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 June 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: 363,036,685 shares outstanding at July 24, 2018.

NISOURCE INC.

FORM 10-Q QUARTERLY REPORT

FOR THE QUARTER ENDED JUNE 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)	6
		Condensed Statements of Consolidated Comprehensive Income (Loss) (unaudited)	7
		Condensed Consolidated Balance Sheets (unaudited)	8
		Condensed Statements of Consolidated Cash Flows (unaudited)	10
		Condensed Statements of Consolidated Equity (unaudited)	11
		Notes to Condensed Consolidated Financial Statements (unaudited)	12
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	37
	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	52
	Item 4.	Controls and Procedures	52
PART II	OTHER INFORMATION
	Item 1.	Legal Proceedings	53
	Item 1A.	Risk Factors	53
	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	53
	Item 3.	Defaults Upon Senior Securities	53
	Item 4.	Mine Safety Disclosures	53
	Item 5.	Other Information	53
	Item 6.	Exhibits	54
	Signature		55

2

DEFINED TERMS
The following is a list of frequently used abbreviations or acronyms that are found in this report:
NiSource Subsidiaries, Affiliates and Former Subsidiaries
Columbia of Kentucky	Columbia Gas of Kentucky, Inc.
Columbia of Maryland	Columbia Gas of Maryland, Inc.
Columbia of Massachusetts	Bay State Gas Company
Columbia of Ohio	Columbia Gas of Ohio, Inc.
Columbia of Pennsylvania	Columbia Gas of Pennsylvania, Inc.
Columbia of Virginia	Columbia Gas of Virginia, Inc.
NIPSCO	Northern Indiana Public Service Company LLC
NiSource ("we," "us" or “our”)	NiSource Inc.
Abbreviations and Other
AFUDC	Allowance for funds used during construction
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
LIFO	Last In, First Out
MGP	Manufactured Gas Plant

3

DEFINED TERMS
MISO	Midcontinent Independent System Operator
MMDth	Million dekatherms
NOL	Net operating loss
NYMEX	New York Mercantile Exchange
OPEB	Other Postretirement Benefits
PSC	Public Service Commission
PUC	Public Utilities 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
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; 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 our Annual Report on Form 10-K for the fiscal year ended December 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.

4

Index	Page
Condensed Statements of Consolidated Income (Loss) (unaudited)	6
Condensed Statements of Consolidated Comprehensive Income (Loss) (unaudited)	7
Condensed Consolidated Balance Sheets (unaudited)	8
Condensed Statements of Consolidated Cash Flows (unaudited)	10
Condensed Statements of Consolidated Equity (unaudited)	11
Notes to Condensed Consolidated Financial Statements (unaudited)	12
1. Basis of Accounting Presentation	12
2. Recent Accounting Pronouncements	12
3. Revenue Recognition	15
4. Earnings Per Share	18
5. Equity	18
6. Gas in Storage	19
7. Asset Retirement Obligations	19
8. Regulatory Matters	19
9. Risk Management Activities	24
10. Fair Value	25
11. Transfers of Financial Assets	27
12. Goodwill	28
13. Income Taxes	28
14. Pension and Other Postretirement Benefits	28
15. Long-Term Debt	30
16. Short-Term Borrowings	30
17. Other Commitments and Contingencies	31
18. Accumulated Other Comprehensive Loss	35
19. Other, Net	36
20. Business Segment Information	36

5

PART I

ITEM 1. FINANCIAL STATEMENTS

NiSource Inc.

Condensed Statements of Consolidated Income (Loss) (unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
(in millions, except per share amounts)	2018			2017			2018			2017
Operating Revenues
Customer revenues	$	982.1		$	960.1		$	2,699.3		$	2,502.6
Other revenues	24.9			30.6			58.5			86.7
Total Operating Revenues	1,007.0			990.7			2,757.8			2,589.3
Operating Expenses
Cost of sales (excluding depreciation and amortization)	313.3			276.8			1,037.7			829.1
Operation and maintenance	365.2			391.6			767.7			803.2
Depreciation and amortization	144.6			142.2			289.3			285.5
Gain on sale of assets and impairments, net	—			(0.1		)	(0.3		)	(0.1		)
Other taxes	65.5			56.2			144.4			132.2
Total Operating Expenses	888.6			866.7			2,238.8			2,049.9
Operating Income	118.4			124.0			519.0			539.4
Other Income (Deductions)
Interest expense, net	(88.7		)	(87.7		)	(181.8		)	(172.9		)
Other, net	12.8			4.2			44.1			6.5
Loss on early extinguishment of long-term debt	(12.5		)	(111.5		)	(12.5		)	(111.5		)
Total Other Deductions, Net	(88.4		)	(195.0		)	(150.2		)	(277.9		)
Income (Loss) before Income Taxes	30.0			(71.0		)	368.8			261.5
Income Taxes	5.5			(26.6		)	68.2			94.6
Net Income (Loss)	24.5			(44.4		)	300.6			166.9
Preferred dividends	(1.3		)	—			(1.3		)	—
Net Income (Loss) Available to Common Shareholders	23.2			(44.4		)	299.3			166.9
Earnings (Loss) Per Share
Basic Earnings (Loss) Per Share	$	0.07		$	(0.14	)	$	0.86		$	0.51
Diluted Earnings (Loss) Per Share	$	0.07		$	(0.14	)	$	0.86		$	0.51
Dividends Declared Per Common Share	$	0.195		$	0.175		$	0.585		$	0.525
Basic Average Common Shares Outstanding	354.2			325.1			346.2			324.4
Diluted Average Common Shares	355.2			325.1			347.1			325.8

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

6

Table of Contents

ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

Condensed Statements of Consolidated Comprehensive Income (Loss) (unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
(in millions, net of taxes)	2018			2017			2018			2017
Net Income (Loss)	$	24.5		$	(44.4	)	$	300.6		$	166.9
Other comprehensive income:
Net unrealized gain (loss) on available-for-sale securities(1)	(0.7		)	0.6			(2.4		)	1.0
Net unrealized gain (loss) on cash flow hedges(2)	(1.4		)	(16.8		)	34.0			(11.9		)
Unrecognized pension and OPEB benefit(3)	0.2			0.2			0.4			0.4
Total other comprehensive income (loss)	(1.9		)	(16.0		)	32.0			(10.5		)
Comprehensive Income (Loss)	$	22.6		$	(60.4	)	$	332.6		$	156.4

⁽¹⁾ Net unrealized gain (loss) on available-for-sale securities, net of $0.2 million tax benefit and $0.4 million tax expense in the second quarter of 2018 and 2017, respectively, and $0.6 million tax benefit and $0.6 million tax expense for the six months ended 2018 and 2017, respectively.

⁽²⁾ Net unrealized gain (loss) on cash flow hedges, net of $0.5 million and $10.3 million tax benefit in the second quarter of 2018 and 2017, respectively, and $11.2 million tax expense and $7.3 million tax benefit for the six months ended 2018 and 2017, respectively. See Note 9, "Risk Management Activities," for additional information.

⁽³⁾ Unrecognized pension and OPEB benefit, net of $0.1 million and $0.2 million tax expense in the second quarter of 2018 and 2017, respectively, and $0.2 million and $0.3 million tax expense for the six months ended 2018 and 2017, respectively.

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 Consolidated Balance Sheets (unaudited)
(in millions)	June 30, 2018			December 31, 2017
ASSETS
Property, Plant and Equipment
Utility plant	$	21,914.8		$	21,026.6
Accumulated depreciation and amortization	(7,083.7		)	(6,953.6		)
Net utility plant	14,831.1			14,073.0
Other property, at cost, less accumulated depreciation	16.8			286.5
Net Property, Plant and Equipment	14,847.9			14,359.5
Investments and Other Assets
Unconsolidated affiliates	4.2			5.5
Other investments	199.6			204.1
Total Investments and Other Assets	203.8			209.6
Current Assets
Cash and cash equivalents	68.2			29.0
Restricted cash	12.9			9.4
Accounts receivable (less reserve of $24.2 and $18.3, respectively)	584.8			898.9
Gas inventory	182.8			285.1
Materials and supplies, at average cost	99.9			105.9
Electric production fuel, at average cost	53.8			80.1
Exchange gas receivable	29.6			45.8
Regulatory assets	174.6			176.3
Prepayments and other	109.1			132.8
Total Current Assets	1,315.7			1,763.3
Other Assets
Regulatory assets	1,918.7			1,624.9
Goodwill	1,690.7			1,690.7
Intangible assets, net	226.2			231.7
Deferred charges and other	104.9			82.0
Total Other Assets	3,940.5			3,629.3
Total Assets	$	20,307.9		$	19,961.7

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) (continued)
(in millions, except share amounts)	June 30, 2018			December 31, 2017
CAPITALIZATION AND LIABILITIES
Capitalization
Stockholders’ Equity
Common stock - $0.01 par value, 400,000,000 shares authorized; 362,915,039 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	394.4			—
Treasury stock	(99.9		)	(95.9		)
Additional paid-in capital	6,151.2			5,529.1
Retained deficit	(965.5		)	(1,073.1		)
Accumulated other comprehensive loss	(20.9		)	(43.4		)
Total Stockholders’ Equity	5,463.0			4,320.1
Long-term debt, excluding amounts due within one year	7,092.5			7,512.2
Total Capitalization	12,555.5			11,832.3
Current Liabilities
Current portion of long-term debt	597.7			284.3
Short-term borrowings	600.0			1,205.7
Accounts payable	455.0			625.6
Dividends payable	70.8			—
Customer deposits and credits	158.0			262.6
Taxes accrued	165.8			208.1
Interest accrued	103.3			112.3
Risk management liabilities	4.0			43.2
Exchange gas payable	36.9			59.6
Regulatory liabilities	121.5			58.7
Legal and environmental	36.0			32.1
Accrued compensation and employee benefits	135.8			195.4
Other accruals	75.6			90.8
Total Current Liabilities	2,560.4			3,178.4
Other Liabilities
Risk management liabilities	44.9			28.5
Deferred income taxes	1,396.7			1,292.9
Deferred investment tax credits	11.9			12.4
Accrued insurance liabilities	86.0			80.1
Accrued liability for postretirement and postemployment benefits	311.7			337.1
Regulatory liabilities	2,821.4			2,736.9
Asset retirement obligations	334.6			268.7
Other noncurrent liabilities	184.8			194.4
Total Other Liabilities	5,192.0			4,951.0
Commitments and Contingencies (Refer to Note 17, "Other Commitments and Contingencies")	—			—
Total Capitalization and Liabilities	$	20,307.9		$	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 Statements of Consolidated Cash Flows (unaudited)
Six Months Ended June 30, (in millions)	2018			2017
Operating Activities
Net Income	$	300.6		$	166.9
Adjustments to Reconcile Net Income to Net Cash from Operating Activities:
Loss on early extinguishment of debt	12.5			111.5
Depreciation and amortization	289.3			285.5
Deferred income taxes and investment tax credits	66.3			88.4
Other adjustments	11.3			22.4
Changes in Assets and Liabilities:
Components of working capital	12.4			(6.4		)
Regulatory assets/liabilities	141.7			23.2
Deferred charges and other noncurrent assets	1.2			(1.1		)
Other noncurrent liabilities	(25.8		)	(39.0		)
Net Cash Flows from Operating Activities	809.5			651.4
Investing Activities
Capital expenditures	(832.5		)	(732.2		)
Cost of removal	(46.1		)	(55.6		)
Purchases of available-for-sale securities	(46.8		)	(105.6		)
Sales of available-for-sale securities	47.5			106.6
Other investing activities	6.8			0.9
Net Cash Flows used for Investing Activities	(871.1		)	(785.9		)
Financing Activities
Issuance of long-term debt	350.0			2,000.0
Repayments of long-term debt and capital lease obligations	(491.2		)	(1,078.4		)
Premiums and other debt related costs	(15.2		)	(130.7		)
Issuance of short-term debt (maturity > 90 days)	600.0			—
Change in short-term borrowings, net (maturity ≤ 90 days)	(1,205.7		)	(586.7		)
Issuance of common stock	607.7			46.2
Issuance of preferred stock	394.4			—
Acquisition of treasury stock	(4.0		)	(5.9		)
Dividends paid - common stock	(131.7		)	(113.2		)
Net Cash Flows from Financing Activities	104.3			131.3
Change in cash, cash equivalents and restricted cash	42.7			(3.2		)
Cash, cash equivalents and restricted cash at beginning of period	38.4			36.0
Cash, Cash Equivalents and Restricted Cash at End of Period	$	81.1		$	32.8

Supplemental Disclosures of Cash Flow Information

Six Months Ended June 30, (in millions)	2018		2017
Non-cash transactions:
Capital expenditures included in current liabilities	$	191.9	$	206.9
Dividends declared but not paid	70.8		57.0
Reclassification of other property to regulatory assets(1)	245.3		—
Change in estimated costs of asset retirement obligations(2)	$	62.5	$	—

⁽¹⁾See Note 17-D "Other Matters" for additional information.

