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 September 30, 2018

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: 363,286,952 shares outstanding at October 23, 2018.

NISOURCE INC.

FORM 10-Q QUARTERLY REPORT

FOR THE QUARTER ENDED SEPTEMBER 30, 2018

Table of Contents

			Page
	Defined Terms		3
PART I	FINANCIAL INFORMATION
	Item 1.	Financial Statements - unaudited
		Condensed Statements of Consolidated Income (Loss) (unaudited)	7
		Condensed Statements of Consolidated Comprehensive Income (Loss) (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)	13
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	40
	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	56
	Item 4.	Controls and Procedures	56
PART II	OTHER INFORMATION
	Item 1.	Legal Proceedings	57
	Item 1A.	Risk Factors	57
	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	57
	Item 3.	Defaults Upon Senior Securities	57
	Item 4.	Mine Safety Disclosures	57
	Item 5.	Other Information	57
	Item 6.	Exhibits	58
	Signature		59

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
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
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
IRS	Internal Revenue Service
IURC	Indiana Utility Regulatory Commission
LDCs	Local distribution companies
LIBOR	London InterBank Offered Rate

3

DEFINED TERMS
LIFO	Last In, First Out
MGP	Manufactured Gas Plant
MISO	Midcontinent Independent System Operator
MMDth	Million dekatherms
NOL	Net operating loss
NTSB	National Transportation Safety Board
NYMEX	New York Mercantile Exchange
OPEB	Other Postretirement Benefits
PHMSA	Pipeline and Hazardous Materials Safety Administration
PSC	Public Service Commission
PUC	Public Utility Commission
PUCO	Public Utilities Commission of Ohio
Pure Air	Pure Air on the Lake LP
RCRA	Resource Conservation and Recovery Act
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
VIE	Variable Interest Entities
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 (the "Securities Act") and Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). Investors and prospective investors should understand that many factors govern whether any forward-looking statement contained herein will be or can be realized. Any one of those factors could cause actual results to differ materially from those projected. These forward-looking statements include, but are not limited to, statements concerning 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 in our credit rating; 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; advances in technology; any damage to our reputation; 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; potential incidents and other operating risks associated with our business; impacts from the Greater Lawrence Incident (as defined in this report) (including any changes in management's estimates or assumptions regarding financial impact, the timing and amount of insurance recoveries, the outcomes of governmental investigations, changes to state and federal legislation or regulation impacting our operating practices, and our ability to recover our costs through rates or offset them through operational or other cost savings); 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; tax liabilities associated with the separation of Columbia Pipeline Group, Inc. on July 1, 2015; our ability to manage new initiatives and organizational changes; the performance of certain third-party suppliers upon which we rely; our ability to obtain sufficient insurance coverage; and other matters set forth in the “Risk Factors” section of this report and our Annual Report on Form 10-K for the fiscal year ended December

4

31, 2017, many of which risks are beyond our control. In addition, the relative contributions to profitability by each business segment, and the assumptions underlying the forward-looking statements relating thereto, may change over time.

All forward-looking statements are expressly qualified in their entirety by the foregoing cautionary statements. We undertake no obligation to, and expressly disclaim any such obligation to, update or revise any forward-looking statements to reflect changed assumptions, the occurrence of anticipated or unanticipated events or changes to the future results over time or otherwise, except as required by law.

5

Index	Page
Condensed Statements of Consolidated Income (Loss) (unaudited)	7
Condensed Statements of Consolidated Comprehensive Income (Loss) (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)	13
1. Basis of Accounting Presentation	13
2. Recent Accounting Pronouncements	13
3. Revenue Recognition	16
4. Earnings Per Share	19
5. Equity	19
6. Asset Retirement Obligations	20
7. Regulatory Matters	20
8. Risk Management Activities	26
9. Fair Value	27
10. Transfers of Financial Assets	29
11. Goodwill	30
12. Income Taxes	30
13. Pension and Other Postretirement Benefits	30
14. Long-Term Debt	32
15. Short-Term Borrowings	32
16. Other Commitments and Contingencies	33
17. Accumulated Other Comprehensive Income (Loss)	38
18. Other, Net	39
19. Business Segment Information	39

6

PART I

ITEM 1. FINANCIAL STATEMENTS

NiSource Inc.

Condensed Statements of Consolidated Income (Loss) (unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
(in millions, except per share amounts)	2018			2017			2018			2017
Operating Revenues
Customer revenues	$	855.8		$	883.4		$	3,555.1		$	3,386.0
Other revenues	39.2			33.6			97.7			120.3
Total Operating Revenues	895.0			917.0			3,652.8			3,506.3
Operating Expenses
Cost of sales (excluding depreciation and amortization)	222.0			233.6			1,259.7			1,062.7
Operation and maintenance	780.8			371.7			1,548.5			1,174.9
Depreciation and amortization	148.5			143.0			437.8			428.5
Loss (Gain) on sale of assets and impairments, net	0.7			—			0.4			(0.1		)
Other taxes	58.9			57.5			203.3			189.7
Total Operating Expenses	1,210.9			805.8			3,449.7			2,855.7
Operating Income (Loss)	(315.9		)	111.2			203.1			650.6
Other Income (Deductions)
Interest expense, net	(83.4		)	(87.9		)	(265.2		)	(260.8		)
Other, net	(1.7		)	(6.8		)	42.4			(0.3		)
Loss on early extinguishment of long-term debt	(33.0		)	—			(45.5		)	(111.5		)
Total Other Deductions, Net	(118.1		)	(94.7		)	(268.3		)	(372.6		)
Income (Loss) before Income Taxes	(434.0		)	16.5			(65.2		)	278.0
Income Taxes	(94.5		)	2.5			(26.3		)	97.1
Net Income (Loss)	(339.5		)	14.0			(38.9		)	180.9
Preferred dividends	(5.6		)	—			(6.9		)	—
Net Income (Loss) Available to Common Shareholders	(345.1		)	14.0			(45.8		)	180.9
Earnings (Loss) Per Share
Basic Earnings (Loss) Per Share	$	(0.95	)	$	0.04		$	(0.13	)	$	0.55
Diluted Earnings (Loss) Per Share	$	(0.95	)	$	0.04		$	(0.13	)	$	0.55
Dividends Declared Per Common Share	$	0.195		$	0.175		$	0.780		$	0.700
Basic Average Common Shares Outstanding	363.9			331.1			352.1			326.7
Diluted Average Common Shares	363.9			332.4			352.1			328.0

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 (Loss) (unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
(in millions, net of taxes)	2018			2017			2018			2017
Net Income (Loss)	$	(339.5	)	$	14.0		$	(38.9	)	$	180.9
Other comprehensive income (loss):
Net unrealized gain (loss) on available-for-sale securities(1)	0.1			0.1			(2.3		)	1.1
Net unrealized gain (loss) on cash flow hedges(2)	22.5			(9.3		)	56.5			(21.2		)
Unrecognized pension and OPEB benefit(3)	0.8			1.1			1.2			1.5
Total other comprehensive income (loss)	23.4			(8.1		)	55.4			(18.6		)
Comprehensive Income (Loss)	$	(316.1	)	$	5.9		$	16.5		$	162.3

⁽¹⁾ Net unrealized gain (loss) on available-for-sale securities, net of zero tax expense in the third quarter of 2018 and 2017, and $0.6 million tax benefit and $0.6 million tax expense for the nine months ended 2018 and 2017, respectively.

⁽²⁾ Net unrealized gain (loss) on cash flow hedges, net of $7.5 million tax expense and $5.8 million tax benefit in the third quarter of 2018 and 2017, respectively, and $18.7 million tax expense and $13.1 million tax benefit for the nine months ended 2018 and 2017, respectively. See Note 8, "Risk Management Activities," for additional information.

⁽³⁾ Unrecognized pension and OPEB benefit, net of zero and $0.5 million tax expense in the third quarter of 2018 and 2017, respectively, and $0.2 million and $0.8 million tax expense for the nine months ended 2018 and 2017, 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)	September 30, 2018			December 31, 2017
ASSETS
Property, Plant and Equipment
Utility plant	$	22,328.2		$	21,026.6
Accumulated depreciation and amortization	(7,171.0		)	(6,953.6		)
Net utility plant	15,157.2			14,073.0
Other property, at cost, less accumulated depreciation	17.2			286.5
Net Property, Plant and Equipment	15,174.4			14,359.5
Investments and Other Assets
Unconsolidated affiliates	2.6			5.5
Other investments	214.5			204.1
Total Investments and Other Assets	217.1			209.6
Current Assets
Cash and cash equivalents	41.8			29.0
Restricted cash	12.0			9.4
Accounts receivable (less reserve of $13.0 and $18.3, respectively)	500.4			898.9
Gas inventory	320.2			285.1
Materials and supplies, at average cost	97.7			105.9
Electric production fuel, at average cost	49.0			80.1
Exchange gas receivable	37.3			45.8
Regulatory assets	221.0			176.3
Prepayments and other	89.7			132.8
Total Current Assets	1,369.1			1,763.3
Other Assets
Regulatory assets	1,907.4			1,624.9
Goodwill	1,690.7			1,690.7
Intangible assets, net	223.5			231.7
Deferred charges and other	117.2			82.0
Total Other Assets	3,938.8			3,629.3
Total Assets	$	20,699.4		$	19,961.7

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)	September 30, 2018			December 31, 2017
CAPITALIZATION AND LIABILITIES
Capitalization
Stockholders’ Equity
Common stock - $0.01 par value, 400,000,000 shares authorized; 363,167,067 and 337,015,806 shares outstanding, respectively	$	3.7		$	3.4
Preferred stock - $1,000 par value, 20,000,000 shares authorized; 400,000 shares outstanding	393.9			—
Treasury stock	(99.9		)	(95.9		)
Additional paid-in capital	6,161.0			5,529.1
Retained deficit	(1,387.5		)	(1,073.1		)
Accumulated other comprehensive income (loss)	2.5			(43.4		)
Total Stockholders’ Equity	5,073.7			4,320.1
Long-term debt, excluding amounts due within one year	7,094.5			7,512.2
Total Capitalization	12,168.2			11,832.3
Current Liabilities
Current portion of long-term debt	48.6			284.3
Short-term borrowings	1,611.0			1,205.7
Accounts payable	433.7			625.6
Dividends payable - common stock	70.8			—
Dividends payable - preferred stock	11.6			—
Customer deposits and credits	238.4			262.6
Taxes accrued	150.0			208.1
Interest accrued	108.0			112.3
Risk management liabilities	4.8			43.2
Exchange gas payable	58.2			59.6
Regulatory liabilities	81.9			58.7
Legal and environmental	20.4			32.1
Accrued compensation and employee benefits	153.4			195.4
Claims accrued	365.9			12.5
Other accruals	54.5			78.3
Total Current Liabilities	3,411.2			3,178.4
Other Liabilities
Risk management liabilities	45.2			28.5
Deferred income taxes	1,291.7			1,292.9
Deferred investment tax credits	11.7			12.4
Accrued insurance liabilities	81.8			80.1
Accrued liability for postretirement and postemployment benefits	300.9			337.1
Regulatory liabilities	2,826.8			2,736.9
Asset retirement obligations	346.9			268.7
Other noncurrent liabilities	215.0			194.4
Total Other Liabilities	5,120.0			4,951.0
Commitments and Contingencies (Refer to Note 16, "Other Commitments and Contingencies")	—			—
Total Capitalization and Liabilities	$	20,699.4		$	19,961.7

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)
Nine Months Ended September 30, (in millions)	2018			2017
Operating Activities
Net Income (Loss)	$	(38.9	)	$	180.9
Adjustments to Reconcile Net Income to Net Cash from Operating Activities:
Loss on early extinguishment of debt	45.5			111.5
Depreciation and amortization	437.8			428.5
Deferred income taxes and investment tax credits	(26.4		)	96.3
Other adjustments	15.6			28.5
Changes in Assets and Liabilities:
Components of working capital	442.9			32.6
Regulatory assets/liabilities	61.3			(12.9		)
Postretirement and postemployment benefits	(41.4		)	(314.5		)
Deferred charges and other noncurrent assets	0.8			(3.7		)
Other noncurrent liabilities	30.0			(17.6		)
Net Cash Flows from Operating Activities	927.2			529.6
Investing Activities
Capital expenditures	(1,296.6		)	(1,216.4		)
Cost of removal	(72.6		)	(78.9		)
Purchases of available-for-sale securities	(71.4		)	(139.4		)
Sales of available-for-sale securities	58.5			129.4
Other investing activities	5.6			(1.4		)
Net Cash Flows used for Investing Activities	(1,376.5		)	(1,306.7		)
Financing Activities
Issuance of long-term debt	350.0			2,750.0
Repayments of long-term debt and capital lease obligations	(1,044.0		)	(1,352.4		)
Premiums and other debt related costs	(46.1		)	(139.8		)
Issuance of short-term debt (maturity > 90 days)	600.0			—
Change in short-term borrowings, net (maturity ≤ 90 days)	(194.6		)	(644.9		)
Issuance of common stock	611.6			332.6
Issuance of preferred stock	394.3			—
Acquisition of treasury stock	(4.0		)	(5.9		)
Dividends paid - common stock	(202.5		)	(170.2		)
Net Cash Flows from Financing Activities	464.7			769.4
Change in cash, cash equivalents and restricted cash	15.4			(7.7		)
Cash, cash equivalents and restricted cash at beginning of period	38.4			36.0
Cash, Cash Equivalents and Restricted Cash at End of Period	$	53.8		$	28.3

Supplemental Disclosures of Cash Flow Information

Nine Months Ended September 30, (in millions)	2018		2017
Non-cash transactions:
Capital expenditures included in current liabilities	$	167.5	$	219.1
Dividends declared but not paid	82.4		58.9
Reclassification of other property to regulatory assets(1)	245.3		—
Change in estimated costs of asset retirement obligations(2)	$	70.7	$	—

⁽¹⁾See Note 16-D "Other Matters" for additional information.

⁽²⁾See Note 6 "Asset Retirement Obligations" for additional information.

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

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Table of Contents

ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

Condensed Statements of Consolidated Equity (unaudited)

(in millions)	Common Stock		Preferred Stock		Treasury Stock			Additional Paid-In Capital		Retained Deficit			Accumulated Other Comprehensive Income (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 Loss	—		—		—			—		(38.9		)	—			(38.9		)
Other comprehensive income, net of tax	—		—		—			—		—			55.4			55.4
Common stock dividends ($0.78 per share)	—		—		—			—		(273.4		)	—			(273.4		)
Preferred stock dividends ($28.88 per share)	—		—		—			—		(11.6		)	—			(11.6		)
Treasury stock acquired	—		—		(4.0		)	—		—			—			(4.0		)
Cumulative effect of change in accounting principle(1)	—		—		—			—		9.5			(9.5		)	—
Stock issuances:
Common stock - private placement(2)	0.3		—		—			599.3		—			—			599.6
Preferred stock(2)	—		393.9		—			—		—			—			393.9
Employee stock purchase plan	—		—		—			4.2		—			—			4.2
Long-term incentive plan	—		—		—			11.5		—			—			11.5
401(k) and profit sharing	—		—		—			16.9		—			—			16.9
Balance as of September 30, 2018	$	3.7	$	393.9	$	(99.9	)	$	6,161.0	$	(1,387.5	)	$	2.5		$	5,073.7

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

⁽²⁾ See Note 5, "Equity," for additional information.

	Preferred	Common
(in thousands)	Shares	Shares	Treasury		Outstanding
Balance as of January 1, 2018	—	340,813	(3,797	)	337,016
Treasury Stock acquired	—	—	(166	)	(166	)
Issued:
Common stock - private placement(1)	—	24,964	—		24,964
Preferred stock(1)	400	—	—		—
Employee stock purchase plan	—	166	—		166
Long-term incentive plan	—	499	—		499
401(k) and profit sharing	—	688	—		688
Balance as of September 30, 2018	400	367,130	(3,963	)	363,167

⁽¹⁾ See Note 5, "Equity," for additional information.

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

12

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, 2017. 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 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), including potential early adoption in the fourth quarter of 2018.
ASU 2016-13, Financial Instruments-Credit Losses (Topic 326)	The pronouncement changes the impairment model for most financial assets, replacing the current "incurred loss" model. ASU 2016-13 will require the use of an "expected loss" model for instruments measured at amortized cost. It will also require entities to record allowances for available-for-sale debt securities rather than impair the carrying amount of the securities. Subsequent improvements to the estimated credit losses of available-for-sale securities will be recognized immediately in earnings instead of over time as they are under historic guidance.	Annual periods beginning after December 15, 2019, including interim periods therein. Early adoption is permitted for annual or interim periods beginning after December 15, 2018.	We maintain investments in U.S. Treasury, corporate and mortgage-backed debt securities, which are pledged as collateral for trust accounts related to our wholly-owned insurance company. These debt securities are classified as available for sale. We are currently evaluating the impact of adoption, if any, on our Condensed Consolidated Financial Statements (unaudited) and Notes to Condensed Consolidated Financial Statements (unaudited).

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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 2018-11, Leases (Topic 842): Targeted Improvements	The pronouncement allows entities the option to initially apply ASC 842 at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption.	Annual periods beginning after December 15, 2018, including interim periods therein. Early adoption is permitted.	We are the lessee for substantially all of our current leasing activity. Upon adopting ASC 842 we will begin recognizing right-of-use assets and liabilities associated with operating leases (other than short term operating leases) on our Condensed Consolidated Balance Sheets (unaudited). The impact of this change on the balance sheet is not reasonably estimable at this time. We do not anticipate the adoption of ASC 842 will have a material impact to our results of operations or cash flows. We have undertaken efforts to outline mock footnote disclosures intended to satisfy ASC 842’s disclosure requirements, which will enhance our disclosures on lease accounting policies and elections. We are implementing a new lease accounting system, which we will utilize to capture, track, and account for lease data. The new system will also aid in automating the compilation of disclosure information. We expect to conclude final system tests in the fourth quarter of 2018, with full system implementation prior to the effective date of these standards. 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 currently anticipate adopting this practical expedient for certain classes of leases. Further, we will elect the "practical expedient package" described in ASC 842-10-65-1. We maintain a substantial number of easements and will also elect the provisions of ASU 2018-01 to ease the process of implementing ASC 842. Lastly, we anticipate electing the transition method provided in ASU 2018-11 when we adopt these standards effective January 1, 2019.
ASU 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842	The pronouncement offers a practical expedient for accounting for land easements under ASU 2016-02. This practical expedient allows an entity the option of not evaluating existing land easements under ASC 842. New or modified land easements will still require evaluation under ASC 842 on a prospective basis beginning on the date of adoption.
ASU 2016-02, Leases (Topic 842)	The pronouncement introduces a lessee model that brings most leases on 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.

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ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

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

Recently Adopted Accounting Pronouncements

Standard	Adoption
ASU 2018-15, Intangibles—Goodwill and Other— Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract	In August 2018, the FASB issued this ASU, which amends current guidance to align the accounting for costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing costs associated with developing or obtaining internal-use software. We elected to early adopt the ASU on a prospective basis, effective October 1, 2018. As a result of adopting this ASU, we will defer onto the balance sheet those up-front implementation costs of cloud computing arrangements if they would have been capitalized in a similar on-premise software solution.
ASU 2018-02, Income Statement—Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income	We adopted this ASU effective March 31, 2018. Upon adoption, $9.5 million of tax effects that were stranded in accumulated other comprehensive income (loss) as a result of the implementation of the TCJA were reclassified to retained deficit. This change is reflected on our Condensed Statements of Consolidated Equity (unaudited).
ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force)	We adopted this ASU effective January 1, 2018. The adoption of this standard did not have a material impact on our Condensed Consolidated Financial Statements (unaudited) or Notes to Condensed Consolidated Financial Statements (unaudited).
ASU 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients	See Note 3, "Revenue Recognition," for our discussion of the effects of implementing these standards.
ASU 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations
ASU 2014-09, Revenue from Contracts with Customers (Topic 606)

We also adopted ASU 2017-07, Compensation -  Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, effective January 1, 2018. We continue to present the service cost component of net periodic benefit cost within "Operation and maintenance;" however, other components of the net periodic benefit cost (including regulatory deferrals and settlement charges) are now presented separately within "Other, net" on our Condensed Statements of Consolidated Income (Loss) (unaudited).

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ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

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

Changes in income statement presentation were implemented on a retrospective basis. The impact of this ASU on previously issued annual financial statements is summarized in the tables below:

Year Ended December 31, 2016 (in millions)	As Previously Reported			Effect of Change(1)			As Adjusted
Operation and maintenance	$	1,453.7		$	(7.9	)	$	1,445.8
Total Operating Expenses	3,634.3			(7.9		)	3,626.4
Operating Income	858.2			7.9			866.1
Other Income (Deductions)
Other, net	1.5			(7.9		)	(6.4		)
Total Other Deductions	(348.0		)	(7.9		)	(355.9		)
Income before Income Taxes	$	510.2		$	—		$	510.2

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

Year Ended December 31, 2017 (in millions)	As Previously Reported			Effect of Change(1)			As Adjusted
Operation and maintenance	$	1,612.3		$	(10.6	)	$	1,601.7
Total Operating Expenses	3,964.0			(10.6		)	3,953.4
Operating Income	910.6			10.6			921.2
Other Income (Deductions)
Other, net	(2.8		)	(10.6		)	(13.4		)
Total Other Deductions	(467.5		)	(10.6		)	(478.1		)
Income before Income Taxes	$	443.1		$	—		$	443.1

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

3.    Revenue Recognition

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

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ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

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

The table below provides results for the three and nine months ended September 30, 2018 as if they had been prepared under historic accounting guidance. We included operating revenue information for the three and nine months ended September 30, 2017 for comparability.

	Three Months Ended September 30,				Nine Months Ended September 30,
(in millions)	2018		2017		2018		2017
Operating Revenues
Gas Distribution	$	232.3	$	239.4	$	1,600.3	$	1,403.0
Gas Transportation	186.0		191.6		745.2		735.1
Electric	476.2		485.8		1,304.4		1,365.5
Other	0.5		0.2		2.9		2.7
Total Operating Revenues	$	895.0	$	917.0	$	3,652.8	$	3,506.3

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

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

We have identified our performance obligations created under tariff-based sales as 1) the commodity (natural gas or electricity, which includes generation and capacity) and 2) delivery. These commodities are sold and / or delivered to and generally consumed by customers simultaneously, leading to satisfaction of our performance obligations over time as gas or electricity is delivered to customers. Due to the at-will nature of utility customers, performance obligations are limited to the services requested and received to date. Once complete, we generally maintain no additional performance obligations.

Transaction prices for each performance obligation are generally prescribed by each operating company’s respective tariff. Rates include provisions to adjust billings for fluctuations in fuel and purchased power costs and cost of natural gas. Revenues are adjusted for differences between actual costs subject to reconciliation and the amounts billed in current rates. Under or over recovered revenues related to these cost recovery mechanisms are included in regulatory assets or liabilities on the Condensed Consolidated Balance Sheets (unaudited) and are recovered from or returned to customers through adjustments to tariff rates. As we provide and deliver service to customers, revenue is recognized based on the transaction price allocated to each performance obligation. In general, revenue recognized from tariff-based sales is equivalent to the value of natural gas or electricity supplied and billed each period, in addition to an estimate for deliveries completed during the period but not yet billed to the customer.

In addition to tariff-based sales, our Gas Distribution Operations segment enters into balancing and exchange arrangements of natural gas as part of our operations and off-system sales programs. We have concluded that these sales are within the scope of ASC 606. Performance obligations for these types of sales include transportation and storage of natural gas and can be satisfied at a point in time or over a period of time, depending on the specific transaction. For those transactions that span a period of time, we record a receivable or payable for any cumulative gas imbalances, as well as for any gas inventory borrowed or lent under a Gas Distributions Operations exchange agreement.

Revenue Disaggregation and Reconciliation. We disaggregate revenue from contracts with customers based upon reportable segment as well as by customer class. As our revenues are primarily earned over a period of time, and we do not earn a material amount of revenues at a point in time, revenues are not disaggregated as such below. The Gas Distribution Operations segment provides natural gas service and transportation for residential, commercial and industrial customers in Ohio, Pennsylvania, Virginia,

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ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

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

Kentucky, Maryland, Indiana and Massachusetts. The Electric Operations segment provides electric service in 20 counties in the northern part of Indiana.

The table below reconciles revenue disaggregation by customer class to segment revenue as well as to revenues reflected on the Condensed Statements of Consolidated Income (Loss) (unaudited):

Three Months Ended September 30, 2018 (in millions)	Gas Distribution Operations		Electric Operations		Corporate and Other		Total
Customer Revenues(1)
Residential	$	257.0	$	154.7	$	—	$	411.7
Commercial	80.9		140.7		—		221.6
Industrial	39.0		153.6		—		192.6
Off-system	20.4		—		—		20.4
Miscellaneous	9.2		0.1		0.2		9.5
Total Customer Revenues	$	406.5	$	449.1	$	0.2	$	855.8
Other Revenues	12.1		27.1		—		39.2
Total Operating Revenues	$	418.6	$	476.2	$	0.2	$	895.0

⁽¹⁾ Customer revenue amounts exclude intersegment revenues. See Note 19, "Business Segment Information," for discussion of intersegment revenues.

Nine Months Ended September 30, 2018 (in millions)	Gas Distribution Operations		Electric Operations		Corporate and Other		Total
Customer Revenues(1)
Residential	$	1,540.3	$	382.3	$	—	$	1,922.6
Commercial	516.2		374.2		—		890.4
Industrial	161.3		468.1		—		629.4
Off-system	63.6		—		—		63.6
Miscellaneous	36.2		12.3		0.6		49.1
Total Customer Revenues	$	2,317.6	$	1,236.9	$	0.6	$	3,555.1
Other Revenues	30.2		67.5		—		97.7
Total Operating Revenues	$	2,347.8	$	1,304.4	$	0.6	$	3,652.8

⁽¹⁾ Customer revenue amounts exclude intersegment revenues. See Note 19, "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 nine months endedSeptember 30, 2018 are presented in the table below. We had no significant contract assets or liabilities during the period. Additionally, we have not incurred any significant costs to obtain or fulfill contracts.

(in millions)	Customer Accounts Receivable, Billed (less reserve)(1)			Customer Accounts Receivable, Unbilled (less reserve)(2)
Balance as of December 31, 2017	$	477.0		$	356.0
Balance as of September 30, 2018	297.2			154.8
Increase (Decrease)	$	(179.8	)	$	(201.2	)

⁽¹⁾ Customer billed receivables decreased over the period due to the expected seasonal decrease in customer usage in September when compared to December.

⁽²⁾ Customer unbilled receivables decreased over the period due to the expected seasonal decrease in customer usage in September when compared to December.

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ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

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

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

Other Revenues. As permitted by accounting principles generally accepted in the United States, regulated utilities have the ability to earn certain types of revenue that are outside the scope of ASC 606. These revenues primarily represent revenue earned under Alternative Revenue Programs. Alternative Revenue Programs represent regulator-approved programs that allow for the adjustment of billings and revenue for certain broad, external factors, or for additional billings if the entity achieves certain objectives, such as a specified reduction of costs. We maintain a variety of these programs, including demand side management initiatives that recover costs associated with the implementation of energy efficiency programs, as well as normalization programs that adjust revenues for the effects of weather or other external factors. Additionally, we maintain certain programs with future test periods that operate similarly to FERC formula rate programs and allow for recovery of costs incurred to replace aging infrastructure. When the criteria to recognize Alternative Revenue have been met, we establish a regulatory asset and present revenue from Alternative Revenue Programs on the Condensed Statements of Consolidated Income (Loss) (unaudited) as “Other revenues.” When amounts previously recognized under Alternative Revenue accounting guidance are billed, we reduce the regulatory asset and record a customer account receivable.

4.    Earnings Per Share

Basic EPS is computed by dividing net income available 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. The computation of diluted average common shares for the three and nine months ended September 30, 2018 is not presented since we had a net loss on the Condensed Statements of Consolidated Income (Loss) (unaudited) during the periods, and any incremental shares would have had an anti-dilutive impact on EPS. The computation of diluted average common shares is as follows:

	Three Months Ended	Nine Months Ended
	September 30,	September 30,
(in thousands)	2017	2017
Denominator
Basic average common shares outstanding	331,139	326,662
Dilutive potential common shares:
Shares contingently issuable under employee stock plans	604	503
Shares restricted under employee stock plans	653	866
Diluted Average Common Shares	332,396	328,031

5.    Equity

ATM Program and Forward Sale Agreement. On May 3, 2017, we entered into four separate equity distribution agreements, pursuant to which we may sell, from time to time, up to an aggregate of $500.0 million of our common stock. As of September 30, 2018, the ATM program (including impacts of forward sales agreements discussed below) had $10.0 million of equity available for issuance. The program expires on December 31, 2018. The following table summarizes our activity under the ATM Program:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
Number of shares issued	—		10,612,915		—		11,931,376
Average price per share	$	—	$	26.67	$	—	$	26.58
Proceeds, net of fees (in millions)	$	—	$	281.0	$	—	$	314.7

On November 13, 2017, 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 November 13, 2017 to December 8, 2017, 6,345,860 shares were borrowed from third parties and sold by the dealer at a weighted average price of $27.24 per share. We may settle this agreement in shares, cash, or net shares by November 12, 2018. Had we settled all 6,345,860 shares under the forward agreement at September 30, 2018, we

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ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

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

would have received approximately $168.7 million, based on a net price of $26.59 per share.

Private Placement of Common Stock. On May 4, 2018, we completed the sale of 24,964,163 shares of $0.01 par value common stock at a price of $24.28 per share in a private placement to selected institutional and accredited investors. The private placement resulted in $606.0 million of gross proceeds or $599.6 million of net proceeds, after deducting commissions and sale expenses. The common stock issued in connection with the private placement was registered on Form S-1, filed with the SEC on May 11, 2018.

Private Placement of Preferred Stock. On June 11, 2018, we completed the sale of 400,000 shares of 5.650% Series A Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Stock (the "Series A Preferred Stock") at a price of $1,000 per share. The transaction resulted in $400.0 million of gross proceeds or $393.9 million of net proceeds, after deducting commissions and sales expenses. The Series A Preferred Stock was issued in a private placement pursuant to SEC Rule 144A. We agreed pursuant to a registration rights agreement to file with the SEC a registration statement enabling holders to exchange their unregistered shares of Series A Preferred Stock for publicly registered shares with substantially identical terms.

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

Dividends on the Series A Preferred Stock accrue and are cumulative from the date the shares of Series A Preferred Stock were originally issued to, but not including, June 15, 2023 at a rate of 5.650% per annum of the $1,000 liquidation preference per share. On and after June 15, 2023, dividends on the Series A Preferred Stock will accumulate for each five year period at a percentage of the $1,000 liquidation preference equal to the five-year U.S. Treasury Rate plus (i) in respect of each five year period commencing on or after June 15, 2023 but before June 15, 2043, a spread of 2.843% (the “Initial Margin”), and (ii) in respect of each five year period commencing on or after June 15, 2043, the Initial Margin plus 1.000%. The Series A Preferred Stock may be redeemed by us at our option on June 15, 2023, or on each date falling on the fifth anniversary thereafter, or in connection with a ratings event (as defined in the Certificate of Designation of the Series A Preferred Stock).

Holders of Series A Preferred Stock generally have no voting rights, except for limited voting rights with respect to (i) potential amendments to our certificate of incorporation that would have a material adverse effect on the existing preferences, rights, powers or duties of the Series A Preferred Stock, (ii) the creation or issuance of any security ranking on a parity with the Series A Preferred Stock if the cumulative dividends payable on then outstanding Series A Preferred Stock are in arrears, or (iii) the creation or issuance of any security ranking senior to the Series A Preferred Stock. The Series A Preferred Stock does not have a stated maturity and is not subject to mandatory redemption or any sinking fund. The Series A Preferred Stock will remain outstanding indefinitely unless repurchased or redeemed by us. Any such redemption would be effected only out of funds legally available for such purposes and will be subject to compliance with the provisions of our outstanding indebtedness.

6.    Asset Retirement Obligations

During 2018, we made revisions to the estimated costs associated with refining the CCR compliance plan. The CCR rule requires the continued collection of data over time to determine the specific compliance solution. The change in estimated costs resulted in an increase to the asset retirement obligation liability of $70.7 million that was recorded in 2018. See Note 16-C, "Environmental Matters," for additional information on CCRs.

7.    Regulatory Matters

Gas Distribution Operations Regulatory Matters

Cost Recovery and Trackers. Comparability of Gas Distribution Operations 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 operating costs of our distribution companies are significant, recurring in nature and generally outside the control of the distribution 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 distribution 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 and bad debt recovery mechanisms.

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ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

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

A portion of the distribution companies' 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.

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

Columbia of Ohio. On January 10, 2018, the PUCO issued an entry to investigate the impacts of the TCJA including an invitation to utilities and other interested stakeholders to file public comments including: (1) those components of utility rates that the PUCO will need to reconcile with the TCJA; and (2) the process and mechanics for how the PUCO should do so. The PUCO also directed utilities to record a regulatory liability for the estimated reduction in federal income tax resulting from the TCJA. On February 15, 2018, Columbia of Ohio filed comments proposing to: (1) reflect the impact of the TCJA on its application to adjust rates associated with its IRP rider, subsequently filed on February 27, 2018; and (2) file a reduction in other base rates reflecting the impact of the TCJA. The PUCO issued a procedural schedule on May 24, 2018 and a hearing was held on July 10, 2018. As discussed in further detail below, on October 25, 2018, Columbia of Ohio filed a joint stipulation and recommendation with the PUCO related to its CEP. Included in that stipulation were terms that would serve to resolve all remaining TCJA-related considerations for Columbia of Ohio.

On January 31, 2018, the PUCO approved Columbia of Ohio’s application to extend its IRP for an additional five years (2018-2022), allowing Columbia of Ohio to continue to invest and recover on its accelerated main replacements. The Office of the Ohio Consumers’ Counsel filed an application for rehearing asserting certain issues with Columbia of Ohio's application. On May 9, 2018, the PUCO issued an order denying the application for rehearing.

As referred to above, Columbia of Ohio filed its most recent application to adjust rates associated with its IRP rider on February 27, 2018, which requested authority to increase annual billings by approximately $2.3 million (net of the impact of the TCJA) reflecting recovery of and return on approximately $207 million of incremental IRP capital additions in 2017. A stipulation was filed with the PUCO on March 28, 2018. On April 25, 2018, the PUCO approved Columbia of Ohio’s annual IRP tracker adjustment with rates effective May 1, 2018.

On December 1, 2017, Columbia of Ohio filed an application that requested authority to implement a rider to begin recovering plant and associated deferrals related to its CEP. The CEP was established in 2011 and allows for deferral of interest, depreciation and property taxes on certain plant investments not recovered through its IRP modernization tracker. The application requested authority to increase annual revenues, through the requested rider, by approximately $70 million, with biennial increases up to approximately $98 million in 2022. On May 9, 2018, the PUCO appointed an independent auditor to assist the PUCO with the review of the accounting accuracy, prudency and compliance of Columbia of Ohio with its PUCO-approved CEP deferrals. The independent audit report was filed on September 4, 2018 and the PUCO Staff's Report on the investigation was filed on September 14, 2018. On October 25, 2018, a joint stipulation and recommendation was filed recommending an initial revenue requirement of $74.5 million to recover CEP investments and deferrals through December 31, 2017, with annual adjustments for capital investments made in subsequent years. Additionally, the signatory parties to the stipulation agreed to a reduction in rates to adjust for the impacts of the TCJA and for a base rate case filing to be made by Columbia of Ohio with a test period of calendar year 2021. A hearing on the stipulation is expected to occur on November 6, 2018.

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

On September 27, 2017, NIPSCO filed a base rate case with the IURC, seeking an annual revenue increase of $143.5 million (inclusive of amounts being recovered through various tracker programs). As part of this filing and among other items, NIPSCO proposed to update base rates for ongoing infrastructure improvements, revised depreciation rates and ongoing level of expenses to reflect the current costs of providing natural gas service. NIPSCO submitted a rebuttal on March 28, 2018 updating its request, including the impact of the TCJA, seeking a revised annual revenue increase of $138.1 million. On April 20, 2018, a settlement agreement was filed with the IURC seeking, among other items, an annual revenue increase of $107.3 million. An order approving

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ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

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

the settlement agreement, as filed, was issued by the IURC on September 19, 2018. Rates will be implemented in three steps, with implementation of step 1 rates effective October 1, 2018, reflecting an annual revenue increase of $84.3 million. Step 2 rates will be effective on or about March 1, 2019, and step 3 rates will be effective on January 1, 2020. The IURC’s order also approved NIPSCO’s dismissal from phase 2 of the IURC’s TCJA investigation.

On November 8, 2017, NIPSCO filed a petition with the IURC seeking approval of NIPSCO’s federally mandated pipeline safety compliance plan. As part of the aforementioned settlement agreement filed in NIPSCO’s gas base rate case proceeding, NIPSCO and the parties to the settlement agreement settled all issues in this proceeding as well, including moving certain costs from the base rate proceeding to this pipeline safety compliance plan. The updated four year compliance plan includes a total estimated $91.5 million of capital costs and $35.5 million of expected operating and maintenance costs. NIPSCO received approval for accounting and ratemaking relief, including establishment of a periodic rate adjustment mechanism. NIPSCO anticipates filing the first tracker proceeding in this case on or around December 1, 2018.

On April 30, 2013, the Governor of Indiana signed Senate Enrolled Act 560, the TDSIC statute, into law. Among other provisions, this legislation provides for cost recovery outside of a base rate proceeding for new or replacement electric and gas transmission, distribution and storage projects that a public utility undertakes for the purposes of safety, reliability, system modernization or economic development. Provisions of the TDSIC statute require that, among other things, requests for recovery include a seven-year plan of eligible investments. Once the plan is approved by the IURC, eighty percent of eligible costs can be recovered using a periodic rate adjustment mechanism. The cost recovery mechanism is referred to as a TDSIC mechanism. Recoverable costs include a return on, and of, the investment, including AFUDC, post-in-service carrying charges, operation and maintenance expenses, depreciation and property taxes. The remaining twenty percent of recoverable costs are to be deferred for future recovery in the public utility’s next general rate case. The periodic rate adjustment mechanism is capped at an annual increase of no more than two percent of total retail revenues. On April 2, 2018, NIPSCO filed a new seven-year gas TDSIC plan with the IURC beginning in 2019 seeking approval of a total capital expenditure level of approximately $1.25 billion. On September 4, 2018, the IURC dismissed the filing without prejudice. The initial seven-year gas TDSIC plan, approving a total capital expenditure level of approximately $767 million remains in effect as approved by the IURC in April 2014. A new seven-year gas TDSIC plan may be filed with IURC once the considerations in the pending TDSIC tracker appeal discussed below are resolved.

On February 27, 2018, NIPSCO filed TDSIC-8 requesting to recover an incremental increase to revenue of $0.8 million (net of the impacts of TCJA) associated with incremental capital investment of $77.9 million made in the second half of 2017. On June 20, 2018, the Indiana Supreme Court issued an order reversing the IURC and the Court of Appeals in NIPSCO’s gas TDSIC-4 proceeding. The Indiana Supreme Court order stated that periodic rate increases are available only for specific projects designated in the threshold proceeding and multiple-unit-projects not identified with particularity are not recoverable through the tracker. In the second quarter of 2018, NIPSCO recorded a liability of $2.5 million associated with the TDSIC-4 through TDSIC-8 filings for a related passback of revenue previously billed to customers. A revised TDSIC-8 was filed on July 18, 2018 and reduced the previous February 27, 2018 request by $0.2 million associated with incremental capital investment of approximately $54 million. On August 22, 2018, the IURC issued an order approving the requested rates, subject to refund. On August 28, 2018, NIPSCO filed TDSIC-9 requesting an incremental decrease to revenue of $0.5 million associated with incremental capital investment of $72.9 million through June 30, 2018. The filing included the pass back of the revenue associated with multiple-unit-projects from prior TDSIC filings and the pass back of TCJA revenues of $7.1 million for associated tax expense collected from January 1, 2018 through April 30, 2018. On September 26, 2018, NIPSCO filed a revised TDSIC-9 decreasing the requested revenue amount by an additional $7.6 million to reflect assets being included in the base rate amounts for the step 1 rate implementation discussed above. An IURC order is expected in the fourth quarter of 2018.

Columbia of Massachusetts. On February 2, 2018, the Massachusetts DPU opened an investigation into the effect of the reduction in federal income tax rates on the rates charged by utility companies. Columbia of Massachusetts was directed to account for any revenues associated with the difference between previous and current income tax rates and excess deferred income taxes as regulatory liabilities effective January 1, 2018. Companies were ordered to submit a proposal to revise rates by May 1, 2018. The order indicates that if a company files a base rate case prior to the conclusion of the investigation, it must address the TCJA issues as part of the case. Since CMA filed a base rate case on April 13, 2018, the changes in base rates and the regulatory liability disposition related to the TCJA are reflected in the case. On June 29, 2018, the Massachusetts DPU required companies in a rate case to reduce rates as of July 1, 2018 or, in the alternative, defer this rate reduction to coincide with the effective date of new rates in a rate case, provided that tax savings from July 1, 2018 through the effective date of new rates accrue interest at prime rate. On July 2, 2018, Columbia of Massachusetts filed tariffs reflecting revised rates incorporating the lower federal corporate income tax rate for effect July 1, 2018. In the filing, Columbia of Massachusetts noted the Massachusetts DPU stated it would address the refund of any tax savings accrued from January 1, 2018, through June 30, 2018, in a separate phase of its investigation. On July

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ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

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

10, 2018, the Massachusetts DPU approved the tariffs effective July 1, 2018, finding the adjustment is in the public interest, as it provides an immediate benefit to ratepayers.

As noted above, on April 13, 2018, Columbia of Massachusetts filed a rate case with the Massachusetts DPU, seeking approval for an annual revenue increase of approximately $43.8 million which is offset by revenue decreases in other rate factors of $19.7 million, representing a net increase in operating revenues of $24.1 million. Included in the filing was a proposal to adjust rates and address the regulatory liability disposition related to the TCJA. As a result of the incident that occurred on September 13, 2018, involving a series of fires and explosions that occurred in Lawrence, Andover and North Andover, Massachusetts related to the delivery of natural gas by Columbia of Massachusetts (the “Greater Lawrence Incident”), Columbia of Massachusetts filed a motion with the Massachusetts DPU on September 19, 2018, seeking to withdraw its petition for a base rate revenue increase in the interest of focusing its efforts on the on-going service restoration and customer assistance in the area. Refer to Note 16, "Other Commitments and Contingencies," in the Notes to Condensed Consolidated Financial Statements (unaudited) for additional information regarding the Greater Lawrence Incident. On October 9, 2018, Columbia of Massachusetts filed an application with the Massachusetts DPU, seeking authority to pass back approximately $95.8 million in excess deferred taxes with an effective date of rates to be determined by the Massachusetts DPU.

On July 7, 2014, the Governor of Massachusetts signed into law Chapter 149 of the Acts of 2014, An Act Relative to Natural Gas Leaks (“the Act”). The Act authorizes natural gas distribution companies to file gas infrastructure replacement plans with the Massachusetts DPU to address the replacement of aging natural gas pipeline infrastructure. In addition, the Act provides that the Massachusetts DPU may, after review of the plans, allow the proposed estimated costs of the plan into rates as of May 1 of the subsequent year. On October 31, 2017, Columbia of Massachusetts filed its GSEP for the 2018 construction year which proposed to recover incremental revenue of $9.7 million associated with incremental capital investment of $83.9 million to be made during calendar year 2018. The filing included a request for approval of a waiver to allow collection of the $3.1 million revenue requirement that exceeds the GSEP cap provision. On January 29, 2018, Columbia of Massachusetts filed a revision to its GSEP tracker for the 2018 construction season reducing the proposed revenue requirement by $2.4 million to reflect the impact of the TCJA. On June 21, 2018, the Massachusetts DPU issued an order granting the waiver on the revenue cap allowing an incremental revenue requirement of $6.5 million with new rates effective July 1, 2018. On October 31, 2018, Columbia of Massachusetts filed its GSEP for the 2019 construction year, proposing to recover an incremental revenue requirement of $10.7 million associated with incremental capital of $64.0 million. The filing included a request for approval of a waiver to allow collection of the $2.9 million revenue requirement that exceeds the GSEP cap provision. An order is expected from the Massachusetts DPU in the second quarter of 2019, with new rates effective May 1, 2019.

Columbia of Pennsylvania. On February 12, 2018, the Pennsylvania PUC established a docket to investigate the impact of the TCJA on customer rates. The Pennsylvania PUC directed Pennsylvania utilities to account for any revenues associated with the difference between previous and current income tax rates and excess deferred taxes as regulatory liabilities effective January 1, 2018. On May 17, 2018, the Pennsylvania PUC issued an order directing utilities that do not have a pending rate case to implement a negative surcharge in their billings to reflect the annual reduction in federal tax expense and associated revenue requirement for each utility, effective July 1, 2018.

On March 16, 2018, Columbia of Pennsylvania filed a rate case with the Pennsylvania PUC, incorporating the impacts of the TCJA and seeking approval for an annual revenue increase of $46.9 million. On March 21, 2018, Columbia of Pennsylvania filed a supplement to the rate case, under which it proposed to hold the overcollection of taxes during 2018 until the effective date of new base rates as credit to rate base for a period beginning January 2019 not to exceed three years. On August 31, 2018 a partial settlement was filed with the Pennsylvania PUC which included a revenue increase of $26.0 million and provided for the TCJA federal tax expense reduction of $22.5 million to be returned to customers over an 18 month period beginning December 16, 2018. On September 18, 2018 the administrative law judge issued a recommended decision approving the partial settlement without modification. A final order is expected in the fourth quarter of 2018 with new rates anticipated to be implemented in December 2018.

Columbia of Virginia. On January 8, 2018, the VSCC issued an order regarding the TCJA requiring Columbia of Virginia and other Virginia utilities subject to the TCJA to accrue regulatory liabilities reflecting the impacts of the reduced corporate income tax rate effective January 1, 2018. On August 28, 2018 Columbia of Virginia filed a request with the VSCC requesting a $22.2 million increase in base rates. The filing seeks to recover costs associated with ongoing infrastructure investment programs and incorporates the impacts of the TCJA. Columbia of Virginia proposed that the TCJA regulatory liability associated with lower federal income tax expense accrued prior to the implementation of new rates be considered in future VSCC reviews that assess earnings for the associated time period. Rates will be implemented on an interim basis, subject to refund, effective February 1, 2019, with a final order expected from the VSCC in the second half of 2019.

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ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

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

Columbia of Kentucky. On January 26, 2018, in accordance with the Kentucky PSC investigation related to the TCJA, Columbia of Kentucky filed testimony and proposed a reduction to base rates effective May 1, 2018, to reflect the tax expense reduction as a result of the TCJA. Columbia of Kentucky was directed to account for any revenues associated with the difference between previous and current income tax rates and excess deferred taxes as regulatory liabilities effective January 1, 2018. Columbia of Kentucky proposed to include the impact of the excess deferred taxes in rates effective October 2018 and to return the revenue related to the regulatory liability subsequent to this date. On April 30, 2018 Columbia of Kentucky received an order from the Kentucky PSC requiring implementation of interim proposed rates that are subject to future adjustment effective May 1, 2018. The order directed Columbia of Kentucky to file, by September 1, 2018, revised TCJA adjustment factors reflecting the tax expense savings from January 1, 2018, through April 30, 2018, and an estimate of the annual reduction due to the excess deferred taxes to be effective with the first billing cycle of October 2018. On August 31, 2018, Columbia of Kentucky filed updated rate schedules with the Kentucky PSC for rates proposed to be effective October 1, 2018. On September 27, 2018, Columbia of Kentucky received a PSC order suspending the filing for five months. No procedural time line beyond the five month suspension period has been set.

On October 15, 2018, Columbia of Kentucky filed an application to adjust rates associated with its AMRP, requesting authority to increase annual revenues by $3.6 million associated with incremental capital investment of $30.1 million to be made during calendar year 2019. An order is anticipated from the Kentucky PSC in December 2018, with new rates effective January 2019.

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

On April 13, 2018, Columbia of Maryland filed a request with the Maryland PSC to increase base rates by $6.1 million, inclusive of the impacts of the TCJA. On July 31, 2018, Columbia of Maryland filed a settlement with the Maryland PSC. If approved as filed, the settlement would result in an annual revenue increase of $3.7 million. On October 2, 2018, the assigned judge issued a proposed order which recommended that the settlement be approved. A final order from the Maryland PSC is expected in the fourth quarter of 2018 with rates anticipated to be effective November 2018.

On April 6, 2018, Columbia of Maryland filed an application requesting authority to extend its STRIDE plan for an additional five years (2019-2023). The proposed order issued on August 28, 2018 was not appealed or modified and therefore it became final on September 28, 2018.

Electric Operations Regulatory Matters

Cost Recovery and Trackers. Comparability of Electric Operations 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 result in a corresponding increase in operating revenues and therefore have essentially no impact on total operating income results.

Certain operating costs of the Electric Operations are significant, recurring in nature, and generally outside the control of NIPSCO. The IURC allows for recovery of such costs through cost tracking mechanisms. Such tracking mechanisms allow for abbreviated regulatory proceedings in order for NIPSCO 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 electric energy efficiency programs, MISO non-fuel costs and revenues, resource capacity charges, federally mandated costs and environmental-related costs.

A portion of NIPSCO's 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.

As noted above in the NIPSCO Gas regulatory matters, the IURC initiated an investigation on January 3, 2018, to review and consider the implications of the TCJA on utility rates. The commission ordered a two phase investigation. Phase 1 solely dealt with the prospective changes in rates to reflect the change in tax rates. On March 26, 2018, NIPSCO filed revised electric tariffs reflecting the impact of the change in tax rate for its applicable rates and charges. The IURC approved NIPSCO's phase 1 filing on April 26, 2018. The revised tariffs were effective May 1, 2018. On July 31, 2018, NIPSCO filed an unopposed motion requesting that the over-collection of income taxes from January 1, 2018 through April 30, 2018 be passed back in NIPSCO’s TDSIC-4 filing, also filed on July 31, 2018, and requesting that all other phase 2 issues be handled in a rate case filing to be made in the fourth

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ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

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

quarter of 2018. On August 15, 2018, the IURC approved the motion to pass back the over-collection and stated that all other phase 2 issues will be addressed in the to-be-filed base rate case, as discussed below.

On October 31, 2018 NIPSCO filed a request for an increase in base rates with the IURC for a proposed $21.4 million increase in revenues in part, to address anticipated revenue loss resulting from the WCE filing discussed below, as well as to address phase 2 issues of the TCJA. The filing also addresses the appropriate depreciation rates for the accelerated retirement of NIPSCO’s aging coal fleet, as discussed in the 2018 Integrated Resource Plan below. An order is expected from the IURC in the third quarter of 2019 with rates anticipated to be effective September 2019.

Also on October 31, 2018, NIPSCO submitted its 2018 Integrated Resource Plan with the IURC. The plan evaluated demand-side and supply-side resource alternatives to reliably and cost effectively meet NIPSCO customers' future energy requirements over the ensuing 20 years. Refer to Note 16-D, "Other Matters," in the Notes to Condensed Consolidated Financial Statements (unaudited) for additional information.

