Cost	11.0
Capitalized Finance Lease Cost	0.6
Capitalized Operating Lease Cost	$ 0.3

[1] Total finance lease cost includes $0.6 million in costs that have been capitalized into Net Property, Plant and Equipment.

[2] Operating lease cost includes $0.3 million in costs that have been capitalized into Net Property, Plant and Equipment.

XML

Leases (Right-of-Use Assets and Liabilities) (Details) - USD ($) $ in Millions	Mar. 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	$ 179.8
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible List]	us-gaap:DeferredChargesAndOther
Operating Lease, Right-of-Use Asset	$ 53.8	$ 57.0
Total leased assets	$ 233.6
Finance Lease, Liability, Current, Statement of Financial Position [Extensible List]	us-gaap:Currentportionoflong-termdebt
Finance Lease, Liability, Current	$ 10.4
Operating Lease, Liability, Current, Statement of Financial Position [Extensible List]	us-gaap:OtherAccruals
Operating Lease, Liability, Current	$ 9.3
Finance Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List]	us-gaap:Long-termDebtExcludingAmountsDueWithinOneYear
Finance Lease, Liability, Noncurrent	$ 188.5
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List]	us-gaap:OtherNoncurrentLiabilities
Operating Lease, Liability, Noncurrent	$ 44.5
Total Lease Liability	$ 252.7

XML

Leases (Lease Information) (Details) $ in Millions	3 Months Ended
	Mar. 31, 2019 USD ($) Rate
Leases [Abstract]
Finance Lease, Interest Payment on Liability	$ 3.0
Operating Lease, Payments	3.7
Finance Lease, Principal Payments	2.4
Right-of-Use Asset Obtained in Exchange for Finance Lease Liability	6.6
Right-of-Use Asset Obtained in Exchange for Operating Lease Liability	$ 0.1
Finance Lease, Weighted Average Remaining Lease Term	15 years 9 months 18 days
Operating Lease, Weighted Average Remaining Lease Term	10 years 1 month 6 days
Finance Lease, Weighted Average Discount Rate, Percent | Rate	5.80%
Operating Lease, Weighted Average Discount Rate, Percent | Rate	4.40%

XML

Leases (Lease Maturity) (Details) - USD ($) $ in Millions		Mar. 31, 2019	Dec. 31, 2018
Lease Maturity [Line Items]
Total Future Minimum Lease Payments Due, Next Twelve Months		$ 35.5	$ 34.0
Total Future Minimum Lease Payments, Due in Two Years		31.8	29.8
Total Future Minimum Lease Payments, Due in Three Years		31.0	28.7
Total Future Minimum Lease Payments, Due in Four Years		28.8	26.3
Total Future Minimum Lease Payments, Due in Five Years		25.8	22.6
Total Future Minimum Lease Payments, Due Thereafter		246.7	226.9
Total Future Minimum Lease Payments Due		399.6	$ 368.3
Undiscounted Excess Amount		(125.2)
Total Lease Liability		252.7
Short-term Lease Liability		19.7
Long-term Lease Liability		233.0
Finance Lease, Liability, Current		10.4
Finance Lease, Liability, Noncurrent		188.5
Leases Not Yet Commenced	[1]	(21.7)
Operating Lease, Liability, Current		9.3
Operating Lease, Liability, Noncurrent		44.5
Finance Lease
Lease Maturity [Line Items]
Finance Lease, Liability, Payments, Due in Next Rolling Twelve Months		24.0
Finance Lease, Liability, Payments, Due in Rolling Year Two		23.7
Finance Lease, Liability, Payments, Due in Rolling Year Three		23.9
Finance Lease, Liability, Payments, Due in Rolling Year Four		22.7
Finance Lease, Liability, Payments, Due in Rolling Year Five		20.1
Finance Lease, Liability, Payments, Due in Rolling after Year Five		217.7
Finance Lease, Liability, Payments, Due		332.1
Finance Lease, Liability, Undiscounted Excess Amount		(111.5)
Finance Lease, Liability		198.9
Finance Lease, Liability, Current		10.4
Finance Lease, Liability, Noncurrent		188.5
Leases Not Yet Commenced	[1]	(21.7)
Operating Lease
Lease Maturity [Line Items]
Lessee, Operating Lease, Liability, Payments, Due Next Rolling Twelve Months		11.5
Lessee, Operating Lease, Liability, Payments, Due in Rolling Year Two		8.1
Lessee, Operating Lease, Liability, Payments, Due in Rolling Year Three		7.1
Lessee, Operating Lease, Liability, Payments, Due Year Four		6.1
Lessee, Operating Lease, Liability, Payments, Due in Rolling Year Five		5.7
Lessee, Operating Lease, Liability, Payments, Due after Rolling Year Five		29.0
Lessee, Operating Lease, Liability, Payments, Due		67.5
Lessee, Operating Lease, Liability, Undiscounted Excess Amount		(13.7)
Leases Not Yet Commenced	[1]	0.0
Operating Lease, Liability		53.8
Operating Lease, Liability, Current		9.3
Operating Lease, Liability, Noncurrent		$ 44.5

[1] Expected payments include obligations for leases not yet commenced of approximately $21.7 million for interconnection facilities. The facilities will have a lease term of 10 years, with an estimated commencement in the second quarter of 2019.