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

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 Equity (unaudited)

(in millions)	Common Stock		Preferred Stock		Treasury Stock			Additional Paid-In Capital		Retained Deficit			Accumulated Other Comprehensive Loss			Total
Balance as of January 1, 2018	$	3.4	$	—	$	(95.9	)	$	5,529.1	$	(1,073.1	)	$	(43.4	)	$	4,320.1
Comprehensive Income (Loss):
Net Income	—		—		—			—		300.6			—			300.6
Other comprehensive income, net of tax	—		—		—			—		—			32.0			32.0
Common stock dividends ($0.585 per share)	—		—		—			—		(202.5		)	—			(202.5		)
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	—		394.4		—			—		—			—			394.4
Employee stock purchase plan	—		—		—			2.7		—			—			2.7
Long-term incentive plan	—		—		—			8.2		—			—			8.2
401(k) and profit sharing	—		—		—			11.9		—			—			11.9
Balance as of June 30, 2018	$	3.7	$	394.4	$	(99.9	)	$	6,151.2	$	(965.5	)	$	(20.9	)	$	5,463.0

⁽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	400	—	—		—
Employee stock purchase plan	—	111	—		111
Long-term incentive plan	—	494	—		494
401(k) and profit sharing	—	496	—		496
Balance as of June 30, 2018	400	366,878	(3,963	)	362,915

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

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

11

Table of Contents

ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

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:

12

Table of Contents

ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

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

Standard	Description	Effective Date	Effect on the financial statements or other significant matters
ASU 2016-13, Financial Instruments-Credit Losses (Topic 326)	The pronouncement changes the impairment model for most financial assets, replacing the current "incurred loss" model. ASU 2016-13 will require the use of an "expected loss" model for instruments measured at amortized cost. It will also require entities to record allowances for available-for-sale 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).
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 are implementing a new lease accounting system, which we will utilize to capture, track, and account for lease data. We began system testing at the end of June 2018 and anticipate 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 tentatively expect to elect the "practical expedient package" described in ASC 842-10-65-1. We maintain a substantial number of easements and expect the provisions of ASU 2018-01 will ease the process of implementing ASC 842. We tentatively plan to elect the transition method provided in ASU 2018-11. We intend to 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 2018-02, 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 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 six months ended June 30, 2018 as if they had been prepared under historic accounting guidance. We included operating revenue information for the three and six months ended June 30, 2017 for comparability.

	Three Months Ended June 30,				Six Months Ended June 30,
(in millions)	2018		2017		2018		2017
Operating Revenues
Gas Distribution	$	384.2	$	327.1	$	1,368.0	$	1,163.6
Gas Transportation	216.9		204.9		559.1		543.5
Electric	405.0		458.0		828.3		879.7
Other	0.9		0.7		2.4		2.5
Total Operating Revenues	$	1,007.0	$	990.7	$	2,757.8	$	2,589.3

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 June 30, 2018 (in millions)	Gas Distribution Operations		Electric Operations		Corporate and Other		Total
Customer Revenues(1)
Residential	$	389.7	$	113.1	$	—	$	502.8
Commercial	127.0		116.6		—		243.6
Industrial	47.7		152.0		—		199.7
Off-system	20.9		—		—		20.9
Miscellaneous	10.2		4.7		0.2		15.1
Total Customer Revenues	$	595.5	$	386.4	$	0.2	$	982.1
Other Revenues	6.4		18.5		—		24.9
Total Operating Revenues	$	601.9	$	404.9	$	0.2	$	1,007.0

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

Six Months Ended June 30, 2018 (in millions)	Gas Distribution Operations		Electric Operations		Corporate and Other		Total
Customer Revenues(1)
Residential	$	1,283.3	$	227.6	$	—	$	1,510.9
Commercial	435.3		233.5		—		668.8
Industrial	122.3		314.5		—		436.8
Off-system	43.2		—		—		43.2
Miscellaneous	27.0		12.2		0.4		39.6
Total Customer Revenues	$	1,911.1	$	787.8	$	0.4	$	2,699.3
Other Revenues	18.1		40.4		—		58.5
Total Operating Revenues	$	1,929.2	$	828.2	$	0.4	$	2,757.8

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

Customer Accounts Receivable. Accounts receivable on our Condensed Consolidated Balance Sheets (unaudited) includes both billed and unbilled amounts as well as certain amounts that are not related to customer revenues. Unbilled amounts of accounts receivable relate to a portion of a customer’s consumption of gas or electricity from the date of the last cycle billing date through the last day of the month (balance sheet date). Factors taken into consideration when estimating unbilled revenue include historical usage, customer rates and weather. The opening and closing balances of customer receivables for the six months endedJune 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 June 30, 2018	373.6			155.1
Increase (Decrease)	$	(103.4	)	$	(200.9	)

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

⁽²⁾ Customer unbilled receivables decreased over the period due to the expected seasonal decrease in customer usage in June 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 calculation of diluted earnings per share excludes the impact of forward agreements (see Note 5, "Equity"), which had an anti-dilutive effect for the periods outstanding. The computation of diluted average common shares for the three months ended June 30, 2017 is not presented since we had a net loss on the Condensed Statements of Consolidated Income (Loss) (unaudited) during the period 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	Six Months Ended
	June 30,	June 30,
(in thousands)	2018	2018	2017
Denominator
Basic average common shares outstanding	354,229	346,165	324,386
Dilutive potential common shares:
Shares contingently issuable under employee stock plans	861	789	452
Shares restricted under employee stock plans	71	167	975
Diluted Average Common Shares	355,161	347,121	325,813

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. During the three and six months ended June 30, 2017, we issued 1,318,461 shares of common stock under the program at an average price of $25.88 per share, receiving proceeds, net of fees, of $33.8 million. There was no activity under the ATM program in 2018. As of June 30, 2018, the ATM program (including impacts of forward sales agreements discussed below) had approximately $10.0 million of equity available for issuance. The program expires on December 31, 2018.

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 June 30, 2018, we would have received approximately $169.4 million, based on a net price of $26.70 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.

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ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

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

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 $394.4 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 15, “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.    Gas in Storage

We use both the LIFO inventory methodology and the weighted-average cost methodology to value natural gas in storage. Gas Distribution Operations prices natural gas storage injections at the average of the costs of natural gas supply purchased during the year. For interim periods, the difference between current projected replacement cost and the LIFO cost for quantities of gas temporarily withdrawn from storage is recorded as a temporary LIFO liquidation credit or debit within the Condensed Consolidated Balance Sheets (unaudited). Due to seasonality requirements, we expect interim variances in LIFO layers to be replenished by year end. We had a temporary LIFO liquidation debit of $12.9 million and zero as of June 30, 2018 and December 31, 2017, respectively, for certain gas distribution companies recorded within “Prepayments and other,” on the Condensed Consolidated Balance Sheets (unaudited).

7.    Asset Retirement Obligations

In the second quarter of 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 $62.5 million that was recorded in June 2018. See Note 17-C, "Environmental Matters," for additional information on CCRs.

8.    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.

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ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

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

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 no later than October 15, 2018 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.

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 Commission-approved CEP deferrals. The audit of the CEP is expected to be completed by September 4, 2018 at which point we anticipate a full procedural schedule will be established.

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 Commission 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

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ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

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

agreement was filed with the IURC seeking, among other items, an annual revenue increase of $107.3 million. An order from the IURC is expected in the third quarter of 2018 with rates expected to be effective October 1, 2018 for Phase 1 implementation.

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 is requesting all associated accounting and ratemaking relief, including establishment of a periodic rate adjustment mechanism. An IURC order is expected in the third quarter of 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. The filing seeks approval of a total capital expenditure level of approximately $1.25 billion. An IURC order is expected in the fourth quarter of 2018.

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. An IURC order was expected in the second quarter of 2018, with new rates effective in July. 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 and held 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. 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. An order on the revised filing is expected in the third quarter of 2018. 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. Timing of this passback has not yet been determined.

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 is a proposal to adjust rates and address the regulatory liability disposition related to the TCJA. Rates are expected to go into effect March 1, 2019, upon approval from the Massachusetts DPU. On June 29, 2018, Columbia of Massachusetts filed a letter with a settlement negotiations update noting the Office of the Attorney General and Columbia of Massachusetts continue to discuss the possibility of a negotiated settlement.

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ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

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

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. Columbia of Massachusetts 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 an alternative calculation or a waiver to allow collection of the $3.1 million revenue requirement that exceeds the GSEP cap provision as previously calculated. On January 29, 2018, Columbia of Massachusetts filed a revision to its GSEP tracker for the 2018 construction season reducing the proposed revenue requirement to reflect the impact of the TCJA. The revenue requirement was reduced by $2.4 million due to the TCJA. An order was received from the Massachusetts DPU on April 30, 2018, approving an incremental revenue requirement of $6.1 million associated with the incremental capital investment of $83.9 million, with new rates effective May 1, 2018. The order did not approve the alternative cap calculation and the portion of the revenue requirement that exceeds the GSEP cap provision. On May 21, 2018, Columbia of Massachusetts filed a motion for reconsideration on the Massachusetts DPU’s denial of Columbia of Massachusetts’s request for a waiver on the 1.5% revenue cap calculation. On June 21, 2018, the Massachusetts DPU issued an order granting a waiver on the revenue cap allowing an incremental revenue requirement of $6.5 million with new rates effective July 1, 2018.

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 income 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. Since Columbia of Pennsylvania has a pending rate case, it is not required to implement the negative surcharge, and it has made a proposal in its pending rate case regarding the use of 2018 tax over-collection proceeds.

As highlighted above, on March 16, 2018, Columbia of Pennsylvania filed a rate case with the Pennsylvania PUC, seeking approval for an annual revenue increase of $46.9 million. Included in the filing is a proposal to adjust rates as a result of the TCJA. On March 21, 2018, Columbia of Pennsylvania filed a supplement to the rate case, under which it proposes 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. A decision on Columbia of Pennsylvania’s rate request is expected in the fourth quarter of 2018 with new rates 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. In addition, pursuant to the order, Columbia of Virginia is required to reflect the impacts of the TCJA in its annual informational filing, including: (1) the expected cost of service impacts through calendar year 2018; (2) the amount of protected and unprotected excess accumulated deferred income taxes as of December 31, 2017, and the estimated reversal of such excess deferred income taxes during calendar year 2018; and (3) such additional information that the utility wishes to include addressing the financial and cost of service impacts of the TCJA and the appropriate treatment of the accrued regulatory liabilities. On April 25, 2018 the VSCC, by order, supplemented the above annual informational filing requirements of the January 8, 2018 order to include a proposed rate reduction that reflects the cost savings from the TCJA. This April 25, 2018 order directs that if a utility desires to propose an alternative method for returning the tax savings to customers, then it may instead file a rate case that incorporates the income tax savings. As a result of these orders, Columbia of Virginia made the decision to file a rate case. This rate case is expected to be filed by August 28, 2018.

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 income 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 directs 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 accumulated deferred income taxes to be effective with the first billing cycle of October 2018.

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ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

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

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 income 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. An order from the PSC is expected in the fourth quarter of 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. The impact on NIPSCO electric of the Phase 2 investigation is unknown at this time.

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 in May 2019. NIPSCO is currently evaluating the impact of the WCE petition, including the associated impacts on revenue. NIPSCO anticipates filing an electric rate case in the fourth quarter of 2018, in part, to address anticipated revenue loss resulting from this filing. NIPSCO also anticipates filing an updated Integrated Resource Plan in the fourth quarter of 2018, which will evaluate demand-side and supply-side resource alternatives to reliably and cost effectively meet NIPSCO customers' future energy requirements over the ensuing 20 years.  

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 seeking an incremental semi-annual revenue decrease of $10.6 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 $3.5 million increase associated with $77.1 million of incremental capital expenditures from December 2017 through May 2018. An order approving the request is expected in the fourth quarter of 2018.

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ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

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

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 six months ended June 30, 2018, we recorded additional TCJA-related regulatory liabilities of $65.0 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 13, "Income Taxes," in 2018 we began amortizing regulatory liabilities associated with excess deferred income taxes, which resulted in a $7.4 million and $17.8 million income tax benefit for the three and six months ended June 30, 2018, respectively. Related to this activity, we recorded an offsetting reserve of $4.7 million and $12.4 million (net of tax) in "Customer revenues" to reflect the probable future passback of this earnings benefit to customers for the three and six months ended June 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 June 30, 2018.

Bailly Generating Station. During the six months ended June 30, 2018, we reclassified approximately $245 million from "Other property, at cost, less accumulated depreciation" to “Regulatory assets (noncurrent)” on the Condensed Consolidated Balance Sheets (unaudited) in connection with the retirement of Bailly Generating Station Units 7 and 8. Refer to Note 17-D, "Other Matters," in the Notes to Condensed Consolidated Financial Statements (unaudited) for additional information.

9.    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)	June 30, 2018		December 31, 2017
Risk Management Assets - Current(1)
Interest rate risk programs	$	1.7	$	14.0
Commodity price risk programs	0.5		0.5
Total	$	2.2	$	14.5
Risk Management Assets - Noncurrent(2)
Interest rate risk programs	$	23.5	$	5.6
Commodity price risk programs	1.8		1.0
Total	$	25.3	$	6.6
Risk Management Liabilities - Current
Interest rate risk programs	$	—	$	38.6
Commodity price risk programs	4.0		4.6
Total	$	4.0	$	43.2
Risk Management Liabilities - Noncurrent
Interest rate risk programs	$	—	$	—
Commodity price risk programs	44.9		28.5
Total	$	44.9	$	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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ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

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

Commodity Price Risk Management

We, along with our utility customers, are exposed to variability in cash flows associated with natural gas purchases and volatility in natural gas prices. We purchase natural gas for sale and delivery to our retail, commercial and industrial customers, and for most customers the variability in the market price of gas is passed through in their rates. Some of our utility subsidiaries offer programs whereby variability in the market price of gas is assumed by the respective utility. The objective of our commodity price risk programs is to mitigate the gas cost variability, for us or on behalf of our customers, associated with natural gas purchases or sales by economically hedging the various gas cost components using a combination of futures, options, forwards or other derivative contracts.