On March 29, 2018, WCE, which is currently owned by BP p.l.c ("BP") and BP Products North America, which operates the BP Refinery, filed a petition at the IURC asking that the combined operations of WCE and BP be treated as a single premise, and the WCE generation be dedicated primarily to BP Refinery operations beginning in May 2019 as WCE has self-certified as a qualifying facility at FERC. BP Refinery planned to continue to purchase electric service from NIPSCO at a reduced demand level beginning in May 2019. NIPSCO is currently in discussions with BP.

On January 30, 2018, NIPSCO made a TDSIC-3 rate adjustment mechanism filing requesting a revenue decrease of $1.8 million to be billed over six months, associated with $75.0 million of incremental capital expenditures made from May 1, 2017 to November 30, 2017. The decrease was due to the impact of the TCJA as well as a shorter billing period compared to TDSIC-2. TDSIC-3 was approved on May 30, 2018 and became effective for the first billing cycle of June. Additionally, the TDSIC-2 rates revised for tax reform approved as a part of NIPSCO’s Phase 1 filing described above were made effective on May 1, 2018, until TDSIC-3 rates went into effect. The impact of TCJA on TDSIC-2 was an approximate decrease in revenue of $1.2 million for the period from January through May 2018. NIPSCO made a TDSIC-4 rate adjustment mechanism filing on July 31, 2018, which was modified on October 25, 2018, seeking an incremental semi-annual revenue decrease of $11.2 million due primarily to the pass back of a $14.1 million TCJA electric base rate customer refund for the period January through May 2018. The TCJA refund offsets a $2.8 million increase associated with $72.2 million of incremental capital expenditures from December 2017 through May 2018. An order approving the request is expected in the fourth quarter of 2018.

On February 1, 2018, NIPSCO and certain other MISO transmission owners filed with the FERC a request for waiver of tariff provisions to allow for implementation of TCJA provisions into 2018 transmission formula rates as soon as possible. On March 15, 2018, the FERC issued an order granting the request for waiver and set the effective date of the waiver at January 1, 2018. In the March billing cycle, the MISO began billing the new transmission rates reflecting the lower federal tax rate. In addition, the MISO began to re-bill January and February 2018 affected revenues and costs in the March 2018 billing cycle, and completed the re-settlement in the April 2018 billing cycle. The new 2018 transmission formula rates will lower revenue by approximately $8.5 million in 2018 associated with NIPSCO's multi-value projects.

Material Updates to Regulatory Assets and Liabilities Since December 31, 2017

TCJA-Related Regulatory Liabilities.As referenced above, during the nine months ended September 30, 2018, we recorded additional TCJA-related regulatory liabilities of $69.9 million to reflect 2018 collections from customers which we believe are probable of being refunded back to customers once new customer rates are approved by our regulators.

As discussed in Note 12, "Income Taxes," in 2018 we began amortizing regulatory liabilities associated with excess deferred taxes, which resulted in a $6.8 million and $24.6 million income tax benefit for the three and nine months ended September 30, 2018, respectively. Related to this activity, we recorded an offsetting reserve of $3.6 million and $15.9 million (net of tax) in "Customer revenues" to reflect the probable future passback of this earnings benefit to customers for the three and nine months ended September 30, 2018, respectively. In certain jurisdictions, we received additional regulatory guidance on the treatment and passback period of excess deferred income taxes, indicating that such a reserve was not required as of September 30, 2018.

Bailly Generating Station. On February 1, 2018, as previously approved by the MISO, NIPSCO commenced a four-month outage of Bailly Generating Station Unit 8 in order to begin work on converting the unit to a synchronous condenser (a piece of equipment designed to maintain voltage to ensure continued reliability on the transmission system). Approximately $15 million of net book value of Unit 8 remained in “Net Utility Plant” as it is expected to remain used and useful upon completion of the synchronous condenser, while the remaining net book value of approximately $142 million was reclassified to “Regulatory assets (noncurrent)”

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ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

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

on the Condensed Consolidated Balance Sheets (unaudited). On May 31, 2018, Units 7 and 8 were retired from service. As a result, the remaining net book value of Unit 7 of approximately $103 million was reclassified to “Regulatory assets (noncurrent)” on the Condensed Consolidated Balance Sheets (unaudited).These amounts continue to be amortized at a rate consistent with their inclusion in customer rates.

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.

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

(in millions)	September 30, 2018		December 31, 2017
Risk Management Assets - Current(1)
Interest rate risk programs	$	21.4	$	14.0
Commodity price risk programs	1.0		0.5
Total	$	22.4	$	14.5
Risk Management Assets - Noncurrent(2)
Interest rate risk programs	$	32.6	$	5.6
Commodity price risk programs	2.6		1.0
Total	$	35.2	$	6.6
Risk Management Liabilities - Current
Interest rate risk programs	$	—	$	38.6
Commodity price risk programs	4.8		4.6
Total	$	4.8	$	43.2
Risk Management Liabilities - Noncurrent
Interest rate risk programs	$	—	$	—
Commodity price risk programs	45.2		28.5
Total	$	45.2	$	28.5

⁽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).

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 twenty percent of NIPSCO’s average annual GCA purchase volume. Gains and losses on these derivative contracts are deferred as regulatory liabilities or assets and are remitted to or collected from customers through NIPSCO’s quarterly GCA mechanism. These instruments are not designated as accounting hedges.

Interest Rate Risk Management

As of September 30, 2018, we have forward-starting interest rate swaps with an aggregate notional value totaling $750.0 million to hedge the variability in cash flows attributable to changes in the benchmark interest rate during the periods from the effective dates of the swaps to the anticipated dates of forecasted debt issuances, which are expected to take place by the end of 2019. These interest rate swaps are designated as cash flow hedges. The effective portions of the gains and losses related to these swaps are

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ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

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

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 April 2018, we settled forward-starting interest rate swaps with a notional value of $250.0 million. These derivative contracts were accounted for as cash flow hedges. As part of the transaction, the associated net unrealized gain of $21.2 million was recognized immediately in "Other, net" on the Condensed Statements of Consolidated Income (Loss) (unaudited) due to the probability associated with the forecasted borrowing transaction no longer occurring.

There were no amounts excluded from effectiveness testing for derivatives in cash flow hedging relationships at September 30, 2018 and December 31, 2017.

Our derivative instruments measured at fair value as of September 30, 2018 and December 31, 2017 do not contain any credit-risk-related contingent features.

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 September 30, 2018 and December 31, 2017:

Recurring Fair Value Measurements September 30, 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 September 30, 2018
Assets
Risk management assets	$	—	$	57.6	$	—	$	57.6
Available-for-sale securities	—		143.8		—		143.8
Total	$	—	$	201.4	$	—	$	201.4
Liabilities
Risk management liabilities	$	—	$	50.0	$	—	$	50.0
Total	$	—	$	50.0	$	—	$	50.0

Recurring Fair Value Measurements December 31, 2017 (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, 2017
Assets
Risk management assets	$	—	$	21.1	$	—	$	21.1
Available-for-sale securities	—		133.9		—		133.9
Total	$	—	$	155.0	$	—	$	155.0
Liabilities
Risk management liabilities	$	—	$	71.4	$	0.3	$	71.7
Total	$	—	$	71.4	$	0.3	$	71.7

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

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ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

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

derivatives are classified within Level 2. Non-exchange-based derivative instruments include swaps, forwards, options and treasury lock agreements. 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 September 30, 2018 and December 31, 2017, 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 September 30, 2018 and December 31, 2017 were:

September 30, 2018 (in millions)	Amortized Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
Available-for-sale securities
U.S. Treasury debt securities	$	29.7	$	—	$	(0.2	)	$	29.5
Corporate/Other debt securities	116.8		0.4		(2.9		)	114.3
Total	$	146.5	$	0.4	$	(3.1	)	$	143.8
December 31, 2017 (in millions)	Amortized Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
Available-for-sale securities
U.S. Treasury debt securities	$	26.9	$	—	$	(0.1	)	$	26.8
Corporate/Other debt securities	106.8		0.9		(0.6		)	107.1
Total	$	133.7	$	0.9	$	(0.7	)	$	133.9

Realized gains and losses on available-for-sale securities were immaterial for the three and nine months ended September 30, 2018 and 2017.

The cost of maturities sold is based upon specific identification. At September 30, 2018, approximately $14.9 million of U.S. Treasury debt securities and approximately $3.0 million of Corporate/Other debt securities have maturities of less than a year.

There are no material items in the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis for the three and nine months ended September 30, 2018 and 2017.

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ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

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

Non-recurring Fair Value Measurements. There were no significant non-recurring fair value measurements recorded during the three and nine months ended September 30, 2018.

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 nine months endedSeptember 30, 2018, there was no change in the method or significant assumptions used to estimate the fair value of long-term debt.

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

(in millions)	Carrying Amount as of September 30, 2018		Estimated Fair Value as of September 30, 2018		Carrying Amount as of Dec. 31, 2017		Estimated Fair Value as of Dec. 31, 2017
Long-term debt (including current portion)	$	7,143.1	$	7,280.1	$	7,796.5	$	8,603.4

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 March 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 September 30, 2018, the maximum amount of debt that could be recognized related to our accounts receivable programs is $265.0 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 September 30, 2018 and December 31, 2017:

(in millions)	September 30, 2018		December 31, 2017
Gross Receivables	$	410.9	$	635.3
Less: Receivables not transferred	145.9		298.6
Net receivables transferred	$	265.0	$	336.7
Short-term debt due to asset securitization	$	265.0	$	336.7

For the nine months ended September 30, 2018 and 2017, $71.7 million and $47.8 million, respectively, was recorded as cash flows used for financing activities related to the change in short-term borrowings due to securitization transactions. Fees associated with the securitization transactions were $0.4 million and $0.6 million for the three months ended September 30, 2018 and 2017, respectively, and $1.9 million for the nine months ended September 30, 2018 and 2017, respectively. We remain responsible for collecting on the receivables securitized, and the receivables cannot be transferred to another party.

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ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

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

11.Goodwill

The following presents our goodwill balance allocated by segment as of September 30, 2018:

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

We applied the qualitative "step 0" analysis 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.

In the third quarter of 2018, we determined the Greater Lawrence Incident (see FN 16, "Other Commitments and Contingencies") represents a triggering event that requires an impairment analysis of goodwill. This incident specifically impacts our Columbia of Massachusetts reporting unit in which the associated goodwill totaled $204.8 million immediately prior to the incident. We performed a quantitative impairment analysis as of September 30, 2018 and determined that the fair value of the Columbia of Massachusetts reporting unit continues to exceed its carrying value. Therefore, no goodwill impairment charges were recorded in the third quarter of 2018. This interim analysis was performed using updated cash flow projections reflecting the estimated ongoing impacts of the Greater Lawrence Incident on Columbia of Massachusetts' operations. We also updated other significant inputs to the fair value calculation (e.g. discount rate, market multiples) to reflect current market conditions and the increased risk and uncertainty resulting from the incident. We will continue to monitor the impacts of the Greater Lawrence Incident for events that could trigger a new impairment analysis including, but not limited to, unfavorable regulatory outcomes, extended customer impacts, and NTSB investigation results.

12.    Income Taxes

Our interim effective tax rates reflect the estimated annual effective tax rates for 2018 and 2017, adjusted for tax expense associated with certain discrete items. The effective tax rates for the three months ended September 30, 2018 and 2017 were 21.8% and 15.2%, respectively. The effective tax rates for the nine months endedSeptember 30, 2018 and 2017 were 40.3% and 34.9%, respectively. These effective tax rates differ from the federal statutory tax rate of 21% in 2018 and 35% in 2017, primarily due to the effects of tax credits, state income taxes, utility ratemaking and other permanent book-to-tax differences.

The increase in the three month effective tax rate of 6.6% in 2018 compared to 2017 is due to state tax apportionment benefits recorded in the third quarter of 2017 that were not recorded in the current year period along with the impact of the Greater Lawrence Incident on consolidated state income taxes. These increases were partially offset by the change in the federal statutory rate due to the enactment of the TCJA.

The increase in the nine month effective tax rate of 5.4% in 2018 versus the same period in 2017 is primarily due to the impact of the Greater Lawrence Incident on consolidated state income taxes, partially offset by the change in the federal statutory rate due to the enactment of the TCJA.

In 2018 we began amortizing a portion of our regulatory liability associated with excess deferred taxes which resulted in a current year income tax benefit of $6.8 million and $24.6 million for the three and nine months ended September 30, 2018, respectively. Additionally, we continue to work with the public utility commissions in each of our seven states on the appropriate treatment and resolution of TCJA impacts. Final regulatory orders from our public utility commissions in ongoing proceedings may decrease our TCJA-related regulatory liabilities by up to approximately $150 million. Such decreases would be recorded in the period the respective orders are received. Refer to Note 7, "Regulatory Matters," for additional information.

There were no material changes recorded in 2018 to our uncertain tax positions as of December 31, 2017.

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

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ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

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

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 nine months ended September 30, 2018, we contributed $2.1 million to our pension plans and $16.8 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 and nine months ended September 30, 2018 and 2017:

	Pension Benefits						Other Postretirement Benefits
Three Months Ended September 30, (in millions)	2018			2017			2018			2017
Components of Net Periodic Benefit Cost(1)
Service cost	$	7.8		$	7.4		$	1.3		$	1.2
Interest cost	16.8			17.1			4.4			4.4
Expected return on assets	(35.4		)	(30.8		)	(3.7		)	(3.9		)
Amortization of prior service credit	(0.1		)	(0.1		)	(1.0		)	(1.1		)
Recognized actuarial loss	10.2			13.2			0.9			0.7
Settlement loss	8.3			10.6			—			—
Total Net Periodic Benefit Cost	$	7.6		$	17.4		$	1.9		$	1.3

⁽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 (Loss) (unaudited).

	Pension Benefits						Other Postretirement Benefits
Nine Months Ended September 30, (in millions)	2018			2017			2018			2017
Components of Net Periodic Benefit Cost(1)
Service cost	$	23.6		$	22.4		$	3.9		$	3.6
Interest cost	50.0			51.5			13.2			13.4
Expected return on assets	(107.9		)	(91.3		)	(11.1		)	(11.9		)
Amortization of prior service credit	(0.3		)	(0.5		)	(3.0		)	(3.3		)
Recognized actuarial loss	30.6			40.0			2.7			2.2
Settlement loss	11.8			10.6			—			—
Total Net Periodic Benefit Cost	$	7.8		$	32.7		$	5.7		$	4.0

⁽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 (Loss) (unaudited).

As of May 31, 2018, two of our qualified pension plans paid lump sums in excess of the respective plan's 2018 service cost plus interest cost, thereby meeting the requirement for settlement accounting. A settlement charge of $3.5 million was recorded during the second quarter of 2018. As a result of these settlements, the two pension plans were remeasured. The remeasurements led to an increase to the pension benefit obligation, net of plan assets, of $1.1 million, a net decrease to regulatory assets of $2.3 million, and a net credit to accumulated other comprehensive income (loss) of $0.1 million. Net periodic pension benefit cost for 2018 increased by $1.1 million as a result of the second quarter remeasurement.

As of August 31, 2018, an additional qualified pension plan paid lump sums in excess of its 2018 service cost plus interest cost, thereby meeting the requirement for settlement accounting. A settlement charge of $8.3 million was recorded during the third quarter of 2018. As a result of this settlement, the plan was remeasured, leading to a decrease to the net pension asset of $2.5 million, a net decrease to regulatory assets of $5.3 million, and a net credit to accumulated other comprehensive income (loss) of $0.5 million. Net periodic pension benefit cost for 2018 increased by $1.9 million as a result of the third quarter remeasurement.

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ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

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

The following table provides the key assumptions that were used to calculate the pension benefit obligation and the net periodic benefit cost for the plans that triggered settlement accounting at the measurement dates of August 31, 2018, May 31, 2018 and December 31, 2017:

	August 31, 2018		May 31, 2018		December 31, 2017
Weighted-average Assumption to Determine Benefit Obligation:
Discount rate	4.08	%	4.03	%	3.58	%
Weighted-average Assumptions to Determine Net Periodic Benefit Costs for the period ended:
Discount rate - service cost	3.79	%	3.79	%	4.40	%
Discount rate - interest cost	3.15	%	3.15	%	3.31	%
Expected return on assets	6.30	%	6.30	%	7.25	%

14.    Long-Term Debt

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

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

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

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

15.    Short-Term Borrowings

We generate short-term borrowings from our revolving credit facility, commercial paper program, letter of credit issuances, 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. At September 30, 2018 and December 31, 2017, 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 $746.0 million and $869.0 million of commercial paper outstanding as of September 30, 2018 and December 31, 2017, respectively.

As of September 30, 2018 and December 31, 2017, we had $10.2 million and $11.1 million of stand-by letters of credit, respectively. All stand-by letters of credit were under the revolving credit facility.

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 $265.0 million in transfers as of September 30, 2018 and $336.7 million as of December 31, 2017. Refer to Note 10, "Transfers of Financial Assets," for additional information.

On April 18, 2018, we entered into a multiple-draw $600.0 million term loan agreement with a syndicate of banks led by MUFG Bank, Ltd. The term loan matures April 17, 2019, at which point any and all outstanding borrowings under the agreement are due. Interest charged on borrowings depends on the variable rate structure we elected at the time of each borrowing. Under the agreement, we borrowed an initial tranche of $150.0 million on April 18, 2018 with an interest rate of LIBOR plus 50 basis points and a second tranche of $450.0 million on May 31, 2018 with an interest rate of LIBOR plus 55 basis points.

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ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

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

Short-term borrowings were as follows:

(in millions)	September 30, 2018		December 31, 2017
Commercial paper weighted-average interest rate of 2.57% and 1.97% at September 30, 2018 and December 31, 2017, respectively	$	746.0	$	869.0
Accounts receivable securitization facility borrowings	265.0		336.7
Term loan weighted-average interest rate of 2.79% at September 30, 2018	600.0		—
Total Short-Term Borrowings	$	1,611.0	$	1,205.7

Other than for the term loan, 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.

16.    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 September 30, 2018 and December 31, 2017, we had issued stand-by letters of credit of $10.2 million and $11.1 million, respectively.

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 (referred to herein as the “Greater Lawrence Incident”). The Greater Lawrence Incident resulted in one fatality and a number of injuries, damaged multiple homes and businesses, and caused the temporary evacuation of significant portions of each municipality. The Massachusetts Governor’s office declared a state of emergency, authorizing the Massachusetts DPU to order another utility company to coordinate the restoration of utility services in Lawrence, Andover and North Andover. The incident resulted in the interruption of gas and other utility service for approximately 8,500 gas meters, of which approximately 700 serve businesses. Columbia of Massachusetts is currently in the process of replacing the cast iron and bare steel gas pipeline system to restore service to these meters. See “ - D. Other Matters - Greater Lawrence Pipeline Replacement” below for more information.

The NTSB is investigating the Greater Lawrence Incident. The parties to the investigation include the PHMSA, the Massachusetts DPU, Columbia of Massachusetts, and police and fire first responders. The Company and Columbia of Massachusetts 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 which appears to have been related to work being done on behalf of Columbia of Massachusetts on a pipeline replacement project in Lawrence. In addition, 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. While the NTSB investigation is pending, the Company and Columbia of Massachusetts are prohibited from disclosing information related to the investigation without approval from the NTSB.

The Massachusetts DPU has announced its intent to hire an independent evaluator to conduct a statewide examination of the safety of the natural gas distribution systems within 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 examination is expected to complement, but not duplicate, the NTSB’s investigation. Following the release of the NTSB's preliminary report, the Massachusetts DPU placed a moratorium on Columbia of Massachusetts, which prohibits the company from performing any work in the state through at least December 1, 2018. The ban does not apply to compliance and emergency work, including the restoration of service in Lawrence, Andover and North Andover.

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

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ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

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

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.

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. 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 implied warranty of merchantability, breach of contract and gross negligence, and seek punitive damages. Many residents and business owners have submitted individual damage claims to Columbia of Massachusetts. We also have received notice from two parties indicating an intent to assert wrongful death claims. 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 Company and Columbia of Massachusetts are subject to a criminal investigation 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.

During the quarter ended September 30, 2018, Columbia of Massachusetts expensed approximately $415 million for estimated third-party claims related to the Greater Lawrence Incident, including personal injury and property damage claims, damage to infrastructure, and other damage claims, which include mutual aid payments to other utilities assisting with the restoration effort, gas-fueled appliance replacement and related services for impacted customers, temporary lodging for displaced customers, and claims-related legal fees. We estimate that total costs related to third-party claims resulting from the incident will range from $415 million to $450 million, depending on the final outcome of open investigations and the number, nature, and value of third-party claims. We also expect to incur losses for third party business interruption claims, the costs for which are not included in the amounts disclosed above due to insufficient information to reasonably estimate the damages from such claims. The amounts set forth above do not include non-claims related expenses resulting from the incident or the estimated capital cost of the pipeline replacement, which are 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 information resulting from the NTSB investigation, management’s estimates and assumptions regarding the financial impact of the Greater Lawrence Incident may change.

Further, it is not possible at this time to reasonably estimate the amount of any fines, penalties or settlements with governmental authorities, including the Massachusetts DPU and other regulators, that the Company or Columbia of Massachusetts may incur in connection with the Greater Lawrence Incident. Therefore, the foregoing amounts do not include estimates for any such fines, penalties or settlements.

The current and noncurrent portions of the remaining liability as of September 30, 2018 are presented within “Claims accrued” and “Other noncurrent liabilities,” respectively, in the Company’s Condensed Consolidated Balance Sheets (unaudited). The expenses above are presented within “Operation and maintenance” in our Condensed Statement of Consolidated Income (unaudited).

The Company maintains liability insurance for damages in the approximate amount of $800 million. The Company and Columbia of Massachusetts believe that third-party claims related to the Greater Lawrence Incident will be substantially covered by this insurance, other than any fines, penalties or settlements with governmental authorities that the Company or Columbia of Massachusetts may incur. However, no amounts for insurance recoveries have been recorded as of September 30, 2018. The Company and Columbia of Massachusetts are currently unable to predict the amount and timing of insurance recoveries.

In addition, we are party to certain other claims and legal proceedings arising in the ordinary course of business, none of which are 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 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

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ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

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

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 September 30, 2018 and December 31, 2017, we had recorded a liability of approximately $107.1 million and $111.4 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" in the Condensed Consolidated Balance Sheets (unaudited). 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," below for additional information.

Air

The actions listed below could require further reductions in emissions from various emission sources. We will continue to closely monitor developments in these matters.

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 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 twelve 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 64 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 future remediation costs related to our 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

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ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

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

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 $103.3 million and $106.9 million at September 30, 2018 and December 31, 2017, 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 $25 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 is incurring capital expenditures to modify its infrastructure and manage CCRs. Capital compliance costs are currently expected to total approximately $193 million. 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.

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. The rule imposes new water treatment and discharge requirements on NIPSCO's electric generating facilities to be applied between 2018 and 2023. On April 25, 2017, the EPA published notice in the Federal Register that the EPA is reconsidering the ELG in response to several petitions for reconsideration. On September 18, 2017, the EPA postponed the earliest compliance dates for flue gas desulfurization wastewater and bottom ash transport water requirements from 2018 to 2020 to potentially consider revisions to technology and numeric limits achievable. NIPSCO is unable to estimate the financial impact of the EPA reconsideration at this time. Based upon a preliminary study of the November 3, 2015 final rule, capital compliance costs were expected to be approximately $170 million. However, NIPSCO does not anticipate material ELG compliance costs based on the most viable option for customers 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 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.

On October 31, 2018, NIPSCO submitted its 2018 Integrated Resource Plan to the IURC. The plan evaluated demand-side and supply-side resource alternatives to reliably and cost effectively meet NIPSCO customers' future energy requirements over the ensuing 20 years. 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. The replacement plan is still being defined, but currently points to renewable sources of energy, including wind, solar, and battery storage.

NIPSCO Pure Air. NIPSCO had a service agreement with Pure Air, a general partnership between Air Products and Chemicals, Inc. and First Air Partners LP, under which Pure Air provided scrubber services to reduce sulfur dioxide emissions for Units 7 and 8 at the Bailly Generating Station. Services under this contract commenced on July 1, 1992 and expired on June 30, 2012. The agreement was renewed effective July 1, 2012 for ten years, requiring NIPSCO to pay for the services under a combination of fixed and variable charges. We made an exhaustive effort to obtain information needed from Pure Air to determine the status of Pure Air as a VIE. However, NIPSCO was not able to obtain this information and, as a result, it was not determined whether Pure Air was a VIE and whether NIPSCO was the primary beneficiary. Payments under this agreement were $8.3 million and $16.5 million for the nine months endedSeptember 30, 2018 and 2017, respectively. In accordance with GAAP, the renewed agreement was evaluated to determine whether the arrangement qualified as a lease. Based on the terms of the agreement, the arrangement

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ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

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

qualified for capital lease accounting. As the effective date of the new agreement was July 1, 2012, we capitalized this lease beginning in the third quarter of 2012.

NIPSCO retired the generation station units serviced by Pure Air on May 31, 2018. In December 2016, as allowed by the provisions of the service agreement, NIPSCO provided Pure Air formal notice of intent to terminate the service agreement, effective May 31, 2018. Providing this notice to Pure Air triggered a contract termination liability of $16 million, which was recorded in fourth quarter of 2016. In connection with the closure of Bailly Units 7 and 8, NIPSCO paid the termination payment to Pure Air during the second quarter of 2018. Cash flows associated with this payment are presented within operating activities on the Condensed Statements of Consolidated Cash Flows (unaudited).

Greater Lawrence Incident Restoration. During the quarter ended September 30, 2018, Columbia of Massachusetts recorded a loss of approximately $460 million in connection with the Greater Lawrence Incident. This amount includes approximately $415 million for estimated third-party claims associated with the incident as described above in " - B. Legal Proceedings." The additional $45 million included in the loss recorded includes certain consulting costs, administration costs, charitable contributions, and other labor and related expenses in connection with the incident. We expect to incur a total of $180 million to $210 million in such incident-related costs, depending on the incurrence of future restoration work, substantially all of which we expect to incur by the end of 2018. The amounts set forth above do not include the estimated capital cost of the pipeline replacement, which is set forth below.

The Company maintains liability insurance for damages in the approximate amount of $800 million. The Company and Columbia of Massachusetts believe that third-party claims and other expenses related to the Greater Lawrence Incident will be substantially covered by insurance, other than any fines, penalties or settlements with governmental authorities that the Company or Columbia of Massachusetts may incur. However, no amounts for insurance recoveries have been recorded as of September 30, 2018. The Company and Columbia of Massachusetts are currently unable to predict the amount and timing of insurance recoveries.

The current and noncurrent portions of the remaining liability as of September 30, 2018 are presented within “Claims accrued” and “Other noncurrent liabilities,” respectively, in the Company’s Condensed Consolidated Balance Sheets (unaudited). Costs associated with charitable contributions are presented within “Other, Net” in our Condensed Statement of Consolidated Income (unaudited). All other losses incurred are presented within “Operation and maintenance.”

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 8,500 gas meters, of which approximately 700 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. Columbia of Massachusetts is aiming to restore gas service to all homes and workplaces by December 16, 2018. 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 has hired an outside contractor to serve as the Chief Recovery Officer for the Greater Lawrence Incident, responsible for command, control and communications. The estimated capital cost of the pipeline replacement is between $135 - $165 million. The recovery of this capital investment will be addressed in a future regulatory proceeding.

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ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

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

17.    Accumulated Other Comprehensive Income (Loss)

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

Three Months Ended September 30, 2018 (in millions)	Gains and Losses on Securities(1)			Gains and Losses on Cash Flow Hedges(1)			Pension and OPEB Items(1)			Accumulated Other Comprehensive Income (Loss)(1)
Balance as of July 1, 2018	$	(2.2	)	$	(1.7	)	$	(17.0	)	$	(20.9	)
Other comprehensive income before reclassifications	—			21.6			1.0			22.6
Amounts reclassified from accumulated other comprehensive loss	0.1			0.9			(0.2		)	0.8
Net current-period other comprehensive income	0.1			22.5			0.8			23.4
Balance as of September 30, 2018	$	(2.1	)	$	20.8		$	(16.2	)	$	2.5
Nine Months Ended September 30, 2018 (in millions)	Gains and Losses on Securities(1)			Gains and Losses on Cash Flow Hedges(1)			Pension and OPEB Items(1)			Accumulated Other Comprehensive Income (Loss)(1)
Balance as of January 1, 2018	$	0.2		$	(29.4	)	$	(14.2	)	$	(43.4	)
Other comprehensive income (loss) before reclassifications	(2.5		)	70.8			1.0			69.3
Amounts reclassified from accumulated other comprehensive loss(2)	0.2			(14.3		)	0.2			(13.9		)
Net current-period other comprehensive income (loss)	(2.3		)	56.5			1.2			55.4
Reclassification due to adoption of ASU 2018-02 (Refer to Note 2)	—			(6.3		)	(3.2		)	(9.5		)
Balance as of September 30, 2018	$	(2.1	)	$	20.8		$	(16.2	)	$	2.5

Three Months Ended September 30, 2017 (in millions)	Gains and Losses on Securities(1)			Gains and Losses on Cash Flow Hedges(1)			Pension and OPEB Items(1)			Accumulated Other Comprehensive (Loss)(1)
Balance as of July 1, 2017	$	0.4		$	(18.8	)	$	(17.2	)	$	(35.6	)
Other comprehensive income (loss) before reclassifications	0.1			(9.7		)	—			(9.6		)
Amounts reclassified from accumulated other comprehensive loss	—			0.4			1.1			1.5
Net current-period other comprehensive income (loss)	0.1			(9.3		)	1.1			(8.1		)
Balance as of September 30, 2017	$	0.5		$	(28.1	)	$	(16.1	)	$	(43.7	)
Nine Months Ended September 30, 2017 (in millions)	Gains and Losses on Securities(1)			Gains and Losses on Cash Flow Hedges(1)			Pension and OPEB Items(1)			Accumulated Other Comprehensive (Loss)(1)
Balance as of January 1, 2017	$	(0.6	)	$	(6.9	)	$	(17.6	)	$	(25.1	)
Other comprehensive income (loss) before reclassifications	1.1			(23.3		)	0.2			(22.0		)
Amounts reclassified from accumulated other comprehensive loss	—			2.1			1.3			3.4
Net current-period other comprehensive income (loss)	1.1			(21.2		)	1.5			(18.6		)
Balance as of September 30, 2017	$	0.5		$	(28.1	)	$	(16.1	)	$	(43.7	)

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

⁽²⁾ Reclassification from accumulated other comprehensive loss for cash flow hedges relates primarily to the interest rate swap settlement gain. Refer to Note 8 "Risk Management Activities" for additional information.

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ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

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

18.    Other, Net

	Three Months Ended September 30,						Nine Months Ended September 30,
(in millions)	2018			2017			2018			2017
Interest Income	$	1.4		$	1.4		$	4.2		$	3.2
AFUDC Equity	5.0			4.3			12.6			10.5
Charitable Contributions	(11.1		)	(0.8		)	(13.9		)	(3.5		)
Pension and other postretirement non-service cost	2.4			(11.8		)	14.7			(10.1		)
Interest rate swap settlement gain(1)	—			—			21.2			—
Miscellaneous	0.6			0.1			3.6			(0.4		)
Total Other, net	$	(1.7	)	$	(6.8	)	$	42.4		$	(0.3	)

⁽¹⁾See Note 8, "Risk Management Activities," for additional information.

19.    Business Segment Information

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 September 30,						Nine Months Ended September 30,
(in millions)	2018			2017			2018			2017
Operating Revenues
Gas Distribution Operations
Unaffiliated	$	418.6		$	431.1		$	2,347.8		$	2,139.9
Intersegment	3.3			3.5			9.8			10.6
Total	421.9			434.6			2,357.6			2,150.5
Electric Operations
Unaffiliated	476.2			485.8			1,304.4			1,365.5
Intersegment	0.2			0.2			0.6			0.6
Total	476.4			486.0			1,305.0			1,366.1
Corporate and Other
Unaffiliated	0.2			0.1			0.6			0.9
Intersegment	116.4			126.4			346.6			367.7
Total	116.6			126.5			347.2			368.6
Eliminations	(119.9		)	(130.1		)	(357.0		)	(378.9		)
Consolidated Operating Revenues	$	895.0		$	917.0		$	3,652.8		$	3,506.3
Operating Income (Loss)
Gas Distribution Operations	$	(455.2	)	$	(15.4	)	$	(94.4	)	$	367.1
Electric Operations	134.9			125.1			300.4			288.3
Corporate and Other	4.4			1.5			(2.9		)	(4.8		)
Consolidated Operating Income	$	(315.9	)	$	111.2		$	203.1		$	650.6

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NiSource Inc.

Index	Page
Executive Summary	41
Summary of Consolidated Financial Results	42
Results and Discussion of Segment Operations	45
Gas Distribution Operations	46
Electric Operations	49
Liquidity and Capital Resources	52
Off Balance Sheet Arrangements	54
Market Risk Disclosures	54
Other Information	55

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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, 2017.

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, 2017 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: 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”). During the quarter ended September 30, 2018, we recorded a loss of approximately $415 million for third-party claims and approximately $45 million for other incident-related expenses in connection with the Greater Lawrence Incident.

We estimate that total costs related to third-party claims will range from $415 million to $450 million, depending on the final outcome of open investigations and the number, nature, and value of third-party claims. We expect to incur a total of $180 million to $210 million in such other incident-related costs, substantially all of which would be incurred by the end of 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 business interruption claims and fines, penalties or settlements with governmental authorities in connection with the Greater Lawrence Incident. We expect these expenses and other expenses related to various lawsuits, including class action suits, to extend beyond 2018.

Columbia of Massachusetts expects to record recoveries from third party insurance, resulting in increases to operating income in future periods as such amounts are recorded. The timing and amount of such recoveries is uncertain.

As discussed in Note 7, "Regulatory Matters," in the Notes to Condensed Consolidated Financial Statements (unaudited), Columbia of Massachusetts withdrew its petition for a base rate revenue increase, resulting in delayed increases in forecasted revenues and cash flows beginning the first quarter of 2019. Columbia of Massachusetts expects to invest between $135 - $165 million for replacement of the entire affected 45-mile cast iron and bare steel pipeline system that delivers gas to those impacted in the Greater Lawrence Incident. The recovery of this capital investment will be addressed in a future regulatory proceeding. 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.

Additionally, as discussed in Note 11, "Goodwill," we concluded the Greater Lawrence Incident was a triggering event requiring a quantitative analysis of goodwill for the Columbia of Massachusetts reporting unit. Future unfavorable events that transpire at Columbia of Massachusetts could trigger the need for another quantitative analysis and a goodwill impairment loss would be required if it's determined Columbia of Massachusetts fair value is less than its book value.

Refer to Note 16-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

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NiSource Inc.

Operations," and "Liquidity and Capital Resources" in this Management's Discussion, and Part II. Item 1A. "Risk Factors" 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 and nine months endedSeptember 30, 2018 and 2017, operating income and a reconciliation of net revenues to the most directly comparable GAAP measure, operating income, was as follows:

	Three Months Ended September 30,								Nine Months Ended September 30,
(in millions)	2018			2017		2018 vs. 2017			2018		2017		2018 vs. 2017
Operating Income (Loss)	$	(315.9	)	$	111.2	$	(427.1	)	$	203.1	$	650.6	$	(447.5	)

	Three Months Ended September 30,									Nine Months Ended September 30,
(in millions, except per share amounts)	2018			2017			2018 vs. 2017			2018			2017			2018 vs. 2017
Operating Revenues	$	895.0		$	917.0		$	(22.0	)	$	3,652.8		$	3,506.3		$	146.5
Cost of Sales (excluding depreciation and amortization)	222.0			233.6			(11.6		)	1,259.7			1,062.7			197.0
Total Net Revenues	673.0			683.4			(10.4		)	$	2,393.1		$	2,443.6		$	(50.5	)
Other Operating Expenses	988.9			572.2			416.7			2,190.0			1,793.0			397.0
Operating Income (Loss)	(315.9		)	111.2			(427.1		)	203.1			650.6			(447.5		)
Total Other Deductions, net	(118.1		)	(94.7		)	(23.4		)	(268.3		)	(372.6		)	104.3
Income Taxes	(94.5		)	2.5			(97.0		)	(26.3		)	97.1			(123.4		)
Net Income (Loss)	(339.5		)	14.0			(353.5		)	(38.9		)	180.9			(219.8		)
Preferred dividends	(5.6		)	—			(5.6		)	(6.9		)	—			(6.9		)
Net Income (Loss) Available to Common Shareholders	(345.1		)	14.0			(359.1		)	(45.8		)	180.9			(226.7		)
Basic Earnings (Loss) Per Share	$	(0.95	)	$	0.04		$	(0.99	)	$	(0.13	)	$	0.55		$	(0.68	)
Basic Average Common Shares Outstanding	363.9			331.1			32.8			352.1			326.7			25.4

On a consolidated basis, we reported a net loss available to common shareholders of $345.1 million, or $0.95 per basic share for the three months ended September 30, 2018, compared to net income available to common shareholders of $14.0 million, or $0.04 per basic share for the same period in 2017. The decrease in income available to common shareholders during 2018 was primarily due to expenses related to the Greater Lawrence Incident restoration, losses on early extinguishment of long-term debt in 2018, other changes in operating income, as discussed below, and dilution resulting from preferred stock dividend commitments.

For the three months ended September 30, 2018, we reported an operating loss of $315.9 million compared to operating income of $111.2 million for the same period in 2017. The decreased operating income was primarily due to increased operation and maintenance expenses related to the Greater Lawrence Incident restoration, increased depreciation expense due to capital expenditures placed in service and decreased net revenues resulting from TCJA impacts on revenue. These increases were partially offset by decreased employee and administrative expenses and outside service costs, higher rates from investments in infrastructure replacement programs and net favorable effects of year-over-year weather variations, which increased revenue in 2018.

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NiSource Inc.

On a consolidated basis, we reported a net loss available to common shareholders of $45.8 million, or $0.13 per basic share for the nine months endedSeptember 30, 2018, compared to net income available to common shareholders of $180.9 million, or $0.55 per basic share for the same period in 2017. The decrease in net income available to common shareholders during 2018 was due primarily to expenses related to the Greater Lawrence Incident restoration, dilution resulting from preferred stock dividend commitments and other changes in operating income, as described below, partially offset by higher losses on early extinguishment of long-term debt expenses in 2017.

For the nine months endedSeptember 30, 2018, we reported operating income of $203.1 million compared to $650.6 million for the same period in 2017. The lower operating income was primarily due to operation and maintenance expenses related to the Greater Lawrence Incident restoration, decreased net revenues attributable to TCJA impacts on revenue as well as higher depreciation expense. These decreases were offset by increased net revenues due to weather variability between the nine months endedSeptember 30, 2018 compared to the same period in 2017 and decreased outside service costs and employee and administrative expenses. Additionally, net revenues increased in 2018 due to new rates from infrastructure replacement programs and base rate proceedings.

Other Deductions, net

Other deductions, net reduced income by $118.1 million in the third quarter of 2018 compared to a reduction in income of $94.7 million in the prior year. This change is primarily due to a loss on early extinguishment of long-term debt of $33.0 million during the third quarter of 2018 and charitable contributions of $10.3 million related to the Greater Lawrence Incident. These reductions were partially offset by higher actuarial investment returns resulting from pension contributions made in the third quarter of 2017.

Other deductions, net reduced income by $268.3 million in the nine months endedSeptember 30, 2018 compared to a reduction in income of $372.6 million in the prior year. This change is primarily due to lower losses on early extinguishment of long-term debt in 2018 of $66.0 million, as well as higher actuarial investment returns resulting from pension contributions made in the third quarter of 2017 and an interest rate swap settlement gain recognized in the first quarter of 2018 of $21.2 million. These favorable variances were partially offset by charitable contributions of $10.3 million made in the third quarter of 2018 related to the Greater Lawrence Incident.

Income Taxes

On December 22, 2017, the President signed into law the TCJA, which, among other things, enacted significant changes to the Internal Revenue Code of 1986, as amended, including a reduction in the maximum U.S. federal corporate income tax rate from 35% to 21%, and certain other provisions related specifically to the public utility industry, including the continuation of certain interest expense deductibility and excluding 100% expensing of capital investments. These changes were effective January 1, 2018.

The decrease in income tax expense from 2017 to 2018 is primarily attributable to the decrease in the federal corporate income tax rate, the effect of amortizing the regulatory liability associated with excess deferred income taxes and lower pre-tax income resulting from expenses incurred for the Greater Lawrence Incident.

Refer to “Liquidity and Capital Resources” below and 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 nine months endedSeptember 30, 2018, we invested $1,296.6 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, construction of new electric transmission assets and maintaining our existing electric generation fleet.

In connection with the Greater Lawrence Incident described above, 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 8,500 gas meters, of which approximately 700 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. Columbia of Massachusetts is aiming to restore gas service to all homes and workplaces by December 16, 2018. 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 has hired an outside contractor to serve as the Chief Recovery Officer for the Greater Lawrence Incident, responsible for command, control and communications. The estimated capital cost of the pipeline replacement is between $135 - $165 million. The recovery of this capital investment will be addressed in a future regulatory proceeding.

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NiSource Inc.

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 $1.7 to $1.8 billion in capital during 2018 to continue to modernize and improve our system across all seven states.

Liquidity

As discussed in further detail below in "Liquidity and Capital Resources," the enactment of the TCJA has and will continue to have an unfavorable impact on our liquidity in 2018; 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 2018 and beyond. As of September 30, 2018 and December 31, 2017, we had $1,135.6 million and $998.9 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 September 30, 2018, we continued to move forward on core infrastructure and environmental investment programs supported by complementary regulatory and customer initiatives across all seven states of our operating area. The discussion below summarizes significant regulatory developments that transpired during the third quarter of 2018:

Gas Distribution Operations

• On October 1, 2018, the first step of a three step implementation of new rates went into effect at NIPSCO following IURC approval of a settlement with parties on its gas base rate case. The settlement supports continued investment in system upgrades, technology improvements and other measures to increase pipeline safety and system reliability and will ultimately result in an annual revenue increase of $107.3 million, inclusive of amounts being recovered through various tracker programs and reflecting the impact of the TCJA.

• On August 31, 2018, Columbia of Pennsylvania filed a settlement agreement in its base rate case with the Pennsylvania PUC. If approved as filed, the settlement supports an annual revenue increase of $26.0 million to upgrade and replace natural gas distribution pipelines and reflects the impact of the TCJA. An order is expected in the fourth quarter of 2018 with new rates to be implemented in December 2018.

• On October 25, 2018, Columbia of Ohio filed a settlement agreement in its CEP application pending before the PUCO. If approved as filed, the initial $74.5 million CEP rider would allow recovery of deferred capital investments made between 2011 and 2017 that are not currently recovered through its IRP modernization tracker. The settlement also benefits customers by reducing base rates by approximately $23 million to reflect the impact of the TCJA.

• On August 28, 2018, Columbia of Virginia filed a base rate case with the VSCC to recover costs associated with ongoing infrastructure investment programs and to incorporate changes from the TCJA. If approved as filed, the request would result in an annual revenue increase of $22.2 million. A VSCC order is expected in the second half of 2019 with interim rates to be implemented February 1, 2019.

• On September 19, 2018, Columbia of Massachusetts' withdrew its base rate case pending before the Massachusetts DPU to focus on service restoration and assisting customers impacted by the Greater Lawrence Incident.

• A settlement of Columbia of Maryland's base rate case remains pending before the Maryland PSC. The settlement supports continued replacement of gas pipelines and pipeline safety upgrades, and reflects the impact of federal tax reform. If approved as filed, the settlement would result in an annual revenue increase of $3.7 million. A Maryland PSC order is expected in the fourth quarter of 2018 with rates anticipated to be effective November 2018.

Electric Operations

• On October 31, 2018, NIPSCO submitted its 2018 Integrated Resource Plan to the IURC. The plan evaluated demand-side and supply-side resource alternatives to reliably and cost effectively meet NIPSCO customers' future energy requirements over the ensuing 20 years. The Integrated Resource Plan proposes to retire R.M. Schahfer Generating Station

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NiSource Inc.

(Units 14, 15, 17, and 18) by 2023 and Michigan City Generating Station (Unit 12) by 2028. The replacement plan is still being defined, but currently points to renewable sources of energy, including wind, solar and battery storage.

• Also on October 31, 2018 NIPSCO filed an electric base rate case with the IURC to address anticipated revenue loss resulting from the WCE filing, as well as to address impacts of the TCJA on customer rates. If approved as filed, the request is expected to increase annual revenues by $21.4 million. An IURC order is anticipated in the third quarter of 2019, with rates effective in September 2019.

• NIPSCO continues to execute on its seven-year electric infrastructure modernization program, which includes enhancements to its electric transmission and distribution system designed to further improve system safety and reliability. The IURC-approved program represents approximately $1.25 billion of electric infrastructure investments expected to be made through 2022. A settlement was filed on October 25, 2018, in NIPSCO's latest tracker update request which remains pending before the IURC. It seeks a semi-annual incremental rate decrease of $11.2 million, due primarily to the pass-back to customers of a $14.1 million base rate refund for the January through May 2018 period related to the TCJA. An order is expected in the fourth quarter of 2018.

Refer to Note 7, “Regulatory Matters,” as well as to Note 16, "Other Commitments and Contingencies," in the Notes to Condensed Consolidated Financial Statements (unaudited) for a complete discussion of key regulatory matters.

RESULTS AND DISCUSSION OF SEGMENT OPERATIONS

Presentation of Segment Information

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

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

NiSource Inc.

Gas Distribution Operations

For the three and nine months endedSeptember 30, 2018 and 2017, operating income and a reconciliation of net revenues to the most directly comparable GAAP measure, operating income, was as follows:

	Three Months Ended September 30,									Nine Months Ended September 30,
(in millions)	2018			2017			2018 vs. 2017			2018			2017		2018 vs. 2017
Operating Income (Loss)	$	(455.2	)	$	(15.4	)	$	(439.8	)	$	(94.4	)	$	367.1	$	(461.5	)

	Three Months Ended September 30,									Nine Months Ended September 30,
(in millions)	2018			2017			2018 vs. 2017			2018			2017			2018 vs. 2017
Net Revenues
Operating Revenues	$	421.9		$	434.6		$	(12.7	)	$	2,357.6		$	2,150.5		$	207.1
Less: Cost of gas sold (excluding depreciation and amortization)	85.7			94.6			(8.9		)	875.1			662.0			213.1
Net Revenues	336.2			340.0			(3.8		)	1,482.5			1,488.5			(6.0		)
Operating Expenses
Operation and maintenance	678.5			249.6			428.9			1,214.2			787.3			426.9
Depreciation and amortization	72.5			67.9			4.6			215.0			199.5			15.5
Other taxes	40.4			37.9			2.5			147.7			134.6			13.1
Total Operating Expenses	791.4			355.4			436.0			1,576.9			1,121.4			455.5
Operating Income (Loss)	$	(455.2	)	$	(15.4	)	$	(439.8	)	$	(94.4	)	$	367.1		$	(461.5	)
Revenues
Residential	$	260.2		$	264.2		$	(4.0	)	$	1,540.8		$	1,404.4		$	136.4
Commercial	81.8			80.9			0.9			517.6			456.0			61.6
Industrial	39.2			39.7			(0.5		)	161.7			156.5			5.2
Off-System	22.0			30.4			(8.4		)	65.2			97.1			(31.9		)
Other	18.7			19.4			(0.7		)	72.3			36.5			35.8
Total	$	421.9		$	434.6		$	(12.7	)	$	2,357.6		$	2,150.5		$	207.1
Sales and Transportation (MMDth)
Residential	13.8			14.5			(0.7		)	187.9			157.2			30.7
Commercial	17.5			17.3			0.2			129.7			111.3			18.4
Industrial	132.1			125.9			6.2			417.7			380.3			37.4
Off-System	7.5			11.1			(3.6		)	21.9			33.8			(11.9		)
Other	—			0.3			(0.3		)	0.3			0.2			0.1
Total	170.9			169.1			1.8			757.5			682.8			74.7
Heating Degree Days	51			75			(24		)	3,498			2,911			587
Normal Heating Degree Days	85			85			—			3,576			3,576			—
% Warmer than Normal	(40		)%	(12		)%				(2		)%	(19		)%
Gas Distribution Customers
Residential										3,140,942			3,114,223			26,719
Commercial										276,832			275,424			1,408
Industrial										6,174			6,163			11
Other										5			3			2
Total										3,423,953			3,395,813			28,140

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

NiSource Inc.

Gas Distribution Operations

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.

Three months ended September 30, 2018 vs. September 30, 2017 Operating Income

For the three months ended September 30, 2018, Gas Distribution Operations reported an operating loss of $455.2 million, compared to an operating loss of $15.4 million from the comparable 2017 period.

Net revenues for the three months ended September 30, 2018 were $336.2 million, a decrease of $3.8 million from the same period in 2017. The change in net revenues was primarily driven by:

• A revenue reserve in 2018 resulting from the probable future refund of certain collections from customers as a result of the lower income tax rate from the TCJA of $11.8 million.

• Decreased rates from implementation of regulatory outcomes related to the TCJA of $7.0 million.

Partially offset by:

• New rates from infrastructure replacement programs and base rate proceedings of $13.0 million.

Operating expenses were $436.0 million higher for the three months ended September 30, 2018 compared to the same period in 2017. This change was primarily driven by:

• Expenses related to third-party claims and other costs following the Greater Lawrence Incident of $451.6 million.

• Increased depreciation of $4.8 million due to higher capital expenditures placed in service.

Partially offset by:

•Lower employee and administrative expenses of $13.8 million.

• Decreased outside services of $8.5 million primarily due to IT service provider transition costs in 2017.

Nine months ended September 30, 2018 vs. September 30, 2017 Operating Income

For the nine months endedSeptember 30, 2018, Gas Distribution Operations reported an operating loss of $94.4 million, compared to operating income of $367.1 million from the comparable 2017 period.

Net revenues for the nine months endedSeptember 30, 2018 were $1,482.5 million, a decrease of $6.0 million from the same period in 2017. The change in net revenues was primarily driven by:

• A revenue reserve in 2018 resulting from the probable future refund of certain collections from customers as a result of the lower income tax rate from the TCJA of $78.2 million.

• Decreased rates from implementation of regulatory outcomes related to the TCJA of $13.4 million.

Partially offset by:

• Higher revenues from the effects of colder weather in 2018 of $34.8 million.

• New rates from infrastructure replacement programs and base rate proceedings of $34.7 million.

• Increased customer growth and usage of $13.1 million.

• Higher regulatory, tax and depreciation trackers, which are offset in expense, of $3.1 million.

Operating expenses were $455.5 million higher for the nine months endedSeptember 30, 2018 compared to the same period in 2017. This change was primarily driven by:

• Expenses related to third-party claims and other costs following the Greater Lawrence Incident of $451.6 million.

• Increased depreciation of $15.1 million due to higher capital expenditures placed in service.

• Increased property taxes of $5.1 million.