XML

Leases (Lease Maturity under ASC 840) (Details) - USD ($) $ in Millions		Mar. 31, 2019	Dec. 31, 2018
Leases [Abstract]
Total Future Minimum Lease Payments Due, Next Twelve Months		$ 35.5	$ 34.0
Total Future Minimum Lease Payments, Due in Two Years		31.8	29.8
Total Future Minimum Lease Payments, Due in Three Years		31.0	28.7
Total Future Minimum Lease Payments, Due in Four Years		28.8	26.3
Total Future Minimum Lease Payments, Due in Five Years		25.8	22.6
Total Future Minimum Lease Payments, Due Thereafter		246.7	226.9
Total Future Minimum Lease Payments Due		$ 399.6	368.3
Capital Leases, Future Minimum Payments Due, Next Twelve Months	[1]		23.0
Capital Leases, Future Minimum Payments Due in Two Years	[1]		22.5
Capital Leases, Future Minimum Payments Due in Three Years	[1]		22.6
Capital Leases, Future Minimum Payments Due in Four Years	[1]		22.1
Capital Leases, Future Minimum Payments Due in Five Years	[1]		19.8
Capital Leases, Future Minimum Payments Due Thereafter	[1]		212.4
Capital Leases, Future Minimum Payments Due	[1]		322.4
Operating Leases, Future Minimum Payments Due, Next Twelve Months			11.0
Operating Leases, Future Minimum Payments, Due in Two Years			7.3
Operating Leases, Future Minimum Payments, Due in Three Years			6.1
Operating Leases, Future Minimum Payments, Due in Four Years			4.2
Operating Leases, Future Minimum Payments, Due in Five Years			2.8
Operating Leases, Future Minimum Payments, Due Thereafter			14.5
Operating Leases, Future Minimum Payments Due			$ 45.9

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

XML

Other Commitments And Contingencies (Narrative) (Details) $ in Thousands		1 Months Ended	3 Months Ended	7 Months Ended	12 Months Ended
	Nov. 30, 2018 USD ($)	May 01, 2019 USD ($)	Mar. 31, 2019 USD ($)	Mar. 31, 2019 USD ($)	Dec. 31, 2018 USD ($)
Other Commitments And Contingencies [Line Items]
Proceeds From Insurance Settlement			$ 108,000	$ 113,000
Estimated Third-Party Claims			346,000	346,000
Insurance Settlements Receivable			122,000	122,000
Liability Insurance for Damages			800,000	800,000
Property Insurance			300,000	300,000
Insurance Recoveries			100,000		$ 135,000
Recorded reserves to cover environmental remediation at various sites			$ 99,700	$ 99,700	101,200
MGP Sites
Other Commitments And Contingencies [Line Items]
Number of waste disposal sites identified by program			63	63
Liability for Estimated Remediation Costs			$ 96,400	$ 96,400	97,500
Reasonably possible remediation costs variance from reserve			$ 20,000	20,000
Columbia Of Massachusetts
Other Commitments And Contingencies [Line Items]
Gas Meters Affected			7,500
Businesses Impacted by Incident			700
Pipeline Replacement Expenses			$ 10,000	177,000
Consent Order Fine	$ 75
Expenses Related to Third Party Claims, Other					266,000
Loss Recorded During Period			$ 32,000
Miles of Affected Cast Iron and Bare Steel Pipeline System			45
NIPSCO
Other Commitments And Contingencies [Line Items]
Estimated Cost of Compliance with Coal Combustion Residuals, Maximum			$ 193,000
Estimated Cost of Compliance with Effluent Limitations Guidelines			170,000
Maximum | Columbia Of Massachusetts
Other Commitments And Contingencies [Line Items]
Civil Penalty Assessed for Violation of Federal Pipeline Safety Regulations			209
Civil Penalty Assessed for Series of Violations of Federal Pipeline Safety Regulations			2,100
Penalty Per Violation of Emergency Response Plan			250
Penalty for Violations of Emergency Response Plan			20,000
Penalty Per Violation of Operational Directives During Restoration Efforts			1,000
Expenses Related to Third Party Claims, Other				370,000
Third-Party Claims Resulting from the Greater Lawrence Incident			1,010,000
Estimated Capital Cost of the Pipeline Replacement			250,000	250,000
Minimum | Columbia Of Massachusetts
Other Commitments And Contingencies [Line Items]
Expenses Related to Third-Party Claims			204,000		$ 757,000
Expenses Related to Third Party Claims, Other				360,000
Third-Party Claims Resulting from the Greater Lawrence Incident			961,000
Estimated Capital Cost of the Pipeline Replacement			240,000	240,000
Standby Letters of Credit
Other Commitments And Contingencies [Line Items]
Long-term Line of Credit			$ 10,200	$ 10,200
Subsequent Event
Other Commitments And Contingencies [Line Items]
Proceeds From Insurance Settlement		$ 22,000