NIPSCO received IURC approval to lock in a fixed price for its natural gas customers using long-term forward purchase instruments. The term of these instruments 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 June 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 March 2018, we initiated settlement of 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 June 30, 2018 and December 31, 2017.

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

10.    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 June 30, 2018 and December 31, 2017:

Recurring Fair Value Measurements June 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 June 30, 2018
Assets
Risk management assets	$	—	$	27.4	$	0.1	$	27.5
Available-for-sale securities	—		130.1		—		130.1
Total	$	—	$	157.5	$	0.1	$	157.6
Liabilities
Risk management liabilities	$	—	$	48.9	$	—	$	48.9
Total	$	—	$	48.9	$	—	$	48.9

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ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

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

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 June 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 9, "Risk Management Activities."

NIPSCO has entered into long-term forward natural gas purchase instruments that range from five to ten years to lock in a fixed price for its natural gas customers. We value these contracts using a pricing model that incorporates market-based information when available, as these instruments trade less frequently and are classified within Level 2 of the fair value hierarchy. For additional information, see Note 9, “Risk Management Activities.”

Available-for-sale securities are investments pledged as collateral for trust accounts related to our wholly-owned insurance company. Available-for-sale securities are included within “Other investments” in the 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 June 30, 2018 and December 31, 2017 were:

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ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

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

June 30, 2018 (in millions)	Amortized Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
Available-for-sale securities
U.S. Treasury debt securities	$	16.8	$	—	$	(0.1	)	$	16.7
Corporate/Other debt securities	116.1		0.3		(3.0		)	113.4
Total	$	132.9	$	0.3	$	(3.1	)	$	130.1
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 six months ended June 30, 2018 and 2017.

The cost of maturities sold is based upon specific identification. At June 30, 2018, approximately $3.2 million of U.S. Treasury debt securities and approximately $3.7 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 six months ended June 30, 2018 and 2017.

Non-recurring Fair Value Measurements. There were no significant non-recurring fair value measurements recorded during the three and six months ended June 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 six months endedJune 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 June 30, 2018		Estimated Fair Value as of June 30, 2018		Carrying Amount as of Dec. 31, 2017		Estimated Fair Value as of Dec. 31, 2017
Long-term debt (including current portion)	$	7,690.2	$	7,996.1	$	7,796.5	$	8,603.4

11.    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 August 2018 and March 2019 and may be further extended if mutually agreed to by the parties thereto.

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ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

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

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 June 30, 2018, the maximum amount of debt that could be recognized related to our accounts receivable programs is $320.0 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 June 30, 2018 and December 31, 2017:

(in millions)	June 30, 2018		December 31, 2017
Gross Receivables	$	470.7	$	635.3
Less: Receivables not transferred	470.7		298.6
Net receivables transferred	$	—	$	336.7
Short-term debt due to asset securitization	$	—	$	336.7

For the six months ended June 30, 2018 and 2017, $336.7 million and $11.7 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 $0.7 million and $0.6 million for the three months ended June 30, 2018 and 2017, respectively and $1.5 million and $1.3 million for the six months ended June 30, 2018 and 2017, respectively. We remain responsible for collecting on the receivables securitized, and the receivables cannot be transferred to another party.

12.Goodwill

The following presents our goodwill balance allocated by segment as of June 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.

13.    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 June 30, 2018 and 2017 were 18.3% and 37.5%, respectively. The effective tax rates for six months endedJune 30, 2018 and 2017 were 18.5% and 36.2%, 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 decrease in the three month effective tax rate in 2018 versus the same period in 2017 is primarily due to the change in the Federal statutory rate due to the enactment of the TCJA. Additionally, 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 $7.4 million and $17.8 million for the three and six months ended June 30, 2018, respectively. Refer to Note 8, "Regulatory Matters," for additional information.

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

14.    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 six months ended June 30, 2018, we contributed $1.4 million to our pension plans and $11.3 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 six months ended June 30, 2018 and 2017:

	Pension Benefits						Other Postretirement Benefits
Three Months Ended June 30, (in millions)	2018			2017			2018			2017
Components of Net Periodic Benefit Cost(1)
Service cost	$	7.9		$	7.5		$	1.3		$	1.2
Interest cost	16.6			17.2			4.4			4.4
Expected return on assets	(36.2		)	(30.2		)	(3.7		)	(3.9		)
Amortization of prior service credit	(0.1		)	(0.2		)	(1.0		)	(1.1		)
Recognized actuarial loss	10.2			13.4			0.9			0.7
Settlement loss	3.5			—			—			—
Total Net Periodic Benefit Cost	$	1.9		$	7.7		$	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
Six Months Ended June 30, (in millions)	2018			2017			2018			2017
Components of Net Periodic Benefit Cost(1)
Service cost	$	15.8		$	15.0		$	2.6		$	2.4
Interest cost	33.2			34.4			8.8			8.9
Expected return on assets	(72.5		)	(60.5		)	(7.4		)	(7.9		)
Amortization of prior service credit	(0.2		)	(0.4		)	(2.0		)	(2.2		)
Recognized actuarial loss	20.4			26.8			1.8			1.5
Settlement loss	3.5			—			—			—
Total Net Periodic Benefit Cost	$	0.2		$	15.3		$	3.8		$	2.7

⁽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 the settlement, these 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 loss of $0.1 million. Net periodic pension benefit cost for 2018 increased by $1.1 million as a result of the interim 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 account at the measurement dates of May 31, 2018 and December 31, 2017:

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

15.    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 anticipate recording a $33.0 million loss on early extinguishment of long-term debt, primarily attributable to early redemption premiums.

16.    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 June 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 no commercial paper outstanding as of June 30, 2018 and $869.0 million outstanding as of December 31, 2017.

As of June 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 no transfers as of June 30, 2018 and $336.7 million as of December 31, 2017. Refer to Note 11, "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)	June 30, 2018		December 31, 2017
Commercial paper weighted-average interest rate of 1.97% at December 31, 2017	$	—	$	869.0
Accounts receivable securitization facility borrowings	—		336.7
Term loan weighted-average interest rate of 2.64% at June 30, 2018	600.0		—
Total Short-Term Borrowings	$	600.0	$	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.

17.    Other Commitments and Contingencies

A. Guarantees and Indemnities. We and certain of our subsidiaries enter into various agreements providing financial or performance assurance to third parties on behalf of certain subsidiaries as a part of normal business. Such agreements include guarantees and stand-by letters of credit. These agreements are entered into primarily to support or enhance the creditworthiness otherwise attributed to a subsidiary on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish the subsidiaries’ intended commercial purposes. As of June 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. We are party to certain 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 June 30, 2018 and December 31, 2017, we had recorded a liability of approximately $109.7 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 November 1, 2016. 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

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ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

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

for natural gas facilities could restrict GHG emissions and impose additional costs. We carefully monitor all GHG reduction proposals and regulations.

Clean Power Plan. On October 23, 2015, the EPA issued a final rule to regulate CO2 emissions from existing fossil-fuel EGUs under section 111(d) of the CAA. The final rule establishes national CO2 emission-rate standards that are applied to each state’s mix of affected EGUs to establish state-specific emission-rate and mass-emission limits. The final rule requires each state to submit a plan indicating how the state will meet the EPA's emission-rate or mass-emission limit, including possibly imposing reduction obligations on specific units. If a state does not submit a satisfactory plan, the EPA will impose a federal plan on that state.

On February 9, 2016, the U.S. Supreme Court stayed implementation of the CPP until litigation is decided on its merits. On October 16, 2017, the EPA published in the Federal Register a Notice of Proposed Rulemaking that would repeal the CPP. On December 28, 2017, in a separate but related action, the EPA published an Advanced Notice of Proposed Rulemaking in the Federal Register to solicit information from the public about a potential future rulemaking to limit greenhouse gas emissions from existing fossil-fuel EGUs. NIPSCO will continue to monitor this matter and cannot estimate its impact at this time. Should costs be incurred to comply with the CPP, NIPSCO believes such costs will be eligible for recovery through customer rates.

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 $105.5 million and $106.9 million at June 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 will be required to incur future 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.

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ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

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

Water

ELG. On November 3, 2015, the EPA issued a final rule to amend the ELG and standards for the Steam Electric Power Generating category. The final rule became effective January 4, 2016. 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. On November 1, 2016, NIPSCO filed a petition with the IURC seeking approval of the projects and recovery of the costs associated with ELG compliance. Given the current postponement of certain compliance dates under the ELG rule, NIPSCO has agreed with the settling parties, as part of the settlement agreement discussed in the "CCRs" subsection above, that these ELG projects and related costs would be addressed in a later proceeding.

D. Other Matters.

NIPSCO 2016 Integrated Resource Plan.Environmental, regulatory and economic factors, including low natural gas prices and aging coal-fired units, have led NIPSCO to pursue modification of its current electric generation supply mix to include less coal-fired generation. Due to enacted CCR and ELG (subsequently postponed) regulations, NIPSCO would expect to have incurred over $1 billion in operating, maintenance, environmental and other costs if the current fleet of coal-fired generating units were to remain operational.

On November 1, 2016, NIPSCO submitted its 2016 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. The 2016 Integrated Resource Plan indicated that the most viable option for customers and NIPSCO involves the retirement of Bailly Generating Station (Units 7 and 8) as soon as mid-2018 and two units (Units 17 and 18) at the R.M. Schahfer Generating Station by 2023. It is projected over the long term that the cost to customers to retire these units at these dates will be lower than maintaining and upgrading them for continued generation.

We committed to the retirement of the Bailly Generating Station units in connection with the filing of the 2016 Integrated Resource Plan, pending approval by the MISO. In the fourth quarter of 2016, the MISO approved NIPSCO's plan to retire the Bailly Generating Station units by May 31, 2018.

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.

NIPSCO anticipates updating its Integrated Resource Plan in a filing by the end of 2018.

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 $7.6 million and $10.4 million for the six months endedJune 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.

As further discussed above in this Note 17 under the heading "NIPSCO 2016 Integrated Resource Plan," 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

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ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

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

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).

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ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.

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

18.    Accumulated Other Comprehensive Loss

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

Three Months Ended June 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 Loss(1)
Balance as of April 1, 2018	$	(1.5	)	$	(0.3	)	$	(17.2	)	$	(19.0	)
Other comprehensive income (loss) before reclassifications	(0.6		)	(2.0		)	0.6			(2.0		)
Amounts reclassified from accumulated other comprehensive loss	(0.1		)	0.6			(0.4		)	0.1
Net current-period other comprehensive income (loss)	(0.7		)	(1.4		)	0.2			(1.9		)
Balance as of June 30, 2018	$	(2.2	)	$	(1.7	)	$	(17.0	)	$	(20.9	)
Six Months Ended June 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 Loss(1)
Balance as of January 1, 2018	$	0.2		$	(29.4	)	$	(14.2	)	$	(43.4	)
Other comprehensive income (loss) before reclassifications	(2.5		)	49.1			—			46.6
Amounts reclassified from accumulated other comprehensive loss(2)	0.1			(15.1		)	0.4			(14.6		)
Net current-period other comprehensive income (loss)	(2.4		)	34.0			0.4			32.0
Reclassification due to adoption of ASU 2018-02 (Refer to Note 2)	—			(6.3		)	(3.2		)	(9.5		)
Balance as of June 30, 2018	$	(2.2	)	$	(1.7	)	$	(17.0	)	$	(20.9	)

Three Months Ended June 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 April 1, 2017	$	(0.2	)	$	(2.0	)	$	(17.4	)	$	(19.6	)
Other comprehensive income (loss) before reclassifications	0.8			(18.2		)	0.1			(17.3		)
Amounts reclassified from accumulated other comprehensive loss	(0.2		)	1.4			0.1			1.3
Net current-period other comprehensive income (loss)	0.6			(16.8		)	0.2			(16.0		)
Balance as of June 30, 2017	$	0.4		$	(18.8	)	$	(17.2	)	$	(35.6	)
Six Months Ended June 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	1.0			(13.6		)	0.2			(12.4		)
Amounts reclassified from accumulated other comprehensive loss	—			1.7			0.2			1.9
Net current-period other comprehensive income (loss)	1.0			(11.9		)	0.4			(10.5		)
Balance as of June 30, 2017	$	0.4		$	(18.8	)	$	(17.2	)	$	(35.6	)

⁽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 9 "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)

19.    Other, Net

	Three Months Ended June 30,					Six Months Ended June 30,
(in millions)	2018		2017			2018		2017
Interest Income	$	1.1	$	0.9		$	2.8	$	1.8
AFUDC Equity	3.9		3.7			7.6		6.2
Pension and other postretirement non-service cost	6.1		0.5			12.3		1.7
Interest rate swap settlement gain(1)	—		—			21.2		—
Miscellaneous	1.7		(0.9		)	0.2		(3.2		)
Total Other, net	$	12.8	$	4.2		$	44.1	$	6.5

⁽¹⁾See Note 9, "Risk Management Activities," for additional information.