Partially offset by:

• Lower outside services expenses of $12.2 million primarily due to IT service provider transition costs in 2017 and ongoing savings related to the new IT service agreements.

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

NiSource Inc.

Gas Distribution Operations

• Decreased employee and administrative expenses of $9.5 million.

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.

Weather in the Gas Distribution Operations service territories for the third quarter of 2018 was about 40% warmer than normal and about 32% warmer than 2017, leading to decreased net revenues of $0.1 million for the quarter ended September 30, 2018 compared to the same period in 2017. This nominal weather-related impact on net revenues for the period is expected as gas usage by customers is traditionally low in the third quarter cooling season

Weather in the Gas Distribution Operations service territories for the nine months endedSeptember 30, 2018 was about 2% warmer than normal and about 20% colder than in 2017, leading to increased net revenues of $34.8 million for the nine months endedSeptember 30, 2018 compared to the same period in 2017.

Throughput

Total volumes sold and transported for the third quarter of 2018 were 170.9 MMDth, compared to 169.1 MMDth for the same period in 2017.

Total volumes sold and transported for the nine months endedSeptember 30, 2018 were 757.5 MMDth, compared to 682.8 MMDth for the same period in 2017. This 11%increase is primarily attributable to the effects of colder weather and increased industrial usage due to energy production from electric generating customers in 2018.

Economic Conditions

All of our Gas Distribution Operations companies have state-approved recovery mechanisms that provide a means for full recovery of prudently incurred gas costs. Gas costs are treated as pass-through costs and have no impact on the net revenues recorded in the period. The gas costs included in revenues are matched with the gas cost expense recorded in the period and the difference is recorded on the 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.

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

NiSource Inc.

Electric Operations

For the three and nine months endedSeptember 30, 2018 and 2017, operating income and a reconciliation of net revenues to the most directly comparable GAAP measure, operating income, was as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
(in millions)	2018		2017		2018 vs. 2017		2018		2017		2018 vs. 2017
Operating Income	$	134.9	$	125.1	$	9.8	$	300.4	$	288.3	$	12.1

	Three Months Ended September 30,									Nine Months Ended September 30,
(in millions)	2018			2017			2018 vs. 2017			2018			2017			2018 vs. 2017
Net Revenues
Operating revenues	$	476.4		$	486.0		$	(9.6	)	$	1,305.0		$	1,366.1		$	(61.1	)
Less: Cost of sales (excluding depreciation and amortization)	136.3			139.0			(2.7		)	384.6			400.9			(16.3		)
Net Revenues	340.1			347.0			(6.9		)	920.4			965.2			(44.8		)
Operating Expenses
Operation and maintenance	123.4			136.0			(12.6		)	377.9			420.1			(42.2		)
Depreciation and amortization	66.3			69.8			(3.5		)	196.3			212.0			(15.7		)
Other taxes	15.5			16.1			(0.6		)	45.8			44.8			1.0
Total Operating Expenses	205.2			221.9			(16.7		)	620.0			676.9			(56.9		)
Operating Income	$	134.9		$	125.1		$	9.8		$	300.4		$	288.3		$	12.1
Revenues
Residential	$	154.7		$	138.0		$	16.7		$	382.3		$	363.7		$	18.6
Commercial	140.7			134.6			6.1			374.2			379.0			(4.8		)
Industrial	153.8			171.5			(17.7		)	468.7			531.4			(62.7		)
Wholesale	3.8			3.7			0.1			12.4			9.0			3.4
Other	23.4			38.2			(14.8		)	67.4			83.0			(15.6		)
Total	$	476.4		$	486.0		$	(9.6	)	$	1,305.0		$	1,366.1		$	(61.1	)
Sales (Gigawatt Hours)
Residential	1,121.5			1,002.3			119.2			2,754.6			2,523.9			230.7
Commercial	1,079.6			1,042.7			36.9			2,929.0			2,868.1			60.9
Industrial	2,223.3			2,390.9			(167.6		)	6,785.8			7,192.7			(406.9		)
Wholesale	2.5			6.1			(3.6		)	94.8			28.0			66.8
Other	34.7			31.2			3.5			95.2			96.3			(1.1		)
Total	4,461.6			4,473.2			(11.6		)	12,659.4			12,709.0			(49.6		)
Cooling Degree Days	739			540			199			1,131			804			327
Normal Cooling Degree Days	570			570						799			799
% Warmer (Colder) than Normal	30		%	(5		)%				42		%	1		%
Electric Customers
Residential										410,848			407,998			2,850
Commercial										56,426			55,912			514
Industrial										2,285			2,311			(26		)
Wholesale										736			740			(4		)
Other										2			2			—
Total										470,297			466,963			3,334

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

NiSource Inc.

Electric Operations

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.

Three months ended September 30, 2018 vs. September 30, 2017 Operating Income

For the three months ended September 30, 2018, Electric Operations reported operating income of $134.9 million, an increase of $9.8 million from the comparable 2017 period.

Net revenues for the three months ended September 30, 2018 were $340.1 million, a decrease of $6.9 million from the same period in 2017. The change in net revenues was primarily driven by:

• Decreased rates from implementation of regulatory outcomes related to the TCJA of $14.1 million.

• Lower regulatory and depreciation trackers, which are offset in operating expense, of $9.9 million.

• Decreased industrial usage of $4.6 million.

Partially offset by:

• The effects of warmer weather of $14.7 million.

• Increased rates from infrastructure replacement programs of $6.2 million.

Operating expenses were $16.7 million lower for the three months ended September 30, 2018 compared to the same period in 2017. This change was primarily driven by:

• Lower regulatory and depreciation trackers, which are offset in net revenues, of $9.9 million.

• Decreased employee and administrative costs of $6.6 million.

• Decreased outside service costs of $5.1 million on lower generation-related maintenance activities.

Partially offset by:

• Increased depreciation of $2.8 million due to higher capital expenditures placed in service.

Nine months ended September 30, 2018 vs. September 30, 2017 Operating Income

For the nine months endedSeptember 30, 2018, Electric Operations reported operating income of $300.4 million, an increase of $12.1 million from the comparable 2017 period.

Net revenues for the nine months endedSeptember 30, 2018 were $920.4 million, a decrease of $44.8 million from the same period in 2017. The change in net revenues was primarily driven by:

• Lower regulatory and depreciation trackers, which are offset in operating expense, of $34.1 million.

• Decreased rates from implementation of regulatory outcomes related to the TCJA of $22.7 million.

• A revenue reserve in 2018 resulting from the probable future refund of certain collections from customers as a result of the lower income tax rate from the TCJA of $16.3 million.

• Decreased industrial usage of $10.1 million.

• Increased fuel handling costs of $5.9 million.

Partially offset by:

• The effects of warmer weather of $24.2 million.

• Increased rates from infrastructure replacement programs of $17.6 million.

Operating expenses were $56.9 million lower for the nine months endedSeptember 30, 2018 compared to the same period in 2017. This change was primarily driven by:

• Decreased regulatory and depreciation trackers, which are offset in net revenues, of $34.1 million.

• Lower outside service costs of $20.8 million and lower materials and supplies costs of $5.3 million primarily related to lower generation-related maintenance activities.

• Decreased employee and administrative costs of $10.1 million.

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NiSource Inc.

Electric Operations

Partially offset by:

• Increased depreciation of $8.1 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.

Weather in the Electric Operations’ territories for the third quarter of 2018 was about 30% warmer than normal and about 37% warmer than in 2017, resulting in increased net revenues of $14.7 million for the quarter ended September 30, 2018 compared to the same period in 2017.

Weather in the Electric Operations' territories for the nine months ended September 30, 2018 was about 42% warmer than normal and about 41% warmer than 2017, resulting in increased net revenues of $24.2 million for the nine months ended September 30, 2018 compared to 2017.

Sales

Electric Operations sales for the third quarter of 2018 were 4,461.6 gwh, a decrease of 11.6 gwh compared to the same period in 2017. This decrease was primarily attributable to higher internal generation from large industrial customers during the third quarter of 2018, partially offset by increased volumes for residential and commercial customers resulting from warmer weather.

Electric Operations sales for the nine months ended September 30, 2018 were 12,659.4 gwh, a decrease of 49.6 gwh compared to the same period in 2017. This decrease was primarily attributable to higher internal generation from large industrial customers during 2018, partially offset by increased volumes for residential and commercial customers resulting from warmer weather.

BP Products North America. On March 29, 2018, WCE, which is currently owned by BP p.l.c ("BP") and BP Products North America, which operates the BP Refinery, filed a petition at the IURC asking that the combined operations of WCE and BP be treated as a single premise, and the WCE generation be dedicated primarily to BP Refinery operations beginning in May 2019 as WCE has self-certified as a qualifying facility at FERC. BP Refinery plans to continue to purchase electric service from NIPSCO at a reduced demand level beginning May 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. On October 31, 2018, NIPSCO submitted its 2018 Integrated Resource Plan with the IURC. The plan evaluated demand-side and supply-side resource alternatives to reliably and cost effectively meet NIPSCO customers' future energy requirements over the ensuing 20 years. Refer to Note 16-D, "Other Matters," in the Notes to Condensed Consolidated Financial Statements (unaudited) for additional information on the NIPSCO Integrated Resource Plan.

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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 16, “Other Commitments and Contingencies,” we have recorded losses associated with the Greater Lawrence Incident and expect to invest 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 16 referenced earlier in this paragraph, and Part II, Item 1A “Risk Factors,” in this report, 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 nine months endedSeptember 30, 2018 was $927.2 million, an increase of $397.6 million compared to the nine months endedSeptember 30, 2017. This increase was driven by decreased pension plan contributions as discussed below as well as changes in gas prices, which impacted working capital. Additionally, cash from operations increased as a result of higher sales due to colder weather during the 2018 winter heating season compared to 2017 and increased rates from infrastructure replacement programs.

Pension and Other Postretirement Plan Funding. During the nine months endedSeptember 30, 2017, we contributed $281.6 million to our pension plans (including a $277 million discretionary contribution made during the third quarter of 2017) and $21.8 million to our other postretirement benefit plans.

For the nine months ended September 30, 2018, we contributed $2.1 million to our pension plans and $16.8 million to our other postretirement benefit plans.

Income Taxes. Rates for our regulated customers include provisions for the collection of U.S. federal income taxes. The reduction in the U.S. federal corporate income tax rate as a result of the TCJA has, and is expected to continue to lead to a decrease in the amount billed to customers through rates, ultimately resulting in lower cash collections from operating activities. As discussed in further detail in Note 7, "Regulatory Matters," in the Notes to Condensed Consolidated Financial Statements (unaudited), our regulated subsidiaries are engaged with the relevant state utility commissions to address the impacts of the TCJA on future customer rates. Through the first nine months of 2018, billings to customers decreased approximately $36.1 million compared to the same period in 2017 as a result of adjustments to certain rates in our Kentucky, Ohio, Maryland, Massachusetts and Indiana jurisdictions. Additionally, during the first nine months of 2018, we recorded additional TCJA-related regulatory liabilities of $69.9 million related to 2018 collections from customers, which we believe are probable of being refunded back to customers once new customer rates are approved by our regulators.

In addition, we will be required to pass back to customers “excess deferred taxes,” which represent amounts collected from customers in the past to cover deferred tax liabilities that, as a result of the passage of the TCJA, are now expected to be less than the originally billed amounts. Approximately $1.5 billion of excess deferred taxes related to implementation of the TCJA were recorded within "Regulatory liabilities (noncurrent)" on the Condensed Consolidated Balance Sheets (unaudited) as of December 31, 2017. The majority of these balances relate to temporary book-to-tax differences on utility property protected by IRS normalization rules. Once modified rates are approved by our regulators, we expect this portion of the balance will be passed back to customers over the remaining average useful life of the associated property. The pass back period for the remainder of the balance will be determined by our state utility commissions in future proceedings. Our estimate of the amount and pass-back period of excess deferred taxes is subject to change pending final review by the utility commissions of the states in which we operate.

As of September 30, 2018, we had a recorded deferred tax asset of $574.9 million related to a Federal NOL carryforward. As a result of being in an NOL position, we were not required to make any cash payments for Federal income tax purposes during the nine months endedSeptember 30, 2018 or 2017. This NOL carryforward expires in 2030; however, we expect to fully utilize the carryforward benefit prior to its expiration.

Investing Activities

Net cash used for investing activities for the nine months endedSeptember 30, 2018 was $1,376.5 million, an increase of $69.8 million compared to the nine months endedSeptember 30, 2017. This increase was mostly attributable to increased capital expenditures in 2018.

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NiSource Inc.

Our capital expenditures for the nine months endedSeptember 30, 2018 were $1,296.6 million compared to $1,216.4 million for the comparable period in 2017. The increase was driven by an increase in planned capital expenditures in the current year and the timing of payments through September 2018 compared to September 2017. We project total 2018 capital expenditures to be approximately $1.7 to $1.8 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 September 30, 2018, an aggregate of $1,135.6 million of net liquidity was available, including cash and credit available under the revolving credit facility and accounts receivable securitization programs.

The following table displays our liquidity position as of September 30, 2018 and December 31, 2017:

(in millions)	September 30, 2018		December 31, 2017
Current Liquidity
Revolving Credit Facility	$	1,850.0	$	1,850.0
Accounts Receivable Program(1)	265.0		336.7
Less:
Commercial Paper	746.0		869.0
Accounts Receivable Program Utilized	265.0		336.7
Letters of Credit Outstanding Under Credit Facility	10.2		11.1
Add:
Cash and Cash Equivalents	41.8		29.0
Net Available Liquidity	$	1,135.6	$	998.9

⁽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 September 30, 2018, the ratio was 63.3%.

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 September 30, 2018. In June 2018, Fitch upgraded the NiSource Commercial Paper rating to 'F2' from 'F3'. In September 2018, as a result of potential impacts of the Greater Lawrence Incident, S&P changed our outlook from Stable to Negative. In October 2018, Fitch affirmed both NiSource and NIPSCO ratings of BBB. There were no other changes to the below credit ratings or outlooks since December 31, 2017.

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NiSource Inc.

	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 September 30, 2018, the collateral requirement that would be required in the event of a downgrade below the ratings trigger levels would amount to approximately $56.1 million. In addition to agreements with ratings triggers, there are other agreements that contain “adequate assurance” or “material adverse change” provisions that could necessitate additional credit support such as letters of credit and cash collateral to transact business.

Equity. Our authorized capital stock consists of 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 September 30, 2018, 363,167,067 shares of common stock and 400,000 shares of preferred stock were outstanding.

Contractual Obligations. Aside from the previously referenced issuances and repayments of long-term debt and payments associated with the Greater Lawrence Incident, there were no material changes recorded during the nine months endedSeptember 30, 2018 to our contractual obligations as of December 31, 2017.

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

Market Risk Disclosures

Risk is an inherent part of our businesses. The extent to which we properly and effectively identify, assess, monitor and manage each of the various types of risk involved in our businesses is critical to our profitability. We seek to identify, assess, monitor and manage, in accordance with defined policies and procedures, the following principal market risks that are involved in our businesses: commodity price risk, interest rate risk and credit risk. Risk management for us is a multi-faceted process with oversight by the Risk Management Committee that requires constant communication, judgment and knowledge of specialized products and markets. Our senior management takes an active role in the risk management process and has developed policies and procedures that require specific administrative and business functions to assist in the identification, assessment and control of various risks. These may include, but are not limited to market, operational, financial, compliance and strategic risk types. In recognition of the increasingly varied and complex nature of the energy business, our risk management process, policies and procedures continue to evolve and are subject to ongoing review and modification.

Commodity Price Risk

We are exposed to commodity price risk as a result of our subsidiaries’ operations involving natural gas and power. To manage this market risk, our subsidiaries use derivatives, including commodity futures contracts, swaps, forwards and options. We do not participate in speculative energy trading activity.

Commodity price risk resulting from derivative activities at our rate-regulated subsidiaries is limited, since regulations allow recovery of prudently incurred purchased power, fuel and gas costs through the 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.

54

Table of Contents

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

NiSource Inc.

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 September 30, 2018 or December 31, 2017.

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 $3.1 million and $9.1 million for the three and nine months ended September 30, 2018, and $3.7 million and $12.6 million for the three and nine months ended September 30, 2017, 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 September 30, 2018 and December 31, 2017.

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 16, "Other Commitments and Contingencies," in the Notes to Condensed Consolidated Financial Statements (unaudited) and Item 1A, "Risk Factors," 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.

55

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.

56

PART II

ITEM 1. LEGAL PROCEEDINGS

NiSource Inc.

For a description of the Company’s legal proceedings, see Note 16-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, 2017, and as set forth below.

The Greater Lawrence Incident may have a material adverse impact on the Company’s and Columbia of Massachusetts' financial condition, results of operations and cash flows.

In connection with the Greater Lawrence Incident, the Company has incurred and will incur various costs and expenses as set forth in Note 16, "Other Commitments and Contingencies - B. Legal Proceedings," and " - D. Other Matters" in the Notes to Condensed Consolidated Financial Statements (unaudited). As more information becomes known, including information resulting from the NTSB investigation, management’s estimates and assumptions regarding the financial impact of the Greater Lawrence Incident may change. A change in management’s estimates or assumptions could result in an adjustment that would have a material impact on the Company’s and Columbia of Massachusetts' financial condition and results of operations during the period in which such change occurred.

In addition, the Company is unable to predict the timing and amount of insurance recoveries. If Columbia of Massachusetts is ultimately unable to recover losses related to the Greater Lawrence Incident from insurance, the Company's and Columbia of Massachusetts' financial condition, results of operations and cash flows could be materially adversely affected.

Columbia of Massachusetts also may incur costs, beyond the amount currently anticipated, in response to NTSB, Massachusetts DPU or other orders or requests as the investigations continue. Further, state or federal legislation may be enacted that would require Columbia of Massachusetts to incur additional costs by mandating various changes, including changes to its operating practice standards for natural gas distribution operations and safety. If Columbia of Massachusetts is unable to recover the capital cost of the gas pipeline replacement in the impacted area or incurs a material amount of other costs that it is unable to recover through rates or offset through operational or other cost savings, the Company’s and Columbia of Massachusetts' financial condition, results of operations, and cash flows would be materially and adversely affected.

Further, if it is determined that Columbia of Massachusetts did not comply with applicable statutes, regulations, rules, tariffs, or orders in connection with the Greater Lawrence Incident or in connection with the operations or maintenance of Columbia of Massachusetts’ natural gas system, and Columbia of Massachusetts is ordered to pay a material amount in customer refunds, penalties, or other amounts, the Company’s and Columbia of Massachusetts' financial condition, results of operations, and cash flows would be materially and adversely affected.

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.

57

ITEM 6. EXHIBITS

NiSource Inc.

(10.1)	Amended and Restated NiSource Inc. Supplemental Executive Retirement Plan effective August 10, 2017.*
(10.2)	Amended and Restated Pension Restoration Plan for NiSource Inc. and Affiliates effective August 10, 2017.*
(10.3)	Amended Restated Savings Restoration Plan for NiSource Inc. and Affiliates effective August 10, 2017.*
(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
(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.

58

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:	November 1, 2018	By:	/s/ Joseph W. Mulpas
			Joseph W. Mulpas
			Vice President and Chief Accounting Officer (Principal Accounting Officer)

59

EX-10.1

Exhibit 10.1

NISOURCE INC.

SUPPLEMENTAL EXECUTIVE RETIREMENT PLAN

As Amended and Restated Effective August 10, 2017

TABLE OF CONTENTS

Page

ARTICLE I Background and Purpose			1
	1.1	Background	1
	1.2	Purpose	1
ARTICLE II Definitions			2
	2.1	Affiliate	2
	2.2	Benefits Committee	2
	2.3	Board	2
	2.4	Code	2
	2.5	Company	2
	2.6	Compensation	2
	2.7	Disability or Disabled	2
	2.8	Early Retirement	3
	2.9	Effective Date	3
	2.10	Final Average Compensation	3
	2.11	NiSource Pension Plan	3
	2.12	Normal Retirement	3
	2.13	ONC Committee	3
	2.14	Participant	3
	2.15	Pension	3
	2.16	Pension Restoration Plan	3
	2.17	Plan	3
	2.18	Plan Administrator	3
	2.19	Post‑2004 Benefit	3
	2.20	Pre‑2005 Benefit	3
	2.21	Primary Social Security Benefit	4
	2.22	Qualified Pension Plan	4
	2.23	Retirement	4
	2.24	Service	4
ARTICLE III Eligibility and Participation			4
ARTICLE IV Supplemental Retirement Pension			4
	4.1	Applicability	4
	4.2	Supplemental Retirement Pension	4
	4.3	Reduction for Early Retirement	5
	4.4	Separation from Service Prior to Early Retirement	6
	4.5	Supplemental Disability Pension	6
	4.6	Supplemental Spouse Pension	7
	4.7	Retiree Death Benefit	8
	4.8	Cost of Living Adjustment	8
	4.9	Separate Agreement	8

i

TABLE OF CONTENTS

(continued)

Page

ARTICLE V Supplemental Retirement Account			8
	5.1	Applicability	8
	5.2	Supplemental Retirement Account	8
	5.3	Supplemental Credits	8
	5.4	Separation from Service	8
	5.5	Death	9
ARTICLE VI Distributions			9
	6.1	Pre‑2005 Benefit	9
	6.2	Post‑2004 Benefit	9
ARTICLE VII Change in Control			12
	7.1	Change in Control	12
	7.2	Potential Change in Control	14
	7.3	Additional Service and Compensation Upon Change in Control	14
	7.4	Waiver of Service and Age Requirements Upon Change in Control	14
	7.5	Funding of Plan Benefits Upon Potential Change in Control	15
	7.6	Plan Administration and Amendment Upon a Change in Control	15
	7.7	Committee Discretion to Pay Lump Sum After a Change in Control	15
	7.8	Lump Sum Election	15
	7.9	Definitions	16
ARTICLE VIII Beneficiary Designation			17
	8.1	Beneficiary Designation	17
	8.2	Changing Beneficiary	17
	8.3	No Beneficiary Designation	17
ARTICLE IX Plan Administration			17
	9.1	Allocation of Duties to Committees	17
	9.2	Agents	18
	9.3	Information Required by Committee	18
	9.4	Binding Effect of Decisions	18
ARTICLE X Claims Procedure			18
	10.1	Claim	18
	10.2	Review of Claim	18
	10.3	Notice of Denial of Claim	19
	10.4	Reconsideration of Denied Claim	19
ARTICLE XI Plan Amendment and Termination			20
	11.1	Plan Amendment	20
	11.2	Plan Termination	20

ii

TABLE OF CONTENTS

(continued)

Page

ARTICLE XII Miscellaneous			21
	12.1	Plan Financing	21
	12.2	Non‑Compete and Related Provisions	21
	12.3	Nonguarantee of Employment	21
	12.4	Nonalienation of Benefits	22
	12.5	Indemnification	22
	12.6	Severability	23
	12.7	Action by Company	23
	12.8	Protective Provisions	23
	12.9	Governing Law	23
	12.1	Notice	23
	12.11	Successors	23
	12.12	Actuarial Assumptions	23

iii

NISOURCE INC.

SUPPLEMENTAL EXECUTIVE RETIREMENT PLAN

As Amended and Restated Effective August 10, 2017

ARTICLE I

Background and Purpose

1.1Background. Northern Indiana Public Service Company adopted the Northern Indiana Public Service Company Supplemental Executive Retirement Plan effective as of December 23, 1982. The Plan was amended as of January 1, 1989. The Plan was subsequently adopted by NIPSCO Industries, Inc., the successor to Northern Indiana Public Service Company, effective as of January 1, 1991. The Plan was amended and restated, effective January 1, 1993 and September 1, 1994. Effective June 1, 2002, NiSource Inc., the parent company of NIPSCO Industries, Inc., assumed sponsorship of the Plan and the Plan was further amended and restated to make administrative and technical changes. The Plan was further amended, effective January 1, 2004, to reflect changes in the structure of benefits under the Plan. The Plan was again amended and restated, effective January 1, 2005, to comply with Internal Revenue Code Section 409A with respect to benefits earned under the Plan from and after January 1, 2005. Benefits under the Plan earned and vested prior to January 1, 2005 shall be administered without giving effect to Code Section 409A, and guidance and regulations thereunder. The Plan was again amended and restated, effective January 1, 2008, to incorporate special transition relief under Internal Revenue Service Notice 2007-86 to allow Participants to elect to change the time and form of payment of certain Post-2004 Benefits. The Plan was further amended and restated, effective January 1, 2010, to clarify how certain supplemental death benefits will be paid to Participants who have reached Retirement. The Plan was further amended and restated effective May 13, 2011 to transfer all administrative authority with respect to the Plan (including the authority to render decisions on claims and appeals and make administrative or ministerial amendments) from the ONC Committee to the Benefits Committee. The Plan is hereby amended and restated again, effective August 10, 2017, to revise the procedures for determining Disability under the Plan.

1.2Purpose. The purpose of the Plan is to provide selected key executives and employees with additional security in order to aid the Company (as defined herein and including its predecessors) in retaining its present management and, should circumstances require it, to aid the Company in attracting additions to management. The Company, by providing such additional benefits, expects such key executives and employees to be available for consulting assignments to the Company after retirement, at the Company’s request.

It is intended that the Plan be exempt from the reporting and disclosure requirements of Title I of the Employee Retirement Income Security Act of 1974 because it is an unfunded plan maintained by an employer for the purpose of providing benefits for a select group of management or highly compensated employees.

ARTICLE IIDefinitions

For the purposes of the Plan, the following terms shall have the meanings indicated, unless the context clearly indicates otherwise. Except when otherwise required by the context, any masculine terminology in this document shall include the feminine, and any singular terminology shall include the plural. The headings of Articles and Sections are included solely for convenience, and if there is any conflict between such headings and the text of the Plan, the text shall control.

2.1Affiliate. Any corporation that is a member of a controlled group of corporations (as defined in Code Section 414(b)) that includes the Company; any trade or business (whether or not incorporated) that is under common control (as defined in Code Section 414(c)) with the Company; any organization (whether or not incorporated) that is a member of an affiliated service group (as defined in Code Section 414(m)) that includes the Company; any leasing organization, to the extent that its employees are required to be treated as if they were employed by the Company pursuant to Code Section 414(n) and the regulations thereunder; and any other entity required to be aggregated with the Company pursuant to regulations under Code Section 414(o). An entity shall be an Affiliate only with respect to the existing period as described in the preceding sentence.

2.2Benefits Committee. The NiSource Benefits Committee.

2.3Board. The Board of Directors of NiSource Inc.

2.4Code. The Internal Revenue of Code of 1986, as amended.

2.5Company. NiSource Inc. and its subsidiaries and affiliates that adopt the Plan for the benefit of key employees, or its successor or successors.

2.6Compensation. As defined in the NiSource Pension Plan, but disregarding the definition of Taxable Compensation and the limitations required by Code Section 401(a)(17), or any successor Section. In addition, for purposes of the Plan, bonuses shall be considered in full as Compensation and not limited to 50% of base pay.

2.7Disability or Disabled. A Participant has a Disability or is Disabled if he or she has a condition that (a)  causes a Participant, by reason of any medically determinable physical or mental impairment that can be expected to result in death or can be expected to last for a continuous period of not less than 12 months, to receive income replacement benefits for a period of not less than three months under an accident and health plan covering employees of the Company or an Affiliate or (b) causes a Participant to be eligible to receive Social Security disability payments.

2.8Early Retirement. Separation from Service for reasons other than death or Disability after the Participant has both attained age 55 and completed at least 10 years of Service, but before the Participant’s Normal Retirement, except as otherwise provided.

2

2.9Effective Date. August 10, 2017, the date on which the provisions of this amended and restated Plan become effective, except as otherwise provided herein. The original Effective Date of the Plan was December 23, 1982.

2.10Final Average Compensation. The result obtained by dividing the total Compensation paid to a Participant during a considered period by the number of months for which such Compensation was received. The considered period shall be the 60 consecutive calendar months within the last 120 months of service that produces the highest result.

2.11NiSource Pension Plan. The NiSource Salaried Pension Plan, as amended from time to time.

2.12Normal Retirement. Separation from Service for reasons other than death or Disability after a Participant has: (1) attained age 62; or (2) attained age 60 and completed at least 25 years of Service, except as otherwise provided.

2.13ONC Committee. The Officer Nomination and Compensation Committee of the Board, which has certain specific duties with respect to the Plan.

2.14Participant. An employee or retiree participating in the Plan in accordance with the provisions of Article III.

2.15Pension Restoration Plan. Pension Restoration Plan for NiSource Inc. and Affiliates, as amended from time to time.

2.16Plan. NiSource Inc. Supplemental Executive Retirement Plan.

2.17Plan Administrator. The Benefits Committee, or such delegate of the Benefits Committee delegated to carry out the administrative functions of the Plan.

2.18Post‑2004 Benefit. The portion of a Participant’s Supplemental Retirement Pension or Supplemental Retirement Account, as applicable, equal to the present value, determined as of a Participant’s date of separation from Service after December 31, 2004, of the excess of such benefit or account balance to which a Participant would be entitled under the Plan if he or she voluntarily separated from Service without cause after December 31, 2004 over his or her Pre‑2005 Benefit and received a full payment of benefits from the Plan on the earliest possible date allowed under the Plan following the separation from Service, pursuant to Articles IV and V, calculated from and after January 1, 2005 to the date of separation from Service.

2.19Pre‑2005 Benefit. The portion of a Participant’s Supplemental Retirement Pension or Supplemental Retirement Account, as applicable, equal to the present value of the benefit or account balance, determined as of December 31, 2004, to which a Participant would be entitled under the Plan if he or she voluntarily separated from Service without cause on December 31, 2004 and received a full payment of benefits from the Plan on the earliest possible date allowed under the Plan following separation from Service, pursuant to Articles IV and V, calculated as of December 31, 2004.

3

2.20Primary Social Security Benefit. The monthly amount available to a Participant at age 65 (or at Retirement, if later) under the provisions of Title II of the Social Security Act in effect at the time of separation from Service, assuming the following:

(a) The Participant attained age 65 in the year of Retirement, and

(b) The Participant earned maximum taxable wages under Code Section 3121(a)(1) in all years prior to the year of Retirement. A Participant’s Primary Social Security Benefit will be deducted in accordance with Article IV, even though he or she may not be receiving or may not be eligible to receive Social Security benefits.

2.21Qualified Pension Plan. The NiSource Pension Plan and any other tax‑qualified defined benefit pension plan maintained by the Company or any Affiliate.

2.22Retirement. A Participant’s Normal or Early Retirement.

2.23Service. A Participant’s or employee’s employment or service with the Company, as defined in the NiSource Pension Plan, or such other employment or service date as determined by the Board.

ARTICLE IIIEligibility and Participation

The ONC Committee shall select which key employees of the Company will be eligible to participate in the Plan. In accordance with Article I, it is intended that officers and certain other employees be eligible for participation.

After the ONC Committee approves participation for an individual, the Company or the Benefits Committee shall provide the individual with a notice of participation in the Plan and a description of the Plan.

ARTICLE ISupplemental Retirement Pension

4.1Applicability. This Article IV shall apply to each Participant or former Participant who first participated in the Plan prior to January 23, 2004.

4.2Supplemental Retirement Pension. Upon Normal Retirement, a Participant shall receive a monthly Supplemental Retirement Pension calculated on a single‑life basis equal to the larger of (a) or (b) below, reduced in each case by the accrued benefit (stated in the form of a single‑life pension and excluding any supplements related to eligibility for a Social Security benefit) the Participant is eligible to receive under (1) either the FAP Benefit or the AB I or AB II Benefit

4

Option, as applicable, of the NiSource Pension Plan or other Qualified Pension Plan (as such terms are defined in the respective plan) and (2) the Pension Restoration Plan.

(a) The sum of:

(i) 1.7% of the Participant’s Final Average Compensation multiplied by the Participant’s Service to a maximum of 30 years; plus

(ii) 0.6% of the Participant’s Final Average Compensation multiplied by the Participant’s Service in excess of 30 years.

(b) The sum of:

(i) 3% of the Participant’s Final Average Compensation multiplied by the Participant’s Service to a maximum of 20 years; plus

(ii) 0.5% of the Participant’s Final Average Compensation multiplied by the Participant’s Service in excess of 20 years, to a maximum of 30 years;

(iii) less 5% of the Participant’s Primary Social Security Benefit, multiplied by the Participant’s Service to a maximum of 20 years.

Upon Early Retirement, a Participant shall receive a monthly Supplemental Retirement Pension in a reduced amount (as described in Section 4.3 below).

4.3Reduction for Early Retirement. A Participant who experiences a separation from Service prior to Normal Retirement, but after Early Retirement, shall receive a monthly Supplemental Retirement Pension in an amount determined in accordance with Section 4.2 above, but reduced as follows: (1) by 6% for each of the first two (2) years and 4% for each of the next five years that commencement of the Participant’s Supplemental Retirement Pension precedes the date that the Participant would attain age 62; or (2) if the Participant had completed 25 years of Service at the time of his or her separation, by 6% for the first year and 4% for each of the next four years that commencement of the Participant’s Supplemental Retirement Pension precedes the date that the Participant would attain age 60, with a pro rata reduction for any fraction of a year.

Payment of the Participant’s monthly reduced Supplemental Retirement Pension shall normally commence within 45 days following a separation from Service, or, if later, within such timeframe permitted under Code Section 409A, and guidance and regulations thereunder. Notwithstanding the preceding sentence, a Participant may elect to defer the commencement of the portion of his or her reduced Supplemental Retirement Pension that constitutes the Pre‑2005 Benefit to any date between Early Retirement and attainment of age 62 by a written election delivered to the Plan Administrator on or before the last day of the calendar year preceding the calendar year of Early Retirement. A Participant may elect to defer the commencement of the portion of his or her reduced Supplemental Retirement Pension that constitutes the Post‑2004 Benefit to any date between Early Retirement and attainment of age 62 by a written election delivered to the Plan Administrator only if such election (i) constitutes a delay in payment or change in the form of payment, (ii) does

5

not take effect until at least 12 months after the date on which the election is made, (iii) defers the first payment with respect to which such new election is effective for a period of not less than five years from the date such payment would otherwise have been made, and (iv) is not made less than 12 months prior to the date of the first scheduled payment.

4.4Separation from Service Prior to Early Retirement. Upon separation from Service prior to Early Retirement, a Participant shall receive a monthly Supplemental Retirement Pension, calculated on a single‑life basis equal to the excess, if any, of the single‑life pension the Participant would be eligible to receive under either the FAP Benefit option or the Account Balance Option of the NiSource Pension Plan, or any other Qualified Pension Plan, if the limitations required by Code Sections 401(a)(17) and 415, or any other limitation imposed by the Code, the limitation on bonuses to 50% of base pay and the potential limitations relating to Taxable Compensation were not applied, reduced by the single‑life pension the Participant is eligible to receive under (1) either such option of the NiSource Pension Plan, or any other Qualified Pension Plan and (2) the Pension Restoration Plan.

Payment of the Pre‑2005 Benefit to a Participant or his or her beneficiary in accordance with this Section shall commence on the same date as the pension under the NiSource Pension Plan or any other Qualified Pension Plan. Payment of the Post‑2004 Benefit to a Participant or his or her beneficiary in accordance with this Section, shall commence within 45 days after (i) the Participant attains (or would have attained) age 62, if the Participant has not completed at least 25 years of Service, or (ii) if the Participant has completed at least 25 years of Service, the Participant attains (or would have attained) age 60, or, if later, within such timeframe permitted under Code Section 409A, and guidance and regulations thereunder.

4.5Supplemental Disability Pension. If a Participant becomes Disabled while in the active employment of the Company prior to age 65, the Participant shall be eligible for a monthly Supplemental Disability Pension commencing on the date the Disability begins and continuing to the first to occur of the Participant’s death or attainment of age 65, calculated on a single‑life basis, and equal to the larger of (a) or (b) below, reduced in each case by the basic benefit the Participant is eligible to receive under the long‑term group disability insurance coverage provided under any long term disability plan maintained by the Company or any Affiliate.

(a) The sum of:

(i) 1.7% of the Participant’s Final Average Compensation multiplied by the Participant’s Service to a maximum of 30 years, plus

(ii) 0.6% of the Participant’s Final Average Compensation multiplied by the Participant’s Service in excess of 30 years.

(b) The sum of:

(i) 3% of the Participant’s Final Average Compensation multiplied by the Participant’s Service to a maximum of 20 years; plus

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(ii) 0.5% of the Participant’s Final Average Compensation multiplied by the Participant’s Service in excess of 20 years, to a maximum of 30 years; less

(iii) 5% of the Participant’s Primary Social Security Benefit, multiplied by the Participant’s Service to a maximum of 20 years.

After age 65, the Participant shall be eligible for a monthly Supplemental Retirement Pension in accordance with Section 4.2, based on Service the Participant would have had if the Participant had continued working for the Company or an Affiliate to age 65, the Participant’s Final Average Compensation at the time he or she became Disabled, the Primary Social Security Benefit determined at the time the Participant became Disabled, and the single‑life pension the Participant is entitled to receive at age 65 from the NiSource Pension Plan, or any other Qualified Pension Plan, and the Pension Restoration Plan, determined at the time he or she became Disabled.

4.6Supplemental Spouse Pension. Upon the death of a Participant in active employment or while receiving a Supplemental Disability Pension, his or her surviving spouse, if any, shall be eligible to receive a monthly Supplemental Spouse Pension equal to the greater of:

(a) 25% of the Participant’s Final Average Compensation; or

(b) the monthly amount that would have been payable to such surviving spouse if the Participant had elected payment of his or her monthly Supplemental Retirement Pension in the form of a reduced 50% joint and survivor Pension, with his or her spouse as the contingent annuitant, terminated employment (on the date of his or her actual death) and then died immediately prior to the commencement of payments.

The Supplemental Spouse Pension shall commence in the month next following the month of the Participant’s death and continue for the life of such spouse. In the event that the Supplemental Spouse Pension calculated under option (a) of this Section will provide a greater benefit to the spouse immediately following the Participant’s death, but option (b) of this Section will provide a greater monthly benefit as of the date the Participant would have attained age 55, the amount of monthly Supplemental Spouse Pension payable to the surviving spouse shall be: (1) calculated and payable under option (a) during the period immediately following the Participant’s death; and (2) recalculated and payable according to option (b) beginning on the date the Participant would have attained age 55. Beginning on the earliest date that the surviving spouse could have begun receiving a benefit under the NiSource Pension Plan, or any other Qualified Pension Plan, the Supplemental Spouse Pension payable under this Section shall be reduced by the amount of benefit under the NiSource Pension Plan, or any other Qualified Pension Plan, and the Pension Restoration Plan that the spouse is (or would have been) entitled to receive.

4.7Retiree Death Benefit. Upon the death of a Participant who has reached Retirement (including a former Participant who reached Retirement and was paid his or her benefits under this Plan), a lump sum death benefit equal to 50% of his or her retiree group life insurance coverage shall be paid to such Participant’s spouse or other beneficiaries designated with respect to such coverage.

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4.8Cost of Living Adjustment. For Participants in the FAP Benefit of the NiSource Pension Plan, the benefits payable under Sections 4.2 through 4.7 shall be increased in the same percentage and at the same time as cost of living adjustments are made to the pensions of salaried employees of the Company or an Affiliate under the NiSource Pension Plan, or any other Qualified Pension Plan.

4.9Separate Agreement. Notwithstanding prior provisions pertaining to Compensation and Service, each Participant who first becomes eligible to participate in the Plan on and after January 1, 2004 and prior to January 23, 2004 shall have his or her Supplemental Retirement Pension determined based upon his or her Service and Compensation as set forth in a separate, written agreement, if any, between the Company and such Participant.

ARTICLE VSupplemental Retirement Account

5.1Applicability. This Article V shall apply to each Participant who first participates in the Plan on and after January 23, 2004.

5.2Supplemental Retirement Account. A Participant’s Supplemental Retirement Account is a notional account equal to the sum of his or her Compensation Credits, Supplemental Credits, if any, and Interest Credits. Compensation Credits shall be credited to a Participant’s Supplemental Retirement Account as of the last day of each Plan Year beginning on or after January 1, 2004 equal to five percent of the Participant’s Compensation for such Plan Year. Supplemental Credits, if any, shall be credited pursuant to Section 5.3. Interest Credits shall be calculated in the same manner and shall be credited to a Participant’s Supplemental Retirement Account at the same time as provided under the NiSource Pension Plan or any other Qualified Pension Plan.

5.3Supplemental Credits. The ONC Committee, subject to approval of the Board, may authorize Supplemental Credits to a Participant’s Supplemental Retirement Account in such amounts and at such times, and subject to such specific terms and provisions, as authorized by the ONC Committee.

5.4Separation from Service. Upon separation from Service, for any reason other than death, with five or more years of Service, unless a shorter period is provided in a separate, written agreement between the Company and the Participant and approved by the Plan Administrator, a Participant shall receive the balance of his or her Supplemental Retirement Account distributed in accordance with Sections 6.1 and 6.2 within 45 days after such separation from Service, or, if later, within such timeframe permitted under Code Section 409A, and guidance and regulations thereunder.

5.5Death. Upon the death of a Participant prior to final distribution of his or her Supplemental Retirement Account after completing five or more years of Service, unless a shorter period is provided in a separate, written agreement between the Company and the Participant and

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approved by the Board, the Participant’s beneficiary, designated in such manner as provided by the Plan Administrator, shall receive the balance of the Participant’s Supplemental Retirement Account distributed in accordance with Sections 6.1 and 6.2.

ARTICLE VIDistributions

6.1Pre‑2005 Benefit. This Section 6.1 applies only to a Pre‑2005 Benefit.

(a) Form of Payment. Notwithstanding Sections 4.2, 4.3 and 4.4, a Participant shall receive distribution of his or her Pre‑2005 Benefit, pursuant to Articles IV or V, in the same form as his or her distribution under the NiSource Pension Plan, computed in the same manner as in the NiSource Pension Plan, or under any other Qualified Pension Plan, computed in the same manner as in such Qualified Pension Plan. Any election under the NiSource Pension Plan or any other Qualified Pension Plan shall apply to his or her Pre‑2005 Benefit pursuant to the preceding sentence only if it is made by written instrument delivered to the Plan Administrator at least 30 days prior to the date of such distribution. If such election is not so made at least 30 days prior to the date of distribution of his or her Pre‑2005 Benefit, the Participant’s Pre‑2005 Benefit shall be paid as a 50% joint and survivor Pension if such Participant is married, or as a single‑life Pension if such Participant is unmarried. If a Participant who makes an election pursuant to this subsection 6.1(a) at least 30 days prior to the date of distribution dies prior to distribution pursuant to such election, such election shall be revoked and the provisions of Article IV and subsection 6.1(b) shall apply.

(b) Small Benefit Amounts. At the discretion of the Plan Administrator, the present value of any Pre‑2005 Benefit payable under the Plan that does not exceed $5,000 may be paid to the Participant or his or her surviving spouse or other designated beneficiary in quarterly, semi‑annual or annual installments, or in a single lump sum.

6.2Post‑2004 Benefit. This Section 6.2 applies only to a Post‑2004 Benefit.

(a) Form of Payment. The Post‑2004 Benefit shall be payable in a form available under the NiSource Pension Plan, computed in the same manner as in the NiSource Pension Plan, or under any other Qualified Pension Plan, computed in the same manner as in such Qualified Pension Plan, as elected by a Participant by written notice delivered to the Plan Administrator on or before December 31, 2005. Notwithstanding the preceding sentence, in the case of an employee who first becomes a Participant on or after January 1, 2005, the aforementioned election with respect to a Post‑2004 Benefit shall be made by written notice delivered to the Plan Administrator within 30 days after the date the Participant first becomes eligible to participate in the Plan and such election shall be effective with respect to Compensation related to services to be performed subsequent to the election; provided, however, that a Participant shall not be considered first eligible if, on the date he or she becomes a Participant, he or she participates in any other nonqualified plan of the same category (account

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balance or nonaccount balance, as applicable), which is subject to Code Section 409A, maintained by the Company or any Affiliate. If payment in the form of an annuity is elected, the annuity type shall be elected by the Participant at the time he or she makes the election described in the first or second sentence of this paragraph from among those annuities available at that time under the NiSource Pension Plan or under any other Qualified Pension Plan. If a Participant fails to elect a form of distribution, the Participant’s Post‑2004 Benefit shall be payable in a lump sum.

If a Participant who makes an election pursuant to this subsection 6.2(a) dies prior to distribution pursuant to such election, such election shall be revoked and the provisions of Article IV and subsection 6.2(b) shall apply.

Any change in an election of a form of distribution available under the NiSource Pension Plan or any other Qualified Pension Plan shall apply to his or her Post‑2004 Benefit pursuant to the preceding paragraph only if it is made by written instrument delivered to the Plan Administrator and if (i) such new election does not take effect until at least 12 months after the date on which the election is made, (ii) the first payment with respect to which such new election is effective is deferred for a period of not less than five (5) years from the date such payment would otherwise have been made, and (iii) such new election is not made less than 12 months prior to the date of the first scheduled payment; provided, however, that an election to change from one type of annuity payment to a different, actuarially equivalent, type of annuity payment shall not be considered a change to the method of payment for purposes of applying the restrictions in clauses (i), (ii) and (iii).

Notwithstanding the preceding paragraph of this Section 6.2(a), a Participant may change an election with respect to the form of payment of a Post‑2004 Benefit, without regard to the restrictions imposed under the preceding paragraph, on or before December 31, 2006; provided that such election (i) applies only to amounts that would not otherwise be payable in calendar year 2006, and (ii) shall not cause an amount to be paid in calendar year 2006 that would not otherwise be payable in such year. Additionally, a Participant may change an election with respect to the form of payment of a Post-2004 Benefit, without regard to the restrictions imposed under the preceding paragraph, on or before December 31, 2007; provided that such election (i) applies only to amounts that would not otherwise be payable in calendar year 2007, and (ii) shall not cause an amount to be paid in calendar year 2007 that would not otherwise be paid in such year. Additionally, a Participant may change an election with respect to the form of payment of a Post-2004 Benefit, without regard to the restrictions imposed by the preceding paragraph, on or before December 31, 2008; provided that such election (i) applies only to amounts that would not otherwise be payable before January 1, 2009, and (ii) shall not cause an amount to be paid in calendar year 2007 or 2008 that would not otherwise be paid in such years.

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(b) Specified Employees. Notwithstanding any other provision of the Plan, in no event can a payment of a Post‑2004 Benefit, pursuant to Article IV or Section 5.4, to a Participant who is a Specified Employee of the Company or an Affiliate, at a time during which the Company’s capital stock or capital stock of an Affiliate is publicly traded on an established securities market, in the calendar year of his or her separation from Service be made before the date that is six months after the date of the Participant’s separation from Service with the Company and all Affiliates, unless such separation is due to his or her death or Disability.

A Participant shall be deemed to be a Specified Employee for purposes of this paragraph (b) if he or she is in job category C2 or above with respect to the Company or any Affiliate that employs him or her; provided that if at any time the total number of employees in job category C2 and above is less than 50, a Specified Employee shall include any person who meets the definition of Key Employee set forth in Code Section 416(i) without reference to paragraph (5). A Participant shall be deemed to be a Specified Employee with respect to a calendar year if he or she is a Specified Employee on September 30th of the preceding calendar year. If a Specified Employee will receive payments hereunder in the form of installments or an annuity, the first payment made as of the date six months after the date of the Participant’s separation from Service with the Company and all Affiliates shall be a lump sum, paid as soon as practicable after the end of such six-month period, that includes all payments that would otherwise have been made during such six-month period. From and after the end of such six month period, any such installment or annuity payments shall be made pursuant to the terms of the applicable installment or annuity form of payment.

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ARTICLE VIIChange in Control

7.1Change in Control. A “Change in Control” shall be deemed to take place on the occurrence of either a “Change in Ownership,” “Change in Effective Control” or a “Change of Ownership of a Substantial Portion of Assets,” as defined below:

(a) Change in Ownership. A Change in Ownership of the Company occurs on the date that any one person, or more than one Person Acting as a Group (as defined below), acquires ownership of stock of the Company that, together with stock held by such person or group, constitutes more than 50% of the total fair market value or total voting power of the stock of the Company. However, if any one person or more than one Person Acting as a Group, is considered to own more than 50% of the total fair market value or total voting power of the stock of the Company, the acquisition of additional stock by the same person or persons is not considered to cause a Change in Ownership of the Company, as applicable (or to cause a Change in Effective Control of the Company). An increase in the percentage of stock owned by any one person, or Persons Acting as a Group, as a result of a transaction in which the Company acquires its stock in exchange for property s be treated as an acquisition of stock. This paragraph (a) applies only when there is a transfer of stock of the Company (or issuance of stock of the Company) and stock in the Company remains outstanding after the transaction.

(b) Change in Effective Control. A Change in Effective Control of the Company occurs on the date that either –

(i) Any one person, or more than one Person Acting as a Group, acquires (or has acquired during the 12-month period ending on the date of the most recent acquisition by such person or persons) ownership of stock of the Company possessing 35% or more of the total voting power of the stock of the Company; or

(ii) a majority of members of the Board is replaced during any 12‑month period by directors whose appointment or election is not endorsed by a majority of the members of the Board prior to the date of the appointment or election,

In the absence of an event described in paragraph (i) or (ii), a Change in Effective Control of the Company will not have occurred.

Acquisition of additional control. If any one person, or more than one Person Acting as a Group, is considered to effectively control the Company, the acquisition of additional control of the Company by the same person or persons is not considered

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to cause a Change in Effective Control of the Company (or to cause a Change in Ownership of the Company).

(c) Change of Ownership of a Substantial Portion of Assets. A Change of Ownership of a Substantial Portion of Assets occurs on the date that any one person, or more than one Person Acting as a Group, acquires (or has acquired during the 12-month period ending on the date of the most recent acquisition by such person or persons) assets from the Company that have a total gross fair market value equal to or more than 40% of the total gross fair market value of all of the assets of the Company immediately prior to such acquisition or acquisitions. For this purpose, gross fair market value means the value of the assets of the Company, or the value of the assets being disposed of, determined without regard to any liabilities associated with such assets.

Transfers to a related person. There is no Change in Control when there is a transfer to an entity that is controlled by the shareholders of the Company immediately after the transfer. A transfer of assets by the Company is not treated as a Change of Ownership of a Substantial Portion of Assets if the assets are transferred to –

(i) A shareholder of the Company (immediately before the asset transfer) in exchange for or with respect to its stock;

(ii) An entity, 50% or more of the total value or voting power of which is owned, directly or indirectly, by the Company;

(iii) A person, or more than one Person Acting as a Group, that owns, directly or indirectly, 50% or more of the total value or voting power of all the outstanding stock of the Company; or

(iv) An entity, at least 50% of the total value or voting power of which is owned, directly or indirectly, by a person described in paragraph (iii).

A person’s status is determined immediately after the transfer of the assets. For example, a transfer to a corporation in which the Company has no ownership interest before the transaction, but which is a majority-owned subsidiary of the Company after the transaction is not treated as a Change of Ownership of a Substantial Portion of Assets of the Company.