XML

Accumulated Other Comprehensive Loss (Components Of Accumulated Other Comprehensive Loss) (Details) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2019	Mar. 31, 2018
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance	[1]	$ (37.2)	$ (43.4)
Other Comprehensive Income before reclassifications	[1]	(16.1)	48.6
Amounts reclassified from accumulated other comprehensive loss	[1]	0.5	(14.7)
Net current-period other comprehensive income (loss)	[1]	(15.6)	33.9
New Accounting Pronouncement or Change in Accounting Principle, Cumulative Effect of Change on Equity or Net Assets			(9.5)
Ending Balance	[1]	(52.8)	(19.0)
Gains and Losses on Securities
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance	[1]	(2.4)	0.2
Other Comprehensive Income before reclassifications	[1]	2.7	(1.9)
Amounts reclassified from accumulated other comprehensive loss	[1]	0.1	0.2
Net current-period other comprehensive income (loss)	[1]	2.8	(1.7)
New Accounting Pronouncement or Change in Accounting Principle, Cumulative Effect of Change on Equity or Net Assets			0.0
Ending Balance	[1]	0.4	(1.5)
Gains and Losses on Cash Flow Hedges
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance	[1]	(13.0)	(29.4)
Other Comprehensive Income before reclassifications	[1]	(19.3)	51.1
Amounts reclassified from accumulated other comprehensive loss	[1]	0.0	(15.7)
Net current-period other comprehensive income (loss)	[1]	(19.3)	35.4
New Accounting Pronouncement or Change in Accounting Principle, Cumulative Effect of Change on Equity or Net Assets	[1]		(6.3)
Ending Balance	[1]	(32.3)	(0.3)
Pension and OPEB Items
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance	[1]	(21.8)	(14.2)
Other Comprehensive Income before reclassifications	[1]	0.5	(0.6)
Amounts reclassified from accumulated other comprehensive loss	[1]	0.4	0.8
Net current-period other comprehensive income (loss)	[1]	0.9	0.2
New Accounting Pronouncement or Change in Accounting Principle, Cumulative Effect of Change on Equity or Net Assets	[1]		(3.2)
Ending Balance	[1]	$ (20.9)	$ (17.2)

[1] All amounts are net of tax. Amounts in parentheses indicate debits.

XML

Other, Net (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Other, Net [Abstract]
Interest Income	$ 2.1	$ 1.7
AFUDC Equity	1.7	3.7
Pension and other postretirement non-service cost	(2.8)	6.2
Interest rate swap settlement gain	0.0	21.2
Miscellaneous	(1.7)	(1.5)
Other, net	$ (0.7)	$ 31.3

XML

Business Segment Information (Narrative) (Details)	3 Months Ended
	Mar. 31, 2019
Segment Reporting [Abstract]
Primary business segments	2
Number of counties in which electric service provided by Electric Operations	20

XML

Business Segment Information (Schedule Of Operating Income Derived From Revenues And Expenses By Segment) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Segment Reporting Information [Line Items]
Regulated Operating Revenue	$ 1,869.8	$ 1,750.8
Revenues	1,869.8	1,750.8
Consolidated Operating Income (Loss)	374.2	400.6
Gas Distribution Operations
Segment Reporting Information [Line Items]
Regulated Operating Revenue	1,438.8	1,327.3
Revenues	1,442.1	1,330.6
Consolidated Operating Income (Loss)	275.4	321.7
Gas Distribution Operations | Unaffiliated
Segment Reporting Information [Line Items]
Revenues		1,327.3
Gas Distribution Operations | Intersegment
Segment Reporting Information [Line Items]
Revenues	3.3	3.3
Electric Operations
Segment Reporting Information [Line Items]
Regulated Operating Revenue	430.8	423.3
Revenues	431.0	423.5
Consolidated Operating Income (Loss)	95.0	83.1
Electric Operations | Unaffiliated
Segment Reporting Information [Line Items]
Revenues		423.3
Electric Operations | Intersegment
Segment Reporting Information [Line Items]
Revenues	0.2	0.2
Corporate and Other
Segment Reporting Information [Line Items]
Regulated Operating Revenue	0.2	0.2
Revenues	111.3	114.3
Consolidated Operating Income (Loss)	3.8	(4.2)
Corporate and Other | Unaffiliated
Segment Reporting Information [Line Items]
Revenues		0.2
Corporate and Other | Intersegment
Segment Reporting Information [Line Items]
Revenues	111.1	114.1
Eliminations
Segment Reporting Information [Line Items]
Revenues	$ (114.6)	$ (117.6)