20.    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 June 30,						Six Months Ended June 30,
(in millions)	2018			2017			2018			2017
Operating Revenues
Gas Distribution Operations
Unaffiliated	$	601.9		$	532.5		$	1,929.2		$	1,708.8
Intersegment	3.2			3.6			6.5			7.1
Total	605.1			536.1			1,935.7			1,715.9
Electric Operations
Unaffiliated	404.9			458.0			828.2			879.7
Intersegment	0.2			0.2			0.4			0.4
Total	405.1			458.2			828.6			880.1
Corporate and Other
Unaffiliated	0.2			0.2			0.4			0.8
Intersegment	116.1			121.7			230.2			241.3
Total	116.3			121.9			230.6			242.1
Eliminations	(119.5		)	(125.5		)	(237.1		)	(248.8		)
Consolidated Operating Revenues	$	1,007.0		$	990.7		$	2,757.8		$	2,589.3
Operating Income (Loss)
Gas Distribution Operations	$	39.1		$	43.7		$	360.8		$	382.5
Electric Operations	82.4			85.6			165.5			163.2
Corporate and Other	(3.1		)	(5.3		)	(7.3		)	(6.3		)
Consolidated Operating Income	$	118.4		$	124.0		$	519.0		$	539.4

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Index	Page
Executive Summary	38
Summary of Consolidated Financial Results	38
Results and Discussion of Segment Operations	41
Gas Distribution Operations	42
Electric Operations	45
Liquidity and Capital Resources	48
Off Balance Sheet Arrangements	49
Market Risk Disclosures	50
Other Information	51

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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.

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.

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For the three and six months endedJune 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 June 30,							Six Months Ended June 30,
(in millions)	2018		2017		2018 vs. 2017			2018		2017		2018 vs. 2017
Operating Income	$	118.4	$	124.0	$	(5.6	)	$	519.0	$	539.4	$	(20.4	)

	Three Months Ended June 30,									Six Months Ended June 30,
(in millions, except per share amounts)	2018			2017			2018 vs. 2017			2018			2017			2018 vs. 2017
Operating Revenues	$	1,007.0		$	990.7		$	16.3		$	2,757.8		$	2,589.3		$	168.5
Cost of Sales (excluding depreciation and amortization)	313.3			276.8			36.5			1,037.7			829.1			208.6
Total Net Revenues	693.7			713.9			(20.2		)	$	1,720.1		$	1,760.2		$	(40.1	)
Other Operating Expenses	575.3			589.9			(14.6		)	1,201.1			1,220.8			(19.7		)
Operating Income	118.4			124.0			(5.6		)	519.0			539.4			(20.4		)
Total Other Deductions	(88.4		)	(195.0		)	106.6			(150.2		)	(277.9		)	127.7
Income Taxes	5.5			(26.6		)	32.1			68.2			94.6			(26.4		)
Net Income (Loss)	24.5			(44.4		)	68.9			300.6			166.9			133.7
Preferred dividends	(1.3		)	—			(1.3		)	(1.3		)	—			(1.3		)
Net Income Available to Common Shareholders	23.2			(44.4		)	67.6			299.3			166.9			132.4
Basic Earnings (Loss) Per Share	$	0.07		$	(0.14	)	$	0.21		$	0.86		$	0.51		$	0.35
Basic Average Common Shares Outstanding	354.2			325.1			29.1			346.2			324.4			21.8

On a consolidated basis, we reported net income available to common shareholders of $23.2 million, or $0.07 per basic share for the three months ended June 30, 2018, compared to a net loss available to common shareholders of $44.4 million, or $0.14 per basic share for the same period in 2017. The increase in net income available to common shareholders during 2018 was due primarily to a loss on early extinguishment of long-term debt in 2017 and decreased income taxes and operating expenses, partially offset by a decrease in net revenues as discussed below.

For the three months ended June 30, 2018, we reported operating income of $118.4 million compared to $124.0 million for the same period in 2017. The lower operating income was primarily due to decreased net revenues, attributable to a regulatory revenue reserve in 2018 resulting from the probable future refund of certain collections and new rates as a result of implementation of regulatory outcomes related to the lower income tax rate under the TCJA. These decreases were offset by increased net revenues due to weather variability between the three months ended June 30, 2018 compared to the same period in 2017, as well as from new rates from infrastructure replacement programs. Other operating expenses decreased due to lower outside service costs and employee and administrative costs, partially offset by higher depreciation expense.

On a consolidated basis, we reported net income available to common shareholders of $299.3 million, or $0.86 per basic share for the six months endedJune 30, 2018, compared to $166.9 million, or $0.51 per basic share for the same period in 2017. The increase in net income available to common shareholders during 2018 was due primarily to a loss on early extinguishment of long-term debt in 2017 and decreased income taxes and operating expenses partially offset by a decrease in net revenues as discussed below.

For the six months endedJune 30, 2018, we reported operating income of $519.0 million compared to $539.4 million for the same period in 2017. The lower operating income was primarily due to decreased net revenues, attributable to a regulatory revenue reserve in 2018 resulting from the probable future refund of certain collections and new rates as a result of implementation of regulatory outcomes related to the lower income tax rate under the TCJA. These decreases were offset by increased net revenues due to weather variability between the six months ended June 30, 2018 compared to the same period in 2017, as well as from new rates from infrastructure replacement programs. Other operating expenses decreased due to lower outside service and materials and supplies costs, partially offset by higher depreciation expense.

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Other Income (Deductions), net

Other income (deductions), net reduced income by $88.4 million in the second quarter of 2018 compared to a reduction in income of $195.0 million in the prior year. This change is primarily due to a loss on early extinguishment of long-term debt of $111.5 million during the second quarter of 2017.

Other income (deductions), net reduced income by $150.2 million in the six months ended June 30, 2018 compared to a reduction in income of $277.9 million in the prior year. This change is primarily due to a loss on early extinguishment of long-term debt of $111.5 million during the second quarter of 2017.

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 and the effect of amortizing the regulatory liability associated with excess deferred income taxes.

Refer to “Liquidity and Capital Resources” below and Note 13, "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 six months endedJune 30, 2018, we invested $832.5 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. 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 and capital expenditures in 2018 and beyond. At June 30, 2018 and December 31, 2017, we had $2,228.0 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 June 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 second quarter of 2018:

Gas Distribution Operations

• NIPSCO is awaiting an order on the settlement with parties on its base rate case pending before the IURC. The request, which seeks NIPSCO's first natural gas base rate increase in more than 25 years, supports continued investment in system upgrades, technology improvements and other measures to increase pipeline safety and system reliability. If the settlement is approved as filed, it will 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. An order is expected from the IURC in the third quarter of 2018.

• NIPSCO's application for a new seven-year gas infrastructure modernization program remains pending before the IURC. The filing represents approximately $1.25 billion of gas infrastructure investments through 2025. The program allows for modernization of underground natural gas infrastructure and recovery of associated costs through the TDSIC. An

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IURC order on the new seven-year plan is expected in the fourth quarter of 2018. On July 18, 2018, NIPSCO filed its latest revised TDSIC-8, covering approximately $54 million of investments made in the second half of 2017. This request remains pending before the IURC with an order expected the third quarter of 2018.

• Columbia of Pennsylvania's base rate case remains pending before the Pennsylvania PUC. Filed on March 16, 2018, the request seeks approval for an annual revenue increase of $46.9 million to upgrade and replace the underground natural gas distribution pipelines and enhance pipeline safety. An order is expected in the fourth quarter of 2018 with new rates to be implemented in December 2018.

• On April 25, 2018, the PUCO approved Columbia of Ohio’s annual IRP tracker adjustment. The order allowed recovery to begin on approximately $207 million of infrastructure investments made in 2017 with the May 2018 billing cycle. This well-established pipeline replacement program covers replacement of priority mainline pipe and targeted customer service lines.

• Columbia of Massachusetts' base rate case remains pending before the Massachusetts DPU. The request, filed April 13, 2018, seeks authorization to increase base rates to recover operating costs associated with federal and state regulatory mandates and capital costs associated with upgrading its gas distribution infrastructure. If approved as filed, the request would increase annual revenues by $24.1 million, net of infrastructure trackers and impacts of the TCJA. If approved, rates are expected to go into effect March 1, 2019.

• Also at Columbia of Massachusetts, the Massachusetts DPU approved the 2018 GSEP on April 30, 2018. This approval authorizes recovery of incremental capital investments of $83.9 million. New rates were effective May 1, 2018.

• On July 31, 2018, Columbia of Maryland filed a settlement in its base rate case pending before the Maryland PSC. 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.

Electric Operations

• 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. On January 30, 2018, NIPSCO filed its latest tracker update request, covering $75.0 million in incremental investments made from May 2017 through November 2017. The filing was approved by the IURC on May 30, 2018 with rates in effect with the first billing cycle of June 2018. NIPSCO filed its latest update request on July 31, 2018 seeking a semi-annual incremental rate decrease of $10.6 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 approving the request is expected in the fourth quarter of 2018.

• NIPSCO's two major transmission projects were completed and placed into service in June 2018. The 100-mile 345-kV and 65-mile 765-kV projects are expected to enhance region-wide system flexibility and reliability, and represent an investment of approximately $600 million.

Refer to Note 8, “Regulatory Matters,” as well as to Note 17, "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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Gas Distribution Operations

For the three and six months endedJune 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 June 30,							Six Months Ended June 30,
(in millions)	2018		2017		2018 vs. 2017			2018		2017		2018 vs. 2017
Operating Income	$	39.1	$	43.7	$	(4.6	)	$	360.8	$	382.5	$	(21.7	)

	Three Months Ended June 30,									Six Months Ended June 30,
(in millions)	2018			2017			2018 vs. 2017			2018			2017			2018 vs. 2017
Net Revenues
Operating Revenues	$	605.1		$	536.1		$	69.0		$	1,935.7		$	1,715.9		$	219.8
Less: Cost of gas sold (excluding depreciation and amortization)	197.6			131.2			66.4			789.4			567.4			222.0
Net Revenues	407.5			404.9			2.6			1,146.3			1,148.5			(2.2		)
Operating Expenses
Operation and maintenance	248.5			253.2			(4.7		)	535.7			537.7			(2.0		)
Depreciation and amortization	71.8			66.3			5.5			142.5			131.6			10.9
Other taxes	48.1			41.7			6.4			107.3			96.7			10.6
Total Operating Expenses	368.4			361.2			7.2			785.5			766.0			19.5
Operating Income	$	39.1		$	43.7		$	(4.6	)	$	360.8		$	382.5		$	(21.7	)
Revenues
Residential	$	387.6		$	338.4		$	49.2		$	1,280.6		$	1,140.2		$	140.4
Commercial	126.9			105.3			21.6			435.8			375.1			60.7
Industrial	47.8			45.3			2.5			122.5			116.8			5.7
Off-System	20.9			35.8			(14.9		)	43.2			66.7			(23.5		)
Other	21.9			11.3			10.6			53.6			17.1			36.5
Total	$	605.1		$	536.1		$	69.0		$	1,935.7		$	1,715.9		$	219.8
Sales and Transportation (MMDth)
Residential	39.0			29.2			9.8			174.1			142.7			31.4
Commercial	30.0			24.6			5.4			112.2			94.0			18.2
Industrial	140.1			121.6			18.5			285.6			254.4			31.2
Off-System	6.8			11.9			(5.1		)	14.4			22.7			(8.3		)
Other	0.2			—			0.2			0.3			(0.1		)	0.4
Total	216.1			187.3			28.8			586.6			513.7			72.9
Heating Degree Days	624			457			167			3,447			2,836			611
Normal Heating Degree Days	599			599			—			3,491			3,491			—
% (Warmer) Colder than Normal	4		%	(24		)%				(1		)%	(19		)%
Gas Distribution Customers
Residential										3,149,948			3,122,349			27,599
Commercial										278,251			277,187			1,064
Industrial										6,193			6,203			(10		)
Other										3			—			3
Total										3,434,395			3,405,739			28,656

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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 June 30, 2018 vs. June 30, 2017 Operating Income

For the three months ended June 30, 2018, Gas Distribution Operations reported operating income of $39.1 million, a decrease of $4.6 million from the comparable 2017 period.

Net revenues for the three months ended June 30, 2018 were $407.5 million, an increase of $2.6 million from the same period in 2017. The change in net revenues was primarily driven by:

• The effects of colder weather in 2018 of $10.3 million.

• New rates from infrastructure replacement programs of $8.5 million.

• The effects of increased customer usage and growth of $5.3 million.

• Higher regulatory, tax and depreciation trackers, which are offset in operating expense, of $2.9 million.

Partially offset by:

• A regulatory 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 $18.8 million.

• Decreased rates from implementation of regulatory outcomes related to the TCJA of $6.4 million.

Operating expenses were $7.2 million higher for the three months ended June 30, 2018 compared to the same period in 2017. This change was primarily driven by:

• Increased depreciation of $5.1 million due to higher capital expenditures placed in service.

• Higher regulatory, tax and depreciation trackers, which are offset in net revenues, of $2.9 million.

• Increased property taxes of $2.3 million.

Partially offset by:

•Decreased employee and administrative expenses of $3.7 million.

Six months ended June 30, 2018 vs. June 30, 2017 Operating Income

For the six months endedJune 30, 2018, Gas Distribution Operations reported operating income of $360.8 million, a decrease of $21.7 million from the comparable 2017 period.