(d) Persons Acting as a Group. Persons shall not be considered to be acting as a group solely because they purchase or own stock of the same corporation at the same time or as a result of the same public offering. However, persons shall be considered to be acting as a group if they are owners of a corporation that enters into a merger, consolidation, purchase or acquisition of stock, or similar business transaction with the Company. If a person, including an entity, owns stock in both corporations that enter into a merger, consolidation, purchase or acquisition of stock, or similar transaction, such shareholder is considered to be acting as a group with other

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shareholders in a corporation prior to the transaction giving rise to the change and not with respect to the ownership interest in the other corporation.

7.2Potential Change in Control. A “Potential Change in Control” shall include any of the following:

(a) The delivery to the Company by any “person,” as defined in Section 13(d)(3) of The Securities Exchange Act of 1934 (the “Act”), of a statement containing the information required by Schedule 13‑D under the Act, or any amendment to any such statement, that shows that such person has acquired, directly or indirectly, the beneficial ownership of (1) more than twenty percent (20%) of any class of equity security of the Company entitled to vote as a class in the election or removal from office of directors, or (2) more than twenty percent (20%) of the voting power of any group of classes of equity securities of the Company entitled to vote as a single class in the election or removal from office of directors.

(b) The Company becomes aware that preliminary or definitive copies of a proxy statement and information statement or other information have been filed with the Securities and Exchange Commission pursuant to Rule 14a‑6, Rule 14c‑5 or Rule 14f‑1 under the Act relating to a proposed change in control of the Company.

(c) The delivery to the Company pursuant to Rule 14d‑3 under the Act of a Tender Offer Statement relating to equity securities of the Company.

(d) The Board adopts a resolution to the effect that for purposes of the Plan a Potential Change in Control has occurred.

7.3Additional Service and Compensation Upon Change in Control. With respect to a Participant who, pursuant to contract with the Company, is entitled to compensation from the Company for an additional 36 months in the event that after a Change in Control the Participant’s employment is terminated by the Company or an Affiliate under circumstances described in the contract, such Participant’s years of Service under Article II, and Supplemental Retirement Pension under Section 4.2 or Supplemental Retirement Account under Section 5.2, as applicable, shall be calculated as if the Participant had continued in employment with the Company for an additional 36 months at the rate of Compensation in effect immediately prior to his or her employment termination; provided that, in no event shall the counting of a Participant’s Compensation during this 36‑month period reduce his or her Final Average Compensation figure below its highest level prior to the Participant’s separation from Service.

7.4Waiver of Service and Age Requirements Upon Change in Control. A Participant who separates from service within 24 months following a Change in Control for any reason other than a termination by the Company for Good Cause, but prior to Early Retirement, shall be eligible for the Supplemental Retirement Pension specified in Section 4.2, rather than the Supplemental Retirement Pension specified in Section 4.4, commencing at Normal Retirement. Notwithstanding the previous sentence, such a Participant may elect to begin receiving the portion of his or her Supplemental Retirement Pension that constitutes his or her Pre‑2005 Benefit pursuant to this

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Section 7.4 at any time after attaining age 55 years, subject to the reduction specified in Section 4.3. Such election shall have no effect on the distribution of his or her Post‑2004 Benefit at his or her Normal Retirement Date.

7.5Funding of Plan Benefits Upon Potential Change in Control. Upon a Potential Change in Control, the Plan Administrator shall identify the amount by which the present value of all benefits earned to date under the Plan (after offsets) exceeds the then fair market value of the applicable Trust assets, calculated using the Pension Benefit Guaranty Corporation immediate annuity interest rate as of the date of the Potential Change in Control, the 1983 GAM mortality tables, and the most valuable optional payment form (the “Full Funding Amount”), and the Company shall contribute such Full Funding Amount to the Trust. Each Participant’s benefits for purposes of calculating present value shall be the highest benefit the Participant would have under the Plan within the six months following a Potential Change in Control, assuming that the Participant’s employment continues for six months at the same rate of Compensation, and that the Participant receives any benefit enhancement provided by the Plan, or any other agreement, upon a Change in Control.

7.6Plan Administration and Amendment Upon a Change in Control. Upon and after a Change in Control, the Company no longer shall have the power to appoint or remove members of the Benefits Committee or ONC Committee, nor the power to approve legal counsel or actuaries employed by such committees. Upon and after a Change in Control, only the respective committee members shall have the power to appoint or remove members. If, at any time after a Change in Control, all members of the Benefits Committee or ONC Committee have been removed or resigned, then all of the powers, rights and duties vested in such committee by Article IX below shall be vested in the trustee of the Trust.

7.7Plan Administrator Discretion to Pay Lump Sum After a Change in Control. Upon and after a Change in Control, the Plan Administrator may, in its sole discretion, distribute, or cause the trustee under the Trust to distribute, to a Participant or a surviving spouse, the present value (determined in accordance with the assumptions in Section 12.11) of the Participant’s Pre‑2005 Benefit, or the portion of Supplemental Disability Pension or the surviving spouse’s Supplemental Spouse Pension attributable to his or her Pre‑2005 Benefit, payable under the Plan in a lump sum payment. The Plan Administrator shall distribute, or cause the trustee under the Trust to distribute, the present value of the Participant’s Post‑2004 Benefit.

7.8Lump Sum Election. Each calendar year, a Participant shall have the right to elect to receive the present value (determined in accordance with the assumptions in Section 12.11) of the portion of the Participant’s Supplemental Retirement Pension or the balance of the Participant’s Supplemental Retirement Account that constitutes the Participant’s Pre‑2005 Benefit or the Participant’s Supplemental Disability Pension, in a lump sum if:

(a) a Change in Control occurs in the calendar year subsequent to the calendar year in which the election is made; and

(b) (1)    within 24 months following the Change in Control any one of the payment triggering conditions set forth in the Change in Control and

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Termination Agreement between the Company and the Participant shall have occurred; or

(i) if no Change in Control and Termination Agreement is in effect between the Company and the Participant on the date of the Change in Control and within 24 months following the Change in Control the employment of the Participant with the Company is terminated by the Company for any reason other than Good Cause or the Participant terminates his or her employment with the Company for Good Reason.

Such election shall be irrevocable for the calendar year to which it applies. A distribution pursuant to this Section shall be made as soon as practicable following the Participant’s separation from Service. Notwithstanding the preceding provisions of this Section, a Participant had the right to make the election set forth in this Section at any time during the first three (3) months of calendar year 2003 with respect to a Change in Control that occurred during the last nine (9) months of calendar year 2003. Any such election was irrevocable for calendar year 2003 and was subject to the other provisions of this Section.

7.9Definitions.

(a) “Good Cause” shall be deemed to exist if, and only if:

(i) the Participant engages in acts or omissions constituting dishonesty, intentional breach of fiduciary obligation or intentional wrongdoing or malfeasance, in each case that results in substantial harm to the Company; or

(ii) the Participant is convicted of a criminal violation involving fraud or dishonesty.

(b) “Good Reason” shall be deemed to exist if, and only if:

(i) there is a significant change in the nature or the scope of the Participant's authorities or duties;

(ii) there is a significant reduction in the Participant's monthly rate of base salary, his or her opportunity to earn a bonus under an incentive bonus compensation plan maintained by the Company or his or her benefits; or

(iii) the Company changes by 100 miles or more the principal location in which the Participant is required to perform services.

ARTICLE VIIIBeneficiary Designation

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8.1Beneficiary Designation. Each Participant shall have the right, at any time, to designate one or more persons or an entity as Beneficiary (both primary as well as secondary) to whom benefits under the Plan shall be paid in the event of the Participant’s death prior to complete distribution of the Participant’s interest under the Plan. Each Beneficiary designation shall be in a written form prescribed by the Benefits Committee and shall be effective only when filed with the Benefits Committee during the Participant’s lifetime.

If the Participant designates multiple beneficiaries, he or she shall designate the percentage, in whole numbers, allocated to each such beneficiary.

8.2Changing Beneficiary. Any Beneficiary designation may be changed by a Participant without the consent of the previously named Beneficiary by the filing of a new designation with the Benefits Committee. The filing of a new designation shall cancel all designations previously filed.

8.3No Beneficiary Designation. If any Participant fails to designate a beneficiary in the manner provided above, if the designation is void or if the beneficiary designated by a deceased Participant dies before the Participant or before complete distribution of the Participant’s benefits, the Participant’s beneficiary shall be the person in the first of the following classes in which there is a survivor:

(a) The Participant’s spouse;

(b) The Participant’s children in equal shares, except that if any of the children predeceases the Participant but leaves issue surviving, then such issue shall take, by right of representation, the share the parent would have taken if living;

(c) The Participant’s estate.

ARTICLE IXPlan Administration

9.1Allocation of Duties to Committees. The Plan shall be administered by the Benefits Committee, as delegated by the ONC Committee. The Benefits Committee shall have the authority to make, amend, interpret, and enforce all appropriate rules and regulations for the administration of the Plan and decide or resolve any and all questions, including interpretations of the Plan, as may arise in such administration, except as otherwise reserved to the ONC Committee herein, or by resolution or charter of the respective committees. Members of the Benefits Committee may be Participants under the Plan.

In its discretion, the Plan Administrator may delegate to any division or department of the Company the discretionary authority to make decisions regarding Plan administration, within limits and guidelines from time to time established by the Plan Administrator. The delegated discretionary authority shall be exercised by such division or department’s senior officer, or his/her delegate.

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Within the scope of the delegated discretionary authority, such officer or person shall act in the place of the Plan Administrator and his/her decisions shall be treated as decisions of the Plan Administrator.

9.2Agents. The Plan Administrator may, from time to time, employ agents and delegate to them such administrative duties as it sees fit, and may from time to time consult with counsel who may be counsel to the Company.

9.3Information Required by Plan Administrator. The Company shall furnish the Plan Administrator with such data and information as the Plan Administrator may deem necessary or desirable in order to administer the Plan. The records of the Company as to an employee’s or Participant’s period or periods of employment, separation from Service and the reason therefore, reemployment and Compensation will be conclusive on all persons unless determined to the Plan Administrator’s satisfaction to be incorrect. Participants and other persons entitled to benefits under the Plan also shall furnish the Plan Administrator with such evidence, data or information as the Plan Administrator considers necessary or desirable to administer the Plan.

9.4Binding Effect of Decisions. Subject to applicable law, and the provisions of Article X, any interpretation of the provisions of the Plan and any decision on any matter within the discretion of the Benefits Committee and/or the ONC Committee (or any duly authorized delegate of either such committee) and made in good faith shall be binding on all persons.

ARTICLE XClaims Procedure

10.1Claim. Claims for benefits under the Plan shall be made in writing to the Plan Administrator. The Plan Administrator shall establish rules and procedures to be followed by Participants and Beneficiaries in filing claims for benefits, and for furnishing and verifying proof necessary to establish the right to benefits in accordance with the Plan, consistent with the remainder of this Article.

10.2Review of Claim. The Plan Administrator shall review all claims for benefits. Upon receipt by the Plan Administrator of such a claim, it shall determine all facts that are necessary to establish the right of the claimant to benefits under the provisions of the Plan and the amount thereof as herein provided within 90 days of receipt of such claim. If prior to the expiration of the initial 90 day period, the Plan Administrator determines additional time is needed to come to a determination on the claim, the Plan Administrator shall provide written notice to the Participant, Beneficiary or other claimant of the need for the extension, not to exceed a total of 180 days from the date the application was received. If the Plan Administrator fails to notify the claimant in writing of the denial of the claim within 90 days after the Plan Administrator receives it, the claim shall be deemed denied.

10.3Notice of Denial of Claim. If the Plan Administrator wholly or partially denies a claim for benefits, the Plan Administrator shall, within a reasonable period of time, but no later than 90 days after receiving the claim (unless extended as provided above), notify the claimant in writing

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of the denial of the claim. Such notification shall be written in a manner reasonably expected to be understood by such claimant and shall in all respects comply with the requirements of ERISA, including but not limited to inclusion of the following:

(a) the specific reason or reasons for denial of the claim;

(b) a specific reference to the pertinent Plan provisions upon which the denial is based;

(c) a description of any additional material or information necessary for the claimant to perfect the claim, together with an explanation of why such material or information is necessary; and

(d) an explanation of the Plan’s review procedure.

10.4Reconsideration of Denied Claim. Within 60 days of the receipt by the claimant of the written notice of denial of the claim, or within 60 days after the claim is deemed denied as set forth above, if applicable, the claimant or duly authorized representative may file a written request with the Benefits Committee that it conduct a full and fair review of the denial of the claimant’s claim for benefits. If the claimant or duly authorized representative fails to request such a reconsideration within such 60 day period, it shall be conclusively determined for all purposes of the Plan that the denial of such claim by the Benefits Committee is correct. In connection with the claimant’s appeal of the denial of his or her benefit, the claimant may review pertinent documents and may submit issues and comments in writing.

The Benefits Committee shall render a decision on the claim appeal promptly, but not later than 60 days after receiving the claimant’s request for review, unless, in the discretion of the Benefits Committee, special circumstances require an extension of time for processing, in which case the 60‑day period may be extended to 120 days. The Benefits Committee shall notify the claimant in writing of any such extension. The notice of decision shall be in writing and shall include specific reasons for the decision, written in a manner calculated to be understood by the claimant, as well as specific references to the pertinent Plan provisions on which the decision is based. If the decision on review is not furnished within the time period set forth above, the claim shall be deemed denied on review.

If such determination is favorable to the claimant, it shall be binding and conclusive. If such determination is adverse to such claimant, it shall be binding and conclusive unless the claimant or his duly authorized representative notifies the Benefits Committee within 90 days after the mailing or delivery to the claimant by the Benefits Committee of its determination that claimant intends to institute legal proceedings challenging the determination of the Benefits Committee and actually institutes such legal proceedings within 180 days after such mailing or delivery.

ARTICLE XIPlan Amendment and Termination

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11.1Plan Amendment. The ONC Committee or the Board shall have the authority to amend the Plan. The ONC Committee or the Board shall have the exclusive authority to amend the Plan regarding eligibility for the Plan, the amount or level of benefits awarded under the Plan, and the time and form of payments for benefits from the Plan. In addition, the ONC Committee or the Board shall also have the exclusive authority to make amendments that constitute a material increase in compensation, any change requiring action or consent by a committee of the Board pursuant to the rules of the Securities and Exchange Commission, the New York Stock Exchange or other applicable law, or such other material changes to the Plan such that approval of the Board is required. Unless otherwise determined by the ONC Committee, the Benefits Committee shall have the authority to amend the Plan in all respects that are not exclusively reserved to the ONC Committee or the Board.

The respective committee may at any time amend the Plan by written instrument, notice of which is given to all Participants, and to Beneficiaries receiving installment payments. Notwithstanding the preceding sentence, no amendment shall reduce the amount accrued in any Account prior to the date such notice of the amendment is given.

11.2Plan Termination. The ONC Committee or the Company may terminate the Plan at any time, except that any benefits that are payable due to a Retirement, death, Disability, or other separation from Service occurring prior to the amendment or termination shall not be reduced or discontinued. No amendment or termination of the Plan shall directly or indirectly deprive any current or former Participant (or surviving spouse) of all or any portion of any Supplemental Retirement Benefit, Supplemental Disability Pension, Supplemental Spouse Pension, or Supplemental Retirement Account, the payment of which has commenced prior to the effective date of such amendment or termination, or which would be payable if the Participant experienced a separation from Service for any reason on such effective date.

ARTICLE XIIMiscellaneous

12.1Plan Financing. Except as set forth below in this Section and in Section 7.5, benefits under the Plan shall be paid from the general assets of the Company. To the extent any Participant or surviving spouse or other designated beneficiary acquires a right to receive payments hereunder, such right shall be no greater than the right of any other unsecured creditor of the Company. Notwithstanding the foregoing, the Company has entered into a trust agreement (“Trust Agreement”) whereby the Company agrees to contribute to a trust (“Trust”) for the purpose of accumulating assets to assist the Company in fulfilling its obligations to Participants and surviving spouses or other designated beneficiaries hereunder. Such Trust includes the provision that all assets of the Trust shall be subject to the creditors of the Company in the event of its insolvency.

12.2Non‑Compete and Related Provisions. Benefits under the Plan may be forfeited if:

(a) A Participant, while employed by the Company or within a period of three years after the Participant’s separation from Service for any reason, including Retirement (the “Restrictive Period”), engages in activity or employment that directly or

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indirectly competes with the business of the Company or its Affiliates, including, but not by way of limitation, by directly or indirectly owning, managing, operating, controlling, financing, or by directly or indirectly serving as an employee, officer or director of or consultant to, or by soliciting or inducing, or attempting to solicit or induce, any employee or agent of the Company or its Affiliates to terminate employment with the Company or its Affiliates, and become employed by, any person, firm, partnership, corporation, trust or other entity that provides commodities, products or services to customers of the Company or its Affiliates of the same type as commodities, products or services provided by the Company or its Affiliates (the “Restrictive Covenant”). The foregoing Restrictive Covenant shall not prohibit a Participant from owning directly or indirectly capital stock or similar securities which are listed on a securities exchange or quoted on the National Association of Securities Dealers Automated Quotation System which do not represent more than 1% of the outstanding capital stock of any such entity; or

(b) A Participant performs any action or makes any statement that is detrimental to the Company or its Affiliates, unless such action or statement is retracted to the Company’s satisfaction after the Participant is notified regarding such action or statement.

12.3Nonguarantee of Employment. Participation in the Plan does not limit the right of the Company or an Affiliate to discharge any individual with or without cause.

12.4Nonalienation of Benefits. Neither a Participant nor any other person shall have any right to commute, sell, assign, transfer, pledge, anticipate, mortgage, or otherwise encumber, transfer, hypothecate, or convey in advance of actual receipt the amounts, if any, payable hereunder, or any part thereof or rights to, which are expressly declared to be unassignable and nontransferable. No part of the amounts payable shall, prior to actual payment, be subject to seizure or sequestration for the payment of any debts, judgments, alimony, or separate maintenance owed by a Participant or any other person, nor be transferable by operation of law in the event of a Participant’s or any other person’s bankruptcy or insolvency.

Notwithstanding the preceding paragraph, the benefit of any Participant shall be subject to and payable in the amount determined in accordance with any qualified domestic relations order, as that term is defined in Section 206(d)(3) of ERISA. The Plan Administrator shall provide for payment in a lump sum from a Participant’s benefit to an alternate payee (as defined in Code Section 414(p)(8)) as soon as administratively practicable following receipt of such order. Any federal, state or local income tax associated with such payment shall be the responsibility of the alternate payee. The balance of a benefit that is subject to any qualified domestic relations order shall be reduced by the amount of any payment made pursuant to such order.

12.5Indemnification.

(a) Limitation of Liability. Notwithstanding any other provision of the Plan or the Trust, none of the Company, any member of the Benefits Committee or ONC Committee, nor an individual acting as an employee or agent of any of them, shall be liable to

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any Participant or former Participant, or any surviving spouse or other designated beneficiary of any Participant or former Participant, for any claim, loss, liability or expense incurred in connection with the Plan or the Trust, except when the same shall have been judicially determined to be due to the willful misconduct of such person.

(b) Indemnity. The Company shall indemnify and hold harmless each member of the Benefits Committee and the ONC Committee, or any employee of the Company or any individual acting as an employee or agent of either of them (to the extent not indemnified or saved harmless under any liability insurance or any other indemnification arrangement with respect to the Plan or the Trust) from any and all claims, losses, liabilities, costs and expenses (including attorneys’ fees) arising out of any actual or alleged act or failure to act made in good faith pursuant to the provisions of the Plan, including expenses reasonably incurred in the defense of any claim relating thereto with respect to the administration of the Plan or the Trust, except that no indemnification or defense shall be provided to any person with respect to any conduct that has been judicially determined, or agreed by the parties, to have constituted willful misconduct on the part of such person, or to have resulted in his or her receipt of personal profit or advantage to which he or she is not entitled. In connection with the indemnification provided by the preceding sentence, expenses incurred in defending a civil or criminal action, suit or proceeding, or incurred in connection with a civil or criminal investigation, may be paid by the Company in advance of the final disposition of such action, suit, proceeding, or investigation, as authorized by the Plan Administrator in the specific case, upon receipt of an undertaking by or on behalf of the party to be indemnified to repay such amount unless it shall ultimately be determined that the person is entitled to be indemnified by the Company pursuant to this paragraph.

12.6Severability. Each of the Sections contained in the Plan, and each provision in each Section, shall be enforceable independently of every other Section or provision in the Plan, and the invalidity or unenforceability of any Section or provision shall not invalidate or render unenforceable any other Section or provision contained herein. If any Section or provision in a Section is found invalid or unenforceable, it is the intent of the parties that a court of competent jurisdiction shall reform the Section or provision to produce its nearest enforceable economic equivalent.

12.7Action by Company. Any action required of, or permitted by, the Company under the Plan shall be by resolution of the respective committee identified herein, or by a person or persons authorized by resolution of the such committee.

12.8Protective Provisions. A Participant shall cooperate with the Company by furnishing any and all information requested by the Company and its Affiliates in order to facilitate the payment of benefits hereunder, and by taking such physical examinations as the Company and its Affiliates may deem necessary and taking such other action as may be requested by the Company and its Affiliates.

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12.9Governing Law. The provisions of the Plan shall be construed and interpreted according to the laws of the State of Indiana, except as preempted by federal law.

12.10Notice. Any notice required or permitted under the Plan shall be sufficient if in writing and hand delivered or sent by registered or certified mail. Such notice shall be deemed as given as of the date of delivery or, if delivery is made by mail, as of the date shown on the postmark on the receipt for registration or certification. Mailed notice to the Plan Administrator shall be directed to the Company’s address. Mailed notice to a Participant, a surviving spouse or other designated beneficiary shall be directed to the individual’s last known address in the Company’s records.

12.11Successors. The provisions of the Plan shall bind and inure to the benefit of the Company, its Affiliates and their successors and assigns. The term successors as used herein shall include any corporate or other business entity that shall, whether by merger, consolidation, purchase, or otherwise, acquire all or substantially all of the business and assets of the Company, and successors of any such corporation or other business entity.

12.12Actuarial Assumptions. Unless otherwise provided in the Plan, all actuarial adjustments necessary to determine the amount, form or timing of any distribution shall be based on the same actuarial assumptions used for the pension a Participant is eligible to receive under the NiSource Pension Plan.

12.13Tax Savings.

(a) Notwithstanding anything to the contrary contained in the Plan, (1) in the event that the Internal Revenue Service prevails in its claim that benefits under the Plan constitute taxable income to a Participant, his or her spouse or other designated beneficiary, for any taxable year, prior to the taxable year in which such benefits are distributed to him or her, or (2) in the event that legal counsel satisfactory to the Company and the applicable Participant, his or her spouse or other designated beneficiary, renders an opinion that the Internal Revenue Service would likely prevail in such a claim, the Pre‑2005 Benefit, to the extent constituting taxable income, shall be immediately distributed to the Participant, his or her spouse or other designated beneficiary. For purposes of this Section, the Internal Revenue Service shall be deemed to have prevailed in a claim if such claim is upheld by a court of final jurisdiction, or, if based upon an opinion of legal counsel satisfactory to the Company and the Participant, his or her spouse or other designated beneficiary, the Plan fails to appeal a decision of the Internal Revenue Service, or a court of applicable jurisdiction, with respect to such claim to an appropriate Internal Revenue Service appeals authority or to a court of higher jurisdiction within the appropriate time period.

(b) Notwithstanding anything to the contrary contained in the Plan, (1) in the event that the Internal Revenue Service prevails in its claim that benefits under the Plan constitute taxable income under Code Section 409A, and guidance and regulations thereunder, to a Participant, his or her spouse or other designated beneficiary, for

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any taxable year prior to the taxable year in which such benefits are distributed to him or her, or (2) in the event that legal counsel satisfactory to the Company and the applicable Participant, his or her spouse or other designated beneficiary, renders an opinion that the Internal Revenue Service would likely prevail in such a claim, the Post‑2004 Benefit or Supplemental Spouse Pension, to the extent constituting taxable income, shall be immediately distributed to the Participant, his or her spouse or other designated beneficiary. For purposes of this Section, the Internal Revenue Service shall be deemed to have prevailed in a claim if such claim is upheld by a court of final jurisdiction, or, if based upon an opinion of legal counsel satisfactory to the Company and the Participant, his or her spouse or other designated beneficiary, the Plan fails to appeal a decision of the Internal Revenue Service, or a court of applicable jurisdiction, with respect to such claim to an appropriate Internal Revenue Service appeals authority or to a court of higher jurisdiction within the appropriate time period.

[signature block follows on next page]

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IN WITNESS WHEREOF, the Company has caused this amendment and restatement of the NiSource Inc. Supplemental Executive Retirement Plan to be executed in its name by its duly authorized officer, effective as of August 10, 2017.

NISOURCE INC.

By:

Its:

Date:

COLUMBUS/1401953v.8

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EX-10.2

Exhibit 10.2

PENSION RESTORATION PLAN
FOR NISOURCE INC. AND AFFILIATES

As Amended and Restated Effective August 10, 2017

i

TABLE OF CONTENTS

Page

ARTICLE I Background and Purpose			1
	1.1	Background	1
	1.2	Purpose	1
ARTICLE II Definitions			2
	2.1	AB Account	2
	2.2	AB Benefit	2
	2.3	Affiliate	2
	2.4	Basic Plans	2
	2.5	Beneficiary	2
	2.6	Benefits Committee	2
	2.7	Code	2
	2.8	Company	2
	2.9	DCP	2
	2.10	Disability	2
	2.11	Effective Date	3
	2.12	Employee	3
	2.13	Employer	3
	2.14	ERISA	3
	2.15	Limits	3
	2.16	ONC Committee	3
	2.17	Participant	3
	2.18	Plan	3
	2.19	Plan Administrator	3
ARTICLE III Participation and Benefit Accrual			3
	3.1	Eligibility for Participation and Accrual of Benefit	3
	3.2	Special Provisions for Participants with Basic Plan Benefits Accrued Prior to 2004.	4
	3.3	Service Crediting	4
ARTICLE IV Determination of Benefit Amount			4
	4.1	Amount of Benefit - General Principle	4
	4.2	Amount of Benefit For Participant Who Accrued a Benefit under a Basic Plan Prior to Participating in the Plan on January 1, 2004	5
	4.3	Form of Benefit Accrual.	6
	4.4	Conversion of Benefits.	6
	4.5	Opening Balance.	6
	4.6	Pay-Based Credits and Interest Credits	7
	4.7	Protected Benefit	7
ARTICLE V Time and Method of Payment of Benefit			8
	5.1	Method of Payment.	8

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TABLE OF CONTENTS

Page

	5.2	Timing of Payment	9
	5.3	Changes to the Form of Payment	9
	5.4	Specified Employees	9
	5.5	Interest and Mortality Assumptions	10
ARTICLE VI Administration of Plan			10
	6.1	Allocation of Duties to Committees	10
	6.2	Agents	10
	6.3	Information Required by Plan Administrator	10
	6.4	Binding Effect of Decisions	11
ARTICLE VII CLAIMS PROCEDURE			11
	7.1	Claims Procedure	11
	7.2	Review of Claim	11
	7.3	Notice of Denial of Claim	11
	7.4	Reconsideration of Denied Claim	11
ARTICLE VIII PLAN AmendMENT or Termination			12
	8.1	Plan Amendment	12
	8.2	Plan Termination	13
ARTICLE IX Miscellaneous Provisions			13
	9.1	Unsecured General Creditor	13
	9.2	Income Tax Payout	13
	9.3	General Conditions	13
	9.4	No Guaranty of Benefits	14
	9.5	No Enlargement of Employee Rights	14
	9.6	Nonalienation of Benefits	14
	9.7	Applicable Law	14
	9.8	Incapacity of Recipient	14
	9.9	Unclaimed Benefit	14
	9.1	Limitations on Liability	15
SCHEDULE A			17

ii

PENSION RESTORATION PLAN
FOR NISOURCE INC. AND AFFILIATES

As Amended and Restated Effective August 10, 2017

ARTICLE I.BACKGROUND AND PURPOSE

1.1Background. The Columbia Gas System, Inc. adopted The Pension Restoration Plan for The Columbia Gas System, Inc., as amended and restated effective March 1, 1997. The Plan was amended and restated, effective January 1, 2002, by Columbia Energy Group, successor to Columbia Gas System, Inc., and renamed the Pension Restoration Plan for the Columbia Energy Group. Effective January 1, 2004, NiSource Inc., the parent company of Columbia Energy Group, assumed sponsorship of the Pension Restoration Plan for Columbia Energy Group, renamed the Plan the Pension Restoration Plan for NiSource Inc. and Affiliates, and broadened the Plan to allow participation by employees of NiSource Inc. and Affiliated Companies from and after January 1, 2004. The Plan was further amended and restated, effective January 1, 2005, to comply with Internal Revenue Code Section 409A with respect to benefits earned under the Plan. The Plan was amended and restated again, effective January 1, 2008, to revise certain election procedures. The Plan was further amended and restated, effective January 1, 2010, to clarify the calculation of benefits under the Plan and to reflect Plan benefits parallel to the benefit structures under applicable Basic Plans, including the AB Benefit. The Plan was amended and restated again, effective May 13, 2011 to transfer all administrative authority with respect to the Plan (including the authority to render decisions on claims and appeals and make administrative or ministerial amendments) from the ONC Committee to the Benefits Committee. The Plan is hereby amended and restated again, effective August 10, 2017, to revise the procedures for determining Disability under the Plan.

1.2Purpose. The purpose of the Plan is to provide for the payment of pension restoration benefits to employees of the Employer, whose benefits under the Basic Plans are subject to the Limits, or affected by deferrals into the DCP, so that the total pension benefits of such employees will be determined on the same basis as is applicable to all other employees of the Employer. The Plan is adopted solely (1) for the purpose of providing benefits to Participants in the Plan and their Beneficiaries in excess of the Limits imposed on qualified plans by Code Sections 415 and 401(a)(17), and any other Code Sections, by restoring benefits to such Plan Participants and Beneficiaries that are not available under the Basic Plans as a result of the Limits, and (2) for the purpose of restoring benefits to Plan Participants and Beneficiaries that are no longer available under the Basic Plans as a result of the Participant’s deferrals into the DCP. The provisions of the Plan as stated herein apply only to Participants who actively participate in the Plan on or after the Effective Date. Any Participant who retired or otherwise terminated employment with the Company and Affiliates prior to the Effective Date shall have his or her rights determined under the provision of the Plan, as it existed when his or her employment relationship terminated.

ARTICLE II.DEFINITIONS

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For the purposes of the Plan, the following terms shall have the meanings indicated, unless the context clearly indicates otherwise. Except when otherwise required by the context, any masculine terminology in this document shall include the feminine, and any singular terminology shall include the plural. The headings of Articles and Sections are included solely for convenience, and if there is any conflict between such headings and the text of the Plan, the text shall control.

2.1AB Account. The hypothetical account created for a Participant under the Plan who has an AB Benefit under a Basic Plan.

2.2AB Benefit. A Participant's AB I Benefit or AB II Benefit that is accrued for the benefit of the Participant under a Basic Plan.

2.3Affiliate. Any corporation that is a member of a controlled group of corporations (as defined in Code Section 414(b)) that includes the Company; any trade or business (whether or not incorporated) that is under common control (as defined in Code Section 414(c)) with the Company; any organization (whether or not incorporated) that is a member of an affiliated service group (as defined in Code Section 414(m)) that includes the Company; any leasing organization, to the extent that its employees are required to be treated as if they were employed by the Company pursuant to Code Section 414(n) and the regulations thereunder; and any other entity required to be aggregated with the Company pursuant to regulations under Code Section 414(o). An entity shall be an Affiliate only with respect to the existing period as described in the preceding sentence.

2.4Basic Plans. The tax-qualified defined benefit retirement plan(s) maintained by the Company and Affiliates listed on Schedule A, attached hereto.

2.5Beneficiary. The person, persons or entity entitled to receive any plan benefits payable after a Participant's death.

2.6Benefits Committee. The NiSource Benefits Committee.

2.7Code. The Internal Revenue Code of 1986, as amended.

2.8Company. NiSource Inc., a Delaware corporation.

2.9DCP. The Columbia Energy Group Deferred Compensation Plan, on or prior to December 31, 2003, and, thereafter, the NiSource Inc. Executive Deferred Compensation Plan.

2.10Disability. A condition that (a) causes a Participant, by reason of any medically determinable physical or mental impairment that can be expected to result in death or can be expected to last for a continuous period of not less than 12 months, to receive income replacement benefits for a period of not less than three months under an accident and health plan covering Employees of the Company or an Affiliate or (b) causes a Participant to be eligible to receive Social Security disability payments.

2.11Effective Date. August 10, 2017, the date on which this amendment and restatement of the Plan is effective.

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2.12Employee. Any individual who is employed by an Employer on a basis that involves payment of salary, wages or commissions.

2.13Employer. The Company or any Affiliate who maintains or adopts for its Eligible Employees a Basic Plan.

2.14ERISA. The Employee Retirement Income Security Act of 1974, as amended.

2.15Limits. The limits imposed on the payment, accrual or calculation of tax-qualified retirement plans by Code Sections 415 and 401(a)(17) and any other Code Sections.

2.16ONC Committee. The Officer Nomination and Compensation Committee of the Board of Directors of the Company.

2.17Participant. Any Employee who is participating in the Plan in accordance with its provisions.

2.18Plan. The Pension Restoration Plan for NiSource Inc. and Affiliates (formerly known as the Pension Restoration Plan for the Columbia Energy Group, formerly known as the Pension Restoration Plan for The Columbia Gas System, Inc.), as set forth herein.

2.19Plan Administrator. The Benefits Committee or such delegate of the Benefits Committee delegated to carry out the administrative functions of the Plan.

ARTICLE III.PARTICIPATION AND BENEFIT ACCRUAL

3.1Eligibility for Participation and Accrual of Benefit. Except as provided in Section 3.2 below, each Employee of an Employer shall be eligible to participate in the Plan as of the date he or she is eligible to participate in a Basic Plan. For purposes of accruing a benefit under the Plan, each employee shall be eligible to accrue a benefit under the Plan for any plan year in which his or her benefits under a Basic Plan are affected by the Limits or by his or her deferrals under the DCP.

The ONC Committee (or its delegate) shall determine the eligibility of each Employee to participate in the Plan based on information furnished by the Employer. Such determination shall be within the discretion of the Plan Administrator (or its delegate) and shall be conclusive and binding upon all persons as long as such determination is made pursuant to the Plan and applicable law.

3.2Special Provisions for Participants with Basic Plan Benefits Accrued Prior to 2004.

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(a) Eligibility. As set forth in Article I, prior to January 1, 2004, only Employees of Columbia Energy Group (or its predecessor) who had benefits under a Basic Plan affected by the Limits, or by his or her deferrals under the DCP, participated in the Plan. Pursuant to the extension of participation in the Plan as explained in Article I, on or after January 1, 2004, each Employee meeting the participation requirements set forth in Section 3.1 shall participate in the Plan as of January 1, 2004, and shall be eligible to accrue a benefit under the Plan as of such date or, if later, as of the date that an Employee’s benefits under a Basic Plan are affected by the Limits or by his or her deferrals under the DCP.

(b) Benefit Accrual. With respect to any Participant who was first eligible to participate in the Plan on January 1, 2004 in accordance with this Section, but who had accrued benefits under a Basic Plan prior to such date, such Participant shall have benefits under the Plan calculated in accordance with the Plan’s general provisions, except that the Plan shall only consider the Participant’s Credited Service, Point Service, Compensation or Accrued Benefit under the Basic Plan earned on or after the date participation in the Plan begins (i.e., January 1, 2004), as further described in Section 4.2, Section 4.4(b), Section 4.5(b) Section 4.6(b) and Section 4.7(b).

3.3Service Crediting. A Participant’s service used under the Basic Plan for purposes of determining eligibility for any retirement benefit shall also be used for similar purposes under the Plan. For any Participant described in Section 3.2, the Plan shall only consider such Participant’s Credited Service (or, if applicable, Point Service) as of the date of participation in the Plan for purposes of calculating the benefit under the Plan; however, the Plan shall continue to consider such Participant’s Credited Service (or, if applicable, Point Service) under the Basic Plan for purposes of determining early retirement eligibility or the application of the Pay-Based Credit scale for the Participant as described in Section 4.6.

ARTICLE IV.DETERMINATION OF BENEFIT AMOUNT

4.1Amount of Benefit - General Principle. The benefit payable under the Plan to a Participant (or to his or her Beneficiary under a Basic Plan) shall be equal to the excess (if any) of the benefit determined under subsection (a) below over the benefit determined under subsection (b) below:

(a) The benefit that would have been payable under a Basic Plan to a Participant, or to his or her Beneficiary, determined under a Basic Plan without regard to (i) the Limits or (ii) the Participant’s deferrals into the DCP, if any.

(b) The benefit actually payable to the Participant, or to his or her Beneficiary, determined under a Basic Plan after applying the Limits and considering deferrals into the DCP, if any.

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To the extent that the AB Benefit provisions of the Basic Plan apply to a Participant, such Participant shall have an AB Account created and shall have his or her benefit under the Plan calculated in accordance with the provisions of this Article IV. Specifically, such Participant shall be subject to the conversion, Opening Balance, Pay-Based and Interest Credits and Protected Benefit provisions provided under this Article.

4.2Amount of Benefit For Participant Who Accrued a Benefit under a Basic Plan Prior to Participating in the Plan on January 1, 2004. Notwithstanding the foregoing, the calculation of the benefit payable under Section 4.1 above shall be limited for any Participant described in Section 3.2. For such Participants, the benefit payable under the Plan shall be determined as follows:

(a) FAP Participant. For a Participant whose Accrued Benefit under a Basic Plan is a FAP Benefit, the benefit payable under the Plan to the Participant, or to his or her Beneficiary under the Basic Plan, shall be equal to the excess (if any) of the benefit determined under paragraph (1) below over the benefit determined under paragraph (2) below:

(1) The benefit that would have been payable under a Basic Plan to a Participant, or to his or her Beneficiary determined under a Basic Plan, considering only the Participant’s Credited Service and Compensation from and after the date the Participant first becomes eligible to participate in the Plan, determined without regard to (i) the Limits or (ii) the Participant’s deferrals into the DCP, if any.

(2) The benefit actually payable to the Participant, or to his or her Beneficiary determined under a Basic Plan, calculated based upon the Participant’s Credited Service and Compensation from and after the date the Participant first becomes eligible to participate in the Plan, determined after applying the Limits and considering deferrals into the DCP, if any.

(b) AB Participant. For a Participant whose Accrued Benefit under a Basic Plan is an AB Benefit, the benefit payable under the Plan to the Participant, or to his or her Beneficiary under a Basic Plan, shall be equal to the excess (if any) of the benefit determined under paragraph (1) below over the benefit determined under paragraph (2) below:

(1) The benefit that would have been payable under a Basic Plan to a Participant or his or her Beneficiary, determined as if the Participant’s Opening Balance under the Basic Plan was $0 as of the date the Participant first becomes eligible to participate in the Plan, and considering only the Participant’s Pay-Based Credits, Interest Credits and Compensation from and after such date, and determined without regard to (i) the Limits or (ii) the Participant’s deferrals into the DCP, if any.

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(2) The benefit actually payable under a Basic Plan to the Participant, or to his or her Beneficiary, determined as if the Participant’s Opening Balance under the Basic Plan was $0 as of the date the Participant first becomes eligible to participate in the Plan, and considering only the Participant’s Pay-Based Credits, Interest Credits and Compensation from and after such date, and determined after applying the Limits and considering deferrals into the DCP, if any.

4.3Form of Benefit Accrual. The form of benefit accrual for a Participant in the Plan shall be the form of benefit accrual applicable for such Participant under the relevant Basic Plan.

4.4Conversion of Benefits.

(a) In General. Upon the conversion of any Participant's Accrued Benefit in a Basic Plan from a FAP Benefit to an AB II Benefit or from an AB I Benefit to an AB II Benefit, any benefit under the Plan shall, except as provided below, also be converted upon such date according to the conversion procedures set forth in the relevant Basic Plan, including determination of an Opening Balance.

(b) Exception to the General Provision. Notwithstanding the foregoing, with respect to any Participant in the Plan who is described in Section 3.2, such Participant's benefit under the Plan shall be converted according to the conversion procedures in the relevant Basic Plan, provided that any consideration of Credited Service and Compensation in the calculation of the Participant's Opening Balance shall be limited to Credited Service and Compensation earned from and after the date the Participant first becomes eligible to participate in the Plan.

4.5Opening Balance. For purposes of determining the Opening Balance for Participants in the Plan, the following provisions shall apply:

(a) In General. The Opening Balance shall be calculated using the same methodology and factors as provided in the relevant Basic Plan. The Opening Balance under the Plan shall be determined as the excess of the Opening Balance determined in (1) below over the Opening Balance determined in (2) below:

(1) The Participant's Opening Balance under the Basic Plan determined without regard to (i) the Limits or (ii) the Participant’s deferrals into the DCP, if any.

(2) The Participant’s Opening Balance under the Basic Plan determined after applying the Limits and considering deferrals into the DCP, if any.

(b) Exception to the General Provision. For the purpose of determining the Opening Balance for any Participant in the Plan who is described in Section 3.2, the Opening Balance under the Plan shall be determined in accordance with Section 4.5(a) above, but considering a calculation of the Opening Balance under the Basic Plan using only the Participant’s Credited Service (or, if applicable, Point Service) and

6

Compensation from and after the date the Participant first becomes eligible to participate in the Plan.

4.6Pay-Based Credits and Interest Credits. For purposes of determining Pay-Based Credits and Interest Credits under the Plan, the following provisions shall apply:

(a) Pay-Based Credits Generally. Pay-Based Credits under the Plan shall be calculated using the same methodology and factors as provided in the relevant Basic Plan. Pay-Based Credits under the Plan shall be determined as the excess of the Pay-Based Credits determined in (1) below over the Pay-Based Credits determined in (2) below:

(1) The Participant's Pay-Based Credits under the Basic Plan determined without regard to (i) the Limits or (ii) the Participant’s deferrals into the DCP, if any.

(2) The Participant’s Pay-Based Credits under the Basic Plan determined after applying the Limits and considering deferrals into the DCP, if any.

(b) Exception to the General Pay-Based Credits Provision. For the purpose of determining the Pay-Based Credits for any Participant in the Plan who is described in Section 3.2, the Pay-Based Credits under the Plan shall be determined in accordance with Section 4.6(a) above, but considering a calculation of Pay-Based Credits under the Basic Plan using only Compensation from and after the date the Participant first becomes eligible to participate in the Plan.

(c) Interest Credits. Interest Credits under the Plan shall be calculated using the same methodology and factors as provided in the relevant Basic Plan.

4.7Protected Benefit. Effective for any Participant terminating employment with the Employer on or after January 1, 2011, the benefit payable under the Plan may never be less than the benefit set forth in this section. For purposes of determining the Protected Benefit under the Plan, the following provisions shall apply:

(a) Protected Benefit Generally. The Protected Benefit under the Plan shall be calculated using the same methodology and factors as provided in the relevant Basic Plan. The Protected Benefit under the Plan shall be determined as the excess of the benefit determined in (1) below over the benefit determined in (2) below:

(1) The Protected Benefit under the Basic Plan for the Participant, or for his or her Beneficiary, determined without regard to (i) the Limits or (ii) the Participant’s deferrals into the DCP, if any.

(2) The Protected Benefit under the Basic Plan for the Participant, or for his or her Beneficiary, determined after applying the Limits and considering deferrals into the DCP, if any.

In accordance with the methodology provided in the applicable Basic Plan, a Participant with an AB Benefit shall be entitled to benefit under the Plan equal to

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the greater of (1) the AB Account under the Plan or (2) the sum of the AB Account under the Plan (determined without regard to the Opening Balance calculation) plus the portion of the FAP Benefit that is calculated in accordance with the Plan as of the date of conversion to the AB Benefit as set forth in Section 4.4.

(b) Exception to the General Protected Benefit Provision. For the purpose of determining the Protected Benefit for any Participant in the Plan who is described in Section 3.2, the Protected Benefit under the Plan shall be determined in accordance with Section 4.7(a) above, but considering calculation of the Protected Benefit under the Basic Plan using only Credited Service and Compensation from and after the date the Participant first becomes eligible to participate in the Plan.

ARTICLE V.TIME AND METHOD OF PAYMENT OF BENEFIT

5.1Method of Payment.

(a) The benefit earned under the Plan shall be payable to a Participant in a form available under the Basic Plan, as elected by the Participant by notice delivered to the Plan Administrator on or before December 31, 2005. Notwithstanding the preceding sentence, in the case of an Employee who becomes a Participant on or after January 1, 2005, the aforementioned election with respect to a benefit shall be made no later than January 31 of the calendar year after the calendar year in which the Participant first becomes eligible to participate in the Plan, and such election shall be effective with respect to Compensation related to services to be performed subsequent to the election; provided, however, that a Participant shall not be considered first eligible if, on the date he or she becomes a Participant, he or she participates in any other nonqualified plan of the same category that is subject to Code Section 409A, maintained by the Company or an Affiliate.

(b) If payment in the form of an annuity is elected, the annuity type shall be elected by the Participant at the time he or she makes the election described in the first or second sentence of subsection (a) above from among those annuities available at that time under the Basic Plan. If a benefit hereunder is paid in an annuity form other than a straight life annuity, the amount of the benefit under the Plan shall be reduced by the Basic Plan’s factors in effect at the time of such election for payment in a form other than a straight life annuity. If payment in the form of a lump sum is elected, the lump sum amount payable will be calculated in the same manner and according to the same interest rates and mortality tables as under the Basic Plan at the time of such election.

(c) If the Participant fails to elect a form of payment as required under subsections (a) and (b) above, the Participant’s benefit shall be payable in a lump sum.

8

5.2Timing of Payment. A benefit payable in accordance with Section 5.1 will commence within 45 days after: (i) if the Participant qualifies for Early Retirement under a Basic Plan, when the Participant separates from service, or (ii) if the Participant does not qualify for Early Retirement under a Basic Plan, the later of when the Participant separates from service or attains (or would have attained) age 65, or, if later, within such timeframe permitted under Code Section 409A, and guidance and regulations thereunder.

5.3Changes to the Form of Payment. A Participant cannot change the form of payment of a benefit elected under Section 5.1 or this Section 5.3 unless (i) such election does not take effect until at least 12 months after the date on which the election is made, (ii) in the case of an election related to a payment not due to the Participant’s Disability or death, the first payment with respect to which such new election is effective is deferred for a period of not less than five years from the date such payment would otherwise have been made, and (iii) any election related to a payment based upon a specific time or pursuant to a fixed schedule may not be made less than 12 months prior to the date of the first scheduled payment; provided, however, that an election to change from one type of annuity payment to a different, actuarially equivalent, type of annuity payment shall not be considered a change to the form of payment for purposes of applying the restrictions in clauses (i), (ii) and (iii).

Notwithstanding the preceding paragraphs of this Section 5.3, a Participant may change an election with respect to the form of payment of a benefit, without regard to the restrictions imposed under the preceding paragraph, on or before December 31, 2006; provided that such election (i) applies only to amounts that would not otherwise be payable in calendar year 2006, and (ii) shall not cause an amount to be paid in calendar year 2006 that would not otherwise be payable in such year.

5.4Specified Employees. Notwithstanding any other provision of the Plan, in no event can a payment of a benefit to a Participant who is a Specified Employee of the Company or an Affiliate, at a time during which the Company’s capital stock or capital stock of an Affiliate is publicly traded on an established securities market, in the calendar year of his or her separation from service, be made before the date that is six months after the date of the Participant’s separation from service with the Company and all Affiliates, unless such separation is due to his or her death or Disability.

A Participant shall be deemed to be a Specified Employee for purposes of this Section 5.4 if he or she is in a job category C2 or above with respect to the Company or Affiliate that employs him or her; provided if at any time the total number of Employees in job category C2 and above is less than 50, a Specified Employee shall include any person who meets the definition of Key Employee set forth in Code Section 416(i) without reference to paragraph (5). A Participant shall be deemed to be a Specified Employee with respect to a calendar year if he or she is a Specified Employee on September 30th of the preceding calendar year. If a Specified Employee will receive payments hereunder in the form of installments or an annuity, the first payment made as of the date six months after the date of the Participant’s separation from service with the Company and all Affiliates shall be a lump sum, paid as soon as practicable after the end of such six‑month period, that includes all payments that would otherwise have been made during such six‑month period.

9

From and after the end of such six month period, any such installment or annuity payments shall be made pursuant to the terms of the applicable installment or annuity form of payment.

5.5Interest and Mortality Assumptions. Determinations under the Plan shall be based on the interest and mortality assumptions used in the applicable Basic Plan on the date of such determination.

ARTICLE VI.ADMINISTRATION OF PLAN

6.1Allocation of Duties to Committees. The Plan shall be administered by the Benefits Committee, as delegated by the ONC Committee. The Benefits Committee shall have the authority to make, amend, interpret, and enforce all appropriate rules and regulations for the administration of the Plan and decide or resolve any and all questions, including interpretations of the Plan, as may arise in such administration, except as otherwise reserved to the ONC Committee herein, or by resolution or charter of the respective committees.

In its discretion, the Plan Administrator may delegate to any division or department of the Company the discretionary authority to make decisions regarding Plan administration, within limits and guidelines from time to time established by the Plan Administrator. The delegated discretionary authority shall be exercised by such division or department’s senior officer, or his/her delegate. Within the scope of the delegated discretionary authority, such officer or person shall act in the place of the Plan Administrator and his/her decisions shall be treated as decisions of the Plan Administrator.

6.2Agents. The Plan Administrator may, from time to time, employ agents and delegate to them such administrative duties as it sees fit, and may from time to time consult with counsel who may be counsel to the Company.

6.3Information Required by Plan Administrator. The Company shall furnish the Plan Administrator with such data and information as the Plan Administrator may deem necessary or desirable in order to administer the Plan. The records of the Company as to an employee’s or Participant’s period or periods of employment, separation from Service and the reason therefore, reemployment and Compensation will be conclusive on all persons unless determined to the Plan Administrator’s satisfaction to be incorrect. Participants and other persons entitled to benefits under the Plan also shall furnish the Plan Administrator with such evidence, data or information as the Plan Administrator considers necessary or desirable to administer the Plan.

6.4Binding Effect of Decisions. Subject to applicable law, and the provisions of Article VIII, any interpretation of the provisions of the Plan and any decision on any matter within the discretion of the Benefits Committee and/or the ONC Committee (or any duly authorized delegate of either such committee) and made in good faith shall be binding on all persons.

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ARTICLE VII.CLAIMS PROCEDURE

7.1Claims Procedure. Claims for benefits under the Plan shall be made in writing to the Plan Administrator. The Plan Administrator shall establish rules and procedures to be followed by Participants and Beneficiaries in filing claims for benefits, and for furnishing and verifying proof necessary to establish the right to benefits in accordance with the Plan, consistent with the remainder of this Article.