Net revenues for the six months endedJune 30, 2018 were $1,146.3 million, a decrease of $2.2 million from the same period in 2017. The change in net revenues was primarily driven by:

• A regulatory 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 $66.5 million.

• Decreased rates from implementation of regulatory outcomes related to the TCJA of $6.4 million.

Partially offset by:

• The effects of colder weather in 2018 of $34.9 million.

• New rates from infrastructure replacement programs of $20.5 million.

• Increased customer usage and growth of $11.7 million.

Operating expenses were $19.5 million higher for the six months endedJune 30, 2018 compared to the same period in 2017. This change was primarily driven by:

• Increased depreciation of $10.2 million due to higher capital expenditures placed in service.

• Higher employee and administrative expenses of $3.8 million.

• Increased property taxes of $2.6 million.

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Gas Distribution Operations

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 second quarter of 2018 was about 4% colder than normal and about 37% colder than 2017, leading to increased net revenues of $10.3 million for the quarter ended June 30, 2018 compared to the same period in 2017.

Weather in the Gas Distribution Operations service territories for the six months ended June 30, 2018 was about 1% warmer than normal and about 22% colder than in 2017, leading to increased net revenues of $34.9 million for the six months endedJune 30, 2018 compared to the same period in 2017.

Throughput

Total volumes sold and transported for the second quarter of 2018 were 216.1 MMDth, compared to 187.3 MMDth for the same period in 2017. This 15%increase is primarily attributable to the effects of colder weather and increased industrial usage due to energy production from electric generating customers in 2018.

Total volumes sold and transported for the six months ended June 30, 2018 were 586.6 MMDth, compared to 513.7 MMDth for the same period in 2017. This 14%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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Electric Operations

For the three and six months endedJune 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 June 30,							Six Months Ended June 30,
(in millions)	2018		2017		2018 vs. 2017			2018		2017		2018 vs. 2017
Operating Income	$	82.4	$	85.6	$	(3.2	)	$	165.5	$	163.2	$	2.3

	Three Months Ended June 30,									Six Months Ended June 30,
(in millions)	2018			2017			2018 vs. 2017			2018			2017			2018 vs. 2017
Net Revenues
Operating revenues	$	405.1		$	458.2		$	(53.1	)	$	828.6		$	880.1		$	(51.5	)
Less: Cost of sales (excluding depreciation and amortization)	115.6			145.7			(30.1		)	248.3			261.9			(13.6		)
Net Revenues	289.5			312.5			(23.0		)	580.3			618.2			(37.9		)
Operating Expenses
Operation and maintenance	128.3			145.3			(17.0		)	254.5			284.1			(29.6		)
Depreciation and amortization	64.5			70.2			(5.7		)	130.0			142.2			(12.2		)
Other taxes	14.3			11.4			2.9			30.3			28.7			1.6
Total Operating Expenses	207.1			226.9			(19.8		)	414.8			455.0			(40.2		)
Operating Income	$	82.4		$	85.6		$	(3.2	)	$	165.5		$	163.2		$	2.3
Revenues
Residential	$	113.1		$	110.0		$	3.1		$	227.6		$	225.7		$	1.9
Commercial	116.6			123.7			(7.1		)	233.5			244.4			(10.9		)
Industrial	152.2			180.8			(28.6		)	314.9			359.9			(45.0		)
Wholesale	3.9			2.5			1.4			8.6			5.3			3.3
Other	19.3			41.2			(21.9		)	44.0			44.8			(0.8		)
Total	$	405.1		$	458.2		$	(53.1	)	$	828.6		$	880.1		$	(51.5	)
Sales (Gigawatt Hours)
Residential	844.7			769.0			75.7			1,633.1			1,521.6			111.5
Commercial	943.7			930.4			13.3			1,849.4			1,825.4			24.0
Industrial	2,228.7			2,438.5			(209.8		)	4,562.5			4,801.8			(239.3		)
Wholesale	41.5			1.7			39.8			92.3			21.9			70.4
Other	27.3			31.7			(4.4		)	60.5			65.1			(4.6		)
Total	4,085.9			4,171.3			(85.4		)	8,197.8			8,235.8			(38.0		)
Cooling Degree Days	392			264			128			392			264			128
Normal Cooling Degree Days	229			229						229			229
% Warmer than Normal	71		%	15		%				71		%	15		%
Electric Customers
Residential										410,064			407,406			2,658
Commercial										56,321			55,804			517
Industrial										2,295			2,309			(14		)
Wholesale										738			743			(5		)
Other										2			2			—
Total										469,420			466,264			3,156

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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 June 30, 2018 vs. June 30, 2017 Operating Income

For the three months ended June 30, 2018, Electric Operations reported operating income of $82.4 million, a decrease of $3.2 million from the comparable 2017 period.

Net revenues for the three months ended June 30, 2018 were $289.5 million, a decrease of $23.0 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 $11.0 million.

• Decreased rates from implementation of regulatory outcomes related to the TCJA of $8.6 million.

• Lower industrial and commercial usage of $6.8 million.

• A regulatory 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 $3.8 million.

Partially offset by:

• The effects of warmer weather of $6.5 million.

• Increased rates from infrastructure replacement programs of $6.0 million.

Operating expenses were $19.8 million lower for the three months ended June 30, 2018 compared to the same period in 2017. This change was primarily driven by:

• Decreased outside service costs of $11.4 million on lower generation-related maintenance activities.

• Lower regulatory and depreciation trackers, which are offset in net revenues, of $11.0 million.

Six months ended June 30, 2018 vs. June 30, 2017 Operating Income

For the six months endedJune 30, 2018, Electric Operations reported operating income of $165.5 million, an increase of $2.3 million from the comparable 2017 period.

Net revenues for the six months endedJune 30, 2018 were $580.3 million, a decrease of $37.9 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 $24.2 million.

• A regulatory 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 rates from implementation of regulatory outcomes related to the TCJA of $8.6 million.

• Increased fuel handling costs of $5.9 million.

• Decreased industrial usage of $5.5 million.

Partially offset by:

• Increased rates from infrastructure replacement programs of $11.4 million.

• The effects of warmer weather of $9.5 million.

Operating expenses were $40.2 million lower for the six months endedJune 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 $24.2 million.

• Decreased outside service costs of $15.7 million and lower materials and supplies costs of $5.0 million primarily related to lower generation-related maintenance activities.

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

NiSource Inc.

Electric Operations

Partially offset by:

• Increased depreciation of $5.3 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 second quarter of 2018 was about 71% warmer than normal and about 48% warmer than in 2017, resulting in increased net revenues of $6.5 million for the quarter ended June 30, 2018 compared to the same period in 2017.

Weather in the Electric Operations' territories for the six months ended June 30, 2018 was about 71% warmer than normal and about 48% warmer than 2017, resulting in increased net revenues of $9.5 million for the six months ended June 30, 2018 compared to 2017.

Sales

Electric Operations sales for the second quarter of 2018 were 4,085.9 gwh, a decrease of 85.4 gwh compared to the same period in 2017.

Electric Operations sales for the six months ended June 30, 2018 were 8,197.8 gwh, a decrease of 38.0 gwh compared to the same period in 2017.

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 in May 2019. Refer to Note 8, "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 2016 Integrated Resource Plan. 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). On May 31, 2018, Units 7 and 8 were retired from service. Refer to Note 17-D, "Other Matters," in the Notes to Condensed Consolidated Financial Statements (unaudited) for additional information.

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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

Operating Activities

Net cash from operating activities for the six months endedJune 30, 2018 was $809.5 million, an increase of $158.1 million compared to the six months endedJune 30, 2017. This increase was driven by changes in gas prices, which impacted regulatory assets and regulatory liabilities as discussed further below. Additionally, cash from operations increased as a result of lower operations and maintenance spend in the current year, higher sales due to colder weather during the winter heating season and increased rates from infrastructure replacement programs.

Regulatory Assets and Liabilities. For the six months endedJune 30, 2018 the source of cash related to regulatory assets and liabilities is primarily attributable to the over-collection of gas costs which resulted from decreasing gas prices during the period.

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 8, "Regulatory Matters," 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 six months of 2018, billings to customers decreased approximately $15 million compared to the same period in 2017 as a result of adjustments to certain rates in our Kentucky, Ohio, Maryland and Indiana jurisdictions. Additionally, during the first half of 2018, we recorded additional TCJA-related regulatory liabilities of $65.0 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 balances 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 June 30, 2018, we had a recorded deferred tax asset of $493.5 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 six months endedJune 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 six months endedJune 30, 2018 was $871.1 million, an increase of $85.2 million compared to the six months endedJune 30, 2017. This increase was mostly attributable to increased capital expenditures in 2018.

Our capital expenditures for the six months endedJune 30, 2018 were $832.5 million compared to $732.2 million for the comparable period in 2017. The increase in capital spend was driven by an increase in planned capital expenditures in the current year and the timing of payments through June 2018 compared to June 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 15, “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 16, “Short-Term Borrowings,” in the Notes to Condensed Consolidated Financial Statements (unaudited) for information on short-term debt activity.

Net Available Liquidity. As of June 30, 2018, an aggregate of $2,228.0 million of net liquidity was available, including cash and credit available under the revolving credit facility and accounts receivable securitization programs.

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

NiSource Inc.

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

(in millions)	June 30, 2018		December 31, 2017
Current Liquidity
Revolving Credit Facility	$	1,850.0	$	1,850.0
Accounts Receivable Program(1)	320.0		336.7
Less:
Commercial Paper	—		869.0
Accounts Receivable Program Utilized	—		336.7
Letters of Credit Outstanding Under Credit Facility	10.2		11.1
Add:
Cash and Cash Equivalents	68.2		29.0
Net Available Liquidity	$	2,228.0	$	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 June 30, 2018, the ratio was 60.3%.

Sale of Trade Accounts Receivables. Refer to Note 11, “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 June 30, 2018. In June 2018, Fitch upgraded the NiSource Commercial Paper rating to 'F2' from 'F3'. There were no other changes to the below credit ratings or outlooks since December 31, 2017.

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

Certain of our subsidiaries have agreements that contain “ratings triggers” that require increased collateral if our credit 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 June 30, 2018, the collateral requirement that would be required in the event of a downgrade below the ratings trigger levels would amount to approximately $52.9 million. In addition to agreements with ratings triggers, there are other agreements that contain “adequate assurance” or “material adverse change” provisions that could necessitate additional credit support such as letters of credit and cash collateral to transact business.

Equity. Our authorized capital stock consists of 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 June 30, 2018, 362,915,039 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, there were no material changes recorded during the six months endedJune 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.

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

NiSource Inc.

Refer to Note 17, “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.

Refer to Note 9, "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 June 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 $2.9 million and $5.9 million for the three and six months ended June 30, 2018, and $4.1 million and $8.9 million for the three and six months ended June 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 9, "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 June 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.

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

NiSource Inc.

We closely monitor the financial status of our banking credit providers. We evaluate the financial status of our banking partners through the use of market-based metrics such as credit default swap pricing levels, and also through traditional credit ratings provided by major credit rating agencies.

Other Information

Critical Accounting Policies

There were no significant changes to critical accounting policies for the period ended June 30, 2018.

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.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

NiSource Inc.

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

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

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

Changes in Internal Controls

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

52

PART II

ITEM 1. LEGAL PROCEEDINGS

NiSource Inc.

We are party to certain claims and legal proceedings arising in the ordinary course of business, none of which is deemed to be individually material at this time. Due to the inherent uncertainty of litigation, there can be no assurance that the resolution of any particular claim or proceeding 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 we would be required to pay such liability.

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. There have been no material changes to such risk factors.

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

Refer to Note 5, "Equity," in the Notes to the Condensed Consolidated Financial Statements (unaudited) for information regarding private placements of shares of common stock and preferred stock that occurred during the quarter ended June 30, 2018.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5. OTHER INFORMATION

None.

53

ITEM 6. EXHIBITS

NiSource Inc.