7.2Review of Claim. The Plan Administrator shall review all claims for benefits. Upon receipt by the Plan Administrator of such a claim, it shall determine all facts that are necessary to establish the right of the claimant to benefits under the provisions of the Plan and the amount thereof as herein provided within 90 days of receipt of such claim. If prior to the expiration of the initial 90 day period, the Plan Administrator determines additional time is needed to come to a determination on the claim, the Plan Administrator shall provide written notice to the Participant, Beneficiary or other claimant of the need for the extension, not to exceed a total of 180 days from the date the application was received. If the Plan Administrator fails to notify the claimant in writing of the denial of the claim within 90 days after the Plan Administrator receives it, the claim shall be deemed denied.

7.3Notice of Denial of Claim. If the Plan Administrator wholly or partially denies a claim for benefits, the Plan Administrator shall, within a reasonable period of time, but no later than 90 days after receiving the claim (unless extended as noted above), notify the claimant in writing of the denial of the claim. Such notification shall be written in a manner reasonably expected to be understood by such claimant and shall in all respects comply with the requirements of ERISA, including but not limited to inclusion of the following:

(a) the specific reason or reasons for denial of the claim;

(b) a specific reference to the pertinent Plan provisions upon which the denial is based;

(c) a description of any additional material or information necessary for the claimant to perfect the claim, together with an explanation of why such material or information is necessary; and

(d) an explanation of the Plan’s review procedure.

7.4Reconsideration of Denied Claim. Within 60 days of the receipt by the claimant of the written notice of denial of the claim, or within 60 days after the claim is deemed denied as set forth above, if applicable, the claimant or duly authorized representative may file a written request with the Benefits Committee that it conduct a full and fair review of the denial of the claimant’s claim for benefits. If the claimant or duly authorized representative fails to request such a reconsideration within such 60 day period, it shall be conclusively determined for all purposes of the Plan that the denial of such claim by the Benefits Committee is correct. In connection with the

11

claimant’s appeal of the denial of his or her benefit, the claimant may review pertinent documents and may submit issues and comments in writing.

The Benefits Committee shall render a decision on the claim appeal promptly, but not later than 60 days after receiving the claimant’s request for review, unless, in the discretion of the Benefits Committee, special circumstances require an extension of time for processing, in which case the 60-day period may be extended to 120 days. The Benefits Committee shall notify the claimant in writing of any such extension. The notice of decision upon review shall be in writing and shall include specific reasons for the decision, written in a manner calculated to be understood by the claimant, as well as specific references to the pertinent Plan provisions upon which the decision is based. If the decision on review is not furnished within the time period set forth above, the claim shall be deemed denied on review.

If such determination is favorable to the claimant, it shall be binding and conclusive. If such determination is adverse to such claimant, it shall be binding and conclusive unless the claimant or his duly authorized representative notifies the Benefits Committee within 90 days after the mailing or delivery to the claimant by the Benefits Committee of its determination that claimant intends to institute legal proceedings challenging the determination of the Benefits Committee and actually institutes such legal proceedings within 180 days after such mailing or delivery.

ARTICLE VIII.PLAN AMENDMENT OR TERMINATION

8.1Plan Amendment. While the Company intends to maintain the Plan in conjunction with the Basic Plans, the Company or the ONC Committee reserves the right to amend the Plan at any time and from time to time with respect to eligibility for the Plan, the level of benefits awarded under the Plan and the time and form of payment for benefits from the Plan. The ONC Committee or the Board shall have the authority to amend the Plan. The ONC Committee or the Board shall have the exclusive authority to amend the Plan regarding eligibility for the Plan, the amount or level of benefits awarded under the Plan, and the time and form of payments for benefits from the Plan. In addition, the ONC Committee or the Board shall also have the exclusive authority to make amendments that constitute a material increase in compensation, any change requiring action or consent by a committee of the Board pursuant to the rules of the Securities and Exchange Commission, the New York Stock Exchange or other applicable law, or such other material changes to the Plan such that approval of the Board is required. Unless otherwise determined by the ONC Committee, the Benefits Committee shall have the authority to amend the Plan in all respects that are not exclusively reserved to the ONC Committee or the Board.

All amendments to the Plan must be made by written instrument, notice of which is given to all Participants and to Beneficiaries. Notwithstanding the preceding sentence, no amendment shall impair or alter such right to a benefit accrued under the Plan as of the effective date of such amendment to or with respect to any Employee who has become a Participant in the Plan before the effective date of such amendment or with respect to his or her Beneficiary.

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8.2Plan Termination. The ONC Committee or the Company may terminate the Plan at any time provided that termination of the Plan shall not impair or alter such right to a benefit accrued under the Plan as of the effective date of such termination to or with respect to any Employee who has become a Participant in the Plan before the effective date of such termination or with respect to his or her Beneficiary

Upon termination of the Plan, distribution of Plan benefits shall be made to Participants, surviving spouses and beneficiaries in the manner and at the time described in Article VI of the Plan. No additional benefits shall be earned after termination of the Plan other than the crediting of Interest until the date of distribution of a Participant’s Supplemental Savings Account.

ARTICLE IX.MISCELLANEOUS PROVISIONS

9.1Unsecured General Creditor. Participants and Beneficiaries shall be unsecured general creditors, with no secured or preferential right to any assets of the Company, any other Employer, or any other party for payment of benefits under the Plan. Obligations of the Company and each other Employer under the Plan shall be an unfunded and unsecured promise to pay money in the future.

9.2Income Tax Payout. In the event that the Internal Revenue Service prevails in its claim that that any amount of a Participant’s benefit payable pursuant to the Plan and held in the general assets of the Company or any other Employer constitutes taxable income under Code Section 409A, and guidance and regulations thereunder, to a Participant or his or her Beneficiary for any taxable year prior to the taxable year in which such amount is distributed to him or her, or in the event that legal counsel satisfactory to the Company and the applicable Participant or his or her Beneficiary renders an opinion that the Internal Revenue Service would likely prevail in such a claim, the amount of such benefit held in the general assets of the Company or any other Employer, to the extent constituting such taxable income, shall be immediately distributed to the Participant or his or her Beneficiary. For purposes of this Section, the Internal Revenue Service shall be deemed to have prevailed in a claim if such claim is upheld by a court of final jurisdiction, or if the Participant or Beneficiary, based upon an opinion of legal counsel satisfactory to the Company and the Participant or his or her Beneficiary, fails to appeal a decision of the Internal Revenue Service, or a court of applicable jurisdiction, with respect to such claim, to an appropriate Internal Revenue Service appeals authority or to a court of higher jurisdiction within the appropriate time period.

9.3General Conditions. Except as otherwise expressly provided herein, all terms and conditions of a Basic Plan applicable to a Basic Plan benefit shall also be applicable to a benefit payable hereunder. Any Basic Plan benefit shall be paid solely in accordance with the terms and conditions of the applicable Basic Plan and nothing in the Plan shall operate or be construed in any way to modify, amend or affect the terms and provisions of the Basic Plan. Defined terms used in the Plan that are not defined in this Plan but are defined in the Basic Plans shall have the meanings assigned to them in the Basic Plans.

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9.4No Guaranty of Benefits. Nothing contained in the Plan shall constitute a guaranty by the Company or any other Employer or any other entity or person that the assets of the Company or any other Employer will be sufficient to pay any benefit hereunder.

9.5No Enlargement of Employee Rights. No Participant or Beneficiary shall have any right to a benefit under the Plan except in accordance with the terms of the Plan. Establishment of the Plan shall not be construed to give any Participant or Beneficiary the right to be retained in the service of the Company or any Affiliate.

9.6Nonalienation of Benefits. No interest of any person or entity in, or right to receive a benefit under, the Plan shall be subject in any manner to sale, transfer, assignment, pledge, attachment, garnishment, or other alienation or encumbrance of any kind; nor may such interest or right to receive a benefit be taken, either voluntarily or involuntarily, for the satisfaction of the debts of, or other obligations or claims against, such person or entity, including claims for alimony, support, separate maintenance, and claims in bankruptcy proceedings.

Notwithstanding the preceding paragraph, the benefit of any Participant shall be subject to and payable in the amount determined in accordance with any qualified domestic relations order, as that term is defined in ERISA Section 206(d)(3). The Plan Administrator shall provide for payment of such benefit to an alternate payee (as defined in ERISA Section 206(d)(3)) as soon as administratively possible following receipt of such order. Any federal, state or local income tax associated with such payment shall be the responsibility of the alternate payee. The benefit that is subject to any qualified domestic relations order shall be reduced by the amount of any payment made pursuant to such order.

9.7Applicable Law. The Plan shall be construed and administered under the laws of the State of Indiana, except to the extent preempted by applicable federal law.

9.8Incapacity of Recipient. If any person entitled to a benefit payment under the Plan is deemed by the Plan Administrator to be incapable of personally receiving and giving a valid receipt for such payment, then, unless and until claim therefore shall have been made by a duly appointed guardian or other legal representative of such person, the Plan Administrator may provide for such payment or any part thereof to be made to any other person or institution then contributing toward or providing for the care and maintenance of such person. Any such payment shall be a payment for the account of such person and a complete discharge of any liability of the Company, any other Employer, the Plan Administrator and the Plan therefore.

9.9Unclaimed Benefit. Each Participant shall keep the Plan Administrator informed of his or her current address and the current address of his or her Beneficiaries. The Plan Administrator shall not be obligated to search for the whereabouts of any person. If the location of a Participant is not made known to the Plan Administrator within three years after the date on which payment of the Participant's benefit may first be made, payment may be made as though the Participant had died at the end of the three‑year period. If, within one additional year after such three‑year period has elapsed, or, within three years after the actual death of a Participant, the Plan Administrator is unable to locate any Beneficiary of the Participant, then the Plan Administrator

14

shall have no further obligation to pay any benefit hereunder to such Participant, Beneficiary, or any other person and such benefit shall be irrevocably forfeited.

9.10Limitations on Liability. Notwithstanding any of the preceding provisions of the Plan, none of the Company, any other Employer, any member of the Benefits Committee or the ONC Committee or any delegate of such committees, or any individual acting as an employee, or agent at the direction of the Company or any other Employer, or any member of the Benefits Committee or the ONC Committee or any delegate of such committees, shall be liable to any Participant, former Participant, Beneficiary, or any other person for any claim, loss, liability or expense incurred in connection with the Plan.

[Signature block follows on next page]

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IN WITNESS WHEREOF, NiSource Inc. has caused this amended and restated Pension Restoration Plan for NiSource Inc. and Affiliates to be executed in its name, by its duly authorized officer, effective as of August 10, 2017.

NISOURCE INC.

By:

Its:

Date:

16

SCHEDULE A

NiSource Salaried Pension Plan

NiSource Subsidiary Pension Plan

Columbia Energy Group Pension Plan

Bay State Gas Company Pension Plan

COLUMBUS/1401979v.13

17

EX-10.3

Exhibit 10.3

SAVINGS RESTORATION PLANFOR NISOURCE INC. AND AFFILIATES

As Amended and Restated Effective August 10, 2017

TABLE OF CONTENTS

Page

ARTICLE I BACKGROUND AND PURPOSE			1
	1.1.	Background	1
	1.2.	Purpose	2
ARTICLE II DEFINITIONS			2
	2.1.	Account	2
	2.2.	Affiliate	2
	2.3.	Basic Plan	3
	2.4.	Beneficiary	3
	2.5.	Benefits Committee	3
	2.6.	Board	3
	2.7.	Code	3
	2.8.	Company	3
	2.9.	Compensation	3
	2.10.	DCP	3
	2.11.	Disability	3
	2.12.	Effective Date.	3
	2.13.	Eligible Employee	3
	2.14.	Employer	4
	2.15.	ERISA	4
	2.16.	In-Service Withdrawal	4
	2.17.	Limits	4
	2.18.	ONC Committee	4
	2.19.	Participant	4
	2.20.	Plan	4
	2.21.	Plan Administrator	4
	2.22.	Plan Year	4
	2.23.	Post-2004 Account	4
	2.24.	Pre-2005 Account	4
	2.25.	Separation from Service	4
	2.26.	Specified Employee	4
	2.27.	Unforeseeable Emergency	5
	2.28.	Valuation Date	5
ARTICLE III ELIGIBILITY AND PARTICIPATION			5
	3.1.	Eligibility	5
	3.2.	Participation	5
	3.3.	Continuation of Participation	5
	3.4.	Amendment of Eligibility Criteria	5
ARTICLE IV ACCOUNTS			6

i

TABLE OF CONTENTS

Page

	4.1.	Account	6
	4.2.	Employer Credits	6
	4.3.	Timing of Credits; Withholding	8
	4.4.	Determination of Account	8
	4.5.	Statement of Account	9
ARTICLE V INVESTMENTS			9
	5.1.	Investment Options	9
	5.2.	Election of Investment Options	9
	5.3.	Allocation of Investment Options	9
	5.4.	No Actual Investment	9
ARTICLE VI PAYMENTS AND DISTRIBUTIONS			10
	6.1.	Distributions/Events Generally	10
	6.2.	In-Service Withdrawals	10
	6.3.	Distributions After Separation from Service	11
	6.4.	Unforeseeable Emergency Distributions	13
	6.5.	Automatic Cash-Out	13
	6.6.	Special Payment Election by December 31, 2006, for Code Section 409A Transition Relief	14
	6.7.	Withholding for Taxes	14
	6.8.	Payment to Guardian	14
ARTICLE VII BENEFICIARY DESIGNATION			14
	7.1.	Beneficiary Designation	14
	7.2.	No Beneficiary Designation	14
ARTICLE VIII PLAN ADMINISTRATION			15
	8.1.	Allocation of Duties to Committees	15
	8.2.	Agents	15
	8.3.	Information Required by Plan Administrator	15
	8.4.	Binding Effect of Decisions	15
ARTICLE IX CLAIMS PROCEDURE			15
	9.1.	Claim	15
	9.2.	Review of Claim	16
	9.3.	Notice of Denial of Claim	16
	9.4.	Reconsideration of Denied Claim	16
	9.5.	Employer to Supply Information	17
ARTICLE X PLAN AMENDMENT AND TERMINATION			17
	10.1.	Plan Amendment	17
	10.2.	Partial Plan Termination	18

ii

TABLE OF CONTENTS

Page

ARTICLE XI MISCELLANEOUS PROVISIONS			18
	11.1.	Unfunded Plan	18
	11.2.	Company and Employer Obligations	18
	11.3.	Unsecured General Creditor	18
	11.4.	Trust Fund	18
	11.5.	Nonalienation of Benefits	19
	11.6.	Indemnification	19
	11.7.	No Enlargement of Employee Rights	20
	11.8.	Protective Provisions	20
	11.9.	Governing Law	20
	11.10.	Validity	20
	11.11.	Notice	20
	11.12.	Successors	21
	11.13.	Incapacity of Recipient	21
	11.14.	Unclaimed Benefit	21
	11.15.	Tax Compliance and Payouts.	21
	11.16.	General Conditions	22

iii

SAVINGS RESTORATION PLAN

FOR NISOURCE INC. AND AFFILIATES

ARTICLE I
BACKGROUND AND PURPOSE

1.1Background. Prior to January 1, 2004, Columbia Energy Group sponsored the Savings Restoration Plan for Columbia Energy Group for eligible executives of Columbia Energy Group and certain Affiliates. Effective January 1, 2004, NiSource Inc., the parent company of Columbia Energy Group, assumed sponsorship of the Savings Restoration Plan for Columbia Energy Group, renamed the Plan the Savings Restoration Plan for NiSource Inc. and Affiliates, and broadened the Plan to include all employees of NiSource Inc. and Affiliates.

The Plan was amended and restated effective January 1, 2004, and amended effective January 1, 2005. The Plan was then amended and restated again effective January 1, 2005, to comply with Code Section 409A, and guidance and regulations thereunder, with respect to benefits earned under the Plan from and after January 1, 2005. Benefits under the Plan earned and vested prior to January 1, 2005 shall be administered without giving effect to Code Section 409A, and guidance and regulations thereunder. The provisions of the Plan as set forth herein apply only to Participants who actively participate in the Plan on or after January 1, 2005. Any Participant who retired or otherwise terminated employment with the Company and all Affiliates prior to January 1, 2005 shall have his or her rights determined under the provision of the Plan as it existed when his or her employment relationship terminated.

The Plan was further amended and restated, effective January 1, 2008, to provide for mandatory lump sum payments of small account balances in accordance with Code Section 409A. The Plan was amended and restated again, effective January 1, 2010, to contain provisions that eliminate mid-year enrollment into the Plan and to allow Participants who make Roth Contributions to a Basic Plan to participate in this Plan. The plan was further amended and restated, effective January 1, 2010, to restore certain Employer Contributions given to Participants who are classified as "exempt employees" by the Employer and who are hired or rehired on or after January 1, 2010.

The Plan was amended and restated again, effective May 13, 2011, to restore Profit Sharing Contributions that otherwise would have been contributed to Participants under the Basic Plan (if not subject to the Limits, defined below) and to transfer all administrative authority with respect to the Plan (including the authority to render decisions on claims and appeals and make administrative or ministerial amendments) from the ONC Committee to the Benefits Committee. The Plan was again amended and restated, effective January 1, 2012, to (1) remove the ability of participants to make elective deferrals to the Plan; (2) change eligibility to receive Employer credits under the Plan to those employees who are in job scope level C2 and above; (3) provide for investment options in addition to the fixed interest credits currently available for the crediting of earnings on Accounts under the Plan; and (4) clarify other administrative matters related to the Plan. The Plan was amended

1

and restated again, effective October 22, 2012, to allow certain grandfathered participants in the DCP to receive employer credits to be made under this Plan in 2013 and beyond related to any Profit Sharing Contributions and Next-Gen Contributions that otherwise would have been credited to their accounts under the Basic Plan but were not credited because their DCP deferrals are excluded from Basic Plan compensation for purposes of such contributions. The Plan is hereby amended and restated again, effective August 10, 2017, to revise the procedures for determining Disability under the Plan.

1.2Purpose. The purpose of the Plan is to provide for the payment of savings restoration benefits to employees of NiSource Inc. and Affiliates, whose benefits under the Basic Plan are subject to the Limits or affected by deferrals into the DCP, so that the total savings plan benefits of such employees shall be determined on the same basis as is applicable to all other employees of the Company. The Plan is adopted solely (1) for the purpose of providing benefits to Participants in the Plan and their Beneficiaries in excess of the Limits imposed on qualified plans by Code Section 401(a)(17) and any other Code Sections, by restoring benefits to such Plan Participants and Beneficiaries that are no longer available under the Basic Plan as a result of the Limits, and (2) for the purpose of restoring benefits to Plan Participants and Beneficiaries that are no longer available under the Basic Plan as a result of the Participant’s deferrals into the DCP.

ARTICLE II.
DEFINITIONS

For the purposes of the Plan, the following terms shall have the meanings indicated, unless the context clearly indicates otherwise. Except when otherwise required by the context, any masculine terminology in this document shall include the feminine, and any singular terminology shall include the plural. Defined terms used in the Plan that are not defined in this Article or elsewhere in the Plan but are defined in the Basic Plan shall have the meanings assigned to them in the Basic Plan. The headings of Articles and Sections are included solely for convenience, and if there is any conflict between such headings and the text of the Plan, the text shall control.

2.1Account. The device used by an Employer to measure and determine the amount to be paid under the Plan. Each Account shall be divided into a Pre-2005 Account containing contributions to the Plan earned and vested prior to January 1, 2005, and a Post-2004 Account containing contributions to the Plan earned and/or vested on or after January 1, 2005.

2.2Affiliate. Any corporation that is a member of a controlled group of corporations (as defined in Code Section 414(b)) that includes the Company; any trade or business (whether or not incorporated) that is under common control (as defined in Code Section 414(c)) with the Company; any organization (whether or not incorporated) that is a member of an affiliated service group (as defined in Code Section 414(m)) that includes the Company; any leasing organization, to the extent that its employees are required to be treated as if they were employed by the Company pursuant to Code Section 414(n) and the regulations thereunder; and any other entity required to

2

be aggregated with the Company pursuant to regulations under Code Section 414(o). An entity shall be an Affiliate only with respect to the existing period as described in the preceding sentence.

2.3Basic Plan. The NiSource Inc. Retirement Savings Plan, as amended and restated effective January 1, 2010, and as further amended from time to time (or as amended and restated for any prior period to the extent the provisions of the Plan refer to such prior period for the Basic Plan).

2.4Beneficiary. The person, persons or entity entitled to receive any Plan benefits payable after a Participant's death, as elected by a Participant under the Basic Plan.

2.5Benefits Committee. The NiSource Benefits Committee.

2.6Board. The Board of Directors of NiSource. Inc.

2.7Code. The Internal Revenue Code of 1986, as amended from time to time.

2.8Company. NiSource Inc.

2.9Compensation. Compensation as defined under the Basic Plan for purposes of determining Pre-Tax Contributions, Roth Contributions, and Matching Contributions under the Basic Plan. For purposes of calculating Employer credits to Participant Accounts under this Plan, Compensation may exceed the Compensation Limit under Code Section 401(a)(17)(B) and shall not be impacted by any other Limit.

2.10DCP. The Columbia Energy Group Deferred Compensation Plan on or prior to December 31, 2003, and, thereafter, the NiSource Inc. Executive Deferred Compensation Plan, as further amended from time to time.

2.11Disability. A condition that (a) causes a Participant, by reason of any medically determinable physical or mental impairment that can be expected to result in death or can be expected to last for a continuous period of not less than 12 months, to receive income replacement benefits for a period of not less than three months under an accident and health plan covering employees of the Company or an Affiliate or (b) causes a Participant to be eligible to receive Social Security disability payments.

2.12Effective Date. August 10, 2017, the date on which the provisions of this amended and restated Plan become effective, except as otherwise provided herein.

2.13Eligible Employee. A select group of management or highly compensated employees of the Employer who satisfy the criteria established by the ONC Committee in accordance with this Plan.

2.14Employer. The Company or any Affiliate that maintains or adopts the Basic Plan for the benefit of its eligible Employees.

2.15ERISA. The Employee Retirement Income Security Act of 1974, as amended.

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2.16In-Service Withdrawal. A distribution from a Participant's Pre-2005 Account before that Participant's Separation from Service made in accordance with the Participant's written election under Article V of this Plan.

2.17Limits. The limits imposed on tax qualified retirement plans by Code Sections 415 and 401(a)(17) and any other Code Sections.

2.18ONC Committee. The Officer Nomination and Compensation Committee of the Board of Directors of the Company.

2.19Participant. Any Eligible Employee who is participating in the Plan in accordance with its provisions.

2.20Plan. The Savings Restoration Plan for NiSource Inc. and Affiliates (formerly known as the Savings Restoration Plan for the Columbia Energy Group, and before that as the Thrift Restoration Plan for the Columbia Energy Group), as set forth herein and as amended from time to time.

2.21Plan Administrator. The Benefits Committee or such delegate of the Benefits Committee delegated to carry out the administrative functions of the Plan.

2.22Plan Year. The12‑month period commencing each January 1 and ending the following December 31.

2.23Post-2004 Account. The portion of a Participant's Account equal to the excess of (1) the balance of the Participant’s Account determined as of a Participant’s date of Separation from Service after December 31, 2004, over (2) the Pre-2005 Account, to which the Participant would be entitled under the Plan if he voluntarily separated from service without cause as of such date and received a full payment of benefits from the Plan on the earliest possible date allowed under the Plan following his Separation from Service.

2.24Pre-2005 Account. The portion of a Participant’s Savings Account determined as of December 31, 2004, adjusted to reflect earnings (or losses) credited to such balance from and after such date.

2.25Separation from Service. A termination of services provided by a Participant to his or her Employer, whether voluntarily or involuntarily, consistent with Code Section 409A and the guidance promulgated thereunder.

2.26Specified Employee. A Participant who is in job scope level C2 or above with respect to any Employer that employs him or her; provided that if at any time the total number of employees in job category C2 and above is less than 50, a Specified Employee shall include any employee who meets the definition of "key employee" set forth in Code Section 416(i) (without reference to paragraph 5 of Code Section 416(i)). A Participant shall be deemed to be a Specified Employee with respect to a Separation from Service that occurs during a calendar year if he or she is a Specified Employee on September 30 of the preceding calendar year. The Benefits Committee

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shall determine which Participants are Specified Employees in accordance with the guidance promulgated under Code Section 409A.

2.27Unforeseeable Emergency. A severe financial hardship to a Participant resulting from an illness or accident of the Participant, the Participant’s spouse or a dependent (as defined in Code Section 152(a)), of the Participant, loss of the Participant’s property due to casualty or other similar extraordinary and unforeseeable circumstances arising as a result of events beyond the control of the Participant.

2.28Valuation Date. The close of business of each business day.

ARTICLE III.
ELIGIBILITY AND PARTICIPATION

3.1Eligibility. On and after January 1, 2012, eligibility to participate in the Plan shall be limited to an employee in job scope level C2 or above. On and after October 22, 2012, eligibility to participate in this Plan additionally shall include any employee in job scope level D1 or D2 who completed an election form under the DCP in 2011 to make deferrals related to services performed in the Plan Year beginning January 1, 2012; provided however, that such an employee will be eligible to receive only the Profit Sharing Contribution Credits described in Section 4.2(b) and the Next-Gen Contribution Credits described in Section 4.2(c), to the extent described in such subsections, and will remain eligible to participate in this Plan and receive such contributions after the 2012 Plan Year only if he or she completes an election form under the DCP in each successive Plan Year after 2012 and otherwise remains eligible to continue to participate in the DCP in each successive Plan Year after 2012.

3.2Participation. The Plan Administrator shall inform each Employee of his or her eligibility to participate in the Plan as soon as practicable but before the earliest date such Employee’s participation could become effective. An Eligible Employee becomes a Participant when the Employer credits the Participant’s Account with the Employer credits described in Article IV of this Plan.

3.3Continuation of Participation. A Participant shall remain a Participant so long as his or her Account has not been fully distributed to him or her.

3.4Amendment of Eligibility Criteria. The ONC Committee may, in its discretion, change the criteria for eligibility for any reason, provided, however, that no change in the criteria for eligibility shall be effective unless such changes are (a) within guidelines established by the ONC Committee or (b) approved by the ONC Committee. Eligibility for participation in one year does not guarantee eligibility to participate in any future year.

ARTICLE IV.
ACCOUNTS

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4.1Account. The Employer credits, as described in Sections 4.2 and 4.3, and earnings thereon, shall be credited to the Participant's Account. The Account shall be a bookkeeping device utilized for the sole purpose of determining the benefits payable under the Plan and shall not constitute a separate fund of assets.

4.2Employer Credits.

(a) Matching Contribution Credits. The amount of Employer credits related to Matching Contributions for Participant eligible to receive such contributions under Section 3.1 shall equal (1) minus (2) below:

(1) The total amount of Matching Contributions that would otherwise have been contributed to the Basic Plan for the Participant during all years in which the Participant participated in the Basic Plan without regard to the Limits;

(2) The actual amount of Matching Contributions that have been contributed to the Basic Plan for the Participant.

In addition to making the credits related to Matching Contributions described above, the Employer also will make the following true‑up credit. If (i) the allocation period under the Basic Plan is shorter than the Plan Year, and (ii) on the last day of the Plan Year, the amount of Matching Contributions under the Basic Plan is less than the amount of Matching Contributions that would have been made had the allocation period for Matching Contributions been the Plan Year, then the Employer will make an additional credit to a Participant’s Account. This credit will be in the amount necessary to make the Employer credit related to Matching Contributions equal to the amount of Employer credits related to Matching Contributions that would have been made had the allocation period been the Plan Year. Notwithstanding the foregoing, an Employer shall make this true‑up credit only for Participants who are employed with the Employer on the last day of the Plan Year and Participants who experienced a Separation from Service before the last day of the Plan Year due to death, Disability, or retirement.

(b) Profit Sharing Contribution Credits. Employer credits pursuant to this Section 4.2(b) shall be reflected in the Plan for all Participants in the Plan on or after such date, including the following: (1) those who received Profit Sharing Contributions to the Basic Plan for 2010 or later that were subject to the Limits, or (2) those who otherwise had Profit Sharing Contributions limited or adjusted under the Basic Plan on or after January 1, 2011. The amount of Employer credits related to Profit Sharing Contributions for a participant shall equal (1) minus (2) below:

(1) The total amount of Profit Sharing Contributions that otherwise would have been contributed to the Basic Plan for the Participant

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during all years in which the Participant participated in the Basic Plan, as determined by Compensation as defined under this Plan without regards to the Limits;

(2) The actual amount of Profit Sharing Contributions that have been contributed to the Basic Plan for the Participant.

Notwithstanding the foregoing, a Participant who is in job scope level D1 or D2 shall receive an amount of Employer credits related to Profit Sharing Contributions equal to the difference between (1) minus (2) below:

(1) The total amount of Profit Sharing Contributions that otherwise would have been contributed to the Basic Plan for the Participant during all years in which the Participant participated in the Basic Plan, had Profit Sharing Contributions been calculated using this Plan's definition of Compensation;

(2) The actual amount of Profit Sharing Contributions that have been contributed to the Basic Plan for the Participant.

This amount shall be payable to any applicable Participant regardless of whether such Participant has signed a written agreement to participate in this Plan.

(c) Next-Gen Contribution Credits. With respect to a Participant who is classified by the Employer as an "exempt employee" and who is hired or rehired on or after January 1, 2010, the amount of Employer credits for a Participant shall equal (1) minus (2) below:

(1) The total amount of the Employer Contribution that otherwise would have been contributed to the Basic Plan in an amount equal to 3% of the Participant's Compensation (as defined under this Plan) without regard to the Limits;

(2) The actual amount of the Employer Contribution under the Basic Plan that was contributed to the Participant in an amount equal to 3% of the Participant's Compensation (as defined under the Basic Plan).

This amount shall be payable to any applicable Participant in addition to any amounts he or she may be entitled to under Sections 4.2(a) and 4.2(b) of this Plan and regardless of whether such Participant has signed a written agreement to participate in this Plan.

Notwithstanding the foregoing, a Participant who is in job scope level D1 or D2 shall receive an amount of Employer credits equal to the difference between (1) minus (2) below:

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(1) The total amount of the Employer Contribution that otherwise would have been contributed to the Basic Plan in an amount equal to 3% of the Participant's Compensation (as defined under this Plan);

(2) The actual amount of the Employer Contribution under the Basic Plan that was contributed to the Participant in an amount equal to 3% of the Participant's Compensation (as defined under the Basic Plan).

This amount shall be payable to any applicable Participant regardless of whether such Participant has signed a written agreement to participate in this Plan.

4.3Timing of Credits; Withholding. The Employer credits shall be made to the Participant's Account annually, at such time determined by the Plan Administrator. Any withholding of taxes or other amounts that is required by federal, state, or local law shall be withheld from the Participant's nondeferred Compensation to the maximum extent possible and any remaining amount shall reduce the amount credited to the Participant's Account.

4.4Determination of Account. Each Participant's Account as of each Valuation Date shall consist of the balance of the Account as of the immediately preceding Valuation Date, adjusted as follows:

(a) New Employer Credits. The Account shall be increased by any Employer credits made in accordance with Sections 4.2 or 4.3, as applicable, since such preceding Valuation Date.

(b) Distributions. The Account shall be reduced by any benefits distributed from the Account to the Participant since such preceding Valuation Date.

(c) Valuation of Account. The Account shall be increased or decreased by the aggregate earnings, gains and losses on such Account since such preceding Valuation Date, based on the manner in which the Participant's Account has been hypothetically allocated among the investment options selected by the Participant.

4.5Statement of Account. The Plan Administrator shall give to each Participant a statement showing the balance in the Participant's Account periodically at such times as may be determined by the Plan Administrator, in written or electronic form.

ARTICLE V.
INVESTMENTS

5.1Investment Options. Amounts credited hereunder to the Account of a Participant shall be invested as such Participant elects among the investment choices provided to the Participant.

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The investment options shall be determined by the Plan Administrator from time to time in its sole and absolute discretion. As necessary, the Plan Administrator may, in its sole discretion, discontinue, substitute or add an investment option. Each such action will take effect on such date established by the Plan Administrator.

5.2Election of Investment Options. A Participant, in connection with his or her payment election under Article VI of this Plan, shall elect one or more of the previously described investment options, as applicable, to be used to determine the amounts to be credited or debited to his or her Account. If a Participant does not elect any investment options, the Participant’s Account shall automatically be allocated into the lowest-risk investment option, as determined by the Plan Administrator, in its sole discretion. The Participant may (but is not required to) elect to add or delete one or more investment options to be used to determine the amounts to be credited or debited to his or her Account, or to change the portion of his or her Account allocated to each previously or newly elected investment option. If an election is made in accordance with the previous sentence, it shall apply as of the first business day deemed reasonably practicable by the Plan Administrator, in its sole discretion, and shall continue thereafter for each subsequent day in which the Participant participates in the Plan, unless changed in accordance with the previous sentence. Notwithstanding the foregoing, the Plan Administrator, in its sole discretion, may impose limitations on the frequency with which one or more of the investment options elected in accordance with this Section may be added or deleted by such Participant; furthermore, the Plan Administrator, in its sole discretion, may impose limitations on the frequency with which the Participant may change the portion of his or her Account allocated to each previously or newly elected investment option.

5.3Allocation of Investment Options. In making any election related to investment options, the Participant shall specify, in increments specified by the Plan Administrator, the percentage of his or her Account or investment option, as applicable, to be allocated or reallocated.

5.4No Actual Investment. Notwithstanding any other provision of this Plan that may be interpreted to the contrary, the investment options are to be used for measurement purposes only, and a Participant's election of any such investment option, the allocation of his or her Account thereto, the calculation of additional amounts and the crediting or debiting of such amounts to a Participant's Account shall not be considered or construed in any manner as an actual investment of his or her Account in any such investment option. In the event that the Company, in its own discretion, decides to invest funds in any or all of the investments on which the investment options are based, no Participant shall have any rights in or to such investments themselves. Without limiting the foregoing, a Participant's Account shall at all times be a bookkeeping entry only and shall not represent any investment made on his or her behalf by the Company; the Participant shall at all times remain an unsecured creditor of the Company.

ARTICLE VI.
PAYMENTS AND DISTRIBUTIONS

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6.1Distributions/Events Generally. Participants generally will not be entitled to receive a distribution of their Account balance until they experience a Separation from Service with the Employer for any reason. A Participant may receive a distribution before Separation from Service, however, in accordance with this Article VI, upon (1) an Unforeseeable Emergency that occurs before Separation from Service, or (2) a year that has been designated by the Participant only with respect to his Pre-2005 Account balance that occurs before Separation from Service.

6.2In-Service Withdrawals. This section applies only to a Participant's Pre-2005 Account balance.

(a) General Payments. Subject to the limitations of paragraph (b) below, a Participant, by filing a written request with the Plan Administrator, may, while employed by an Employer or an Affiliate, elect to withdraw 33%, 67% or 100% of his or her Pre-2005 Account.

(b) Limitation on In-Service Withdrawals. Any In-Service Withdrawal under paragraph (a) of this Section 6.2 shall be subject to a 10% early distribution penalty. In addition, the following conditions shall apply to In-Service Withdrawals:

(1) Only one In-Service Withdrawal shall be permitted in any 12-month period.

(2) In-Service Withdrawals shall require suspension of Employer credits (but not credits of earnings or losses) under the Plan for a period of time varying with the percentage of the value of the Participant’s Pre-2005 Account that is withdrawn, according to the following schedule:

Percentage	Suspension
Up to 33%	2 months
34 ‑ 67%	4 months
68 ‑ 100%	6 months

This suspension shall not affect a Participant’s participation in the Basic Plan nor the basis for determining the Employer contributions or Participant Pre‑tax Contributions under the Basic Plan.

6.3Distributions After Separation from Service.

(a) Generally. If a Participant experiences a Separation from Service, the provisions of this Section 6.3 shall apply to the distribution of the Participant’s Account.

(b) Pre-2005 Account.

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(1) Form of Payment of Pre-2005 Account. The Pre-2005 Account payable under the Plan to a Participant or his or her spouse, Beneficiary, or legal representative shall be paid in the same form under which the Basic Plan benefit is payable to the Participant or his or her spouse, Beneficiary, or legal representative. The Participant’s election under the Basic Plan of any optional form of payment of his or her Basic Plan benefit (with the valid consent of his or her surviving spouse where required under the Basic Plan) shall also be applicable to the payment of his or her Pre-2005 Account under the Plan.

(2) Timing of Payment of Pre-2005 Account. Payment of the Pre-2005 Account under the Plan to a Participant or his or her spouse, Beneficiary, or legal representative under the Plan shall commence on the same date as payment of the benefit to the Participant or his or her spouse, Beneficiary, or legal representative under the Basic Plan commences. Any election under the Basic Plan made by the Participant with respect to the commencement of payment of his or her benefit under the Basic Plan shall also be applicable with respect to the commencement of payment of his or her Pre-2005 Account under the Plan.

(3) Approval by Plan Administrator. Notwithstanding the provisions of paragraphs (i) and (ii) above, an election made by the Participant under the Basic Plan with respect to the form of payment of his or her Pre-2005 Account thereunder (with the valid consent of his or her surviving spouse where required under the Basic Plan), or the date for commencement of payment thereof, shall not be effective with respect to the form of payment or date for commencement of payment of his or her Pre-2005 Account under the Plan unless such election is expressly approved in writing by the Plan Administrator. If the Plan Administrator shall not approve such election in writing, then the form of payment or date for commencement of payment of the Participant's Pre-2005 Account under the Plan shall be selected by the Plan Administrator at its sole discretion.

(c) Post-2004 Account.

(1) Form of Payment of Post-2004 Account. The Post-2004 Account shall be payable in a form elected by a Participant no later than December 31, 2005. Notwithstanding the preceding sentence, in the case of an Eligible Employee who becomes a Participant on or after January 1, 2005, the aforementioned election with respect to the form of payment of a Post-2004 Account shall be made at such time prescribed by the Plan Administrator, which shall end no later than

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December 31^st of the year preceding the Plan Year in which the Participant is first eligible to participate in the Plan. The form of payment that a Participant may elect to receive shall be from the choices of either a lump sum or in substantially equal annual installments over a period not to exceed 15 years. Notwithstanding the foregoing, if before January 1, 2014, a Participant made an election to receive payment in the form of monthly or semi-annual installments, payment shall be made in the form elected by the Participant. If a Participant has not made a timely election, payment shall be made a lump sum.

(2) Timing of Payment of Post-2004 Account. Payment of a Post-2004 Account in accordance with this Section 6.3 shall commence within 45 days after the Participant’s date of Separation from Service, or, if later, within such timeframe permitted under Code Section 409A, and guidance and regulations thereunder.

(3) Modifications to Time and Form of Payment. A Participant cannot change the time or form of payment of a Post-2004 Account under this Subsection 6.3(b) unless (A) such election does not take effect until at least 12 months after the date the election is made, (B) in the case of an election related to a payment not related to the Participant’s Disability or death, the first payment with respect to which such new election is effective is deferred for a period of not less than five years from the date such payment would otherwise have been made, and (C) any election related to a payment based upon a specific time or pursuant to a fixed schedule may not be made less than 12 months prior to the date of the first scheduled payment.

(4) Time of Payment for Specified Employees. Notwithstanding any other provision of the Plan, in no event can a payment of a Post-2004 Account to a Participant who is a Specified Employee, at a time during which the Company’s capital stock or capital stock of an Affiliate is publicly traded on an established securities market, in the calendar year of his or her Separation from Service be made before the date that is six months after the date of the Participant’s Separation from Service, unless such Separation from Service is due to death or Disability.

6.4Unforeseeable Emergency Distributions.

(a) Pre-2005 Account. Upon a finding that a Participant has suffered an Unforeseeable Emergency, the Plan Administrator may, in its sole discretion, make distributions from the Participant’s Pre‑2005 Account. The amount of such a distribution shall be limited to the amount reasonably necessary to meet the Participant’s needs resulting from the Unforeseeable Emergency.

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Any distribution pursuant to this Subsection shall be payable in a lump sum. The distribution shall be paid within 30 days after the determination of an Unforeseeable Emergency.

(b) Post-2004 Account. Upon a finding that a Participant has suffered an Unforeseeable Emergency, the Plan Administrator may, in its sole discretion, make distributions from the Participant's Post-2004 Account and/or suspend Employer credits entirely in accordance with the guidance under Code Section 409A. The amount of such distribution shall be limited to the amount necessary to satisfy such Unforeseeable Emergency plus amounts necessary to pay taxes reasonably anticipated as a result of the distribution, after taking into account the extent to which such hardship is or may be relieved through reimbursement or compensation by insurance or otherwise or by liquidation of the Participant's assets (to the extent the liquidation of such assets would not itself cause severe financial hardship). Any distribution pursuant to this Subsection shall be payable in a lump sum. The distribution shall be paid within 30 days after the determination of an Unforeseeable Emergency.

6.5Automatic Cash-Out. Notwithstanding any other provision in the Plan, if (1) the sum of the Participant’s Pre-2005 Account and Post-2004 Account does not exceed the applicable dollar limit under code Section 402(g)(1)(B) and (2) this sum is the entirety of the Participant’s interest in the Plan and all other arrangements that are considered a single nonqualified deferred compensation plan under Code Section 409A and applicable guidance thereunder, the Employer, in its sole discretion may distribute the Participant’s entire Pre-2005 Account and Post-2004 Account (and the Participant’s entire interest under any other arrangement that is required to be aggregated with this Plan under Code Section 409A), regardless whether the Participant has otherwise had a distributable event under this Plan. The form of payment of both the Pre-2005 Account and Post-2004 Account shall be a single lump sum.

6.6Special Payment Election by December 31, 2006, for Code Section 409A Transition Relief.Notwithstanding any preceding provision of this Section 6.3(b), a Participant may change an election with respect to the time and form of payment of a Post-2004 Account, without regard to the restrictions imposed under paragraph (iii) next above, on or before December 31, 2006; provided that such election (A) applies only to amounts that would not otherwise be payable in calendar year 2006, and (B) shall not cause an amount to be paid in calendar year 2006 that would not otherwise be payable in such year.

6.7Withholding for Taxes. To the extent required by the law in effect at the time payments are made, an Employer shall withhold from the payments made hereunder any taxes required to be withheld by the federal or any state or local government, including any amounts which the Employer determines is reasonably necessary to pay any generation-skipping transfer tax which is or may become due. A Beneficiary, however, may elect not to have withholding of federal income tax pursuant to Code Section 3405(a)(2).

6.8Payment to Guardian. The Plan Administrator may direct payment to the duly appointed guardian, conservator or other similar legal representative of a Participant or Beneficiary

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to whom payment is due. In the absence of such a legal representative, the Plan Administrator may, in its sole and absolute discretion, make payment to a person having the care and custody of a minor, incompetent or person incapable of handling the disposition of property upon proof satisfactory to the Plan Administrator of incompetency, status as a minor, or incapacity. Such distribution shall completely discharge the Company from all liability with respect to such benefit.

ARTICLE VII.
BENEFICIARY DESIGNATION

7.1Beneficiary Designation. Each Participant's Beneficiary (both primary as well as secondary) to whom benefits under the Plan shall be paid in the event of the Participant’s death prior to complete distribution of the Participant’s Account, shall be the Beneficiary that the Participant has selected under the Basic Plan. A Participant may designate a Beneficiary or change a prior Beneficiary designation only by designating or changing a Beneficiary under the Basic Plan.

7.2No Beneficiary Designation. If any Participant fails to designate a Beneficiary in the manner provided above, if the designation is void or if the Beneficiary designated by a deceased Participant dies before the Participant or before complete distribution of the Participant’s benefits, the Participant’s Beneficiary shall be the person identified in accordance with the procedures under the Basic Plan.

ARTICLE VIII.
PLAN ADMINISTRATION

8.1Allocation of Duties to Committees. The Plan shall be administered by the Benefits Committee, as delegated by the ONC Committee. The Benefits Committee shall have the authority to make, amend, interpret, and enforce all appropriate rules and regulations for the administration of the Plan and decide or resolve any and all questions, including interpretations of the Plan, as may arise in such administration, except as otherwise reserved to the ONC Committee herein, or by resolution or charter of the respective committees.

In its discretion, the Plan Administrator may delegate to any division or department of the Company the discretionary authority to make decisions regarding Plan administration, within limits and guidelines from time to time established by the Plan Administrator. The delegated discretionary authority shall be exercised by such division or department’s senior officer, or his/her delegate. Within the scope of the delegated discretionary authority, such officer or person shall act in the place of the Plan Administrator and his/her decisions shall be treated as decisions of the Plan Administrator.

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8.2Agents. The Plan Administrator may, from time to time, employ agents and delegate to them such administrative duties as it sees fit, and may from time to time consult with counsel who may be counsel to the Company.

8.3Information Required by Plan Administrator. The Company shall furnish the Plan Administrator with such data and information as the Plan Administrator may deem necessary or desirable in order to administer the Plan. The records of the Company as to an employee’s or Participant’s period or periods of employment, separation from Service and the reason therefore, reemployment and Compensation will be conclusive on all persons unless determined to the Plan Administrator’s satisfaction to be incorrect. Participants and other persons entitled to benefits under the Plan also shall furnish the Plan Administrator with such evidence, data or information as the Plan Administrator considers necessary or desirable to administer the Plan.

8.4Binding Effect of Decisions. Subject to applicable law, and the provisions of Article VIII, any interpretation of the provisions of the Plan and any decision on any matter within the discretion of the Benefits Committee and/or the ONC Committee (or any duly authorized delegate of either such committee) and made in good faith shall be binding on all persons.

ARTICLE IX.
CLAIMS PROCEDURE

9.1Claim. Claims for benefits under the Plan shall be made in writing to the Plan Administrator. The Plan Administrator shall establish rules and procedures to be followed by Participants and Beneficiaries in filing claims for benefits, and for furnishing and verifying proof necessary to establish the right to benefits in accordance with the Plan, consistent with the remainder of this Article.

9.2Review of Claim. The Plan Administrator shall review all claims for benefits. Upon receipt by the Plan Administrator of such a claim, it shall determine all facts that are necessary to establish the right of the claimant to benefits under the provisions of the Plan and the amount thereof as herein provided within 90 days of receipt of such claim. If prior to the expiration of the initial 90 day period, the Plan Administrator determines additional time is needed to come to a determination on the claim, the Plan Administrator shall provide written notice to the Participant, Beneficiary or other claimant of the need for the extension, not to exceed a total of 180 days from the date the application was received. If the Plan Administrator fails to notify the claimant in writing of the denial of the claim within 90 days after the Plan Administrator receives it, the claim shall be deemed denied.

9.3Notice of Denial of Claim. If the Plan Administrator wholly or partially denies a claim for benefits, the Plan Administrator shall, within a reasonable period of time, but no later than 90 days after receiving the claim (unless extended as noted above), notify the claimant in writing of the denial of the claim. Such notification shall be written in a manner reasonably expected to be understood by such claimant and shall in all respects comply with the requirements of ERISA, including but not limited to inclusion of the following:

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(a) the specific reason or reasons for denial of the claim;

(b) a specific reference to the pertinent Plan provisions upon which the denial is based;

(c) a description of any additional material or information necessary for the claimant to perfect the claim, together with an explanation of why such material or information is necessary; and

(d) an explanation of the Plan’s review procedure.

9.4Reconsideration of Denied Claim. Within 60 days of the receipt by the claimant of the written notice of denial of the claim, or within 60 days after the claim is deemed denied as set forth above, if applicable, the claimant or duly authorized representative may file a written request with the Benefits Committee that it conduct a full and fair review of the denial of the claimant’s claim for benefits. If the claimant or duly authorized representative fails to request such a reconsideration within such 60 day period, it shall be conclusively determined for all purposes of the Plan that the denial of such claim by the Benefits Committee is correct. In connection with the claimant’s appeal of the denial of his or her benefit, the claimant may review pertinent documents and may submit issues and comments in writing.

The Benefits Committee shall render a decision on the claim appeal promptly, but not later than 60 days after receiving the claimant’s request for review, unless, in the discretion of the Benefits Committee, special circumstances require an extension of time for processing, in which case the 60-day period may be extended to 120 days. The Benefits Committee shall notify the claimant in writing of any such extension. The notice of decision upon review shall be in writing and shall include specific reasons for the decision, written in a manner calculated to be understood by the claimant, as well as specific references to the pertinent Plan provisions upon which the decision is based. If the decision on review is not furnished within the time period set forth above, the claim shall be deemed denied on review.

If such determination is favorable to the claimant, it shall be binding and conclusive. If such determination is adverse to such claimant, it shall be binding and conclusive unless the claimant or his duly authorized representative notifies the Benefits Committee within 90 days after the mailing or delivery to the claimant by the Benefits Committee of its determination that claimant intends to institute legal proceedings challenging the determination of the Benefits Committee and actually institutes such legal proceedings within 180 days after such mailing or delivery.

9.5Employer to Supply Information. To enable the Benefits Committee to perform its functions, each Employer shall supply fully and timely information to the Benefits Committee of all matters relating to the retirement, death, or other cause for Separation from Service of all Participants, and such other pertinent facts as the Benefits Committee may require.

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ARTICLE X.
PLAN AMENDMENT AND TERMINATION

10.1Plan Amendment. While the Company intends to maintain the Plan in conjunction with the Basic Plan, the Company or the ONC Committee reserves the right to amend the Plan at any time and from time to time with respect to eligibility for the Plan, the level of benefits awarded under the Plan and the time and form of payment for benefits from the Plan. The Benefits Committee, the ONC Committee, or the Board shall have the authority to amend the Plan as described herein. The ONC Committee or the Board shall have the exclusive authority to amend the Plan regarding eligibility for the Plan, the amount or level of benefits awarded under the Plan, and the time and form of payments for benefits from the Plan. In addition, the ONC Committee or the Board shall also have the exclusive authority to make amendments that constitute a material increase in Compensation, any change requiring action or consent by a committee of the Board pursuant to the rules of the Securities and Exchange Commission, the New York Stock Exchange or other applicable law, or such other material changes to the Plan such that approval of the Board is required. Unless otherwise determined by the ONC Committee, the Benefits Committee shall have the authority to amend the Plan in all respects that are not exclusively reserved to the ONC Committee or the Board.

The respective committee may at any time amend the Plan by written instrument, notice of which is given to all Participants and to Beneficiaries. Notwithstanding the preceding sentence, no amendment shall reduce the amount accrued in any Account prior to the date such notice of the amendment is given.

10.2Partial Plan Termination. The ONC Committee or the Company at any time may partially terminate the Plan provided that such partial termination of the Plan shall not impair or alter any Participant's or Beneficiary's right to the applicable Participant's Account balance as of the effective date of such partial termination. If such a partial termination occurs, no additional Employer credits shall be made after the date of such partial termination other than the crediting of earnings (or losses) until the date of distribution of Participant Account balances. Further, the Plan shall otherwise continue to be administered with respect to Account balances credited before the effective date of such partial termination, and distribution shall be made at such times as specified under this Plan.

17

ARTICLE XI.
MISCELLANEOUS PROVISIONS

11.1Unfunded Plan. The Plan is an unfunded plan maintained primarily to provide deferred compensation benefits for a select group of “management or highly-compensated employees” within the meaning of Sections 201, 301 and 401 of the Employee Retirement Income Security Act of 1974, as amended (“ERISA”), and therefore is exempt from the provisions of Parts 2, 3 and 4 of Title I of ERISA. Nothing contained in the Plan shall constitute a guaranty by the

Company or any other Employer or any other entity or person that the assets of the Company or any other Employer shall be sufficient to pay any benefit hereunder.