(3.1)	Certificate of Designations of 5.65% Series A Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Stock (incorporated by reference to Exhibit 3.1 of the NiSource Inc. Form 8-K filed on June 12, 2018).
(4.1)	Third Supplemental Indenture, dated as of June 11, 2018, by and between NiSource Inc. and The Bank of New York Mellon, as trustee (including form of 3.650% Notes due 2023) (incorporated by reference to Exhibit 4.1 of the NiSource Inc. Form 8-K filed on June 12, 2018).
(10.1)	Term Loan Agreement dated as of April 18, 2018 among NiSource Inc., as borrower, the lenders party thereto and MUFG Bank, Ltd., as administrative agent and as sole lead arranger and sole bookrunner (incorporated by reference to Exhibit 10.1 of the NiSource Inc. Form 8-K filed on April 19, 2018).
(10.2)	Common Stock Subscription Agreement, dated as of May 2, 2018, by and among NiSource Inc. and the purchasers named therein (incorporated by reference to Exhibit 10.1 of the NiSource Inc. Form 8-K filed on May 2, 2018).
(10.3)	Registration Rights Agreement, dated as of May 2, 2018, by and among NiSource Inc. and the purchasers named therein (incorporated by reference to Exhibit 10.2 of the NiSource Inc. Form 8-K filed on May 2, 2018).
(10.4)	Purchase Agreement, dated as of June 6, 2018, by and among NiSource Inc. and Credit Suisse Securities (USA) LLC, J.P. Morgan Securities LLC, Morgan Stanley & Co. LLC and MUFG Securities Americas Inc., as representatives, relating to the 5.650% Series A Preferred Stock (incorporated by reference to Exhibit 10.1 of the NiSource Inc. Form 8-K filed on June 12, 2018).
(10.5)	Purchase Agreement, dated as of June 6, 2018, by and among NiSource Inc. and Credit Suisse Securities (USA) LLC, J.P. Morgan Securities LLC, Morgan Stanley & Co. LLC and MUFG Securities Americas Inc., as representatives, relating to the 3.650% Notes due 2023 (incorporated by reference to Exhibit 10.2 of the NiSource Inc. Form 8-K filed on June 12, 2018).
(10.6)	Registration Rights Agreement, dated as of June 11, 2018, by and among NiSource Inc. and Credit Suisse Securities (USA) LLC, J.P. Morgan Securities LLC, Morgan Stanley & Co. LLC and MUFG Securities Americas Inc., as representatives, relating to the 5.650% Series A Preferred Stock (incorporated by reference to Exhibit 10.3 of the NiSource Inc. Form 8-K filed on June 12, 2018).
(10.7)	Registration Rights Agreement, dated as of June 11, 2018, by and among NiSource Inc. and Credit Suisse Securities (USA) LLC, J.P. Morgan Securities LLC, Morgan Stanley & Co. LLC and MUFG Securities Americas Inc., as representatives, relating to the 3.650% Notes due 2023 (incorporated by reference to Exhibit 10.4 of the NiSource Inc. Form 8-K filed on June 12, 2018).
(12)	Ratio of Earnings to Fixed Charges.*
(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.

54

SIGNATURE

NiSource Inc.

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

			NiSource Inc.
			(Registrant)
Date:	August 1, 2018	By:	/s/ Joseph W. Mulpas
			Joseph W. Mulpas
			Vice President and Chief Accounting Officer (Principal Accounting Officer)

55

EX-12

Exhibit 12

NiSource Inc.

Ratio of Earnings to Fixed Charges

	June 30, 2018		December 31, 2017		December 31, 2016		December 31, 2015		December 31, 2014		December 31, 2013
Earnings as defined in item 503(d) of Regulation S-K:
Add:
Pretax income from continuing operations (a)(b)	$	368,601,497	$	442,760,285	$	510,208,667	$	340,406,027	$	423,910,493	$	330,158,304
Fixed Charges	212,683,653		412,282,807		407,450,678		422,886,197		421,483,105		410,081,138
Amortization of capitalized interest (c)	—		—		—		—		—		—
Distributed income of equity investees	1,582,863		1,392,463		224,702		151,119		110,964		118,416
Share of pre-tax losses of equity investees for which charges arising guarantees are included in fixed charges	—		—		—		—		—		—
Deduct:
Interest capitalized (c)	—		—		—		—		—		—
Preference security dividend requirements of consolidated subsidiaries(d)	1,540,426		—		—		—		—		—
Non-Controlling interest in pre-tax income of subsidiaries that have not incurred fixed charges	—		—		—		—		—		—
	$	581,327,587	$	856,435,555	$	917,884,047	$	763,443,343	$	845,504,562	$	740,357,858
Fixed charges as defined in item 503(d) of Regulation S-K:
Interest on long-term debt	$	180,412,978	$	354,777,430	$	352,265,520	$	377,469,202	$	368,614,101	$	364,427,942
Other interest	19,739,142		33,771,593		30,244,516		20,897,004		22,963,342		20,521,761
Capitalized interest during period (c)	—		—		—		—		—		—
Amortization of premium, reacquisition premium, discount and expense on debt, net	3,836,547		7,237,875		7,618,345		8,701,321		9,967,085		9,395,881
Interest portion of rent expense	7,154,560		16,495,909		17,322,297		15,818,670		19,938,578		15,735,555
Non-controlling interest	—		—		—		—		—		—
	$	211,143,227	$	412,282,807	$	407,450,678	$	422,886,197	$	421,483,106	$	410,081,139
Plus preferred stock dividends: Preferred dividend requirements of subsidiary	$	1,255,556	$	—	$	—	$	—	$	—	$	—
Preferred dividend requirements factor	0.82		0.29		0.64		0.58		0.61		0.67
Preference security dividend requirements of consolidated subsidiaries (d)	1,540,426		—		—		—		—		—
Fixed charges	211,143,227		412,282,807		407,450,678		422,886,197		421,483,106		410,081,139
	$	212,683,653	$	412,282,807	$	407,450,678	$	422,886,197	$	421,483,106	$	410,081,139
Ratio of earnings to fixed charges	2.73		2.08		2.25		1.81		2.01		1.81

^(a) Income Statement amounts have been adjusted for discontinued operations.

^(b) Excludes adjustment for minority interest in consolidated subsidiaries or income or loss from equity investees.

^(c) NiSource is a public utility following ASC 980 and therefore does not add amortization of capitalized interest or subtract interest capitalized in determining earnings, nor reduces fixed charges for Allowance for Funds Used During Construction.

^(d) Preferred dividends, as defined by SEC regulation S-K, are computed by dividing the preferred dividend requirement by one minus the effective income tax rate applicable to continuing operations.

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 June 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:	August 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 June 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:	August 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 June 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:	August 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 June 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:	August 1, 2018

XML

Document And Entity Information - shares	6 Months Ended
	Jun. 30, 2018	Jul. 24, 2018
Document Information [Line Items]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2018
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	Q2
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		363,036,685

XML

Statements Of Consolidated Income - USD ($) shares in Thousands, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Operating Revenues
Customer revenues	$ 982.1	$ 960.1	$ 2,699.3	$ 2,502.6
Other revenues	24.9	30.6	58.5	86.7
Total Operating Revenues	1,007.0	990.7	2,757.8	2,589.3
Operating Expenses
Cost of Sales (excluding depreciation and amortization)	313.3	276.8	1,037.7	829.1
Operation and maintenance	365.2	391.6	767.7	803.2
Depreciation and amortization	144.6	142.2	289.3	285.5
Gain on sale of assets and impairments, net	0.0	(0.1)	(0.3)	(0.1)
Other taxes	65.5	56.2	144.4	132.2
Total Operating Expenses	888.6	866.7	2,238.8	2,049.9
Operating Income	118.4	124.0	519.0	539.4
Other Income (Deductions)
Interest expense, net	(88.7)	(87.7)	(181.8)	(172.9)
Other, net	12.8	4.2	44.1	6.5
Loss on early extinguishment of long-term debt	(12.5)	(111.5)	(12.5)	(111.5)
Total Other Deductions, Net	(88.4)	(195.0)	(150.2)	(277.9)
Income (Loss) before Income Taxes	30.0	(71.0)	368.8	261.5
Income Taxes	5.5	(26.6)	68.2	94.6
Net Income (Loss)	24.5	(44.4)	300.6	166.9
Preferred dividends	(1.3)	0.0	(1.3)	0.0
Net Income (Loss) Available to Common Shareholders	$ 23.2	$ (44.4)	$ 299.3	$ 166.9
Earnings (Loss) Per Share
Basic Earnings (Loss) Per Share	$ 0.07	$ (0.14)	$ 0.86	$ 0.51
Diluted Earnings (Loss) Per Share	0.07	(0.14)	0.86	0.51
Dividends Declared Per Common Share	$ 0.195	$ 0.175	$ 0.585	$ 0.525
Basic Average Common Shares Outstanding	354,229	325,084	346,165	324,386
Diluted Average Common Shares	355,161	325,084	347,121	325,813

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Statements of Consolidated Comprehensive Income - USD ($) $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Net Income		$ 24.5	$ (44.4)	$ 300.6	$ 166.9
Other comprehensive income:
Net unrealized gain (loss) on available-for-sale securities	[1]	(0.7)	0.6	(2.4)	1.0
Net unrealized gain (loss) on cash flow hedges	[2]	(1.4)	(16.8)	34.0	(11.9)
Unrecognized pension and OPEB benefit	[3]	0.2	0.2	0.4	0.4
Total other comprehensive income (loss)	[4]	(1.9)	(16.0)	32.0	(10.5)
Comprehensive Income (Loss)		$ 22.6	$ (60.4)	$ 332.6	$ 156.4

[1] Net unrealized gain (loss) on available-for-sale securities, net of $0.2 million tax benefit and $0.4 million tax expense in the second quarter of 2018 and 2017, respectively, and $0.6 million tax benefit and $0.6 million tax expense for the six months ended 2018 and 2017, respectively.

[2] Net unrealized gain (loss) on cash flow hedges, net of $0.5 million and $10.3 million tax benefit in the second quarter of 2018 and 2017, respectively, and $11.2 million tax expense and $7.3 million tax benefit for the six months ended 2018 and 2017, respectively. See Note 9, "Risk Management Activities," for additional information.

[3] Unrecognized pension and OPEB benefit, net of $0.1 million and $0.2 million tax expense in the second quarter of 2018 and 2017, respectively, and $0.2 million and $0.3 million tax expense for the six months ended 2018 and 2017, respectively.

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

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Statements of Consolidated Comprehensive Income (Parenthetical) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Other Comprehensive Income (Loss), Unrealized Holding Gain (Loss) on Securities Arising During Period, Tax	$ (0.2)	$ 0.4	$ (0.6)	$ 0.6
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Tax	(0.5)	(10.3)	11.2	(7.3)
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, Tax	$ (0.1)	$ (0.2)	$ (0.2)	$ (0.3)

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Statements of Consolidated Balance Sheets - USD ($) $ in Millions		Jun. 30, 2018	Dec. 31, 2017
Property, Plant and Equipment
Utility Plant		$ 21,914.8	$ 21,026.6
Accumulated depreciation and amortization		(7,083.7)	(6,953.6)
Net utility plant		14,831.1	14,073.0
Other property, at cost, less accumulated depreciation		16.8	286.5
Net Property, Plant and Equipment		14,847.9	14,359.5
Investments and Other Assets
Unconsolidated affiliates		4.2	5.5
Other investments		199.6	204.1
Total Investments and Other Assets		203.8	209.6
Current Assets
Cash and cash equivalents		68.2	29.0
Restricted Cash		12.9	9.4
Accounts receivable (less reserve of $24.2 and $18.3, respectively)		584.8	898.9
Gas inventory		182.8	285.1
Materials and supplies, at average cost		99.9	105.9
Electric production fuel, at average cost		53.8	80.1
Exchange gas receivable		29.6	45.8
Regulatory assets		174.6	176.3
Prepayments and other		109.1	132.8
Total Current Assets		1,315.7	1,763.3
Other Assets
Regulatory assets		1,918.7	1,624.9
Goodwill		1,690.7	1,690.7
Intangible assets, net		226.2	231.7
Deferred charges and other		104.9	82.0
Total Other Assets		3,940.5	3,629.3
Total Assets		20,307.9	19,961.7
Common Stockholders' Equity
Common stock - $0.01 par value, 400,000,000 shares authorized; 362,915,039 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		394.4	0.0
Treasury stock		(99.9)	(95.9)
Additional paid-in capital		6,151.2	5,529.1
Retained deficit		(965.5)	(1,073.1)
Accumulated other comprehensive loss	[1]	(20.9)	(43.4)
Total Common Stockholders' Equity		5,463.0	4,320.1
Long-term debt, excluding amounts due within one year		7,092.5	7,512.2
Total Capitalization		12,555.5	11,832.3
Current Liabilities
Current portion of long-term debt		597.7	284.3
Short-term borrowings		600.0	1,205.7
Accounts payable		455.0	625.6
Dividends payable		70.8	0.0
Customer deposits and credits		158.0	262.6
Taxes accrued		165.8	208.1
Interest accrued		103.3	112.3
Derivative Instruments and Hedges, Liabilities		4.0	43.2
Exchange gas payable		36.9	59.6
Regulatory liabilities		121.5	58.7
Legal and environmental		36.0	32.1
Accrued compensation and employee benefits		135.8	195.4
Other accruals		75.6	90.8
Total Current Liabilities		2,560.4	3,178.4
Other Liabilities and Deferred Credits
Risk management liabilities		44.9	28.5
Deferred income taxes		1,396.7	1,292.9
Deferred investment tax credits		11.9	12.4
Accrued insurance liabilities		86.0	80.1
Accrued liability for postretirement and postemployment benefits		311.7	337.1
Regulatory liabilities		2,821.4	2,736.9
Asset retirement obligations		334.6	268.7
Other noncurrent liabilities		184.8	194.4
Total Other Liabilities and Deferred Credits		5,192.0	4,951.0
Commitments and Contingencies		0.0	0.0
Total Capitalization and Liabilities		$ 20,307.9	$ 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	Jun. 30, 2018	Dec. 31, 2017
Accounts receivable less reserve	$ 24.2	$ 18.3
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	400,000,000	400,000,000
Common Stock, Shares, Outstanding	362,915,039	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	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017
Operating Activities
Net Income	$ 300.6	$ 166.9
Adjustments to Reconcile Net Income to Net Cash from Continuing Operations:
Loss on early extinguishment of debt	12.5	111.5
Depreciation and amortization	289.3	285.5
Deferred income taxes and investment tax credits	66.3	88.4
Other adjustments	11.3	22.4
Changes in Assets and Liabilities:
Components of working capital	12.4	(6.4)
Regulatory assets/liabilities	141.7	23.2
Deferred charges and other noncurrent assets	1.2	(1.1)
Other noncurrent liabilities	(25.8)	(39.0)
Net Cash Flows from Operating Activities	809.5	651.4
Investing Activities
Capital expenditures	(832.5)	(732.2)
Cost of removal	(46.1)	(55.6)
Purchases of available-for-sale securities	(46.8)	(105.6)
Sales of available-for-sale securities	47.5	106.6
Other investing activities	6.8	0.9
Net Cash Flows used for Investing Activities	(871.1)	(785.9)
Financing Activities
Issuance of long-term debt	350.0	2,000.0
Repayments of long-term debt and capital lease obligations	(491.2)	(1,078.4)
Premiums and other debt related costs	(15.2)	(130.7)
Issuance of short-term debt (maturity 90 days)	600.0	0.0
Change in short-term borrowings, net (maturity ≤ 90 days)	(1,205.7)	(586.7)
Issuance of common stock	607.7	46.2
Issuance of preferred stock	394.4	0.0
Acquisition of treasury stock	(4.0)	(5.9)
Dividends paid - common stock	(131.7)	(113.2)
Net Cash Flows from Financing Activities	104.3	131.3
Change in cash, cash equivalents and restricted cash	42.7	(3.2)
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	38.4	36.0
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	$ 81.1	$ 32.8

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Statements Of Consolidated Cash Flows (Supplemental Disclosures of Cash Flow Information) - USD ($) $ in Millions		6 Months Ended
		Jun. 30, 2018	Jun. 30, 2017
Supplemental Cash Flow [Abstract]
Capital expenditures included in current liabilities		$ 191.9	$ 206.9
Dividends declared but not paid		70.8	57.0
Reclassification of other property to regulatory assets	[1]	245.3	0.0
Asset Retirement Obligation, Revision of Estimate	[2]	$ 62.5
Change in estimated costs of asset retirement obligations(2)			$ 0.0

[1] See Note 17-D "Other Matters" for additional information.