11.2Company and Employer Obligations. The obligation to make benefit payments to any Participant under the Plan shall be a joint and several liability of the Company and the Employer that employed the Participant.

11.3Unsecured General Creditor. Participants and Beneficiaries shall be unsecured general creditors, with no secured or preferential right to any assets of the Company, any other Employer, or any other party for payment of benefits under the Plan. Any life insurance policies, annuity contracts or other property purchased by the Employer in connection with the Plan shall remain its general, unpledged and unrestricted assets. Obligations of the Company and each other Employer under the Plan shall be an unfunded and unsecured promise to pay money in the future.

11.4Trust Fund. Subject to Section 12.3, the Company may establish separate subtrusts for deferrals by employees of each Employer, pursuant to a trust agreement entered into with such trustees as the Benefits Committee may approve, for the purpose of providing for the payment of benefits owed under the Plan. At its discretion, each Employer may contribute deferrals under the Plan for its employees to the subtrust established with respect to such Employer under such trust agreement. To the extent any benefits provided under the Plan are paid from any such subtrust, the Employer shall have no further obligation to pay them. If not paid from a subtrust, such benefits shall remain the obligation of the Employer. Although such subtrusts may be irrevocable, their assets shall be held for payment of all the Company’s general creditors in the event of insolvency or bankruptcy.

11.5Nonalienation of Benefits. Neither a Participant nor any other person shall have any right to commute, sell, assign, transfer, pledge, anticipate, mortgage, or otherwise encumber, transfer, hypothecate, or convey in advance of actual receipt the amounts, if any, payable hereunder, or any part thereof or rights to, which are expressly declared to be unassignable and nontransferable. No part of the amounts payable shall, prior to actual payment, be subject to seizure or sequestration for the payment of any debts, judgments, alimony, or separate maintenance owed by a Participant or any other person, nor be transferable by operation of law in the event of a Participant’s or any other person’s bankruptcy or insolvency.

Notwithstanding the preceding paragraph, the Account of any Participant shall be subject to and payable in the amount determined in accordance with any qualified domestic relations order, as that term is defined in Section 206(d)(3) of ERISA. The Retirement Committee shall provide for payment in a lump sum from a Participant’s Account to an alternate payee (as defined in Code Section 414(p)(8)) as soon as administratively practicable following receipt of such order. Any federal, state or local income tax associated with such payment shall be the responsibility of the alternate payee. The balance of an Account that is subject to any qualified domestic relations order shall be reduced by the amount of any payment made pursuant to such order.

Notwithstanding the preceding paragraph, the Account of any Participant shall be subject to and payable in the amount determined in accordance with any qualified domestic relations order, as that term is defined in Section 206(d)(3) of ERISA. The Plan Administrator shall provide for

18

payment of such portion of an Account to an alternate payee (as defined in Section 206(d)(3) of ERISA) as soon as administratively possible following receipt of such order. Any federal, state or local income tax associated with such payment shall be the responsibility of the alternate payee. The balance of any Account that is subject to any qualified domestic relations order shall be reduced by the amount of any payment made pursuant to such order.

11.6Indemnification.

(a) Limitation of Liability. Notwithstanding any other provision of the Plan or any trust established under the Plan, none of the Company, any other Employer, any member of the Benefits Committee or the ONC Committee, nor any individual acting as an employee, or agent or delegate of any of them, shall be liable to any Participant, former Participant, Beneficiary, or any other person for any claim, loss, liability or expense incurred in connection with the Plan or any trust established under the Plan, except when the same shall have been judicially determined to be due to the willful misconduct of such person.

(b) Indemnity. The Company shall indemnify and hold harmless each member of the Benefits Committee and the ONC Committee, or any employee of the Company or any individual acting as an employee or agent of either of them (to the extent not indemnified or saved harmless under any liability insurance or any other indemnification arrangement with respect to the Plan or any trust established under the Plan) from any and all claims, losses, liabilities, costs and expenses (including attorneys’ fees) arising out of any actual or alleged act or failure to act made in good faith pursuant to the provisions of the Plan, including expenses reasonably incurred in the defense of any claim relating thereto with respect to the administration of the Plan or any trust established under the Plan, except that no indemnification or defense shall be provided to any person with respect to any conduct that has been judicially determined, or agreed by the parties, to have constituted willful misconduct on the part of such person, or to have resulted in his or her receipt of personal profit or advantage to which he or she is not entitled. In connection with the indemnification provided by the preceding sentence, expenses incurred in defending a civil or criminal action, suit or proceeding, or incurred in connection with a civil or criminal investigation, may be paid by the Company in advance of the final disposition of such action, suit, proceeding, or investigation, as authorized by the Benefits Committee or the ONC Committee in the specific case, upon receipt of an undertaking by or on behalf of the party to be indemnified to repay such amount unless it shall ultimately be determined that the person is entitled to be indemnified by the Company pursuant to this paragraph.

11.7No Enlargement of Employee Rights. No Participant or Beneficiary shall have any right to a benefit under the Plan except in accordance with the terms of the Plan. The Plan shall

19

not constitute a contract of employment between an Employer and the Participant. Nothing in the Plan shall give any Participant or Beneficiary the right to be retained in the service of an Employer or to interfere with the right of an Employer to discipline or discharge a Participant at any time.

11.8Protective Provisions. A Participant shall cooperate with his Employer by furnishing any and all information requested by the Employer in order to facilitate the payment of benefits hereunder, and by taking such physical examinations as the Employer may deem necessary and taking such other action as may be requested by the Employer.

11.9Governing Law. The Plan shall be construed and administered under the laws of the State of Indiana, except to the extent preempted by applicable federal law.

11.10Validity. In case any provision of the Plan shall be held illegal or invalid for any reason, said illegality or invalidity shall not affect the remaining parts hereof, but the Plan shall be construed and enforced as if such illegal and invalid provision had never been inserted herein.

11.11Notice. Any notice required or permitted under the Plan shall be sufficient if in writing and hand delivered or sent by registered or certified mail. Such notice shall be deemed as given as of the date of delivery or, if delivery is made by mail, as of the date shown on the postmark on the receipt for registration or certification. Mailed notice to the Benefits Committee shall be directed to the Company’s address. Mailed notice to a Participant or Beneficiary shall be directed to the individual’s last known address in the applicable Employer’s records.

11.12Successors. The provisions of the Plan shall bind and inure to the benefit of the Employers and their successors and assigns. The term successors as used herein shall include any corporate or other business entity that shall, whether by merger, consolidation, purchase, or otherwise, acquire all or substantially all of the business and assets of an Employer, and successors of any such corporation or other business entity.

11.13Incapacity of Recipient. If any person entitled to a benefit payment under the Plan is deemed by the Plan Administrator to be incapable of personally receiving and giving a valid receipt for such payment, then, unless and until a claim shall have been made by a duly appointed guardian or other legal representative of such person, the Plan Administrator may provide for such payment or any part thereof to be made to any other person or institution then contributing toward or providing for the care and maintenance of such person. Any such payment shall be a payment for the account of such person and a complete discharge of any liability of the Company, any other Employer, the Plan Administrator and the Plan.

11.14Unclaimed Benefit. Each Participant shall keep the Plan Administrator informed of his or her current address and the current address of his or her Beneficiaries. The Plan Administrator shall not be obligated to search for the whereabouts of any person. If the location of a Participant is not made known to the Plan Administrator within three years after the date on which payment of the Participant's benefit may first be made, payment may be made as though the Participant had died at the end of the three-year period. If, within one additional year after such three-year period has elapsed or within three years after the actual death of a Participant, the Plan Administrator is unable to locate any Beneficiary of the Participant, then the Plan Administrator

20

shall have no further obligation to pay any benefit hereunder to such Participant, Beneficiary, or any other person and such benefit shall be irrevocably forfeited.

11.15Tax Compliance and Payouts.

(a) It is intended that the Plan comply with the provisions of Code Section 409A of the Code, so as to prevent the inclusion in gross income of any amounts deferred hereunder in a taxable year that is prior to the taxable year or years in which such amounts would otherwise actually be paid or made available to Participants or Beneficiaries. This Plan shall be construed, administered, and governed in a manner that affects such intent, and neither any Participant, Beneficiary, nor Plan Administrator shall not take any action that would be inconsistent with such intent.

(b) Although the Plan Administrator shall use its best efforts to avoid the imposition of taxation, interest and penalties under Code Section 409A, the tax treatment of deferrals under this Plan is not warranted or guaranteed. Neither the Company, the other Affiliates, the Plan Administrator, the Retirement Committee, nor any designee shall be held liable for any taxes, interest, penalties or other monetary amounts owed by any Participant, Beneficiary or other taxpayer as a result of the Plan.

(c) Notwithstanding anything to the contrary contained herein, (1) in the event that the Internal Revenue Service prevails in its claim that any amount of a Pre-2005 Account, payable pursuant to the Plan and held in the general assets of the Company or any other Employer, constitutes taxable income to a Participant or his or her Beneficiary for a taxable year prior to the taxable year in which such amount is distributed to him or her, or (2) in the event that legal counsel satisfactory to the Company, and the applicable Participant or his or her Beneficiary, renders an opinion that the Internal Revenue Service would likely prevail in such a claim, the amount of such Pre-2005 Account held in the general assets of the Company or any other Employer, to the extent constituting taxable income, shall be immediately distributed to the Participant or his or her Beneficiary. For purposes of this Section, the Internal Revenue Service shall be deemed to have prevailed in a claim if such claim is upheld by a court of final jurisdiction, or if the Participant or Beneficiary, based upon an opinion of legal counsel satisfactory to the Company and the Participant or his or her Beneficiary, fails to appeal a decision of the Internal Revenue Service, or a court of applicable jurisdiction, with respect to such claim, to an appropriate Internal Revenue Service appeals authority or to a court of higher jurisdiction within the appropriate time period.

(d) Notwithstanding anything to the contrary contained herein, (1) in the event that the Internal Revenue Service prevails in its claim that any amount of a Post-2004 Account, payable pursuant to the Plan and held in the general assets of the Company or any other Employer, constitutes taxable income

21

under Code Section 409A, and guidance and regulations thereunder, to a Participant or his or her Beneficiary for a taxable year prior to the taxable year in which such amount is distributed to him or her, or (2) in the event that legal counsel satisfactory to the Company, and the applicable Participant or his or her Beneficiary, renders an opinion that the Internal Revenue Service would likely prevail in such a claim, the amount of such Post-2004 Account held in the general assets of the Company or any other Employer, to the extent constituting such taxable income, shall be immediately distributed to the Participant or his or her Beneficiary. For purposes of this Section, the Internal Revenue Service shall be deemed to have prevailed in a claim if such claim is upheld by a court of final jurisdiction, or if the Participant or Beneficiary, based upon an opinion of legal counsel satisfactory to the Company and the Participant or his or her Beneficiary, fails to appeal a decision of the Internal Revenue Service, or a court of applicable jurisdiction, with respect to such claim, to an appropriate Internal Revenue Service appeals authority or to a court of higher jurisdiction within the appropriate time period.

11.16General Conditions. Except as otherwise expressly provided herein, all terms and conditions of the Basic Plan applicable to a Basic Plan benefit shall also be applicable to a benefit payable hereunder. Any Basic Plan benefit shall be paid solely in accordance with the terms and conditions of the Basic Plan and nothing in the Plan shall operate or be construed in any way to modify, amend or affect the terms and provisions of the Basic Plan.

[signature block follows on next page]

22

IN WITNESS WHEREOF, NiSource Inc. has caused this amended and restated Savings and Restoration Plan for NiSource Inc. and Affiliates to be executed in its name, by its duly authorized officer, effective as of August 10, 2017.

NISOURCE INC.

By:     _____________________

Its:     _____________________

Date:    _____________________

COLUMBUS/1597351v.12

23

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 September 30, 2018;

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:	November 1, 2018	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 September 30, 2018;

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:	November 1, 2018	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 September 30, 2018 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:	November 1, 2018

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 September 30, 2018 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:	November 1, 2018

XML

Document And Entity Information - shares	9 Months Ended
	Sep. 30, 2018	Oct. 23, 2018
Document Information [Line Items]
Document Type	10-Q
Amendment Flag	false
Entity Emerging Growth Company	false
Entity Small Business	false
Document Period End Date	Sep. 30, 2018
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	Q3
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		363,286,952

XML

Statements Of Consolidated Income - USD ($) shares in Thousands, $ in Millions	3 Months Ended			9 Months Ended
	Sep. 30, 2018		Sep. 30, 2017	Sep. 30, 2018		Sep. 30, 2017
Operating Revenues
Customer revenues	$ 855.8	[1]	$ 883.4	$ 3,555.1	[1]	$ 3,386.0
Other revenues	39.2		33.6	97.7		120.3
Total Operating Revenues	895.0		917.0	3,652.8		3,506.3
Operating Expenses
Cost of Sales (excluding depreciation and amortization)	222.0		233.6	1,259.7		1,062.7
Operation and maintenance	780.8		371.7	1,548.5		1,174.9
Depreciation and amortization	148.5		143.0	437.8		428.5
Loss (Gain) on sale of assets and impairments, net	0.7		0.0	0.4		(0.1)
Other taxes	58.9		57.5	203.3		189.7
Total Operating Expenses	1,210.9		805.8	3,449.7		2,855.7
Operating Income	(315.9)		111.2	203.1		650.6
Other Income (Deductions)
Interest expense, net	(83.4)		(87.9)	(265.2)		(260.8)
Other, net	(1.7)		(6.8)	42.4		(0.3)
Loss on early extinguishment of long-term debt	(33.0)		0.0	(45.5)		(111.5)
Total Other Deductions, Net	(118.1)		(94.7)	(268.3)		(372.6)
Income (Loss) before Income Taxes	(434.0)		16.5	(65.2)		278.0
Income Taxes	(94.5)		2.5	(26.3)		97.1
Net Income (Loss)	(339.5)		14.0	(38.9)		180.9
Preferred dividends	(5.6)		0.0	(6.9)		0.0
Net Income (Loss) Available to Common Shareholders	$ (345.1)		$ 14.0	$ (45.8)		$ 180.9
Earnings (Loss) Per Share
Basic Earnings (Loss) Per Share	$ (0.95)		$ 0.04	$ (0.13)		$ 0.55
Diluted Earnings (Loss) Per Share	(0.95)		0.04	(0.13)		0.55
Dividends Declared Per Common Share	$ 0.195		$ 0.175	$ 0.780		$ 0.700
Basic Average Common Shares Outstanding	363,900		331,139	352,115		326,662
Diluted Average Common Shares	363,900		332,396	352,115		328,031

[1] Customer revenue amounts exclude intersegment revenues. See Note 19, "Business Segment Information," for discussion of intersegment revenues.

XML

Statements of Consolidated Comprehensive Income (Loss) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Net Income (Loss)		$ (339.5)	$ 14.0	$ (38.9)	$ 180.9
Other comprehensive income (loss):
Net unrealized gain (loss) on available-for-sale securities	[1]	0.1	0.1	(2.3)	1.1
Net unrealized gain (loss) on cash flow hedges	[2]	22.5	(9.3)	56.5	(21.2)
Unrecognized pension and OPEB benefit	[3]	0.8	1.1	1.2	1.5
Total other comprehensive income (loss)	[4]	23.4	(8.1)	55.4	(18.6)
Comprehensive Income (Loss)		$ (316.1)	$ 5.9	$ 16.5	$ 162.3

[1] Net unrealized gain (loss) on available-for-sale securities, net of zero tax expense in the third quarter of 2018 and 2017, and $0.6 million tax benefit and $0.6 million tax expense for the nine months ended 2018 and 2017, respectively.

[2] Net unrealized gain (loss) on cash flow hedges, net of $7.5 million tax expense and $5.8 million tax benefit in the third quarter of 2018 and 2017, respectively, and $18.7 million tax expense and $13.1 million tax benefit for the nine months ended 2018 and 2017, respectively. See Note 8, "Risk Management Activities," for additional information.

[3] Unrecognized pension and OPEB benefit, net of zero and $0.5 million tax expense in the third quarter of 2018 and 2017, respectively, and $0.2 million and $0.8 million tax expense for the nine months ended 2018 and 2017, respectively.

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

XML

Statements of Consolidated Comprehensive Income (Loss) (Parenthetical) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Other Comprehensive Income (Loss), Securities, Available-for-Sale, Unrealized Holding Gain (Loss) Arising During Period, Tax	$ 0.0	$ 0.0	$ (0.6)	$ 0.6
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Tax	7.5	(5.8)	18.7	(13.1)
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, Tax	$ 0.0	$ (0.5)	$ (0.2)	$ (0.8)

XML

Statements of Consolidated Balance Sheets - USD ($) $ in Millions		Sep. 30, 2018	Dec. 31, 2017
Property, Plant and Equipment
Utility Plant		$ 22,328.2	$ 21,026.6
Accumulated depreciation and amortization		(7,171.0)	(6,953.6)
Net utility plant		15,157.2	14,073.0
Other property, at cost, less accumulated depreciation		17.2	286.5
Net Property, Plant and Equipment		15,174.4	14,359.5
Investments and Other Assets
Unconsolidated affiliates		2.6	5.5
Other investments		214.5	204.1
Total Investments and Other Assets		217.1	209.6
Current Assets
Cash and cash equivalents		41.8	29.0
Restricted Cash		12.0	9.4
Accounts receivable (less reserve of $13.0 and $18.3, respectively)		500.4	898.9
Gas inventory		320.2	285.1
Materials and supplies, at average cost		97.7	105.9
Electric production fuel, at average cost		49.0	80.1
Exchange gas receivable		37.3	45.8
Regulatory assets		221.0	176.3
Prepayments and other		89.7	132.8
Total Current Assets		1,369.1	1,763.3
Other Assets
Regulatory assets		1,907.4	1,624.9
Goodwill		1,690.7	1,690.7
Intangible assets, net		223.5	231.7
Deferred charges and other		117.2	82.0
Total Other Assets		3,938.8	3,629.3
Total Assets		20,699.4	19,961.7
Common Stockholders' Equity
Common stock - $0.01 par value, 400,000,000 shares authorized; 363,167,067 and 337,015,806 shares outstanding, respectively		3.7	3.4
Preferred stock - $1,000 par value, 20,000,000 shares authorized; 400,000 shares outstanding		393.9	0.0
Treasury stock		(99.9)	(95.9)
Additional paid-in capital		6,161.0	5,529.1
Retained deficit		(1,387.5)	(1,073.1)
Accumulated other comprehensive loss	[1]	2.5	(43.4)
Total Common Stockholders' Equity		5,073.7	4,320.1
Long-term debt, excluding amounts due within one year		7,094.5	7,512.2
Total Capitalization		12,168.2	11,832.3
Current Liabilities
Current portion of long-term debt		48.6	284.3
Short-term borrowings		1,611.0	1,205.7
Accounts payable		433.7	625.6
Dividends payable - common stock		70.8	0.0
Dividends payable - preferred stock		11.6	0.0
Customer deposits and credits		238.4	262.6
Taxes accrued		150.0	208.1
Interest accrued		108.0	112.3
Derivative Instruments and Hedges, Liabilities		4.8	43.2
Exchange gas payable		58.2	59.6
Regulatory liabilities		81.9	58.7
Legal and environmental		20.4	32.1
Accrued compensation and employee benefits		153.4	195.4
Accrued Insurance, Current		365.9	12.5
Other accruals		54.5	78.3
Total Current Liabilities		3,411.2	3,178.4
Other Liabilities and Deferred Credits
Risk management liabilities		45.2	28.5
Deferred income taxes		1,291.7	1,292.9
Deferred investment tax credits		11.7	12.4
Accrued insurance liabilities		81.8	80.1
Accrued liability for postretirement and postemployment benefits		300.9	337.1
Regulatory liabilities		2,826.8	2,736.9
Asset retirement obligations		346.9	268.7
Other noncurrent liabilities		215.0	194.4
Total Other Liabilities and Deferred Credits		5,120.0	4,951.0
Commitments and Contingencies		0.0	0.0
Total Capitalization and Liabilities		$ 20,699.4	$ 19,961.7

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

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Statements of Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Accounts receivable less reserve	$ 13.0	$ 18.3
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	400,000,000	400,000,000
Common Stock, Shares, Outstanding	363,167,067	337,015,806
Preferred Stock, Par or Stated Value Per Share	$ 1,000
Preferred Stock, Shares Authorized	20,000,000
Preferred Stock, Shares Outstanding	400,000

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Statements Of Consolidated Cash Flows - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Operating Activities
Net Income (Loss)	$ (38.9)	$ 180.9
Adjustments to Reconcile Net Income to Net Cash from Continuing Operations:
Loss on early extinguishment of debt	45.5	111.5
Depreciation and amortization	437.8	428.5
Deferred income taxes and investment tax credits	(26.4)	96.3
Other adjustments	15.6	28.5
Changes in Assets and Liabilities:
Components of working capital	442.9	32.6
Regulatory assets/liabilities	61.3	(12.9)
Postretirement and postemployment benefits	(41.4)	(314.5)
Deferred charges and other noncurrent assets	0.8	(3.7)
Other noncurrent liabilities	30.0	(17.6)
Net Cash Flows from Operating Activities	927.2	529.6
Investing Activities
Capital expenditures	(1,296.6)	(1,216.4)
Cost of removal	(72.6)	(78.9)
Purchases of available-for-sale securities	(71.4)	(139.4)
Sales of available-for-sale securities	58.5	129.4
Other investing activities	5.6	(1.4)
Net Cash Flows used for Investing Activities	(1,376.5)	(1,306.7)
Financing Activities
Issuance of long-term debt	350.0	2,750.0
Repayments of long-term debt and capital lease obligations	(1,044.0)	(1,352.4)
Premiums and other debt related costs	(46.1)	(139.8)
Issuance of short-term debt (maturity 90 days)	600.0	0.0
Change in short-term borrowings, net (maturity ≤ 90 days)	(194.6)	(644.9)
Issuance of common stock	611.6	332.6
Issuance of preferred stock	394.3	0.0
Acquisition of treasury stock	(4.0)	(5.9)
Dividends paid - common stock	(202.5)	(170.2)
Net Cash Flows from Financing Activities	464.7	769.4
Change in cash, cash equivalents and restricted cash	15.4	(7.7)
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	38.4	36.0
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	$ 53.8	$ 28.3

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Statements Of Consolidated Cash Flows (Supplemental Disclosures of Cash Flow Information) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2018		Sep. 30, 2017
Supplemental Cash Flow [Abstract]
Capital expenditures included in current liabilities	$ 167.5		$ 219.1
Dividends declared but not paid	82.4		58.9
Reclassification of other property to regulatory assets	245.3	[1]	0.0
Asset Retirement Obligation, Revision of Estimate	$ 70.7	[2]	$ 0.0

[1] See Note 16-D "Other Matters" for additional information.

[2] See Note 6 "Asset Retirement Obligations" for additional information.

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Statements Of Consolidated Equity - USD ($) $ in Millions		Total	Common Stock	Preferred Stock	Treasury Stock	Additional Paid-in Capital	Retained Deficit	Accumulated Other Comprehensive Loss
Cumulative Effect of New Accounting Principle in Period of Adoption | Accounting Standards Update 2018-02	[1]	$ 0.0	$ 0.0	$ 0.0	$ 0.0	$ 0.0	$ 9.5	$ (9.5)
Balance as of January 1, 2017 at Dec. 31, 2017		4,320.1	3.4	0.0	(95.9)	5,529.1	(1,073.1)	(43.4)
Net Loss		(38.9)	0.0	0.0	0.0	0.0	(38.9)	0.0
Other comprehensive income, net of tax		55.4	0.0	0.0	0.0	0.0	0.0	55.4
Common stock dividends ($0.78 per share)		(273.4)	0.0	0.0	0.0	0.0	(273.4)	0.0
Preferred stock dividends ($28.88 per share)		(11.6)	0.0	0.0	0.0	0.0	(11.6)	0.0
Treasury stock acquired		(4.0)	0.0	0.0	(4.0)	0.0	0.0	0.0
Stock Issuances:
Common stock - private placement	[2]	599.6	0.3	0.0	0.0	599.3	0.0	0.0
Preferred stock	[2]	393.9	0.0	393.9	0.0	0.0	0.0	0.0
Employee stock purchase plan		4.2	0.0	0.0	0.0	4.2	0.0	0.0
Long-term incentive plan		11.5	0.0	0.0	0.0	11.5	0.0	0.0
401(k) and profit sharing		16.9	0.0	0.0	0.0	16.9	0.0	0.0
Balance as of September 30, 2018 at Sep. 30, 2018		$ 5,073.7	$ 3.7	$ 393.9	$ (99.9)	$ 6,161.0	$ (1,387.5)	$ 2.5

[1] See Note 2, "Recent Accounting Pronouncements," for additional information.

[2] See Note 5, "Equity," for additional information.

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Statements of Consolidated Equity (Shares) (Parenthetical) shares in Thousands	9 Months Ended
	Sep. 30, 2018 shares
Balance as of January 1, 2018	337,016
Treasury Stock acquired	(166)
Issued:
Stock Issued During Period, Shares, New Issues	24,964	[1]
Employee stock purchase plan	166
Long-term incentive plan	499
401(k) and profit sharing	688
Balance as of September 30, 2018	363,167
Preferred Stock
Balance as of January 1, 2018	0
Issued:
Stock Issued During Period, Shares, New Issues	400	[1]
Employee stock purchase plan	0
Long-term incentive plan	0
401(k) and profit sharing	0
Balance as of September 30, 2018	400
Common Stock
Balance as of January 1, 2018	340,813
Issued:
Stock Issued During Period, Shares, New Issues	24,964	[1]
Employee stock purchase plan	166
Long-term incentive plan	499
401(k) and profit sharing	688
Balance as of September 30, 2018	367,130
Treasury Stock
Balance as of January 1, 2018	(3,797)
Treasury Stock acquired	(166)
Issued:
Stock Issued During Period, Shares, New Issues	0	[1]
Employee stock purchase plan	0
Long-term incentive plan	0
401(k) and profit sharing	0
Balance as of September 30, 2018	3,963

[1] See Note 5, "Equity," for additional information.

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Statements Of Consolidated Equity (Parenthetical)	9 Months Ended
	Sep. 30, 2018 $ / shares
Dividends Declared Per Share - Common	$ 0.780
Dividends Declared Per Share - Preferred	$ 28.88

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Basis of Accounting Presentation

9 Months Ended

Sep. 30, 2018

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, 2017. 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.

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Recent Accounting Pronouncements

9 Months Ended

Sep. 30, 2018

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

Standard	Description	Effective Date	Effect on the financial statements or other significant matters
ASU 2018-11, Leases (Topic 842): Targeted Improvements	The pronouncement allows entities the option to initially apply ASC 842 at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption.	Annual periods beginning after December 15, 2018, including interim periods therein. Early adoption is permitted.	We are the lessee for substantially all of our current leasing activity. Upon adopting ASC 842 we will begin recognizing right-of-use assets and liabilities associated with operating leases (other than short term operating leases) on our Condensed Consolidated Balance Sheets (unaudited). The impact of this change on the balance sheet is not reasonably estimable at this time. We do not anticipate the adoption of ASC 842 will have a material impact to our results of operations or cash flows. We have undertaken efforts to outline mock footnote disclosures intended to satisfy ASC 842’s disclosure requirements, which will enhance our disclosures on lease accounting policies and elections. We are implementing a new lease accounting system, which we will utilize to capture, track, and account for lease data. The new system will also aid in automating the compilation of disclosure information. We expect to conclude final system tests in the fourth quarter of 2018, with full system implementation prior to the effective date of these standards. 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 currently anticipate adopting this practical expedient for certain classes of leases. Further, we will elect the "practical expedient package" described in ASC 842-10-65-1. We maintain a substantial number of easements and will also elect the provisions of ASU 2018-01 to ease the process of implementing ASC 842. Lastly, we anticipate electing the transition method provided in ASU 2018-11 when we adopt these standards effective January 1, 2019.
ASU 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842	The pronouncement offers a practical expedient for accounting for land easements under ASU 2016-02. This practical expedient allows an entity the option of not evaluating existing land easements under ASC 842. New or modified land easements will still require evaluation under ASC 842 on a prospective basis beginning on the date of adoption.
ASU 2016-02, Leases (Topic 842)	The pronouncement introduces a lessee model that brings most leases on 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.

Recently Adopted Accounting Pronouncements

Standard	Adoption
ASU 2018-15, Intangibles—Goodwill and Other— Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract	In August 2018, the FASB issued this ASU, which amends current guidance to align the accounting for costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing costs associated with developing or obtaining internal-use software. We elected to early adopt the ASU on a prospective basis, effective October 1, 2018. As a result of adopting this ASU, we will defer onto the balance sheet those up-front implementation costs of cloud computing arrangements if they would have been capitalized in a similar on-premise software solution.
ASU 2018-02, Income Statement—Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income	We adopted this ASU effective March 31, 2018. Upon adoption, $9.5 million of tax effects that were stranded in accumulated other comprehensive income (loss) as a result of the implementation of the TCJA were reclassified to retained deficit. This change is reflected on our Condensed Statements of Consolidated Equity (unaudited).
ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force)	We adopted this ASU effective January 1, 2018. The adoption of this standard did not have a material impact on our Condensed Consolidated Financial Statements (unaudited) or Notes to Condensed Consolidated Financial Statements (unaudited).
ASU 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients	See Note 3, "Revenue Recognition," for our discussion of the effects of implementing these standards.
ASU 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations
ASU 2014-09, Revenue from Contracts with Customers (Topic 606)

We also adopted ASU 2017-07, Compensation -  Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, effective January 1, 2018. We continue to present the service cost component of net periodic benefit cost within "Operation and maintenance;" however, other components of the net periodic benefit cost (including regulatory deferrals and settlement charges) are now presented separately within "Other, net" on our Condensed Statements of Consolidated Income (Loss) (unaudited).

Changes in income statement presentation were implemented on a retrospective basis. The impact of this ASU on previously issued annual financial statements is summarized in the tables below:

Year Ended December 31, 2016 (in millions)	As Previously Reported			Effect of Change(1)			As Adjusted
Operation and maintenance	$	1,453.7		$	(7.9	)	$	1,445.8
Total Operating Expenses	3,634.3			(7.9		)	3,626.4
Operating Income	858.2			7.9			866.1
Other Income (Deductions)
Other, net	1.5			(7.9		)	(6.4		)
Total Other Deductions	(348.0		)	(7.9		)	(355.9		)
Income before Income Taxes	$	510.2		$	—		$	510.2

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

Year Ended December 31, 2017 (in millions)	As Previously Reported			Effect of Change(1)			As Adjusted
Operation and maintenance	$	1,612.3		$	(10.6	)	$	1,601.7
Total Operating Expenses	3,964.0			(10.6		)	3,953.4
Operating Income	910.6			10.6			921.2
Other Income (Deductions)
Other, net	(2.8		)	(10.6		)	(13.4		)
Total Other Deductions	(467.5		)	(10.6		)	(478.1		)
Income before Income Taxes	$	443.1		$	—		$	443.1

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

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Revenue Recognition

9 Months Ended

Sep. 30, 2018

Revenue from Contract with Customer [Abstract]

Revenue from Contract with Customer

Revenue Recognition

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

The table below provides results for the three and nine months ended September 30, 2018 as if they had been prepared under historic accounting guidance. We included operating revenue information for the three and nine months ended September 30, 2017 for comparability.

	Three Months Ended September 30,				Nine Months Ended September 30,
(in millions)	2018		2017		2018		2017
Operating Revenues
Gas Distribution	$	232.3	$	239.4	$	1,600.3	$	1,403.0
Gas Transportation	186.0		191.6		745.2		735.1
Electric	476.2		485.8		1,304.4		1,365.5
Other	0.5		0.2		2.9		2.7
Total Operating Revenues	$	895.0	$	917.0	$	3,652.8	$	3,506.3

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

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

We have identified our performance obligations created under tariff-based sales as 1) the commodity (natural gas or electricity, which includes generation and capacity) and 2) delivery. These commodities are sold and / or delivered to and generally consumed by customers simultaneously, leading to satisfaction of our performance obligations over time as gas or electricity is delivered to customers. Due to the at-will nature of utility customers, performance obligations are limited to the services requested and received to date. Once complete, we generally maintain no additional performance obligations.

Transaction prices for each performance obligation are generally prescribed by each operating company’s respective tariff. Rates include provisions to adjust billings for fluctuations in fuel and purchased power costs and cost of natural gas. Revenues are adjusted for differences between actual costs subject to reconciliation and the amounts billed in current rates. Under or over recovered revenues related to these cost recovery mechanisms are included in regulatory assets or liabilities on the Condensed Consolidated Balance Sheets (unaudited) and are recovered from or returned to customers through adjustments to tariff rates. As we provide and deliver service to customers, revenue is recognized based on the transaction price allocated to each performance obligation. In general, revenue recognized from tariff-based sales is equivalent to the value of natural gas or electricity supplied and billed each period, in addition to an estimate for deliveries completed during the period but not yet billed to the customer.

In addition to tariff-based sales, our Gas Distribution Operations segment enters into balancing and exchange arrangements of natural gas as part of our operations and off-system sales programs. We have concluded that these sales are within the scope of ASC 606. Performance obligations for these types of sales include transportation and storage of natural gas and can be satisfied at a point in time or over a period of time, depending on the specific transaction. For those transactions that span a period of time, we record a receivable or payable for any cumulative gas imbalances, as well as for any gas inventory borrowed or lent under a Gas Distributions Operations exchange agreement.

Revenue Disaggregation and Reconciliation. We disaggregate revenue from contracts with customers based upon reportable segment as well as by customer class. As our revenues are primarily earned over a period of time, and we do not earn a material amount of revenues at a point in time, revenues are not disaggregated as such below. The Gas Distribution Operations segment provides natural gas service and transportation for residential, commercial and industrial customers in Ohio, Pennsylvania, Virginia, Kentucky, Maryland, Indiana and Massachusetts. The Electric Operations segment provides electric service in 20 counties in the northern part of Indiana.

The table below reconciles revenue disaggregation by customer class to segment revenue as well as to revenues reflected on the Condensed Statements of Consolidated Income (Loss) (unaudited):

Three Months Ended September 30, 2018 (in millions)	Gas Distribution Operations		Electric Operations		Corporate and Other		Total
Customer Revenues(1)
Residential	$	257.0	$	154.7	$	—	$	411.7
Commercial	80.9		140.7		—		221.6
Industrial	39.0		153.6		—		192.6
Off-system	20.4		—		—		20.4
Miscellaneous	9.2		0.1		0.2		9.5
Total Customer Revenues	$	406.5	$	449.1	$	0.2	$	855.8
Other Revenues	12.1		27.1		—		39.2
Total Operating Revenues	$	418.6	$	476.2	$	0.2	$	895.0

⁽¹⁾ Customer revenue amounts exclude intersegment revenues. See Note 19, "Business Segment Information," for discussion of intersegment revenues.

Nine Months Ended September 30, 2018 (in millions)	Gas Distribution Operations		Electric Operations		Corporate and Other		Total
Customer Revenues(1)
Residential	$	1,540.3	$	382.3	$	—	$	1,922.6
Commercial	516.2		374.2		—		890.4
Industrial	161.3		468.1		—		629.4
Off-system	63.6		—		—		63.6
Miscellaneous	36.2		12.3		0.6		49.1
Total Customer Revenues	$	2,317.6	$	1,236.9	$	0.6	$	3,555.1
Other Revenues	30.2		67.5		—		97.7
Total Operating Revenues	$	2,347.8	$	1,304.4	$	0.6	$	3,652.8

⁽¹⁾ Customer revenue amounts exclude intersegment revenues. See Note 19, "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 nine months endedSeptember 30, 2018 are presented in the table below. We had no significant contract assets or liabilities during the period. Additionally, we have not incurred any significant costs to obtain or fulfill contracts.

(in millions)	Customer Accounts Receivable, Billed (less reserve)(1)			Customer Accounts Receivable, Unbilled (less reserve)(2)
Balance as of December 31, 2017	$	477.0		$	356.0
Balance as of September 30, 2018	297.2			154.8
Increase (Decrease)	$	(179.8	)	$	(201.2	)

⁽¹⁾ Customer billed receivables decreased over the period due to the expected seasonal decrease in customer usage in September when compared to December.

⁽²⁾ Customer unbilled receivables decreased over the period due to the expected seasonal decrease in customer usage in September when compared to December.

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

Other Revenues. As permitted by accounting principles generally accepted in the United States, regulated utilities have the ability to earn certain types of revenue that are outside the scope of ASC 606. These revenues primarily represent revenue earned under Alternative Revenue Programs. Alternative Revenue Programs represent regulator-approved programs that allow for the adjustment of billings and revenue for certain broad, external factors, or for additional billings if the entity achieves certain objectives, such as a specified reduction of costs. We maintain a variety of these programs, including demand side management initiatives that recover costs associated with the implementation of energy efficiency programs, as well as normalization programs that adjust revenues for the effects of weather or other external factors. Additionally, we maintain certain programs with future test periods that operate similarly to FERC formula rate programs and allow for recovery of costs incurred to replace aging infrastructure. When the criteria to recognize Alternative Revenue have been met, we establish a regulatory asset and present revenue from Alternative Revenue Programs on the Condensed Statements of Consolidated Income (Loss) (unaudited) as “Other revenues.” When amounts previously recognized under Alternative Revenue accounting guidance are billed, we reduce the regulatory asset and record a customer account receivable.

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Earnings Per Share

9 Months Ended

Sep. 30, 2018

Earnings Per Share [Abstract]

Earnings Per Share

Earnings Per Share

Basic EPS is computed by dividing net income available 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. The computation of diluted average common shares for the three and nine months ended September 30, 2018 is not presented since we had a net loss on the Condensed Statements of Consolidated Income (Loss) (unaudited) during the periods, and any incremental shares would have had an anti-dilutive impact on EPS. The computation of diluted average common shares is as follows:

	Three Months Ended	Nine Months Ended
	September 30,	September 30,
(in thousands)	2017	2017
Denominator
Basic average common shares outstanding	331,139	326,662
Dilutive potential common shares:
Shares contingently issuable under employee stock plans	604	503
Shares restricted under employee stock plans	653	866
Diluted Average Common Shares	332,396	328,031

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Equity

9 Months Ended

Sep. 30, 2018

Equity [Abstract]

Equity

Equity

ATM Program and Forward Sale Agreement. On May 3, 2017, we entered into four separate equity distribution agreements, pursuant to which we may sell, from time to time, up to an aggregate of $500.0 million of our common stock. As of September 30, 2018, the ATM program (including impacts of forward sales agreements discussed below) had $10.0 million of equity available for issuance. The program expires on December 31, 2018. The following table summarizes our activity under the ATM Program:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
Number of shares issued	—		10,612,915		—		11,931,376
Average price per share	$	—	$	26.67	$	—	$	26.58
Proceeds, net of fees (in millions)	$	—	$	281.0	$	—	$	314.7

On November 13, 2017, 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 November 13, 2017 to December 8, 2017, 6,345,860 shares were borrowed from third parties and sold by the dealer at a weighted average price of $27.24 per share. We may settle this agreement in shares, cash, or net shares by November 12, 2018. Had we settled all 6,345,860 shares under the forward agreement at September 30, 2018, we would have received approximately $168.7 million, based on a net price of $26.59 per share.

Private Placement of Common Stock. On May 4, 2018, we completed the sale of 24,964,163 shares of $0.01 par value common stock at a price of $24.28 per share in a private placement to selected institutional and accredited investors. The private placement resulted in $606.0 million of gross proceeds or $599.6 million of net proceeds, after deducting commissions and sale expenses. The common stock issued in connection with the private placement was registered on Form S-1, filed with the SEC on May 11, 2018.

Private Placement of Preferred Stock. On June 11, 2018, we completed the sale of 400,000 shares of 5.650% Series A Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Stock (the "Series A Preferred Stock") at a price of $1,000 per share. The transaction resulted in $400.0 million of gross proceeds or $393.9 million of net proceeds, after deducting commissions and sales expenses. The Series A Preferred Stock was issued in a private placement pursuant to SEC Rule 144A. We agreed pursuant to a registration rights agreement to file with the SEC a registration statement enabling holders to exchange their unregistered shares of Series A Preferred Stock for publicly registered shares with substantially identical terms.

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

Dividends on the Series A Preferred Stock accrue and are cumulative from the date the shares of Series A Preferred Stock were originally issued to, but not including, June 15, 2023 at a rate of 5.650% per annum of the $1,000 liquidation preference per share. On and after June 15, 2023, dividends on the Series A Preferred Stock will accumulate for each five year period at a percentage of the $1,000 liquidation preference equal to the five-year U.S. Treasury Rate plus (i) in respect of each five year period commencing on or after June 15, 2023 but before June 15, 2043, a spread of 2.843% (the “Initial Margin”), and (ii) in respect of each five year period commencing on or after June 15, 2043, the Initial Margin plus 1.000%. The Series A Preferred Stock may be redeemed by us at our option on June 15, 2023, or on each date falling on the fifth anniversary thereafter, or in connection with a ratings event (as defined in the Certificate of Designation of the Series A Preferred Stock).

Holders of Series A Preferred Stock generally have no voting rights, except for limited voting rights with respect to (i) potential amendments to our certificate of incorporation that would have a material adverse effect on the existing preferences, rights, powers or duties of the Series A Preferred Stock, (ii) the creation or issuance of any security ranking on a parity with the Series A Preferred Stock if the cumulative dividends payable on then outstanding Series A Preferred Stock are in arrears, or (iii) the creation or issuance of any security ranking senior to the Series A Preferred Stock. The Series A Preferred Stock does not have a stated maturity and is not subject to mandatory redemption or any sinking fund. The Series A Preferred Stock will remain outstanding indefinitely unless repurchased or redeemed by us. Any such redemption would be effected only out of funds legally available for such purposes and will be subject to compliance with the provisions of our outstanding indebtedness.

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Asset Retirement Obligations

9 Months Ended

Sep. 30, 2018

Asset Retirement Obligations [Abstract]

Asset Retirement Obligation Disclosure [Text Block]

Asset Retirement Obligations

During 2018, we made revisions to the estimated costs associated with refining the CCR compliance plan. The CCR rule requires the continued collection of data over time to determine the specific compliance solution. The change in estimated costs resulted in an increase to the asset retirement obligation liability of $70.7 million that was recorded in 2018. See Note 16-C, "Environmental Matters," for additional information on CCRs.

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Regulatory Matters

9 Months Ended

Sep. 30, 2018

Regulatory Assets and Liabilities Disclosure [Abstract]

Regulatory Matters

Regulatory Matters

Gas Distribution Operations Regulatory Matters

Cost Recovery and Trackers. Comparability of Gas Distribution Operations 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 operating costs of our distribution companies are significant, recurring in nature and generally outside the control of the distribution 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 distribution 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 and bad debt recovery mechanisms.

A portion of the distribution companies' 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.

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

Columbia of Ohio. On January 10, 2018, the PUCO issued an entry to investigate the impacts of the TCJA including an invitation to utilities and other interested stakeholders to file public comments including: (1) those components of utility rates that the PUCO will need to reconcile with the TCJA; and (2) the process and mechanics for how the PUCO should do so. The PUCO also directed utilities to record a regulatory liability for the estimated reduction in federal income tax resulting from the TCJA. On February 15, 2018, Columbia of Ohio filed comments proposing to: (1) reflect the impact of the TCJA on its application to adjust rates associated with its IRP rider, subsequently filed on February 27, 2018; and (2) file a reduction in other base rates reflecting the impact of the TCJA. The PUCO issued a procedural schedule on May 24, 2018 and a hearing was held on July 10, 2018. As discussed in further detail below, on October 25, 2018, Columbia of Ohio filed a joint stipulation and recommendation with the PUCO related to its CEP. Included in that stipulation were terms that would serve to resolve all remaining TCJA-related considerations for Columbia of Ohio.

On January 31, 2018, the PUCO approved Columbia of Ohio’s application to extend its IRP for an additional five years (2018-2022), allowing Columbia of Ohio to continue to invest and recover on its accelerated main replacements. The Office of the Ohio Consumers’ Counsel filed an application for rehearing asserting certain issues with Columbia of Ohio's application. On May 9, 2018, the PUCO issued an order denying the application for rehearing.

As referred to above, Columbia of Ohio filed its most recent application to adjust rates associated with its IRP rider on February 27, 2018, which requested authority to increase annual billings by approximately $2.3 million (net of the impact of the TCJA) reflecting recovery of and return on approximately $207 million of incremental IRP capital additions in 2017. A stipulation was filed with the PUCO on March 28, 2018. On April 25, 2018, the PUCO approved Columbia of Ohio’s annual IRP tracker adjustment with rates effective May 1, 2018.

On December 1, 2017, Columbia of Ohio filed an application that requested authority to implement a rider to begin recovering plant and associated deferrals related to its CEP. The CEP was established in 2011 and allows for deferral of interest, depreciation and property taxes on certain plant investments not recovered through its IRP modernization tracker. The application requested authority to increase annual revenues, through the requested rider, by approximately $70 million, with biennial increases up to approximately $98 million in 2022. On May 9, 2018, the PUCO appointed an independent auditor to assist the PUCO with the review of the accounting accuracy, prudency and compliance of Columbia of Ohio with its PUCO-approved CEP deferrals. The independent audit report was filed on September 4, 2018 and the PUCO Staff's Report on the investigation was filed on September 14, 2018. On October 25, 2018, a joint stipulation and recommendation was filed recommending an initial revenue requirement of $74.5 million to recover CEP investments and deferrals through December 31, 2017, with annual adjustments for capital investments made in subsequent years. Additionally, the signatory parties to the stipulation agreed to a reduction in rates to adjust for the impacts of the TCJA and for a base rate case filing to be made by Columbia of Ohio with a test period of calendar year 2021. A hearing on the stipulation is expected to occur on November 6, 2018.

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

On September 27, 2017, NIPSCO filed a base rate case with the IURC, seeking an annual revenue increase of $143.5 million (inclusive of amounts being recovered through various tracker programs). As part of this filing and among other items, NIPSCO proposed to update base rates for ongoing infrastructure improvements, revised depreciation rates and ongoing level of expenses to reflect the current costs of providing natural gas service. NIPSCO submitted a rebuttal on March 28, 2018 updating its request, including the impact of the TCJA, seeking a revised annual revenue increase of $138.1 million. On April 20, 2018, a settlement agreement was filed with the IURC seeking, among other items, an annual revenue increase of $107.3 million. An order approving the settlement agreement, as filed, was issued by the IURC on September 19, 2018. Rates will be implemented in three steps, with implementation of step 1 rates effective October 1, 2018, reflecting an annual revenue increase of $84.3 million. Step 2 rates will be effective on or about March 1, 2019, and step 3 rates will be effective on January 1, 2020. The IURC’s order also approved NIPSCO’s dismissal from phase 2 of the IURC’s TCJA investigation.

On November 8, 2017, NIPSCO filed a petition with the IURC seeking approval of NIPSCO’s federally mandated pipeline safety compliance plan. As part of the aforementioned settlement agreement filed in NIPSCO’s gas base rate case proceeding, NIPSCO and the parties to the settlement agreement settled all issues in this proceeding as well, including moving certain costs from the base rate proceeding to this pipeline safety compliance plan. The updated four year compliance plan includes a total estimated $91.5 million of capital costs and $35.5 million of expected operating and maintenance costs. NIPSCO received approval for accounting and ratemaking relief, including establishment of a periodic rate adjustment mechanism. NIPSCO anticipates filing the first tracker proceeding in this case on or around December 1, 2018.

On April 30, 2013, the Governor of Indiana signed Senate Enrolled Act 560, the TDSIC statute, into law. Among other provisions, this legislation provides for cost recovery outside of a base rate proceeding for new or replacement electric and gas transmission, distribution and storage projects that a public utility undertakes for the purposes of safety, reliability, system modernization or economic development. Provisions of the TDSIC statute require that, among other things, requests for recovery include a seven-year plan of eligible investments. Once the plan is approved by the IURC, eighty percent of eligible costs can be recovered using a periodic rate adjustment mechanism. The cost recovery mechanism is referred to as a TDSIC mechanism. Recoverable costs include a return on, and of, the investment, including AFUDC, post-in-service carrying charges, operation and maintenance expenses, depreciation and property taxes. The remaining twenty percent of recoverable costs are to be deferred for future recovery in the public utility’s next general rate case. The periodic rate adjustment mechanism is capped at an annual increase of no more than two percent of total retail revenues. On April 2, 2018, NIPSCO filed a new seven-year gas TDSIC plan with the IURC beginning in 2019 seeking approval of a total capital expenditure level of approximately $1.25 billion. On September 4, 2018, the IURC dismissed the filing without prejudice. The initial seven-year gas TDSIC plan, approving a total capital expenditure level of approximately $767 million remains in effect as approved by the IURC in April 2014. A new seven-year gas TDSIC plan may be filed with IURC once the considerations in the pending TDSIC tracker appeal discussed below are resolved.

On February 27, 2018, NIPSCO filed TDSIC-8 requesting to recover an incremental increase to revenue of $0.8 million (net of the impacts of TCJA) associated with incremental capital investment of $77.9 million made in the second half of 2017. On June 20, 2018, the Indiana Supreme Court issued an order reversing the IURC and the Court of Appeals in NIPSCO’s gas TDSIC-4 proceeding. The Indiana Supreme Court order stated that periodic rate increases are available only for specific projects designated in the threshold proceeding and multiple-unit-projects not identified with particularity are not recoverable through the tracker. In the second quarter of 2018, NIPSCO recorded a liability of $2.5 million associated with the TDSIC-4 through TDSIC-8 filings for a related passback of revenue previously billed to customers. A revised TDSIC-8 was filed on July 18, 2018 and reduced the previous February 27, 2018 request by $0.2 million associated with incremental capital investment of approximately $54 million. On August 22, 2018, the IURC issued an order approving the requested rates, subject to refund. On August 28, 2018, NIPSCO filed TDSIC-9 requesting an incremental decrease to revenue of $0.5 million associated with incremental capital investment of $72.9 million through June 30, 2018. The filing included the pass back of the revenue associated with multiple-unit-projects from prior TDSIC filings and the pass back of TCJA revenues of $7.1 million for associated tax expense collected from January 1, 2018 through April 30, 2018. On September 26, 2018, NIPSCO filed a revised TDSIC-9 decreasing the requested revenue amount by an additional $7.6 million to reflect assets being included in the base rate amounts for the step 1 rate implementation discussed above. An IURC order is expected in the fourth quarter of 2018.