[2] See Note 7 "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 Income		300.6	0.0	0.0	0.0	0.0	300.6	0.0
Other comprehensive income, net of tax		32.0	0.0	0.0	0.0	0.0	0.0	32.0
Common stock dividends ($0.585 per share)		(202.5)	0.0	0.0	0.0	0.0	(202.5)	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)	[2]	599.6	0.3	0.0	0.0	599.3	0.0	0.0
Preferred stock		394.4	0.0	394.4	0.0	0.0	0.0	0.0
Employee stock purchase plan		2.7	0.0	0.0	0.0	2.7	0.0	0.0
Long-term incentive plan		8.2	0.0	0.0	0.0	8.2	0.0	0.0
401(k) and profit sharing		11.9	0.0	0.0	0.0	11.9	0.0	0.0
Balance as of June 30, 2018 at Jun. 30, 2018		$ 5,463.0	$ 3.7	$ 394.4	$ (99.9)	$ 6,151.2	$ (965.5)	$ (20.9)

[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	6 Months Ended
	Jun. 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	111
Long-term incentive plan	494
401(k) and profit sharing	496
Balance as of June 30, 2018	362,915
Preferred Stock
Balance as of January 1, 2018	0
Issued:
Stock Issued During Period, Shares, New Issues	400
Employee stock purchase plan	0
Long-term incentive plan	0
401(k) and profit sharing	0
Balance as of June 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	111
Long-term incentive plan	494
401(k) and profit sharing	496
Balance as of June 30, 2018	366,878
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 June 30, 2018	3,963

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

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Statements Of Consolidated Equity (Parenthetical) - $ / shares	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Dividends Declared Per Common Share	$ 0.195	$ 0.175	$ 0.585	$ 0.525

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Basis of Accounting Presentation

6 Months Ended

Jun. 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

6 Months Ended

Jun. 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 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).
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 are implementing a new lease accounting system, which we will utilize to capture, track, and account for lease data. We began system testing at the end of June 2018 and anticipate 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 tentatively expect to elect the "practical expedient package" described in ASC 842-10-65-1. We maintain a substantial number of easements and expect the provisions of ASU 2018-01 will ease the process of implementing ASC 842. We tentatively plan to elect the transition method provided in ASU 2018-11. We intend to 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 2018-02, 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 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

6 Months Ended

Jun. 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 six months ended June 30, 2018 as if they had been prepared under historic accounting guidance. We included operating revenue information for the three and six months ended June 30, 2017 for comparability.

	Three Months Ended June 30,				Six Months Ended June 30,
(in millions)	2018		2017		2018		2017
Operating Revenues
Gas Distribution	$	384.2	$	327.1	$	1,368.0	$	1,163.6
Gas Transportation	216.9		204.9		559.1		543.5
Electric	405.0		458.0		828.3		879.7
Other	0.9		0.7		2.4		2.5
Total Operating Revenues	$	1,007.0	$	990.7	$	2,757.8	$	2,589.3

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 June 30, 2018 (in millions)	Gas Distribution Operations		Electric Operations		Corporate and Other		Total
Customer Revenues(1)
Residential	$	389.7	$	113.1	$	—	$	502.8
Commercial	127.0		116.6		—		243.6
Industrial	47.7		152.0		—		199.7
Off-system	20.9		—		—		20.9
Miscellaneous	10.2		4.7		0.2		15.1
Total Customer Revenues	$	595.5	$	386.4	$	0.2	$	982.1
Other Revenues	6.4		18.5		—		24.9
Total Operating Revenues	$	601.9	$	404.9	$	0.2	$	1,007.0

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

Six Months Ended June 30, 2018 (in millions)	Gas Distribution Operations		Electric Operations		Corporate and Other		Total
Customer Revenues(1)
Residential	$	1,283.3	$	227.6	$	—	$	1,510.9
Commercial	435.3		233.5		—		668.8
Industrial	122.3		314.5		—		436.8
Off-system	43.2		—		—		43.2
Miscellaneous	27.0		12.2		0.4		39.6
Total Customer Revenues	$	1,911.1	$	787.8	$	0.4	$	2,699.3
Other Revenues	18.1		40.4		—		58.5
Total Operating Revenues	$	1,929.2	$	828.2	$	0.4	$	2,757.8

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

Customer Accounts Receivable. Accounts receivable on our Condensed Consolidated Balance Sheets (unaudited) includes both billed and unbilled amounts as well as certain amounts that are not related to customer revenues. Unbilled amounts of accounts receivable relate to a portion of a customer’s consumption of gas or electricity from the date of the last cycle billing date through the last day of the month (balance sheet date). Factors taken into consideration when estimating unbilled revenue include historical usage, customer rates and weather. The opening and closing balances of customer receivables for the six months endedJune 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 June 30, 2018	373.6			155.1
Increase (Decrease)	$	(103.4	)	$	(200.9	)

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

⁽²⁾ Customer unbilled receivables decreased over the period due to the expected seasonal decrease in customer usage in June 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

6 Months Ended

Jun. 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 calculation of diluted earnings per share excludes the impact of forward agreements (see Note 5, "Equity"), which had an anti-dilutive effect for the periods outstanding. The computation of diluted average common shares for the three months ended June 30, 2017 is not presented since we had a net loss on the Condensed Statements of Consolidated Income (Loss) (unaudited) during the period 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	Six Months Ended
	June 30,	June 30,
(in thousands)	2018	2018	2017
Denominator
Basic average common shares outstanding	354,229	346,165	324,386
Dilutive potential common shares:
Shares contingently issuable under employee stock plans	861	789	452
Shares restricted under employee stock plans	71	167	975
Diluted Average Common Shares	355,161	347,121	325,813

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Equity

6 Months Ended

Jun. 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. During the three and six months ended June 30, 2017, we issued 1,318,461 shares of common stock under the program at an average price of $25.88 per share, receiving proceeds, net of fees, of $33.8 million. There was no activity under the ATM program in 2018. As of June 30, 2018, the ATM program (including impacts of forward sales agreements discussed below) had approximately $10.0 million of equity available for issuance. The program expires on December 31, 2018.

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 June 30, 2018, we would have received approximately $169.4 million, based on a net price of $26.70 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 $394.4 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 15, “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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Gas in Storage

6 Months Ended

Jun. 30, 2018

Gas in Storage [Abstract]

Inventory Disclosure [Text Block]

Gas in Storage

We use both the LIFO inventory methodology and the weighted-average cost methodology to value natural gas in storage. Gas Distribution Operations prices natural gas storage injections at the average of the costs of natural gas supply purchased during the year. For interim periods, the difference between current projected replacement cost and the LIFO cost for quantities of gas temporarily withdrawn from storage is recorded as a temporary LIFO liquidation credit or debit within the Condensed Consolidated Balance Sheets (unaudited). Due to seasonality requirements, we expect interim variances in LIFO layers to be replenished by year end. We had a temporary LIFO liquidation debit of $12.9 million and zero as of June 30, 2018 and December 31, 2017, respectively, for certain gas distribution companies recorded within “Prepayments and other,” on the Condensed Consolidated Balance Sheets (unaudited).

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Asset Retirement Obligations

6 Months Ended

Jun. 30, 2018

Asset Retirement Obligations [Abstract]

Asset Retirement Obligation Disclosure [Text Block]

Asset Retirement Obligations

In the second quarter of 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 $62.5 million that was recorded in June 2018. See Note 17-C, "Environmental Matters," for additional information on CCRs.

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Regulatory Matters

6 Months Ended

Jun. 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 no later than October 15, 2018 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.

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 Commission-approved CEP deferrals. The audit of the CEP is expected to be completed by September 4, 2018 at which point we anticipate a full procedural schedule will be established.

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 Commission 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 from the IURC is expected in the third quarter of 2018 with rates expected to be effective October 1, 2018 for Phase 1 implementation.

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 is requesting all associated accounting and ratemaking relief, including establishment of a periodic rate adjustment mechanism. An IURC order is expected in the third quarter of 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. The filing seeks approval of a total capital expenditure level of approximately $1.25 billion. An IURC order is expected in the fourth quarter of 2018.

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. An IURC order was expected in the second quarter of 2018, with new rates effective in July. 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 and held 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. 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. An order on the revised filing is expected in the third quarter of 2018. 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. Timing of this passback has not yet been determined.

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 is a proposal to adjust rates and address the regulatory liability disposition related to the TCJA. Rates are expected to go into effect March 1, 2019, upon approval from the Massachusetts DPU. On June 29, 2018, Columbia of Massachusetts filed a letter with a settlement negotiations update noting the Office of the Attorney General and Columbia of Massachusetts continue to discuss the possibility of a negotiated settlement.

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. Columbia of Massachusetts 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 an alternative calculation or a waiver to allow collection of the $3.1 million revenue requirement that exceeds the GSEP cap provision as previously calculated. On January 29, 2018, Columbia of Massachusetts filed a revision to its GSEP tracker for the 2018 construction season reducing the proposed revenue requirement to reflect the impact of the TCJA. The revenue requirement was reduced by $2.4 million due to the TCJA. An order was received from the Massachusetts DPU on April 30, 2018, approving an incremental revenue requirement of $6.1 million associated with the incremental capital investment of $83.9 million, with new rates effective May 1, 2018. The order did not approve the alternative cap calculation and the portion of the revenue requirement that exceeds the GSEP cap provision. On May 21, 2018, Columbia of Massachusetts filed a motion for reconsideration on the Massachusetts DPU’s denial of Columbia of Massachusetts’s request for a waiver on the 1.5% revenue cap calculation. On June 21, 2018, the Massachusetts DPU issued an order granting a waiver on the revenue cap allowing an incremental revenue requirement of $6.5 million with new rates effective July 1, 2018.

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 income 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. Since Columbia of Pennsylvania has a pending rate case, it is not required to implement the negative surcharge, and it has made a proposal in its pending rate case regarding the use of 2018 tax over-collection proceeds.

As highlighted above, on March 16, 2018, Columbia of Pennsylvania filed a rate case with the Pennsylvania PUC, seeking approval for an annual revenue increase of $46.9 million. Included in the filing is a proposal to adjust rates as a result of the TCJA. On March 21, 2018, Columbia of Pennsylvania filed a supplement to the rate case, under which it proposes 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. A decision on Columbia of Pennsylvania’s rate request is expected in the fourth quarter of 2018 with new rates 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. In addition, pursuant to the order, Columbia of Virginia is required to reflect the impacts of the TCJA in its annual informational filing, including: (1) the expected cost of service impacts through calendar year 2018; (2) the amount of protected and unprotected excess accumulated deferred income taxes as of December 31, 2017, and the estimated reversal of such excess deferred income taxes during calendar year 2018; and (3) such additional information that the utility wishes to include addressing the financial and cost of service impacts of the TCJA and the appropriate treatment of the accrued regulatory liabilities. On April 25, 2018 the VSCC, by order, supplemented the above annual informational filing requirements of the January 8, 2018 order to include a proposed rate reduction that reflects the cost savings from the TCJA. This April 25, 2018 order directs that if a utility desires to propose an alternative method for returning the tax savings to customers, then it may instead file a rate case that incorporates the income tax savings. As a result of these orders, Columbia of Virginia made the decision to file a rate case. This rate case is expected to be filed by August 28, 2018.

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 income 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 directs 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 accumulated deferred income taxes to be effective with the first billing cycle of October 2018.