Columbia of Massachusetts. On February 2, 2018, the Massachusetts DPU opened an investigation into the effect of the reduction in federal income tax rates on the rates charged by utility companies. Columbia of Massachusetts was directed to account for any revenues associated with the difference between previous and current income tax rates and excess deferred income taxes as regulatory liabilities effective January 1, 2018. Companies were ordered to submit a proposal to revise rates by May 1, 2018. The order indicates that if a company files a base rate case prior to the conclusion of the investigation, it must address the TCJA issues as part of the case. Since CMA filed a base rate case on April 13, 2018, the changes in base rates and the regulatory liability disposition related to the TCJA are reflected in the case. On June 29, 2018, the Massachusetts DPU required companies in a rate case to reduce rates as of July 1, 2018 or, in the alternative, defer this rate reduction to coincide with the effective date of new rates in a rate case, provided that tax savings from July 1, 2018 through the effective date of new rates accrue interest at prime rate. On July 2, 2018, Columbia of Massachusetts filed tariffs reflecting revised rates incorporating the lower federal corporate income tax rate for effect July 1, 2018. In the filing, Columbia of Massachusetts noted the Massachusetts DPU stated it would address the refund of any tax savings accrued from January 1, 2018, through June 30, 2018, in a separate phase of its investigation. On July 10, 2018, the Massachusetts DPU approved the tariffs effective July 1, 2018, finding the adjustment is in the public interest, as it provides an immediate benefit to ratepayers.

As noted above, on April 13, 2018, Columbia of Massachusetts filed a rate case with the Massachusetts DPU, seeking approval for an annual revenue increase of approximately $43.8 million which is offset by revenue decreases in other rate factors of $19.7 million, representing a net increase in operating revenues of $24.1 million. Included in the filing was a proposal to adjust rates and address the regulatory liability disposition related to the TCJA. As a result of the incident that occurred on September 13, 2018, involving a series of fires and explosions that occurred in Lawrence, Andover and North Andover, Massachusetts related to the delivery of natural gas by Columbia of Massachusetts (the “Greater Lawrence Incident”), Columbia of Massachusetts filed a motion with the Massachusetts DPU on September 19, 2018, seeking to withdraw its petition for a base rate revenue increase in the interest of focusing its efforts on the on-going service restoration and customer assistance in the area. Refer to Note 16, "Other Commitments and Contingencies," in the Notes to Condensed Consolidated Financial Statements (unaudited) for additional information regarding the Greater Lawrence Incident. On October 9, 2018, Columbia of Massachusetts filed an application with the Massachusetts DPU, seeking authority to pass back approximately $95.8 million in excess deferred taxes with an effective date of rates to be determined by the Massachusetts DPU.

On July 7, 2014, the Governor of Massachusetts signed into law Chapter 149 of the Acts of 2014, An Act Relative to Natural Gas Leaks (“the Act”). The Act authorizes natural gas distribution companies to file gas infrastructure replacement plans with the Massachusetts DPU to address the replacement of aging natural gas pipeline infrastructure. In addition, the Act provides that the Massachusetts DPU may, after review of the plans, allow the proposed estimated costs of the plan into rates as of May 1 of the subsequent year. On October 31, 2017, Columbia of Massachusetts filed its GSEP for the 2018 construction year which proposed to recover incremental revenue of $9.7 million associated with incremental capital investment of $83.9 million to be made during calendar year 2018. The filing included a request for approval of a waiver to allow collection of the $3.1 million revenue requirement that exceeds the GSEP cap provision. On January 29, 2018, Columbia of Massachusetts filed a revision to its GSEP tracker for the 2018 construction season reducing the proposed revenue requirement by $2.4 million to reflect the impact of the TCJA. On June 21, 2018, the Massachusetts DPU issued an order granting the waiver on the revenue cap allowing an incremental revenue requirement of $6.5 million with new rates effective July 1, 2018. On October 31, 2018, Columbia of Massachusetts filed its GSEP for the 2019 construction year, proposing to recover an incremental revenue requirement of $10.7 million associated with incremental capital of $64.0 million. The filing included a request for approval of a waiver to allow collection of the $2.9 million revenue requirement that exceeds the GSEP cap provision. An order is expected from the Massachusetts DPU in the second quarter of 2019, with new rates effective May 1, 2019.

Columbia of Pennsylvania. On February 12, 2018, the Pennsylvania PUC established a docket to investigate the impact of the TCJA on customer rates. The Pennsylvania PUC directed Pennsylvania utilities to account for any revenues associated with the difference between previous and current income tax rates and excess deferred taxes as regulatory liabilities effective January 1, 2018. On May 17, 2018, the Pennsylvania PUC issued an order directing utilities that do not have a pending rate case to implement a negative surcharge in their billings to reflect the annual reduction in federal tax expense and associated revenue requirement for each utility, effective July 1, 2018.

On March 16, 2018, Columbia of Pennsylvania filed a rate case with the Pennsylvania PUC, incorporating the impacts of the TCJA and seeking approval for an annual revenue increase of $46.9 million. On March 21, 2018, Columbia of Pennsylvania filed a supplement to the rate case, under which it proposed to hold the overcollection of taxes during 2018 until the effective date of new base rates as credit to rate base for a period beginning January 2019 not to exceed three years. On August 31, 2018 a partial settlement was filed with the Pennsylvania PUC which included a revenue increase of $26.0 million and provided for the TCJA federal tax expense reduction of $22.5 million to be returned to customers over an 18 month period beginning December 16, 2018. On September 18, 2018 the administrative law judge issued a recommended decision approving the partial settlement without modification. A final order is expected in the fourth quarter of 2018 with new rates anticipated to be implemented in December 2018.

Columbia of Virginia. On January 8, 2018, the VSCC issued an order regarding the TCJA requiring Columbia of Virginia and other Virginia utilities subject to the TCJA to accrue regulatory liabilities reflecting the impacts of the reduced corporate income tax rate effective January 1, 2018. On August 28, 2018 Columbia of Virginia filed a request with the VSCC requesting a $22.2 million increase in base rates. The filing seeks to recover costs associated with ongoing infrastructure investment programs and incorporates the impacts of the TCJA. Columbia of Virginia proposed that the TCJA regulatory liability associated with lower federal income tax expense accrued prior to the implementation of new rates be considered in future VSCC reviews that assess earnings for the associated time period. Rates will be implemented on an interim basis, subject to refund, effective February 1, 2019, with a final order expected from the VSCC in the second half of 2019.

Columbia of Kentucky. On January 26, 2018, in accordance with the Kentucky PSC investigation related to the TCJA, Columbia of Kentucky filed testimony and proposed a reduction to base rates effective May 1, 2018, to reflect the tax expense reduction as a result of the TCJA. Columbia of Kentucky was directed to account for any revenues associated with the difference between previous and current income tax rates and excess deferred taxes as regulatory liabilities effective January 1, 2018. Columbia of Kentucky proposed to include the impact of the excess deferred taxes in rates effective October 2018 and to return the revenue related to the regulatory liability subsequent to this date. On April 30, 2018 Columbia of Kentucky received an order from the Kentucky PSC requiring implementation of interim proposed rates that are subject to future adjustment effective May 1, 2018. The order directed Columbia of Kentucky to file, by September 1, 2018, revised TCJA adjustment factors reflecting the tax expense savings from January 1, 2018, through April 30, 2018, and an estimate of the annual reduction due to the excess deferred taxes to be effective with the first billing cycle of October 2018. On August 31, 2018, Columbia of Kentucky filed updated rate schedules with the Kentucky PSC for rates proposed to be effective October 1, 2018. On September 27, 2018, Columbia of Kentucky received a PSC order suspending the filing for five months. No procedural time line beyond the five month suspension period has been set.

On October 15, 2018, Columbia of Kentucky filed an application to adjust rates associated with its AMRP, requesting authority to increase annual revenues by $3.6 million associated with incremental capital investment of $30.1 million to be made during calendar year 2019. An order is anticipated from the Kentucky PSC in December 2018, with new rates effective January 2019.

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

On April 13, 2018, Columbia of Maryland filed a request with the Maryland PSC to increase base rates by $6.1 million, inclusive of the impacts of the TCJA. On July 31, 2018, Columbia of Maryland filed a settlement with the Maryland PSC. If approved as filed, the settlement would result in an annual revenue increase of $3.7 million. On October 2, 2018, the assigned judge issued a proposed order which recommended that the settlement be approved. A final order from the Maryland PSC is expected in the fourth quarter of 2018 with rates anticipated to be effective November 2018.

On April 6, 2018, Columbia of Maryland filed an application requesting authority to extend its STRIDE plan for an additional five years (2019-2023). The proposed order issued on August 28, 2018 was not appealed or modified and therefore it became final on September 28, 2018.

Electric Operations Regulatory Matters

Cost Recovery and Trackers. Comparability of Electric Operations 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 result in a corresponding increase in operating revenues and therefore have essentially no impact on total operating income results.

Certain operating costs of the Electric Operations are significant, recurring in nature, and generally outside the control of NIPSCO. The IURC allows for recovery of such costs through cost tracking mechanisms. Such tracking mechanisms allow for abbreviated regulatory proceedings in order for NIPSCO 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 electric energy efficiency programs, MISO non-fuel costs and revenues, resource capacity charges, federally mandated costs and environmental-related costs.

A portion of NIPSCO's 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.

As noted above in the NIPSCO Gas regulatory matters, the IURC initiated an investigation on January 3, 2018, to review and consider the implications of the TCJA on utility rates. The commission ordered a two phase investigation. Phase 1 solely dealt with the prospective changes in rates to reflect the change in tax rates. On March 26, 2018, NIPSCO filed revised electric tariffs reflecting the impact of the change in tax rate for its applicable rates and charges. The IURC approved NIPSCO's phase 1 filing on April 26, 2018. The revised tariffs were effective May 1, 2018. On July 31, 2018, NIPSCO filed an unopposed motion requesting that the over-collection of income taxes from January 1, 2018 through April 30, 2018 be passed back in NIPSCO’s TDSIC-4 filing, also filed on July 31, 2018, and requesting that all other phase 2 issues be handled in a rate case filing to be made in the fourth quarter of 2018. On August 15, 2018, the IURC approved the motion to pass back the over-collection and stated that all other phase 2 issues will be addressed in the to-be-filed base rate case, as discussed below.

On October 31, 2018 NIPSCO filed a request for an increase in base rates with the IURC for a proposed $21.4 million increase in revenues in part, to address anticipated revenue loss resulting from the WCE filing discussed below, as well as to address phase 2 issues of the TCJA. The filing also addresses the appropriate depreciation rates for the accelerated retirement of NIPSCO’s aging coal fleet, as discussed in the 2018 Integrated Resource Plan below. An order is expected from the IURC in the third quarter of 2019 with rates anticipated to be effective September 2019.

Also on October 31, 2018, NIPSCO submitted its 2018 Integrated Resource Plan with the IURC. The plan evaluated demand-side and supply-side resource alternatives to reliably and cost effectively meet NIPSCO customers' future energy requirements over the ensuing 20 years. Refer to Note 16-D, "Other Matters," in the Notes to Condensed Consolidated Financial Statements (unaudited) for additional information.

On March 29, 2018, WCE, which is currently owned by BP p.l.c ("BP") and BP Products North America, which operates the BP Refinery, filed a petition at the IURC asking that the combined operations of WCE and BP be treated as a single premise, and the WCE generation be dedicated primarily to BP Refinery operations beginning in May 2019 as WCE has self-certified as a qualifying facility at FERC. BP Refinery planned to continue to purchase electric service from NIPSCO at a reduced demand level beginning in May 2019. NIPSCO is currently in discussions with BP.

On January 30, 2018, NIPSCO made a TDSIC-3 rate adjustment mechanism filing requesting a revenue decrease of $1.8 million to be billed over six months, associated with $75.0 million of incremental capital expenditures made from May 1, 2017 to November 30, 2017. The decrease was due to the impact of the TCJA as well as a shorter billing period compared to TDSIC-2. TDSIC-3 was approved on May 30, 2018 and became effective for the first billing cycle of June. Additionally, the TDSIC-2 rates revised for tax reform approved as a part of NIPSCO’s Phase 1 filing described above were made effective on May 1, 2018, until TDSIC-3 rates went into effect. The impact of TCJA on TDSIC-2 was an approximate decrease in revenue of $1.2 million for the period from January through May 2018. NIPSCO made a TDSIC-4 rate adjustment mechanism filing on July 31, 2018, which was modified on October 25, 2018, seeking an incremental semi-annual revenue decrease of $11.2 million due primarily to the pass back of a $14.1 million TCJA electric base rate customer refund for the period January through May 2018. The TCJA refund offsets a $2.8 million increase associated with $72.2 million of incremental capital expenditures from December 2017 through May 2018. An order approving the request is expected in the fourth quarter of 2018.

On February 1, 2018, NIPSCO and certain other MISO transmission owners filed with the FERC a request for waiver of tariff provisions to allow for implementation of TCJA provisions into 2018 transmission formula rates as soon as possible. On March 15, 2018, the FERC issued an order granting the request for waiver and set the effective date of the waiver at January 1, 2018. In the March billing cycle, the MISO began billing the new transmission rates reflecting the lower federal tax rate. In addition, the MISO began to re-bill January and February 2018 affected revenues and costs in the March 2018 billing cycle, and completed the re-settlement in the April 2018 billing cycle. The new 2018 transmission formula rates will lower revenue by approximately $8.5 million in 2018 associated with NIPSCO's multi-value projects.

Material Updates to Regulatory Assets and Liabilities Since December 31, 2017

TCJA-Related Regulatory Liabilities.As referenced above, during the nine months ended September 30, 2018, we recorded additional TCJA-related regulatory liabilities of $69.9 million to reflect 2018 collections from customers which we believe are probable of being refunded back to customers once new customer rates are approved by our regulators.

As discussed in Note 12, "Income Taxes," in 2018 we began amortizing regulatory liabilities associated with excess deferred taxes, which resulted in a $6.8 million and $24.6 million income tax benefit for the three and nine months ended September 30, 2018, respectively. Related to this activity, we recorded an offsetting reserve of $3.6 million and $15.9 million (net of tax) in "Customer revenues" to reflect the probable future passback of this earnings benefit to customers for the three and nine months ended September 30, 2018, respectively. In certain jurisdictions, we received additional regulatory guidance on the treatment and passback period of excess deferred income taxes, indicating that such a reserve was not required as of September 30, 2018.

Bailly Generating Station. On February 1, 2018, as previously approved by the MISO, NIPSCO commenced a four-month outage of Bailly Generating Station Unit 8 in order to begin work on converting the unit to a synchronous condenser (a piece of equipment designed to maintain voltage to ensure continued reliability on the transmission system). Approximately $15 million of net book value of Unit 8 remained in “Net Utility Plant” as it is expected to remain used and useful upon completion of the synchronous condenser, while the remaining net book value of approximately $142 million was reclassified to “Regulatory assets (noncurrent)” on the Condensed Consolidated Balance Sheets (unaudited). On May 31, 2018, Units 7 and 8 were retired from service. As a result, the remaining net book value of Unit 7 of approximately $103 million was reclassified to “Regulatory assets (noncurrent)” on the Condensed Consolidated Balance Sheets (unaudited).These amounts continue to be amortized at a rate consistent with their inclusion in customer rates.

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Risk Management Activities

9 Months Ended

Sep. 30, 2018

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)	September 30, 2018		December 31, 2017
Risk Management Assets - Current(1)
Interest rate risk programs	$	21.4	$	14.0
Commodity price risk programs	1.0		0.5
Total	$	22.4	$	14.5
Risk Management Assets - Noncurrent(2)
Interest rate risk programs	$	32.6	$	5.6
Commodity price risk programs	2.6		1.0
Total	$	35.2	$	6.6
Risk Management Liabilities - Current
Interest rate risk programs	$	—	$	38.6
Commodity price risk programs	4.8		4.6
Total	$	4.8	$	43.2
Risk Management Liabilities - Noncurrent
Interest rate risk programs	$	—	$	—
Commodity price risk programs	45.2		28.5
Total	$	45.2	$	28.5

⁽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).

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 twenty percent of NIPSCO’s average annual GCA purchase volume. Gains and losses on these derivative contracts are deferred as regulatory liabilities or assets and are remitted to or collected from customers through NIPSCO’s quarterly GCA mechanism. These instruments are not designated as accounting hedges.

Interest Rate Risk Management

As of September 30, 2018, we have forward-starting interest rate swaps with an aggregate notional value totaling $750.0 million to hedge the variability in cash flows attributable to changes in the benchmark interest rate during the periods from the effective dates of the swaps to the anticipated dates of forecasted debt issuances, which are expected to take place by the end of 2019. 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 April 2018, we settled forward-starting interest rate swaps with a notional value of $250.0 million. These derivative contracts were accounted for as cash flow hedges. As part of the transaction, the associated net unrealized gain of $21.2 million was recognized immediately in "Other, net" on the Condensed Statements of Consolidated Income (Loss) (unaudited) due to the probability associated with the forecasted borrowing transaction no longer occurring.

There were no amounts excluded from effectiveness testing for derivatives in cash flow hedging relationships at September 30, 2018 and December 31, 2017.

Our derivative instruments measured at fair value as of September 30, 2018 and December 31, 2017 do not contain any credit-risk-related contingent features.

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Fair Value

9 Months Ended

Sep. 30, 2018

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 September 30, 2018 and December 31, 2017:

Recurring Fair Value Measurements September 30, 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 September 30, 2018
Assets
Risk management assets	$	—	$	57.6	$	—	$	57.6
Available-for-sale securities	—		143.8		—		143.8
Total	$	—	$	201.4	$	—	$	201.4
Liabilities
Risk management liabilities	$	—	$	50.0	$	—	$	50.0
Total	$	—	$	50.0	$	—	$	50.0

Recurring Fair Value Measurements December 31, 2017 (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, 2017
Assets
Risk management assets	$	—	$	21.1	$	—	$	21.1
Available-for-sale securities	—		133.9		—		133.9
Total	$	—	$	155.0	$	—	$	155.0
Liabilities
Risk management liabilities	$	—	$	71.4	$	0.3	$	71.7
Total	$	—	$	71.4	$	0.3	$	71.7

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, options and treasury lock agreements. 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 September 30, 2018 and December 31, 2017, 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 September 30, 2018 and December 31, 2017 were:

September 30, 2018 (in millions)	Amortized Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
Available-for-sale securities
U.S. Treasury debt securities	$	29.7	$	—	$	(0.2	)	$	29.5
Corporate/Other debt securities	116.8		0.4		(2.9		)	114.3
Total	$	146.5	$	0.4	$	(3.1	)	$	143.8
December 31, 2017 (in millions)	Amortized Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
Available-for-sale securities
U.S. Treasury debt securities	$	26.9	$	—	$	(0.1	)	$	26.8
Corporate/Other debt securities	106.8		0.9		(0.6		)	107.1
Total	$	133.7	$	0.9	$	(0.7	)	$	133.9

Realized gains and losses on available-for-sale securities were immaterial for the three and nine months ended September 30, 2018 and 2017.

The cost of maturities sold is based upon specific identification. At September 30, 2018, approximately $14.9 million of U.S. Treasury debt securities and approximately $3.0 million of Corporate/Other debt securities have maturities of less than a year.

There are no material items in the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis for the three and nine months ended September 30, 2018 and 2017.

Non-recurring Fair Value Measurements. There were no significant non-recurring fair value measurements recorded during the three and nine months ended September 30, 2018.

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 nine months endedSeptember 30, 2018, there was no change in the method or significant assumptions used to estimate the fair value of long-term debt.

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

(in millions)	Carrying Amount as of September 30, 2018		Estimated Fair Value as of September 30, 2018		Carrying Amount as of Dec. 31, 2017		Estimated Fair Value as of Dec. 31, 2017
Long-term debt (including current portion)	$	7,143.1	$	7,280.1	$	7,796.5	$	8,603.4

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Transfers Of Financial Assets

9 Months Ended

Sep. 30, 2018

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 March 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 September 30, 2018, the maximum amount of debt that could be recognized related to our accounts receivable programs is $265.0 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 September 30, 2018 and December 31, 2017:

(in millions)	September 30, 2018		December 31, 2017
Gross Receivables	$	410.9	$	635.3
Less: Receivables not transferred	145.9		298.6
Net receivables transferred	$	265.0	$	336.7
Short-term debt due to asset securitization	$	265.0	$	336.7

For the nine months ended September 30, 2018 and 2017, $71.7 million and $47.8 million, respectively, was recorded as cash flows used for financing activities related to the change in short-term borrowings due to securitization transactions. Fees associated with the securitization transactions were $0.4 million and $0.6 million for the three months ended September 30, 2018 and 2017, respectively, and $1.9 million for the nine months ended September 30, 2018 and 2017, respectively. We remain responsible for collecting on the receivables securitized, and the receivables cannot be transferred to another party.

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Goodwill

9 Months Ended

Sep. 30, 2018

Goodwill and Intangible Assets Disclosure [Abstract]

Goodwill

Goodwill

The following presents our goodwill balance allocated by segment as of September 30, 2018:

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

We applied the qualitative "step 0" analysis 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.

In the third quarter of 2018, we determined the Greater Lawrence Incident (see FN 16, "Other Commitments and Contingencies") represents a triggering event that requires an impairment analysis of goodwill. This incident specifically impacts our Columbia of Massachusetts reporting unit in which the associated goodwill totaled $204.8 million immediately prior to the incident. We performed a quantitative impairment analysis as of September 30, 2018 and determined that the fair value of the Columbia of Massachusetts reporting unit continues to exceed its carrying value. Therefore, no goodwill impairment charges were recorded in the third quarter of 2018. This interim analysis was performed using updated cash flow projections reflecting the estimated ongoing impacts of the Greater Lawrence Incident on Columbia of Massachusetts' operations. We also updated other significant inputs to the fair value calculation (e.g. discount rate, market multiples) to reflect current market conditions and the increased risk and uncertainty resulting from the incident. We will continue to monitor the impacts of the Greater Lawrence Incident for events that could trigger a new impairment analysis including, but not limited to, unfavorable regulatory outcomes, extended customer impacts, and NTSB investigation results.

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Income Taxes

9 Months Ended

Sep. 30, 2018

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

Our interim effective tax rates reflect the estimated annual effective tax rates for 2018 and 2017, adjusted for tax expense associated with certain discrete items. The effective tax rates for the three months ended September 30, 2018 and 2017 were 21.8% and 15.2%, respectively. The effective tax rates for the nine months endedSeptember 30, 2018 and 2017 were 40.3% and 34.9%, respectively. These effective tax rates differ from the federal statutory tax rate of 21% in 2018 and 35% in 2017, primarily due to the effects of tax credits, state income taxes, utility ratemaking and other permanent book-to-tax differences.

The increase in the three month effective tax rate of 6.6% in 2018 compared to 2017 is due to state tax apportionment benefits recorded in the third quarter of 2017 that were not recorded in the current year period along with the impact of the Greater Lawrence Incident on consolidated state income taxes. These increases were partially offset by the change in the federal statutory rate due to the enactment of the TCJA.

The increase in the nine month effective tax rate of 5.4% in 2018 versus the same period in 2017 is primarily due to the impact of the Greater Lawrence Incident on consolidated state income taxes, partially offset by the change in the federal statutory rate due to the enactment of the TCJA.

In 2018 we began amortizing a portion of our regulatory liability associated with excess deferred taxes which resulted in a current year income tax benefit of $6.8 million and $24.6 million for the three and nine months ended September 30, 2018, respectively. Additionally, we continue to work with the public utility commissions in each of our seven states on the appropriate treatment and resolution of TCJA impacts. Final regulatory orders from our public utility commissions in ongoing proceedings may decrease our TCJA-related regulatory liabilities by up to approximately $150 million. Such decreases would be recorded in the period the respective orders are received. Refer to Note 7, "Regulatory Matters," for additional information.

There were no material changes recorded in 2018 to our uncertain tax positions as of December 31, 2017.

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Pension And Other Postretirement Benefits

9 Months Ended

Sep. 30, 2018

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 nine months ended September 30, 2018, we contributed $2.1 million to our pension plans and $16.8 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 and nine months ended September 30, 2018 and 2017:

	Pension Benefits						Other Postretirement Benefits
Three Months Ended September 30, (in millions)	2018			2017			2018			2017
Components of Net Periodic Benefit Cost(1)
Service cost	$	7.8		$	7.4		$	1.3		$	1.2
Interest cost	16.8			17.1			4.4			4.4
Expected return on assets	(35.4		)	(30.8		)	(3.7		)	(3.9		)
Amortization of prior service credit	(0.1		)	(0.1		)	(1.0		)	(1.1		)
Recognized actuarial loss	10.2			13.2			0.9			0.7
Settlement loss	8.3			10.6			—			—
Total Net Periodic Benefit Cost	$	7.6		$	17.4		$	1.9		$	1.3

⁽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 (Loss) (unaudited).

	Pension Benefits						Other Postretirement Benefits
Nine Months Ended September 30, (in millions)	2018			2017			2018			2017
Components of Net Periodic Benefit Cost(1)
Service cost	$	23.6		$	22.4		$	3.9		$	3.6
Interest cost	50.0			51.5			13.2			13.4
Expected return on assets	(107.9		)	(91.3		)	(11.1		)	(11.9		)
Amortization of prior service credit	(0.3		)	(0.5		)	(3.0		)	(3.3		)
Recognized actuarial loss	30.6			40.0			2.7			2.2
Settlement loss	11.8			10.6			—			—
Total Net Periodic Benefit Cost	$	7.8		$	32.7		$	5.7		$	4.0

⁽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 (Loss) (unaudited).

As of May 31, 2018, two of our qualified pension plans paid lump sums in excess of the respective plan's 2018 service cost plus interest cost, thereby meeting the requirement for settlement accounting. A settlement charge of $3.5 million was recorded during the second quarter of 2018. As a result of these settlements, the two pension plans were remeasured. The remeasurements led to an increase to the pension benefit obligation, net of plan assets, of $1.1 million, a net decrease to regulatory assets of $2.3 million, and a net credit to accumulated other comprehensive income (loss) of $0.1 million. Net periodic pension benefit cost for 2018 increased by $1.1 million as a result of the second quarter remeasurement.

As of August 31, 2018, an additional qualified pension plan paid lump sums in excess of its 2018 service cost plus interest cost, thereby meeting the requirement for settlement accounting. A settlement charge of $8.3 million was recorded during the third quarter of 2018. As a result of this settlement, the plan was remeasured, leading to a decrease to the net pension asset of $2.5 million, a net decrease to regulatory assets of $5.3 million, and a net credit to accumulated other comprehensive income (loss) of $0.5 million. Net periodic pension benefit cost for 2018 increased by $1.9 million as a result of the third quarter remeasurement.

The following table provides the key assumptions that were used to calculate the pension benefit obligation and the net periodic benefit cost for the plans that triggered settlement accounting at the measurement dates of August 31, 2018, May 31, 2018 and December 31, 2017:

	August 31, 2018		May 31, 2018		December 31, 2017
Weighted-average Assumption to Determine Benefit Obligation:
Discount rate	4.08	%	4.03	%	3.58	%
Weighted-average Assumptions to Determine Net Periodic Benefit Costs for the period ended:
Discount rate - service cost	3.79	%	3.79	%	4.40	%
Discount rate - interest cost	3.15	%	3.15	%	3.31	%
Expected return on assets	6.30	%	6.30	%	7.25	%

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Long-Term Debt

9 Months Ended

Sep. 30, 2018

Long-term Debt, Current and Noncurrent [Abstract]

Long-term Debt

Long-Term Debt

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

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

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

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

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Short-Term Borrowings

9 Months Ended

Sep. 30, 2018

Short-term Debt [Abstract]

Short-Term Borrowings

Short-Term Borrowings

We generate short-term borrowings from our revolving credit facility, commercial paper program, letter of credit issuances, 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. At September 30, 2018 and December 31, 2017, 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 $746.0 million and $869.0 million of commercial paper outstanding as of September 30, 2018 and December 31, 2017, respectively.

As of September 30, 2018 and December 31, 2017, we had $10.2 million and $11.1 million of stand-by letters of credit, respectively. All stand-by letters of credit were under the revolving credit facility.

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 $265.0 million in transfers as of September 30, 2018 and $336.7 million as of December 31, 2017. Refer to Note 10, "Transfers of Financial Assets," for additional information.

On April 18, 2018, we entered into a multiple-draw $600.0 million term loan agreement with a syndicate of banks led by MUFG Bank, Ltd. The term loan matures April 17, 2019, at which point any and all outstanding borrowings under the agreement are due. Interest charged on borrowings depends on the variable rate structure we elected at the time of each borrowing. Under the agreement, we borrowed an initial tranche of $150.0 million on April 18, 2018 with an interest rate of LIBOR plus 50 basis points and a second tranche of $450.0 million on May 31, 2018 with an interest rate of LIBOR plus 55 basis points.

Short-term borrowings were as follows:

(in millions)	September 30, 2018		December 31, 2017
Commercial paper weighted-average interest rate of 2.57% and 1.97% at September 30, 2018 and December 31, 2017, respectively	$	746.0	$	869.0
Accounts receivable securitization facility borrowings	265.0		336.7
Term loan weighted-average interest rate of 2.79% at September 30, 2018	600.0		—
Total Short-Term Borrowings	$	1,611.0	$	1,205.7

Other than for the term loan, 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.

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Other Commitments And Contingencies

9 Months Ended

Sep. 30, 2018

Other Commitments and Contingencies [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 September 30, 2018 and December 31, 2017, we had issued stand-by letters of credit of $10.2 million and $11.1 million, respectively.

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 (referred to herein as the “Greater Lawrence Incident”). The Greater Lawrence Incident resulted in one fatality and a number of injuries, damaged multiple homes and businesses, and caused the temporary evacuation of significant portions of each municipality. The Massachusetts Governor’s office declared a state of emergency, authorizing the Massachusetts DPU to order another utility company to coordinate the restoration of utility services in Lawrence, Andover and North Andover. The incident resulted in the interruption of gas and other utility service for approximately 8,500 gas meters, of which approximately 700 serve businesses. Columbia of Massachusetts is currently in the process of replacing the cast iron and bare steel gas pipeline system to restore service to these meters. See “ - D. Other Matters - Greater Lawrence Pipeline Replacement” below for more information.

The NTSB is investigating the Greater Lawrence Incident. The parties to the investigation include the PHMSA, the Massachusetts DPU, Columbia of Massachusetts, and police and fire first responders. The Company and Columbia of Massachusetts 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 which appears to have been related to work being done on behalf of Columbia of Massachusetts on a pipeline replacement project in Lawrence. In addition, 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. While the NTSB investigation is pending, the Company and Columbia of Massachusetts are prohibited from disclosing information related to the investigation without approval from the NTSB.

The Massachusetts DPU has announced its intent to hire an independent evaluator to conduct a statewide examination of the safety of the natural gas distribution systems within 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 examination is expected to complement, but not duplicate, the NTSB’s investigation. Following the release of the NTSB's preliminary report, the Massachusetts DPU placed a moratorium on Columbia of Massachusetts, which prohibits the company from performing any work in the state through at least December 1, 2018. The ban does not apply to compliance and emergency work, including the restoration of service in Lawrence, Andover and North Andover.

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.

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. 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 implied warranty of merchantability, breach of contract and gross negligence, and seek punitive damages. Many residents and business owners have submitted individual damage claims to Columbia of Massachusetts. We also have received notice from two parties indicating an intent to assert wrongful death claims. 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 Company and Columbia of Massachusetts are subject to a criminal investigation 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.

During the quarter ended September 30, 2018, Columbia of Massachusetts expensed approximately $415 million for estimated third-party claims related to the Greater Lawrence Incident, including personal injury and property damage claims, damage to infrastructure, and other damage claims, which include mutual aid payments to other utilities assisting with the restoration effort, gas-fueled appliance replacement and related services for impacted customers, temporary lodging for displaced customers, and claims-related legal fees. We estimate that total costs related to third-party claims resulting from the incident will range from $415 million to $450 million, depending on the final outcome of open investigations and the number, nature, and value of third-party claims. We also expect to incur losses for third party business interruption claims, the costs for which are not included in the amounts disclosed above due to insufficient information to reasonably estimate the damages from such claims. The amounts set forth above do not include non-claims related expenses resulting from the incident or the estimated capital cost of the pipeline replacement, which are 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 information resulting from the NTSB investigation, management’s estimates and assumptions regarding the financial impact of the Greater Lawrence Incident may change.

Further, it is not possible at this time to reasonably estimate the amount of any fines, penalties or settlements with governmental authorities, including the Massachusetts DPU and other regulators, that the Company or Columbia of Massachusetts may incur in connection with the Greater Lawrence Incident. Therefore, the foregoing amounts do not include estimates for any such fines, penalties or settlements.

The current and noncurrent portions of the remaining liability as of September 30, 2018 are presented within “Claims accrued” and “Other noncurrent liabilities,” respectively, in the Company’s Condensed Consolidated Balance Sheets (unaudited). The expenses above are presented within “Operation and maintenance” in our Condensed Statement of Consolidated Income (unaudited).

The Company maintains liability insurance for damages in the approximate amount of $800 million. The Company and Columbia of Massachusetts believe that third-party claims related to the Greater Lawrence Incident will be substantially covered by this insurance, other than any fines, penalties or settlements with governmental authorities that the Company or Columbia of Massachusetts may incur. However, no amounts for insurance recoveries have been recorded as of September 30, 2018. The Company and Columbia of Massachusetts are currently unable to predict the amount and timing of insurance recoveries.

In addition, we are party to certain other claims and legal proceedings arising in the ordinary course of business, none of which are 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 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 September 30, 2018 and December 31, 2017, we had recorded a liability of approximately $107.1 million and $111.4 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" in the Condensed Consolidated Balance Sheets (unaudited). 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," below for additional information.

Air

The actions listed below could require further reductions in emissions from various emission sources. We will continue to closely monitor developments in these matters.

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 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 twelve 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 64 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 future remediation costs related to our 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 $103.3 million and $106.9 million at September 30, 2018 and December 31, 2017, 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 $25 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 is incurring capital expenditures to modify its infrastructure and manage CCRs. Capital compliance costs are currently expected to total approximately $193 million. 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.

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. The rule imposes new water treatment and discharge requirements on NIPSCO's electric generating facilities to be applied between 2018 and 2023. On April 25, 2017, the EPA published notice in the Federal Register that the EPA is reconsidering the ELG in response to several petitions for reconsideration. On September 18, 2017, the EPA postponed the earliest compliance dates for flue gas desulfurization wastewater and bottom ash transport water requirements from 2018 to 2020 to potentially consider revisions to technology and numeric limits achievable. NIPSCO is unable to estimate the financial impact of the EPA reconsideration at this time. Based upon a preliminary study of the November 3, 2015 final rule, capital compliance costs were expected to be approximately $170 million. However, NIPSCO does not anticipate material ELG compliance costs based on the most viable option for customers 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 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.

On October 31, 2018, NIPSCO submitted its 2018 Integrated Resource Plan to the IURC. The plan evaluated demand-side and supply-side resource alternatives to reliably and cost effectively meet NIPSCO customers' future energy requirements over the ensuing 20 years. 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. The replacement plan is still being defined, but currently points to renewable sources of energy, including wind, solar, and battery storage.

NIPSCO Pure Air. NIPSCO had a service agreement with Pure Air, a general partnership between Air Products and Chemicals, Inc. and First Air Partners LP, under which Pure Air provided scrubber services to reduce sulfur dioxide emissions for Units 7 and 8 at the Bailly Generating Station. Services under this contract commenced on July 1, 1992 and expired on June 30, 2012. The agreement was renewed effective July 1, 2012 for ten years, requiring NIPSCO to pay for the services under a combination of fixed and variable charges. We made an exhaustive effort to obtain information needed from Pure Air to determine the status of Pure Air as a VIE. However, NIPSCO was not able to obtain this information and, as a result, it was not determined whether Pure Air was a VIE and whether NIPSCO was the primary beneficiary. Payments under this agreement were $8.3 million and $16.5 million for the nine months endedSeptember 30, 2018 and 2017, respectively. In accordance with GAAP, the renewed agreement was evaluated to determine whether the arrangement qualified as a lease. Based on the terms of the agreement, the arrangement qualified for capital lease accounting. As the effective date of the new agreement was July 1, 2012, we capitalized this lease beginning in the third quarter of 2012.

NIPSCO retired the generation station units serviced by Pure Air on May 31, 2018. In December 2016, as allowed by the provisions of the service agreement, NIPSCO provided Pure Air formal notice of intent to terminate the service agreement, effective May 31, 2018. Providing this notice to Pure Air triggered a contract termination liability of $16 million, which was recorded in fourth quarter of 2016. In connection with the closure of Bailly Units 7 and 8, NIPSCO paid the termination payment to Pure Air during the second quarter of 2018. Cash flows associated with this payment are presented within operating activities on the Condensed Statements of Consolidated Cash Flows (unaudited).

Greater Lawrence Incident Restoration. During the quarter ended September 30, 2018, Columbia of Massachusetts recorded a loss of approximately $460 million in connection with the Greater Lawrence Incident. This amount includes approximately $415 million for estimated third-party claims associated with the incident as described above in " - B. Legal Proceedings." The additional $45 million included in the loss recorded includes certain consulting costs, administration costs, charitable contributions, and other labor and related expenses in connection with the incident. We expect to incur a total of $180 million to $210 million in such incident-related costs, depending on the incurrence of future restoration work, substantially all of which we expect to incur by the end of 2018. The amounts set forth above do not include the estimated capital cost of the pipeline replacement, which is set forth below.

The Company maintains liability insurance for damages in the approximate amount of $800 million. The Company and Columbia of Massachusetts believe that third-party claims and other expenses related to the Greater Lawrence Incident will be substantially covered by insurance, other than any fines, penalties or settlements with governmental authorities that the Company or Columbia of Massachusetts may incur. However, no amounts for insurance recoveries have been recorded as of September 30, 2018. The Company and Columbia of Massachusetts are currently unable to predict the amount and timing of insurance recoveries.

The current and noncurrent portions of the remaining liability as of September 30, 2018 are presented within “Claims accrued” and “Other noncurrent liabilities,” respectively, in the Company’s Condensed Consolidated Balance Sheets (unaudited). Costs associated with charitable contributions are presented within “Other, Net” in our Condensed Statement of Consolidated Income (unaudited). All other losses incurred are presented within “Operation and maintenance.”

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 8,500 gas meters, of which approximately 700 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. Columbia of Massachusetts is aiming to restore gas service to all homes and workplaces by December 16, 2018. 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 has hired an outside contractor to serve as the Chief Recovery Officer for the Greater Lawrence Incident, responsible for command, control and communications. The estimated capital cost of the pipeline replacement is between $135 - $165 million. The recovery of this capital investment will be addressed in a future regulatory proceeding.

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Accumulated Other Comprehensive Loss

9 Months Ended

Sep. 30, 2018

Other Comprehensive Income (Loss), Tax [Abstract]

Accumulated Other Comprehensive Loss

Accumulated Other Comprehensive Income (Loss)

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

Three Months Ended September 30, 2018 (in millions)	Gains and Losses on Securities(1)			Gains and Losses on Cash Flow Hedges(1)			Pension and OPEB Items(1)			Accumulated Other Comprehensive Income (Loss)(1)
Balance as of July 1, 2018	$	(2.2	)	$	(1.7	)	$	(17.0	)	$	(20.9	)
Other comprehensive income before reclassifications	—			21.6			1.0			22.6
Amounts reclassified from accumulated other comprehensive loss	0.1			0.9			(0.2		)	0.8
Net current-period other comprehensive income	0.1			22.5			0.8			23.4
Balance as of September 30, 2018	$	(2.1	)	$	20.8		$	(16.2	)	$	2.5
Nine Months Ended September 30, 2018 (in millions)	Gains and Losses on Securities(1)			Gains and Losses on Cash Flow Hedges(1)			Pension and OPEB Items(1)			Accumulated Other Comprehensive Income (Loss)(1)
Balance as of January 1, 2018	$	0.2		$	(29.4	)	$	(14.2	)	$	(43.4	)
Other comprehensive income (loss) before reclassifications	(2.5		)	70.8			1.0			69.3
Amounts reclassified from accumulated other comprehensive loss(2)	0.2			(14.3		)	0.2			(13.9		)
Net current-period other comprehensive income (loss)	(2.3		)	56.5			1.2			55.4
Reclassification due to adoption of ASU 2018-02 (Refer to Note 2)	—			(6.3		)	(3.2		)	(9.5		)
Balance as of September 30, 2018	$	(2.1	)	$	20.8		$	(16.2	)	$	2.5

Three Months Ended September 30, 2017 (in millions)	Gains and Losses on Securities(1)			Gains and Losses on Cash Flow Hedges(1)			Pension and OPEB Items(1)			Accumulated Other Comprehensive (Loss)(1)
Balance as of July 1, 2017	$	0.4		$	(18.8	)	$	(17.2	)	$	(35.6	)
Other comprehensive income (loss) before reclassifications	0.1			(9.7		)	—			(9.6		)
Amounts reclassified from accumulated other comprehensive loss	—			0.4			1.1			1.5
Net current-period other comprehensive income (loss)	0.1			(9.3		)	1.1			(8.1		)
Balance as of September 30, 2017	$	0.5		$	(28.1	)	$	(16.1	)	$	(43.7	)
Nine Months Ended September 30, 2017 (in millions)	Gains and Losses on Securities(1)			Gains and Losses on Cash Flow Hedges(1)			Pension and OPEB Items(1)			Accumulated Other Comprehensive (Loss)(1)
Balance as of January 1, 2017	$	(0.6	)	$	(6.9	)	$	(17.6	)	$	(25.1	)
Other comprehensive income (loss) before reclassifications	1.1			(23.3		)	0.2			(22.0		)
Amounts reclassified from accumulated other comprehensive loss	—			2.1			1.3			3.4
Net current-period other comprehensive income (loss)	1.1			(21.2		)	1.5			(18.6		)
Balance as of September 30, 2017	$	0.5		$	(28.1	)	$	(16.1	)	$	(43.7	)

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

⁽²⁾ Reclassification from accumulated other comprehensive loss for cash flow hedges relates primarily to the interest rate swap settlement gain. Refer to Note 8 "Risk Management Activities" for additional information.

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Other, Net

9 Months Ended

Sep. 30, 2018

Other, Net [Abstract]

Other Income and Other Expense Disclosure [Text Block]

Other, Net

	Three Months Ended September 30,						Nine Months Ended September 30,
(in millions)	2018			2017			2018			2017
Interest Income	$	1.4		$	1.4		$	4.2		$	3.2
AFUDC Equity	5.0			4.3			12.6			10.5
Charitable Contributions	(11.1		)	(0.8		)	(13.9		)	(3.5		)
Pension and other postretirement non-service cost	2.4			(11.8		)	14.7			(10.1		)
Interest rate swap settlement gain(1)	—			—			21.2			—
Miscellaneous	0.6			0.1			3.6			(0.4		)
Total Other, net	$	(1.7	)	$	(6.8	)	$	42.4		$	(0.3	)

⁽¹⁾See Note 8, "Risk Management Activities," for additional information.

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Business Segment Information

9 Months Ended

Sep. 30, 2018

Segment Reporting [Abstract]

Business Segment Information

Business Segment Information

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 September 30,						Nine Months Ended September 30,
(in millions)	2018			2017			2018			2017
Operating Revenues
Gas Distribution Operations
Unaffiliated	$	418.6		$	431.1		$	2,347.8		$	2,139.9
Intersegment	3.3			3.5			9.8			10.6
Total	421.9			434.6			2,357.6			2,150.5
Electric Operations
Unaffiliated	476.2			485.8			1,304.4			1,365.5
Intersegment	0.2			0.2			0.6			0.6
Total	476.4			486.0			1,305.0			1,366.1
Corporate and Other
Unaffiliated	0.2			0.1			0.6			0.9
Intersegment	116.4			126.4			346.6			367.7
Total	116.6			126.5			347.2			368.6
Eliminations	(119.9		)	(130.1		)	(357.0		)	(378.9		)
Consolidated Operating Revenues	$	895.0		$	917.0		$	3,652.8		$	3,506.3
Operating Income (Loss)
Gas Distribution Operations	$	(455.2	)	$	(15.4	)	$	(94.4	)	$	367.1
Electric Operations	134.9			125.1			300.4			288.3
Corporate and Other	4.4			1.5			(2.9		)	(4.8		)
Consolidated Operating Income	$	(315.9	)	$	111.2		$	203.1		$	650.6

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Recent Accounting Pronouncements (Tables)

9 Months Ended

Sep. 30, 2018

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

Description of New Accounting Pronouncements Not yet Adopted

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

Standard	Description	Effective Date	Effect on the financial statements or other significant matters
ASU 2018-11, Leases (Topic 842): Targeted Improvements	The pronouncement allows entities the option to initially apply ASC 842 at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption.	Annual periods beginning after December 15, 2018, including interim periods therein. Early adoption is permitted.	We are the lessee for substantially all of our current leasing activity. Upon adopting ASC 842 we will begin recognizing right-of-use assets and liabilities associated with operating leases (other than short term operating leases) on our Condensed Consolidated Balance Sheets (unaudited). The impact of this change on the balance sheet is not reasonably estimable at this time. We do not anticipate the adoption of ASC 842 will have a material impact to our results of operations or cash flows. We have undertaken efforts to outline mock footnote disclosures intended to satisfy ASC 842’s disclosure requirements, which will enhance our disclosures on lease accounting policies and elections. We are implementing a new lease accounting system, which we will utilize to capture, track, and account for lease data. The new system will also aid in automating the compilation of disclosure information. We expect to conclude final system tests in the fourth quarter of 2018, with full system implementation prior to the effective date of these standards. 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 currently anticipate adopting this practical expedient for certain classes of leases. Further, we will elect the "practical expedient package" described in ASC 842-10-65-1. We maintain a substantial number of easements and will also elect the provisions of ASU 2018-01 to ease the process of implementing ASC 842. Lastly, we anticipate electing the transition method provided in ASU 2018-11 when we adopt these standards effective January 1, 2019.
ASU 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842	The pronouncement offers a practical expedient for accounting for land easements under ASU 2016-02. This practical expedient allows an entity the option of not evaluating existing land easements under ASC 842. New or modified land easements will still require evaluation under ASC 842 on a prospective basis beginning on the date of adoption.
ASU 2016-02, Leases (Topic 842)	The pronouncement introduces a lessee model that brings most leases on 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.

Schedule of Prospective Adoption of New Accounting Pronouncements

Recently Adopted Accounting Pronouncements

Standard	Adoption
ASU 2018-15, Intangibles—Goodwill and Other— Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract	In August 2018, the FASB issued this ASU, which amends current guidance to align the accounting for costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing costs associated with developing or obtaining internal-use software. We elected to early adopt the ASU on a prospective basis, effective October 1, 2018. As a result of adopting this ASU, we will defer onto the balance sheet those up-front implementation costs of cloud computing arrangements if they would have been capitalized in a similar on-premise software solution.
ASU 2018-02, Income Statement—Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income	We adopted this ASU effective March 31, 2018. Upon adoption, $9.5 million of tax effects that were stranded in accumulated other comprehensive income (loss) as a result of the implementation of the TCJA were reclassified to retained deficit. This change is reflected on our Condensed Statements of Consolidated Equity (unaudited).
ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force)	We adopted this ASU effective January 1, 2018. The adoption of this standard did not have a material impact on our Condensed Consolidated Financial Statements (unaudited) or Notes to Condensed Consolidated Financial Statements (unaudited).
ASU 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients	See Note 3, "Revenue Recognition," for our discussion of the effects of implementing these standards.
ASU 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations
ASU 2014-09, Revenue from Contracts with Customers (Topic 606)

Schedule of New Accounting Pronouncements and Changes in Accounting Principles

Changes in income statement presentation were implemented on a retrospective basis. The impact of this ASU on previously issued annual financial statements is summarized in the tables below:

Year Ended December 31, 2016 (in millions)	As Previously Reported			Effect of Change(1)			As Adjusted
Operation and maintenance	$	1,453.7		$	(7.9	)	$	1,445.8
Total Operating Expenses	3,634.3			(7.9		)	3,626.4
Operating Income	858.2			7.9			866.1
Other Income (Deductions)
Other, net	1.5			(7.9		)	(6.4		)
Total Other Deductions	(348.0		)	(7.9		)	(355.9		)
Income before Income Taxes	$	510.2		$	—		$	510.2

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

Year Ended December 31, 2017 (in millions)	As Previously Reported			Effect of Change(1)			As Adjusted
Operation and maintenance	$	1,612.3		$	(10.6	)	$	1,601.7
Total Operating Expenses	3,964.0			(10.6		)	3,953.4
Operating Income	910.6			10.6			921.2
Other Income (Deductions)
Other, net	(2.8		)	(10.6		)	(13.4		)
Total Other Deductions	(467.5		)	(10.6		)	(478.1		)
Income before Income Taxes	$	443.1		$	—		$	443.1

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

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Revenue Recognition (Tables)

9 Months Ended

Sep. 30, 2018

Revenue from Contract with Customer [Abstract]

Revenue Recognition Under Previous Guidance

The table below provides results for the three and nine months ended September 30, 2018 as if they had been prepared under historic accounting guidance. We included operating revenue information for the three and nine months ended September 30, 2017 for comparability.

	Three Months Ended September 30,				Nine Months Ended September 30,
(in millions)	2018		2017		2018		2017
Operating Revenues
Gas Distribution	$	232.3	$	239.4	$	1,600.3	$	1,403.0
Gas Transportation	186.0		191.6		745.2		735.1
Electric	476.2		485.8		1,304.4		1,365.5
Other	0.5		0.2		2.9		2.7
Total Operating Revenues	$	895.0	$	917.0	$	3,652.8	$	3,506.3

Disaggregation of Revenue

The table below reconciles revenue disaggregation by customer class to segment revenue as well as to revenues reflected on the Condensed Statements of Consolidated Income (Loss) (unaudited):

Three Months Ended September 30, 2018 (in millions)	Gas Distribution Operations		Electric Operations		Corporate and Other		Total
Customer Revenues(1)
Residential	$	257.0	$	154.7	$	—	$	411.7
Commercial	80.9		140.7		—		221.6
Industrial	39.0		153.6		—		192.6
Off-system	20.4		—		—		20.4
Miscellaneous	9.2		0.1		0.2		9.5
Total Customer Revenues	$	406.5	$	449.1	$	0.2	$	855.8
Other Revenues	12.1		27.1		—		39.2
Total Operating Revenues	$	418.6	$	476.2	$	0.2	$	895.0

⁽¹⁾ Customer revenue amounts exclude intersegment revenues. See Note 19, "Business Segment Information," for discussion of intersegment revenues.

Nine Months Ended September 30, 2018 (in millions)	Gas Distribution Operations		Electric Operations		Corporate and Other		Total
Customer Revenues(1)
Residential	$	1,540.3	$	382.3	$	—	$	1,922.6
Commercial	516.2		374.2		—		890.4
Industrial	161.3		468.1		—		629.4
Off-system	63.6		—		—		63.6
Miscellaneous	36.2		12.3		0.6		49.1
Total Customer Revenues	$	2,317.6	$	1,236.9	$	0.6	$	3,555.1
Other Revenues	30.2		67.5		—		97.7
Total Operating Revenues	$	2,347.8	$	1,304.4	$	0.6	$	3,652.8

⁽¹⁾ Customer revenue amounts exclude intersegment revenues. See Note 19, "Business Segment Information," for discussion of intersegment revenues.

Customer Accounts Receivable

The opening and closing balances of customer receivables for the nine months endedSeptember 30, 2018 are presented in the table below. We had no significant contract assets or liabilities during the period. Additionally, we have not incurred any significant costs to obtain or fulfill contracts.

(in millions)	Customer Accounts Receivable, Billed (less reserve)(1)			Customer Accounts Receivable, Unbilled (less reserve)(2)
Balance as of December 31, 2017	$	477.0		$	356.0
Balance as of September 30, 2018	297.2			154.8
Increase (Decrease)	$	(179.8	)	$	(201.2	)

⁽¹⁾ Customer billed receivables decreased over the period due to the expected seasonal decrease in customer usage in September when compared to December.

⁽²⁾ Customer unbilled receivables decreased over the period due to the expected seasonal decrease in customer usage in September when compared to December.

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Earnings Per Share (Tables)

9 Months Ended

Sep. 30, 2018

Earnings Per Share [Abstract]

Computation Of Diluted Average Common Shares

The computation of diluted average common shares is as follows:

	Three Months Ended	Nine Months Ended
	September 30,	September 30,
(in thousands)	2017	2017
Denominator
Basic average common shares outstanding	331,139	326,662
Dilutive potential common shares:
Shares contingently issuable under employee stock plans	604	503
Shares restricted under employee stock plans	653	866
Diluted Average Common Shares	332,396	328,031

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Equity (Tables)

9 Months Ended

Sep. 30, 2018

Equity [Abstract]

Schedule Of Stock Offering Program [Table Text Block]

The following table summarizes our activity under the ATM Program:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
Number of shares issued	—		10,612,915		—		11,931,376
Average price per share	$	—	$	26.67	$	—	$	26.58
Proceeds, net of fees (in millions)	$	—	$	281.0	$	—	$	314.7

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Risk Management Activities (Tables)

9 Months Ended

Sep. 30, 2018

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)	September 30, 2018		December 31, 2017
Risk Management Assets - Current(1)
Interest rate risk programs	$	21.4	$	14.0
Commodity price risk programs	1.0		0.5
Total	$	22.4	$	14.5
Risk Management Assets - Noncurrent(2)
Interest rate risk programs	$	32.6	$	5.6
Commodity price risk programs	2.6		1.0
Total	$	35.2	$	6.6
Risk Management Liabilities - Current
Interest rate risk programs	$	—	$	38.6
Commodity price risk programs	4.8		4.6
Total	$	4.8	$	43.2
Risk Management Liabilities - Noncurrent
Interest rate risk programs	$	—	$	—
Commodity price risk programs	45.2		28.5
Total	$	45.2	$	28.5

⁽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).

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Fair Value (Tables)

9 Months Ended

Sep. 30, 2018

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 September 30, 2018 and December 31, 2017:

Recurring Fair Value Measurements September 30, 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 September 30, 2018
Assets
Risk management assets	$	—	$	57.6	$	—	$	57.6
Available-for-sale securities	—		143.8		—		143.8
Total	$	—	$	201.4	$	—	$	201.4
Liabilities
Risk management liabilities	$	—	$	50.0	$	—	$	50.0
Total	$	—	$	50.0	$	—	$	50.0

Recurring Fair Value Measurements December 31, 2017 (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, 2017
Assets
Risk management assets	$	—	$	21.1	$	—	$	21.1
Available-for-sale securities	—		133.9		—		133.9
Total	$	—	$	155.0	$	—	$	155.0
Liabilities
Risk management liabilities	$	—	$	71.4	$	0.3	$	71.7
Total	$	—	$	71.4	$	0.3	$	71.7

Schedule of Available-For-Sale Securities

The amortized cost, gross unrealized gains and losses and fair value of available-for-sale securities at September 30, 2018 and December 31, 2017 were:

September 30, 2018 (in millions)	Amortized Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
Available-for-sale securities
U.S. Treasury debt securities	$	29.7	$	—	$	(0.2	)	$	29.5
Corporate/Other debt securities	116.8		0.4		(2.9		)	114.3
Total	$	146.5	$	0.4	$	(3.1	)	$	143.8
December 31, 2017 (in millions)	Amortized Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
Available-for-sale securities
U.S. Treasury debt securities	$	26.9	$	—	$	(0.1	)	$	26.8
Corporate/Other debt securities	106.8		0.9		(0.6		)	107.1
Total	$	133.7	$	0.9	$	(0.7	)	$	133.9

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 September 30, 2018		Estimated Fair Value as of September 30, 2018		Carrying Amount as of Dec. 31, 2017		Estimated Fair Value as of Dec. 31, 2017
Long-term debt (including current portion)	$	7,143.1	$	7,280.1	$	7,796.5	$	8,603.4

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Transfers Of Financial Assets (Tables)

9 Months Ended

Sep. 30, 2018

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 September 30, 2018 and December 31, 2017:

(in millions)	September 30, 2018		December 31, 2017
Gross Receivables	$	410.9	$	635.3
Less: Receivables not transferred	145.9		298.6
Net receivables transferred	$	265.0	$	336.7
Short-term debt due to asset securitization	$	265.0	$	336.7

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Goodwill (Tables)

9 Months Ended

Sep. 30, 2018

Goodwill and Intangible Assets Disclosure [Abstract]

Schedule of Goodwill

The following presents our goodwill balance allocated by segment as of September 30, 2018:

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

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Pension And Other Postretirement Benefits (Tables)

9 Months Ended

Sep. 30, 2018

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 and nine months ended September 30, 2018 and 2017:

	Pension Benefits						Other Postretirement Benefits
Three Months Ended September 30, (in millions)	2018			2017			2018			2017
Components of Net Periodic Benefit Cost(1)
Service cost	$	7.8		$	7.4		$	1.3		$	1.2
Interest cost	16.8			17.1			4.4			4.4
Expected return on assets	(35.4		)	(30.8		)	(3.7		)	(3.9		)
Amortization of prior service credit	(0.1		)	(0.1		)	(1.0		)	(1.1		)
Recognized actuarial loss	10.2			13.2			0.9			0.7
Settlement loss	8.3			10.6			—			—
Total Net Periodic Benefit Cost	$	7.6		$	17.4		$	1.9		$	1.3

⁽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 (Loss) (unaudited).

	Pension Benefits						Other Postretirement Benefits
Nine Months Ended September 30, (in millions)	2018			2017			2018			2017
Components of Net Periodic Benefit Cost(1)
Service cost	$	23.6		$	22.4		$	3.9		$	3.6
Interest cost	50.0			51.5			13.2			13.4
Expected return on assets	(107.9		)	(91.3		)	(11.1		)	(11.9		)
Amortization of prior service credit	(0.3		)	(0.5		)	(3.0		)	(3.3		)
Recognized actuarial loss	30.6			40.0			2.7			2.2
Settlement loss	11.8			10.6			—			—
Total Net Periodic Benefit Cost	$	7.8		$	32.7		$	5.7		$	4.0

⁽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 (Loss) (unaudited).

Schedule of Assumptions Used

The following table provides the key assumptions that were used to calculate the pension benefit obligation and the net periodic benefit cost for the plans that triggered settlement accounting at the measurement dates of August 31, 2018, May 31, 2018 and December 31, 2017:

	August 31, 2018		May 31, 2018		December 31, 2017
Weighted-average Assumption to Determine Benefit Obligation:
Discount rate	4.08	%	4.03	%	3.58	%
Weighted-average Assumptions to Determine Net Periodic Benefit Costs for the period ended:
Discount rate - service cost	3.79	%	3.79	%	4.40	%
Discount rate - interest cost	3.15	%	3.15	%	3.31	%
Expected return on assets	6.30	%	6.30	%	7.25	%

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Short-Term Borrowings (Tables)

9 Months Ended

Sep. 30, 2018

Short-term Debt [Abstract]

Schedule Of Short-Term Borrowings

Short-term borrowings were as follows:

(in millions)	September 30, 2018		December 31, 2017
Commercial paper weighted-average interest rate of 2.57% and 1.97% at September 30, 2018 and December 31, 2017, respectively	$	746.0	$	869.0
Accounts receivable securitization facility borrowings	265.0		336.7
Term loan weighted-average interest rate of 2.79% at September 30, 2018	600.0		—
Total Short-Term Borrowings	$	1,611.0	$	1,205.7

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Accumulated Other Comprehensive Loss (Tables)

9 Months Ended

Sep. 30, 2018

Other Comprehensive Income (Loss), Tax [Abstract]

Components Of Accumulated Other Comprehensive Loss

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

Three Months Ended September 30, 2018 (in millions)	Gains and Losses on Securities(1)			Gains and Losses on Cash Flow Hedges(1)			Pension and OPEB Items(1)			Accumulated Other Comprehensive Income (Loss)(1)
Balance as of July 1, 2018	$	(2.2	)	$	(1.7	)	$	(17.0	)	$	(20.9	)
Other comprehensive income before reclassifications	—			21.6			1.0			22.6
Amounts reclassified from accumulated other comprehensive loss	0.1			0.9			(0.2		)	0.8
Net current-period other comprehensive income	0.1			22.5			0.8			23.4
Balance as of September 30, 2018	$	(2.1	)	$	20.8		$	(16.2	)	$	2.5
Nine Months Ended September 30, 2018 (in millions)	Gains and Losses on Securities(1)			Gains and Losses on Cash Flow Hedges(1)			Pension and OPEB Items(1)			Accumulated Other Comprehensive Income (Loss)(1)
Balance as of January 1, 2018	$	0.2		$	(29.4	)	$	(14.2	)	$	(43.4	)
Other comprehensive income (loss) before reclassifications	(2.5		)	70.8			1.0			69.3
Amounts reclassified from accumulated other comprehensive loss(2)	0.2			(14.3		)	0.2			(13.9		)
Net current-period other comprehensive income (loss)	(2.3		)	56.5			1.2			55.4
Reclassification due to adoption of ASU 2018-02 (Refer to Note 2)	—			(6.3		)	(3.2		)	(9.5		)
Balance as of September 30, 2018	$	(2.1	)	$	20.8		$	(16.2	)	$	2.5

Three Months Ended September 30, 2017 (in millions)	Gains and Losses on Securities(1)			Gains and Losses on Cash Flow Hedges(1)			Pension and OPEB Items(1)			Accumulated Other Comprehensive (Loss)(1)
Balance as of July 1, 2017	$	0.4		$	(18.8	)	$	(17.2	)	$	(35.6	)
Other comprehensive income (loss) before reclassifications	0.1			(9.7		)	—			(9.6		)
Amounts reclassified from accumulated other comprehensive loss	—			0.4			1.1			1.5
Net current-period other comprehensive income (loss)	0.1			(9.3		)	1.1			(8.1		)
Balance as of September 30, 2017	$	0.5		$	(28.1	)	$	(16.1	)	$	(43.7	)
Nine Months Ended September 30, 2017 (in millions)	Gains and Losses on Securities(1)			Gains and Losses on Cash Flow Hedges(1)			Pension and OPEB Items(1)			Accumulated Other Comprehensive (Loss)(1)
Balance as of January 1, 2017	$	(0.6	)	$	(6.9	)	$	(17.6	)	$	(25.1	)
Other comprehensive income (loss) before reclassifications	1.1			(23.3		)	0.2			(22.0		)
Amounts reclassified from accumulated other comprehensive loss	—			2.1			1.3			3.4
Net current-period other comprehensive income (loss)	1.1			(21.2		)	1.5			(18.6		)
Balance as of September 30, 2017	$	0.5		$	(28.1	)	$	(16.1	)	$	(43.7	)

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

⁽²⁾ Reclassification from accumulated other comprehensive loss for cash flow hedges relates primarily to the interest rate swap settlement gain. Refer to Note 8 "Risk Management Activities" for additional information.

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Other, Net (Tables)

9 Months Ended

Sep. 30, 2018

Other, Net [Abstract]

Schedule of Other Nonoperating Income (Expense)

	Three Months Ended September 30,						Nine Months Ended September 30,
(in millions)	2018			2017			2018			2017
Interest Income	$	1.4		$	1.4		$	4.2		$	3.2
AFUDC Equity	5.0			4.3			12.6			10.5
Charitable Contributions	(11.1		)	(0.8		)	(13.9		)	(3.5		)
Pension and other postretirement non-service cost	2.4			(11.8		)	14.7			(10.1		)
Interest rate swap settlement gain(1)	—			—			21.2			—
Miscellaneous	0.6			0.1			3.6			(0.4		)
Total Other, net	$	(1.7	)	$	(6.8	)	$	42.4		$	(0.3	)

⁽¹⁾See Note 8, "Risk Management Activities," for additional information.

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Business Segment Information (Tables)

9 Months Ended

Sep. 30, 2018

Segment Reporting [Abstract]

Schedule Of Operating Income Derived From Revenues And Expenses By Segment

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 September 30,						Nine Months Ended September 30,
(in millions)	2018			2017			2018			2017
Operating Revenues
Gas Distribution Operations
Unaffiliated	$	418.6		$	431.1		$	2,347.8		$	2,139.9
Intersegment	3.3			3.5			9.8			10.6
Total	421.9			434.6			2,357.6			2,150.5
Electric Operations
Unaffiliated	476.2			485.8			1,304.4			1,365.5
Intersegment	0.2			0.2			0.6			0.6
Total	476.4			486.0			1,305.0			1,366.1
Corporate and Other
Unaffiliated	0.2			0.1			0.6			0.9
Intersegment	116.4			126.4			346.6			367.7
Total	116.6			126.5			347.2			368.6
Eliminations	(119.9		)	(130.1		)	(357.0		)	(378.9		)
Consolidated Operating Revenues	$	895.0		$	917.0		$	3,652.8		$	3,506.3
Operating Income (Loss)
Gas Distribution Operations	$	(455.2	)	$	(15.4	)	$	(94.4	)	$	367.1
Electric Operations	134.9			125.1			300.4			288.3
Corporate and Other	4.4			1.5			(2.9		)	(4.8		)
Consolidated Operating Income	$	(315.9	)	$	111.2		$	203.1		$	650.6

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Recent Accounting Pronouncements (Schedule of Prospective Adoption of New Accounting Pronouncements) (Details) - Accounting Standards Update 2018-02 $ in Millions	Dec. 31, 2017 USD ($)	[1]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Cumulative Effect of New Accounting Principle in Period of Adoption	$ 0.0
Retained Deficit
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Cumulative Effect of New Accounting Principle in Period of Adoption	$ 9.5

[1] See Note 2, "Recent Accounting Pronouncements," for additional information.

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Recent Accounting Pronouncements (Schedule of New Accounting Pronouncements and Changes in Accounting Princicples) (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017		Dec. 31, 2016
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Operation and maintenance	$ 780.8	$ 371.7	$ 1,548.5	$ 1,174.9
Total Operating Expenses	1,210.9	805.8	3,449.7	2,855.7
Operating Income	(315.9)	111.2	203.1	650.6
Other, net	(1.7)	(6.8)	42.4	(0.3)
Total Other Deductions	(118.1)	(94.7)	(268.3)	(372.6)
Income before Income Taxes	(434.0)	16.5	(65.2)	278.0
Accounting Standards Update 2017-07
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Operation and maintenance					$ (10.6)	[1]	$ (7.9)	[2]
Total Operating Expenses					(10.6)	[1]	(7.9)	[2]
Operating Income					10.6	[1]	7.9	[2]
Other, net					(10.6)	[1]	(7.9)	[2]
Total Other Deductions					(10.6)	[1]	(7.9)	[2]
Income before Income Taxes					0.0	[1]	0.0	[2]
Gas Distribution Operations
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Operating Income	(455.2)	(15.4)	(94.4)	367.1
New Accounting Pronouncement or Change in Accounting Principle, Effect of Change on Operating Results					(4.4)		4.3
Electric Operations
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Operating Income	134.9	125.1	300.4	288.3
New Accounting Pronouncement or Change in Accounting Principle, Effect of Change on Operating Results					(2.6)		(9.8)
Corporate and Other
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Operating Income	$ 4.4	$ 1.5	$ (2.9)	$ (4.8)
New Accounting Pronouncement or Change in Accounting Principle, Effect of Change on Operating Results					(3.6)		(2.4)
Previously Reported
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Operation and maintenance					1,612.3		1,453.7
Total Operating Expenses					3,964.0		3,634.3
Operating Income					910.6		858.2
Other, net					(2.8)		1.5
Total Other Deductions					(467.5)		(348.0)
Income before Income Taxes					443.1		510.2
Restatement Adjustment
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Operation and maintenance					1,601.7		1,445.8
Total Operating Expenses					3,953.4		3,626.4
Operating Income					921.2		866.1
Other, net					(13.4)		(6.4)
Total Other Deductions					(478.1)		(355.9)
Income before Income Taxes					$ 443.1		$ 510.2

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

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

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Revenue Recognition (Narrative) (Details)	9 Months Ended
	Sep. 30, 2018
Revenue from Contract with Customer [Abstract]
Service Area By County	20

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Revenue Recognition (Revenue Recognition Under Previous Guidance) (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Revenue Recognition Under Previous Guidance [Line Items]
Regulated Operating Revenue	$ 895.0	$ 917.0	$ 3,652.8	$ 3,506.3
Previous Accounting Guidance
Revenue Recognition Under Previous Guidance [Line Items]
Regulated Operating Revenue	895.0	917.0	3,652.8	3,506.3
Previous Accounting Guidance | Gas Distribution
Revenue Recognition Under Previous Guidance [Line Items]
Regulated Operating Revenue	232.3	239.4	1,600.3	1,403.0
Previous Accounting Guidance | Gas Transportation
Revenue Recognition Under Previous Guidance [Line Items]
Regulated Operating Revenue	186.0	191.6	745.2	735.1
Previous Accounting Guidance | Electric
Revenue Recognition Under Previous Guidance [Line Items]
Regulated Operating Revenue	476.2	485.8	1,304.4	1,365.5
Previous Accounting Guidance | Other
Revenue Recognition Under Previous Guidance [Line Items]
Regulated Operating Revenue	$ 0.5	$ 0.2	$ 2.9	$ 2.7

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Revenue Recognition (Disaggregation of Revenue) (Details) - USD ($) $ in Millions		3 Months Ended			9 Months Ended
		Sep. 30, 2018		Sep. 30, 2017	Sep. 30, 2018		Sep. 30, 2017
Disaggregation of Revenue [Line Items]
Customer revenues		$ 855.8	[1]	$ 883.4	$ 3,555.1	[1]	$ 3,386.0
Other revenues		39.2		33.6	97.7		120.3
Total Operating Revenues		895.0		$ 917.0	3,652.8		$ 3,506.3
Gas Distribution Operations
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	406.5			2,317.6
Other revenues		12.1			30.2
Total Operating Revenues		418.6			2,347.8
Electric Operations
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	449.1			1,236.9
Other revenues		27.1			67.5
Total Operating Revenues		476.2			1,304.4
Corporate and Other
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	0.2			0.6
Other revenues		0.0			0.0
Total Operating Revenues		0.2			0.6
Residential
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	411.7
Residential | Gas Distribution Operations
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	257.0			1,540.3
Residential | Electric Operations
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	154.7			382.3
Residential | Corporate and Other
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	0.0			0.0
Commercial | Gas Distribution Operations
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	80.9			516.2
Commercial | Electric Operations
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	140.7			374.2
Commercial | Corporate and Other
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	0.0			0.0
Industrial | Gas Distribution Operations
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	39.0			161.3
Industrial | Electric Operations
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	153.6			468.1
Industrial | Corporate and Other
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	0.0			0.0
Off-system | Gas Distribution Operations
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	20.4			63.6
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 | Gas Distribution Operations
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	9.2			36.2
Miscellaneous | Electric Operations
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	0.1			12.3
Miscellaneous | Corporate and Other
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	0.2			0.6
Residential
Disaggregation of Revenue [Line Items]
Customer revenues	[1]				1,922.6
Commercial
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	221.6			890.4
Industrial
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	192.6			629.4
Off-system
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	20.4			63.6
Miscellaneous
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	$ 9.5			$ 49.1

[1] Customer revenue amounts exclude intersegment revenues. See Note 19, "Business Segment Information," for discussion of intersegment revenues.

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Revenue Recognition (Customer Accounts Receivable) (Details) - USD ($) $ in Millions		9 Months Ended
		Sep. 30, 2018	Dec. 31, 2017
Revenue from Contract with Customer [Abstract]
Customer Accounts Receivable, Billed (Less Reserve)	[1]	$ 297.2	$ 477.0
Customer Accounts Receivable, Unbilled (Less Reserve)	[2]	154.8	$ 356.0
Increase (Decrease) in Customer Accounts Receivable, Billed (Less Reserve)	[1]	(179.8)
Increase (Decrease) in Customer Accounts Receivable, Unbilled (Less Reserve)	[2]	$ (201.2)

[1] Customer billed receivables decreased over the period due to the expected seasonal decrease in customer usage in September when compared to December.

[2] Customer unbilled receivables decreased over the period due to the expected seasonal decrease in customer usage in September when compared to December.

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Earnings Per Share (Details) - shares shares in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Denominator
Basic Average Common Shares Outstanding	363,900	331,139	352,115	326,662
Dilutive potential common shares
Shares contingently issuable under employee stock plans		604		503
Shares restricted under stock plans		653		866
Diluted Average Common Shares	363,900	332,396	352,115	328,031

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Equity (Narrative) (Details) $ / shares in Units, $ in Millions			1 Months Ended	3 Months Ended		9 Months Ended
	Jun. 11, 2018 USD ($) $ / shares shares	May 04, 2018 USD ($) $ / shares shares	Dec. 08, 2017 $ / shares	Sep. 30, 2018 USD ($) $ / shares shares	Sep. 30, 2017 USD ($) $ / shares	Sep. 30, 2018 USD ($) $ / shares shares	Sep. 30, 2017 USD ($) $ / shares	Dec. 31, 2017 $ / shares shares
Shares, Issued | shares				363,167,000		363,167,000		337,016,000
Common Stock, Par or Stated Value Per Share | $ / shares				$ 0.01		$ 0.01		$ 0.01
Preferred Stock, Par or Stated Value Per Share | $ / shares				$ 1,000		$ 1,000
Proceeds from Issuance of Common Stock						$ 611.6	$ 332.6
At The Market Program
Number Of Equity Distribution Agreements						4
Common Stock Aggregate Sale Price				$ 500.0		$ 500.0
ATM Program Equity Remaining Available for Issuance						$ 10.0
Common Stock Issued Average Price Per Share | $ / shares				$ 0	$ 26.67	$ 0	$ 26.58
Proceeds from Issuance of Common Stock				$ 0.0	$ 281.0	$ 0.0	$ 314.7
Forward Agreement
Forward Contract Indexed to Issuer's Equity, Shares | shares						6,345,860
Forward Contract Indexed to Issuer's Equity, Forward Rate Per Share | $ / shares			$ 27.24			$ 26.59
Forward Contract Indexed to Issuer's Equity, Settlement Alternatives, Shares, at Fair Value				$ 168.7		$ 168.7
Common Stock
Shares, Issued | shares		24,964,163		367,130,000		367,130,000		340,813,000
Sale of Stock, Price Per Share | $ / shares		$ 24.28
Common Stock, Par or Stated Value Per Share | $ / shares		$ 0.01
Series A Preferred Stock
Preferred Stock, Par or Stated Value Per Share | $ / shares	$ 1,000
Preferred Stock, Dividend Rate, Initial Margin	2.843%
Preferred Stock, Shares Issued | shares	400,000
Preferred Stock, Dividend Rate, Percentage	5.65%
Preferred Stock, Dividend Rate, Initial Margin Plus 1.000%	1.00%
Gross Proceeds | Common Stock
Proceeds from Issuance of Private Placement		$ 606.0
Gross Proceeds | Series A Preferred Stock
Proceeds from Issuance of Private Placement	$ 400.0
Net Proceeds | Common Stock
Proceeds from Issuance of Private Placement		$ 599.6
Net Proceeds | Series A Preferred Stock
Proceeds from Issuance of Private Placement	$ 393.9

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Equity (Schedule of Stock Offering Program) (Details) - USD ($) $ / shares in Units, $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Class of Stock [Line Items]
Stock Issued During Period, Shares, New Issues	[1]			24,964,000
Proceeds from Issuance of Common Stock				$ 611.6	$ 332.6
At The Market Program
Class of Stock [Line Items]
Stock Issued During Period, Shares, New Issues		0	10,612,915	0	11,931,376
Common Stock Issued Average Price Per Share		$ 0	$ 26.67	$ 0	$ 26.58
Proceeds from Issuance of Common Stock		$ 0.0	$ 281.0	$ 0.0	$ 314.7

[1] See Note 5, "Equity," for additional information.

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Asset Retirement Obligations (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2018		Sep. 30, 2017
Asset Retirement Obligations [Abstract]
Asset Retirement Obligation, Revision of Estimate	$ 70.7	[1]	$ 0.0

[1] See Note 6 "Asset Retirement Obligations" for additional information.

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Regulatory Matters (Narrative) (Details) - USD ($) $ in Millions																									3 Months Ended	9 Months Ended
	Oct. 31, 2018	Oct. 25, 2018	Oct. 15, 2018	Oct. 09, 2018	Sep. 26, 2018	Sep. 19, 2018	Aug. 31, 2018	Aug. 28, 2018	Jul. 31, 2018	Jul. 18, 2018	Jun. 21, 2018	Apr. 20, 2018	Apr. 18, 2018	Apr. 13, 2018	Mar. 28, 2018	Mar. 26, 2018	Mar. 16, 2018	Feb. 27, 2018	Feb. 13, 2018	Jan. 30, 2018	Jan. 29, 2018	Nov. 08, 2017	Oct. 31, 2017	Sep. 27, 2017	Sep. 30, 2018	Sep. 30, 2018	Sep. 04, 2018	May 31, 2018	Apr. 30, 2018	Apr. 25, 2018	Feb. 01, 2018
Regulatory Matters [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Net of TCJA																$ (1.2)
Regulatory Liability Adjustment From Tax Reform																									$ 69.9	$ 69.9
Tax Benefit From Excess Deferred Tax Amortization Related To Regulatory LIabilities																									6.8	24.6
TCJA Related Revenue Reserve, Net of Tax																									3.6	15.9
Columbia Of Ohio
Regulatory Matters [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Net of TCJA																		$ 2.3
Public Utilities, Requested Rate Increase (Decrease), Amount													$ 70.0
Regulatory Net Capital Expenditures Included In Filing																														$ 207.0
Public Utilities, Requested Biennial Rate Increase (Decrease), Amount increases													$ 98.0
NIPSCO
Regulatory Matters [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Net of TCJA															$ 138.1
Public Utilities, Requested Rate Increase (Decrease), Amount												$ 107.3												$ 143.5
Public Utilities, Approved Rate Increase (Decrease), Amount						$ 84.3																$ 91.5	$ (8.5)
Regulatory Net Capital Expenditures Included In Filing																						$ 35.5			1,250.0	1,250.0	$ 767.0
Bailly Unit 8 Portion of Net Book Value in Net Utility Plant																															$ 15.0
Regulatory Asset Associated with Bailly Generating Station Retirement																												$ 103.0			$ 142.0
NIPSCO | TDSIC-3
Regulatory Matters [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount																				$ (1.8)
Regulatory Net Capital Expenditures Included In Filing																				$ 75.0
NIPSCO | TDSIC 8 Gas
Regulatory Matters [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Net of TCJA																		0.8
Public Utilities, Requested Rate Increase (Decrease), Amount										$ (0.2)
Regulatory Net Capital Expenditures Included In Filing										$ 54.0								$ 77.9
Public Utilities, Passback Liability for Revenues Previously Billed to Customers																									$ 2.5	$ 2.5
NIPSCO | TDSIC-9 [Member]
Regulatory Matters [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount					$ (7.6)			$ (0.5)
Regulatory Net Capital Expenditures Included In Filing								72.9
Public Utilities, Customer Refund for Tax Rate Change Due to TCJA								7.1
NIPSCO | TDSIC-4
Regulatory Matters [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Net of TCJA									$ 2.8
Regulatory Net Capital Expenditures Included In Filing									72.2
Public Utilities, Requested Biennial Rate Increase (Decrease), Amount increases									(11.2)
Public Utilities, Customer Refund for Tax Rate Change Due to TCJA									14.1
Columbia Of Massachusetts
Regulatory Matters [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount														$ (19.7)
Public Utilities, Approved Rate Increase (Decrease), Cumulative Amount														24.1
Columbia Of Massachusetts | 2018 GSEP
Regulatory Matters [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Cumulative Amount														43.8
Public Utilities, Requested Rate Increase (Decrease), Waiver Amount in excess of Cap																							3.1
Public Utilities, Requested Rate Increase (Decrease), Amount																					$ (2.4)		$ 9.7
Regulatory Net Capital Expenditures Included In Filing																													$ 83.9
Public Utilities, Requested Rate Increase (Decrease), Incremental Revenue Requirement from Waiver on Revenue Cap											$ 6.5
Columbia Of Pennsylvania
Regulatory Matters [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount							$ 26.0										$ 46.9
Public Utilities, Customer Refund for Tax Rate Change Due to TCJA							$ 22.5
Columbia Of Virginia [Member]
Regulatory Matters [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount								$ 22.2
Columbia Of Maryland
Regulatory Matters [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount									$ 3.7					$ 6.1
Public Utilities, Approved Rate Increase (Decrease), Amount																			$ (1.3)
Subsequent Event | Columbia Of Ohio
Regulatory Matters [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount		$ 74.5
Subsequent Event | NIPSCO
Regulatory Matters [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount	$ 21.4
Subsequent Event | Columbia Of Massachusetts
Regulatory Matters [Line Items]
Public Utilities, Customer Refund for Tax Rate Change Due to TCJA				$ 95.8
Subsequent Event | Columbia Of Massachusetts | 2018 GSEP
Regulatory Matters [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Waiver Amount in excess of Cap	2.9
Public Utilities, Requested Rate Increase (Decrease), Amount	10.7
Regulatory Net Capital Expenditures Included In Filing	$ 64.0
Subsequent Event | Columbia Of Kentucky [Member]
Regulatory Matters [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount			$ 3.6
Public Utilities, Requested Incremental Capital Investment			$ 30.1

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Risk Management Activities (Narrative) (Details) - USD ($) $ in Millions	3 Months Ended			9 Months Ended
	Sep. 30, 2018		Sep. 30, 2017	Sep. 30, 2018		Sep. 30, 2017	[1]
Derivative [Line Items]
Gain (Loss) on Sale of Derivatives	$ 0.0	[1]	$ 0.0	$ 21.2	[1]	$ 0.0
Interest Rate Swap
Derivative [Line Items]
Derivative, Notional Amount	750.0			750.0
Interest Rate Swap Settled
Derivative [Line Items]
Derivative, Notional Amount	$ 250.0			$ 250.0

[1] See Note 8, "Risk Management Activities," for additional information.

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Risk Management Activities (Schedule of Derivative Instruments in Statement of Financial Position, Fair Value) (Details) - USD ($) $ in Millions		Sep. 30, 2018	Dec. 31, 2017
Risk Management Assets Current
Derivatives, Fair Value [Line Items]
Derivative Asset	[1]	$ 22.4	$ 14.5
Risk Management Assets Noncurrent
Derivatives, Fair Value [Line Items]
Derivative Asset	[2]	35.2	6.6
Risk Management Liabilities Current
Derivatives, Fair Value [Line Items]
Derivative Liability		4.8	43.2
Risk Management Liabilities Noncurrent
Derivatives, Fair Value [Line Items]
Derivative Liability		45.2	28.5
Interest Rate Risk | Risk Management Assets Current
Derivatives, Fair Value [Line Items]
Derivative Asset	[1]	21.4	14.0
Interest Rate Risk | Risk Management Assets Noncurrent
Derivatives, Fair Value [Line Items]
Derivative Asset	[2]	32.6	5.6
Interest Rate Risk | Risk Management Liabilities Current
Derivatives, Fair Value [Line Items]
Derivative Liability		0.0	38.6
Interest Rate Risk | Risk Management Liabilities Noncurrent
Derivatives, Fair Value [Line Items]
Derivative Liability		0.0	0.0
Commodity Price Risk Programs | Risk Management Assets Current
Derivatives, Fair Value [Line Items]
Derivative Asset	[1]	1.0	0.5
Commodity Price Risk Programs | Risk Management Assets Noncurrent
Derivatives, Fair Value [Line Items]
Derivative Asset	[2]	2.6	1.0
Commodity Price Risk Programs | Risk Management Liabilities Current
Derivatives, Fair Value [Line Items]
Derivative Liability		4.8	4.6
Commodity Price Risk Programs | Risk Management Liabilities Noncurrent
Derivatives, Fair Value [Line Items]
Derivative Liability		$ 45.2	$ 28.5

[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).

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Fair Value (Narrative) (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Fair Value Disclosure [Line Items]
Transfers between Fair Value Hierarchies	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	$ 14.9
Corporate/Other debt securities
Fair Value Disclosure [Line Items]
Available-for-sale Securities, Maturities, Next Twelve Months, Fair Value	$ 3.0

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Fair Value (Fair Value Of Financial Assets And Liabilities Measured On A Recurring Basis) (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Assets
Assets, Fair Value Disclosure	$ 201.4	$ 155.0
Liabilities
Total	50.0	71.7
Fair Value, Inputs, Level 1
Assets
Risk management assets	0.0	0.0
Available-for-sale securities	0.0	0.0
Assets, Fair Value Disclosure	0.0	0.0
Liabilities
Risk management liabilities	0.0	0.0
Total	0.0	0.0
Significant Other Observable Inputs (Level 2)
Assets
Risk management assets	57.6	21.1
Available-for-sale securities	143.8	133.9
Assets, Fair Value Disclosure	201.4	155.0
Liabilities
Risk management liabilities	50.0	71.4
Total	50.0	71.4
Significant Unobservable Inputs (Level 3)
Assets
Risk management assets	0.0	0.0
Available-for-sale securities	0.0	0.0
Assets, Fair Value Disclosure	0.0	0.0
Liabilities
Risk management liabilities	0.0	0.3
Total	0.0	0.3
Available-for-sale Securities
Assets
Available-for-sale securities	143.8	133.9
Risk management assets
Assets
Risk management assets	57.6	21.1
Liabilities
Risk management liabilities	$ 50.0	$ 71.7

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Fair Value (Available-For-Sale Securities) (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Debt Securities, Available-for-sale [Line Items]
Amortized cost	$ 146.5	$ 133.7
Gross unrealized gains	0.4	0.9
Gross unrealized losses	3.1	0.7
Fair value	143.8	133.9
U.S. Treasury debt securities
Debt Securities, Available-for-sale [Line Items]
Amortized cost	29.7	26.9
Gross unrealized gains	0.0	0.0
Gross unrealized losses	0.2	0.1
Fair value	29.5	26.8
Corporate/Other debt securities
Debt Securities, Available-for-sale [Line Items]
Amortized cost	116.8	106.8
Gross unrealized gains	0.4	0.9
Gross unrealized losses	2.9	0.6
Fair value	$ 114.3	$ 107.1

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Fair Value (Carrying Amount And Estimated Fair Values Of Financial Instruments) (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Fair Value Disclosures [Abstract]
Long-term Debt (including current portion), Gross	$ 7,143.1	$ 7,796.5
Long-term debt (including current portion), Estimated Fair Value	$ 7,280.1	$ 8,603.4

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Transfers Of Financial Assets (Narrative) (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
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			$ 71.7	$ 47.8
Securitization Transaction Fees	$ 0.4	$ 0.6		$ 1.9
Accounts Receivable Program
Assets and Associated Liabilities of Transfers Accounted for as Secured Borrowings [Line Items]
Seasonal Limit	$ 265.0		$ 265.0

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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	Sep. 30, 2018	Dec. 31, 2017
Gross Receivables	$ 410.9	$ 635.3
Less: Receivables not transferred	145.9	298.6
Net receivables transferred	265.0	336.7
Accounts receivable securitization facility borrowings	$ 265.0	$ 336.7

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Goodwill (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2018	Dec. 31, 2017
Goodwill [Line Items]
Goodwill, Impairment Loss	$ 0.0
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
Columbia Of Massachusetts
Goodwill [Line Items]
Goodwill	$ 204.8

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Income Taxes (Narrative) (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Income Tax Disclosure [Abstract]
Effective income tax rates	21.80%	15.20%	40.30%	34.90%
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate			21.00%	35.00%
Increase (Decrease) in Effective Tax Rate	6.60%		5.40%
Tax Benefit From Excess Deferred Tax Amortization Related To Regulatory LIabilities	$ 6.8		$ 24.6
Potential Decrease in TCJA-Related Regulatory Liabilities			150.0
Changes to Liability for Uncertain Tax Positions			$ 0.0

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Pension And Other Postretirement Benefits (Narrative) (Details) - USD ($) $ in Millions		3 Months Ended			6 Months Ended	9 Months Ended
		Sep. 30, 2018	Jun. 30, 2018	Sep. 30, 2017	Jun. 30, 2018	Sep. 30, 2018	Sep. 30, 2017	Aug. 31, 2018	May 31, 2018
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Employer contributions						$ 2.1
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement	[1]	$ (8.3)	$ (3.5)	$ (10.6)		(11.8)	$ (10.6)
Defined Benefit Plan, Benefit Obligation, (Increase) Decrease for Remeasurement due to Settlement					$ 1.1	2.5
Change in Regulatory Assets Due To Interim Measurement								$ 5.3	$ 2.3
Change in Accumulated Other Comprehensive Income Due To Interim Measurement								0.5	0.1
Defined Benefit Plan Net Periodic Benefit Costs								$ 1.9	$ 1.1
Other Postretirement Benefit Plan
Defined Benefit Plan Disclosure [Line Items]
Employer contributions						16.8
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement	[1]	$ 0.0		$ 0.0		$ 0.0	$ 0.0

[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 (Loss) (unaudited).

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Pension And Other Postretirement Benefits (Components Of The Plans' Net Periodic Benefits Cost) (Details) - USD ($) $ in Millions		3 Months Ended			9 Months Ended
		Sep. 30, 2018	Jun. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Service Cost	[1]	$ 7.8		$ 7.4	$ 23.6	$ 22.4
Interest cost	[1]	16.8		17.1	50.0	51.5
Expected return on assets	[1]	(35.4)		(30.8)	(107.9)	(91.3)
Amortization of prior service credit	[1]	(0.1)		(0.1)	(0.3)	(0.5)
Recognized actuarial loss	[1]	10.2		13.2	30.6	40.0
Settlement loss	[1]	8.3	$ 3.5	10.6	11.8	10.6
Total Net Periodic Benefits Cost		7.6		17.4	7.8	32.7
Other Postretirement Benefit Plan
Defined Benefit Plan Disclosure [Line Items]
Service Cost	[1]	1.3		1.2	3.9	3.6
Interest cost	[1]	4.4		4.4	13.2	13.4
Expected return on assets	[1]	(3.7)		(3.9)	(11.1)	(11.9)
Amortization of prior service credit	[1]	(1.0)		(1.1)	(3.0)	(3.3)
Recognized actuarial loss	[1]	0.9		0.7	2.7	2.2
Settlement loss	[1]	0.0		0.0	0.0	0.0
Total Net Periodic Benefits Cost		$ 1.9		$ 1.3	$ 5.7	$ 4.0

[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 (Loss) (unaudited).

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Pension and Other Postretirement Benefits (Schedule of Assumptions Used) (Details) - Pension Plan	5 Months Ended	8 Months Ended	12 Months Ended
	May 31, 2018	Aug. 31, 2018	Dec. 31, 2017
Defined Benefit Plan Disclosure [Line Items]
Discount rate	4.03%	4.08%	3.58%
Discount rate - service cost	3.79%	3.79%	4.40%
Discount rate - interest cost	3.15%	3.15%	3.31%
Expected return on assets	6.30%	6.30%	7.25%

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Long-Term Debt (Narrative) (Details) - USD ($) $ in Millions		3 Months Ended		6 Months Ended	9 Months Ended
	Jul. 16, 2018	Sep. 30, 2018	Sep. 30, 2017	Jun. 30, 2018	Sep. 30, 2018	Sep. 30, 2017	Jun. 11, 2018	Mar. 15, 2018
Debt Instrument [Line Items]
Loss on early extinguishment of long-term debt		$ (33.0)	$ 0.0	$ 12.5	$ (45.5)	$ (111.5)
Debt Instrument Tendered					$ 209.0
Senior Notes
Debt Instrument [Line Items]
Debt Instrument, Face Amount							$ 350.0
Senior Note Redeemed 2018 Note 1 | Senior Notes
Debt Instrument [Line Items]
Debt Instrument, Repurchase Amount								$ 275.1
Debt Instrument, Interest Rate, Stated Percentage								6.40%
6.80% Notes Due 2019
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		6.80%			6.80%
6.125% Notes Due 2022
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		6.125%			6.125%
3.65% Notes Due 2023
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		3.65%			3.65%
3.65% Notes Due 2023 | Senior Notes
Debt Instrument [Line Items]
Proceeds from Debt, Net of Issuance Costs					$ 346.6
5.45% Notes due 2020
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		5.45%			5.45%
Senior Note Redeemed 2018 Note 2
Debt Instrument [Line Items]
Loss on early extinguishment of long-term debt	$ 33.0
Debt Instrument, Repurchased Face Amount	$ 551.1

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Short-Term Borrowings (Narrative) (Details) - USD ($) $ in Millions	May 31, 2018	Apr. 18, 2018	Sep. 30, 2018	Dec. 31, 2017
Short-term Debt [Line Items]
Commercial paper outstanding			$ 746.0	$ 869.0
Accounts receivable securitization facility borrowings			265.0	336.7
Term Loan			600.0	0.0
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	$ 11.1
Term Loan
Short-term Debt [Line Items]
Debt Instrument, Basis Spread on Variable Rate	0.55%	0.50%
Term Loan | Debt Oustanding
Short-term Debt [Line Items]
Term Loan	$ 450.0	$ 150.0
Maximum | Term Loan
Short-term Debt [Line Items]
Term Loan		$ 600.0

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Short-Term Borrowings (Schedule Of Short-Term Borrowings) (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Short-term Debt [Line Items]
Commercial paper weighted-average interest rate of 2.57% and 1.97% at September 30, 2018 and December 31, 2017, respectively	$ 746.0	$ 869.0
Accounts receivable securitization facility borrowings	265.0	336.7
Term loan weighted-average interest rate of 2.79% at September 30, 2018	600.0	0.0
Total short-term borrowings	$ 1,611.0	$ 1,205.7
Commercial Paper
Short-term Debt [Line Items]
Short-term Debt, Weighted Average Interest Rate, at Point in Time	2.57%	1.97%
Term Loan
Short-term Debt [Line Items]
Short-term Debt, Weighted Average Interest Rate, at Point in Time	2.79%

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Other Commitments And Contingencies (Narrative) (Details) $ in Millions	3 Months Ended	9 Months Ended		12 Months Ended
	Sep. 30, 2018 USD ($)	Sep. 30, 2018 USD ($)	Sep. 30, 2017 USD ($)	Dec. 31, 2018 USD ($)	May 31, 2018 USD ($)	Feb. 01, 2018 USD ($)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)
Other Commitments And Contingencies [Line Items]
Liability Insurance for Damages	$ 800.0	$ 800.0
Recorded reserves to cover environmental remediation at various sites	$ 107.1	107.1					$ 111.4
Payments Pure Air		$ 8.3	$ 16.5
Liability Associated with Bailly Generating Station Retirement - Pure Air Contract Termination Portion								$ 16.0
MGP Sites
Other Commitments And Contingencies [Line Items]
Number of waste disposal sites identified by program	64	64
Liability for Estimated Remediation Costs	$ 103.3	$ 103.3					106.9
Reasonably possible remediation costs variance from reserve	$ 25.0	25.0
Columbia Of Massachusetts
Other Commitments And Contingencies [Line Items]
Gas Meters Affected	8,500
Businesses Impacted by Incident	700
Expenses Related to Third-Party Claims	$ 415.0
Loss from Consulting Costs, Administration Costs, Charitable Contributions, and Other Labor and Related Expenses	45.0
Loss Recorded During Period	$ 460.0
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		193.0
Estimated Cost of Compliance with Effluent Limitations Guidelines		170.0
Bailly Unit 8 Portion of Net Book Value in Net Utility Plant						$ 15.0
Regulatory Asset Associated with Bailly Generating Station Retirement					$ 103.0	$ 142.0
Maximum | Columbia Of Massachusetts
Other Commitments And Contingencies [Line Items]
Civil Penalty Assessed for Violation of Federal Pipeline Safety Regulations		0.2
Civil Penalty Assessed for Series of Violations of Federal Pipeline Safety Regulations		2.1
Penalty Per Violation of Emergency Response Plan		0.3
Penalty for Violations of Emergency Response Plan		20.0
Penalty Per Violation of Operational Directives During Restoration Efforts		1.0
Third-Party Claims Resulting from the Greater Lawrence Incident		450.0
Estimated Capital Cost of the Pipeline Replacement	$ 165.0	165.0
Minimum | Columbia Of Massachusetts
Other Commitments And Contingencies [Line Items]
Third-Party Claims Resulting from the Greater Lawrence Incident		415.0
Estimated Capital Cost of the Pipeline Replacement	135.0	135.0
Standby Letters of Credit
Other Commitments And Contingencies [Line Items]
Long-term Line of Credit	$ 10.2	$ 10.2					$ 11.1
Scenario, Forecast [Member] | Maximum
Other Commitments And Contingencies [Line Items]
Incident-Related Costs				$ 210.0
Scenario, Forecast [Member] | Minimum
Other Commitments And Contingencies [Line Items]
Incident-Related Costs				$ 180.0

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Accumulated Other Comprehensive Loss (Components Of Accumulated Other Comprehensive Loss) (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018		Sep. 30, 2017	Dec. 31, 2017
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance	[1]	$ (20.9)	$ (35.6)	$ (43.4)		$ (25.1)
Other Comprehensive Income before reclassifications	[1]	22.6	(9.6)	69.3		(22.0)
Amounts reclassified from accumulated other comprehensive loss	[1]	0.8	1.5	(13.9)	[2]	3.4
Net current-period other comprehensive income (loss)	[1]	23.4	(8.1)	55.4		(18.6)
New Accounting Pronouncement or Change in Accounting Principle, Cumulative Effect of Change on Equity or Net Assets	[1]						$ (9.5)
Ending Balance	[1]	2.5	(43.7)	2.5		(43.7)
Gains and Losses on Securities
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance	[1]	(2.2)	0.4	0.2		(0.6)
Other Comprehensive Income before reclassifications	[1]	0.0	0.1	(2.5)		1.1
Amounts reclassified from accumulated other comprehensive loss	[1]	0.1	0.0	0.2	[2]	0.0
Net current-period other comprehensive income (loss)	[1]	0.1	0.1	(2.3)		1.1
New Accounting Pronouncement or Change in Accounting Principle, Cumulative Effect of Change on Equity or Net Assets	[1]						0.0
Ending Balance	[1]	(2.1)	0.5	(2.1)		0.5
Gains and Losses on Cash Flow Hedges
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance	[1]	(1.7)	(18.8)	(29.4)		(6.9)
Other Comprehensive Income before reclassifications	[1]	21.6	(9.7)	70.8		(23.3)
Amounts reclassified from accumulated other comprehensive loss	[1]	0.9	0.4	(14.3)	[2]	2.1
Net current-period other comprehensive income (loss)	[1]	22.5	(9.3)	56.5		(21.2)
New Accounting Pronouncement or Change in Accounting Principle, Cumulative Effect of Change on Equity or Net Assets	[1]						(6.3)
Ending Balance	[1]	20.8	(28.1)	20.8		(28.1)
Pension and OPEB Items
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance	[1]	(17.0)	(17.2)	(14.2)		(17.6)
Other Comprehensive Income before reclassifications	[1]	1.0	0.0	1.0		0.2
Amounts reclassified from accumulated other comprehensive loss	[1]	(0.2)	1.1	0.2	[2]	1.3
Net current-period other comprehensive income (loss)	[1]	0.8	1.1	1.2		1.5
New Accounting Pronouncement or Change in Accounting Principle, Cumulative Effect of Change on Equity or Net Assets	[1]						$ (3.2)
Ending Balance	[1]	$ (16.2)	$ (16.1)	$ (16.2)		$ (16.1)

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

[2] Reclassification from accumulated other comprehensive loss for cash flow hedges relates primarily to the interest rate swap settlement gain. Refer to Note 8 "Risk Management Activities" for additional information.

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Other, Net (Details) - USD ($) $ in Millions	3 Months Ended			9 Months Ended
	Sep. 30, 2018		Sep. 30, 2017	Sep. 30, 2018		Sep. 30, 2017
Other, Net [Abstract]
Interest Income	$ 1.4		$ 1.4	$ 4.2		$ 3.2
AFUDC Equity	5.0		4.3	12.6		10.5
Charitable Contributions	(11.1)		(0.8)	(13.9)		(3.5)
Pension and other postretirement non-service cost	2.4		(11.8)	14.7		(10.1)
Interest rate swap settlement gain	0.0	[1]	0.0	21.2	[1]	0.0	[1]
Miscellaneous	0.6		0.1	3.6		(0.4)
Other, net	$ (1.7)		$ (6.8)	$ 42.4		$ (0.3)

[1] See Note 8, "Risk Management Activities," for additional information.

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Business Segment Information (Narrative) (Details)	9 Months Ended
	Sep. 30, 2018
Segment Reporting [Abstract]
Primary business segments	2
Number of counties in which electric service provided by Electric Operations	20

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Business Segment Information (Schedule Of Operating Income Derived From Revenues And Expenses By Segment) (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Segment Reporting Information [Line Items]
Regulated Operating Revenue	$ 895.0	$ 917.0	$ 3,652.8	$ 3,506.3
Revenues	895.0	917.0	3,652.8	3,506.3
Consolidated Operating Income (Loss)	(315.9)	111.2	203.1	650.6
Gas Distribution Operations
Segment Reporting Information [Line Items]
Regulated Operating Revenue	418.6		2,347.8
Revenues	421.9	434.6	2,357.6	2,150.5
Consolidated Operating Income (Loss)	(455.2)	(15.4)	(94.4)	367.1
Gas Distribution Operations | Unaffiliated
Segment Reporting Information [Line Items]
Revenues		431.1		2,139.9
Gas Distribution Operations | Intersegment
Segment Reporting Information [Line Items]
Revenues	3.3	3.5	9.8	10.6
Electric Operations
Segment Reporting Information [Line Items]
Regulated Operating Revenue	476.2		1,304.4
Revenues	476.4	486.0	1,305.0	1,366.1
Consolidated Operating Income (Loss)	134.9	125.1	300.4	288.3
Electric Operations | Unaffiliated
Segment Reporting Information [Line Items]
Revenues		485.8		1,365.5
Electric Operations | Intersegment
Segment Reporting Information [Line Items]
Revenues	0.2	0.2	0.6	0.6
Corporate and Other
Segment Reporting Information [Line Items]
Regulated Operating Revenue	0.2		0.6
Revenues	116.6	126.5	347.2	368.6
Consolidated Operating Income (Loss)	4.4	1.5	(2.9)	(4.8)
Corporate and Other | Unaffiliated
Segment Reporting Information [Line Items]
Revenues		0.1		0.9
Corporate and Other | Intersegment
Segment Reporting Information [Line Items]
Revenues	116.4	126.4	346.6	367.7
Eliminations
Segment Reporting Information [Line Items]
Revenues	$ (119.9)	$ (130.1)	$ (357.0)	$ (378.9)