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 income 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. An order from the PSC is expected in the fourth quarter of 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. The impact on NIPSCO electric of the Phase 2 investigation is unknown at this time.

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 in May 2019. NIPSCO is currently evaluating the impact of the WCE petition, including the associated impacts on revenue. NIPSCO anticipates filing an electric rate case in the fourth quarter of 2018, in part, to address anticipated revenue loss resulting from this filing. NIPSCO also anticipates filing an updated Integrated Resource Plan in the fourth quarter of 2018, which will evaluate demand-side and supply-side resource alternatives to reliably and cost effectively meet NIPSCO customers' future energy requirements over the ensuing 20 years.  

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 seeking an incremental semi-annual revenue decrease of $10.6 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 $3.5 million increase associated with $77.1 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 six months ended June 30, 2018, we recorded additional TCJA-related regulatory liabilities of $65.0 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 13, "Income Taxes," in 2018 we began amortizing regulatory liabilities associated with excess deferred income taxes, which resulted in a $7.4 million and $17.8 million income tax benefit for the three and six months ended June 30, 2018, respectively. Related to this activity, we recorded an offsetting reserve of $4.7 million and $12.4 million (net of tax) in "Customer revenues" to reflect the probable future passback of this earnings benefit to customers for the three and six months ended June 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 June 30, 2018.

Bailly Generating Station. During the six months ended June 30, 2018, we reclassified approximately $245 million from "Other property, at cost, less accumulated depreciation" to “Regulatory assets (noncurrent)” on the Condensed Consolidated Balance Sheets (unaudited) in connection with the retirement of Bailly Generating Station Units 7 and 8. Refer to Note 17-D, "Other Matters," in the Notes to Condensed Consolidated Financial Statements (unaudited) for additional information.

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Risk Management Activities

6 Months Ended

Jun. 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)	June 30, 2018		December 31, 2017
Risk Management Assets - Current(1)
Interest rate risk programs	$	1.7	$	14.0
Commodity price risk programs	0.5		0.5
Total	$	2.2	$	14.5
Risk Management Assets - Noncurrent(2)
Interest rate risk programs	$	23.5	$	5.6
Commodity price risk programs	1.8		1.0
Total	$	25.3	$	6.6
Risk Management Liabilities - Current
Interest rate risk programs	$	—	$	38.6
Commodity price risk programs	4.0		4.6
Total	$	4.0	$	43.2
Risk Management Liabilities - Noncurrent
Interest rate risk programs	$	—	$	—
Commodity price risk programs	44.9		28.5
Total	$	44.9	$	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 June 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 March 2018, we initiated settlement of 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 June 30, 2018 and December 31, 2017.

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

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Fair Value

6 Months Ended

Jun. 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 June 30, 2018 and December 31, 2017:

Recurring Fair Value Measurements June 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 June 30, 2018
Assets
Risk management assets	$	—	$	27.4	$	0.1	$	27.5
Available-for-sale securities	—		130.1		—		130.1
Total	$	—	$	157.5	$	0.1	$	157.6
Liabilities
Risk management liabilities	$	—	$	48.9	$	—	$	48.9
Total	$	—	$	48.9	$	—	$	48.9

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 June 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 9, "Risk Management Activities."

NIPSCO has entered into long-term forward natural gas purchase instruments that range from five to ten years to lock in a fixed price for its natural gas customers. We value these contracts using a pricing model that incorporates market-based information when available, as these instruments trade less frequently and are classified within Level 2 of the fair value hierarchy. For additional information, see Note 9, “Risk Management Activities.”

Available-for-sale securities are investments pledged as collateral for trust accounts related to our wholly-owned insurance company. Available-for-sale securities are included within “Other investments” in the 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 June 30, 2018 and December 31, 2017 were:

June 30, 2018 (in millions)	Amortized Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
Available-for-sale securities
U.S. Treasury debt securities	$	16.8	$	—	$	(0.1	)	$	16.7
Corporate/Other debt securities	116.1		0.3		(3.0		)	113.4
Total	$	132.9	$	0.3	$	(3.1	)	$	130.1
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 six months ended June 30, 2018 and 2017.

The cost of maturities sold is based upon specific identification. At June 30, 2018, approximately $3.2 million of U.S. Treasury debt securities and approximately $3.7 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 six months ended June 30, 2018 and 2017.

Non-recurring Fair Value Measurements. There were no significant non-recurring fair value measurements recorded during the three and six months ended June 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 six months endedJune 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 June 30, 2018		Estimated Fair Value as of June 30, 2018		Carrying Amount as of Dec. 31, 2017		Estimated Fair Value as of Dec. 31, 2017
Long-term debt (including current portion)	$	7,690.2	$	7,996.1	$	7,796.5	$	8,603.4

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Transfers Of Financial Assets

6 Months Ended

Jun. 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 August 2018 and March 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 June 30, 2018, the maximum amount of debt that could be recognized related to our accounts receivable programs is $320.0 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 June 30, 2018 and December 31, 2017:

(in millions)	June 30, 2018		December 31, 2017
Gross Receivables	$	470.7	$	635.3
Less: Receivables not transferred	470.7		298.6
Net receivables transferred	$	—	$	336.7
Short-term debt due to asset securitization	$	—	$	336.7

For the six months ended June 30, 2018 and 2017, $336.7 million and $11.7 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 $0.7 million and $0.6 million for the three months ended June 30, 2018 and 2017, respectively and $1.5 million and $1.3 million for the six months ended June 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

6 Months Ended

Jun. 30, 2018

Goodwill and Intangible Assets Disclosure [Abstract]

Goodwill

Goodwill

The following presents our goodwill balance allocated by segment as of June 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.

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Income Taxes

6 Months Ended

Jun. 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 June 30, 2018 and 2017 were 18.3% and 37.5%, respectively. The effective tax rates for six months endedJune 30, 2018 and 2017 were 18.5% and 36.2%, 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 decrease in the three month effective tax rate in 2018 versus the same period in 2017 is primarily due to the change in the Federal statutory rate due to the enactment of the TCJA. Additionally, 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 $7.4 million and $17.8 million for the three and six months ended June 30, 2018, respectively. Refer to Note 8, "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

6 Months Ended

Jun. 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 six months ended June 30, 2018, we contributed $1.4 million to our pension plans and $11.3 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 six months ended June 30, 2018 and 2017:

	Pension Benefits						Other Postretirement Benefits
Three Months Ended June 30, (in millions)	2018			2017			2018			2017
Components of Net Periodic Benefit Cost(1)
Service cost	$	7.9		$	7.5		$	1.3		$	1.2
Interest cost	16.6			17.2			4.4			4.4
Expected return on assets	(36.2		)	(30.2		)	(3.7		)	(3.9		)
Amortization of prior service credit	(0.1		)	(0.2		)	(1.0		)	(1.1		)
Recognized actuarial loss	10.2			13.4			0.9			0.7
Settlement loss	3.5			—			—			—
Total Net Periodic Benefit Cost	$	1.9		$	7.7		$	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
Six Months Ended June 30, (in millions)	2018			2017			2018			2017
Components of Net Periodic Benefit Cost(1)
Service cost	$	15.8		$	15.0		$	2.6		$	2.4
Interest cost	33.2			34.4			8.8			8.9
Expected return on assets	(72.5		)	(60.5		)	(7.4		)	(7.9		)
Amortization of prior service credit	(0.2		)	(0.4		)	(2.0		)	(2.2		)
Recognized actuarial loss	20.4			26.8			1.8			1.5
Settlement loss	3.5			—			—			—
Total Net Periodic Benefit Cost	$	0.2		$	15.3		$	3.8		$	2.7

⁽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 the settlement, these 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 loss of $0.1 million. Net periodic pension benefit cost for 2018 increased by $1.1 million as a result of the interim 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 account at the measurement dates of May 31, 2018 and December 31, 2017:

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

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Long-Term Debt

6 Months Ended

Jun. 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 anticipate recording 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

6 Months Ended

Jun. 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 June 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 no commercial paper outstanding as of June 30, 2018 and $869.0 million outstanding as of December 31, 2017.

As of June 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 no transfers as of June 30, 2018 and $336.7 million as of December 31, 2017. Refer to Note 11, "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)	June 30, 2018		December 31, 2017
Commercial paper weighted-average interest rate of 1.97% at December 31, 2017	$	—	$	869.0
Accounts receivable securitization facility borrowings	—		336.7
Term loan weighted-average interest rate of 2.64% at June 30, 2018	600.0		—
Total Short-Term Borrowings	$	600.0	$	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

6 Months Ended

Jun. 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 June 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. We are party to certain 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 June 30, 2018 and December 31, 2017, we had recorded a liability of approximately $109.7 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 November 1, 2016. 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.

Clean Power Plan. On October 23, 2015, the EPA issued a final rule to regulate CO2 emissions from existing fossil-fuel EGUs under section 111(d) of the CAA. The final rule establishes national CO2 emission-rate standards that are applied to each state’s mix of affected EGUs to establish state-specific emission-rate and mass-emission limits. The final rule requires each state to submit a plan indicating how the state will meet the EPA's emission-rate or mass-emission limit, including possibly imposing reduction obligations on specific units. If a state does not submit a satisfactory plan, the EPA will impose a federal plan on that state.

On February 9, 2016, the U.S. Supreme Court stayed implementation of the CPP until litigation is decided on its merits. On October 16, 2017, the EPA published in the Federal Register a Notice of Proposed Rulemaking that would repeal the CPP. On December 28, 2017, in a separate but related action, the EPA published an Advanced Notice of Proposed Rulemaking in the Federal Register to solicit information from the public about a potential future rulemaking to limit greenhouse gas emissions from existing fossil-fuel EGUs. NIPSCO will continue to monitor this matter and cannot estimate its impact at this time. Should costs be incurred to comply with the CPP, NIPSCO believes such costs will be eligible for recovery through customer rates.

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 $105.5 million and $106.9 million at June 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 will be required to incur future 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. On November 1, 2016, NIPSCO filed a petition with the IURC seeking approval of the projects and recovery of the costs associated with ELG compliance. Given the current postponement of certain compliance dates under the ELG rule, NIPSCO has agreed with the settling parties, as part of the settlement agreement discussed in the "CCRs" subsection above, that these ELG projects and related costs would be addressed in a later proceeding.

D. Other Matters.

NIPSCO 2016 Integrated Resource Plan.Environmental, regulatory and economic factors, including low natural gas prices and aging coal-fired units, have led NIPSCO to pursue modification of its current electric generation supply mix to include less coal-fired generation. Due to enacted CCR and ELG (subsequently postponed) regulations, NIPSCO would expect to have incurred over $1 billion in operating, maintenance, environmental and other costs if the current fleet of coal-fired generating units were to remain operational.

On November 1, 2016, NIPSCO submitted its 2016 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. The 2016 Integrated Resource Plan indicated that the most viable option for customers and NIPSCO involves the retirement of Bailly Generating Station (Units 7 and 8) as soon as mid-2018 and two units (Units 17 and 18) at the R.M. Schahfer Generating Station by 2023. It is projected over the long term that the cost to customers to retire these units at these dates will be lower than maintaining and upgrading them for continued generation.

We committed to the retirement of the Bailly Generating Station units in connection with the filing of the 2016 Integrated Resource Plan, pending approval by the MISO. In the fourth quarter of 2016, the MISO approved NIPSCO's plan to retire the Bailly Generating Station units by May 31, 2018.

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.

NIPSCO anticipates updating its Integrated Resource Plan in a filing by the end of 2018.

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 $7.6 million and $10.4 million for the six months endedJune 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.

As further discussed above in this Note 17 under the heading "NIPSCO 2016 Integrated Resource Plan," 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).

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Accumulated Other Comprehensive Loss

6 Months Ended

Jun. 30, 2018

Other Comprehensive Income (Loss), Tax [Abstract]

Accumulated Other Comprehensive Loss

Accumulated Other Comprehensive Loss

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

Three Months Ended June 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 Loss(1)
Balance as of April 1, 2018	$	(1.5	)	$	(0.3	)	$	(17.2	)	$	(19.0	)
Other comprehensive income (loss) before reclassifications	(0.6		)	(2.0		)	0.6			(2.0		)
Amounts reclassified from accumulated other comprehensive loss	(0.1		)	0.6			(0.4		)	0.1
Net current-period other comprehensive income (loss)	(0.7		)	(1.4		)	0.2			(1.9		)
Balance as of June 30, 2018	$	(2.2	)	$	(1.7	)	$	(17.0	)	$	(20.9	)
Six Months Ended June 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 Loss(1)
Balance as of January 1, 2018	$	0.2		$	(29.4	)	$	(14.2	)	$	(43.4	)
Other comprehensive income (loss) before reclassifications	(2.5		)	49.1			—			46.6
Amounts reclassified from accumulated other comprehensive loss(2)	0.1			(15.1		)	0.4			(14.6		)
Net current-period other comprehensive income (loss)	(2.4		)	34.0			0.4			32.0
Reclassification due to adoption of ASU 2018-02 (Refer to Note 2)	—			(6.3		)	(3.2		)	(9.5		)
Balance as of June 30, 2018	$	(2.2	)	$	(1.7	)	$	(17.0	)	$	(20.9	)

Three Months Ended June 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 April 1, 2017	$	(0.2	)	$	(2.0	)	$	(17.4	)	$	(19.6	)
Other comprehensive income (loss) before reclassifications	0.8			(18.2		)	0.1			(17.3		)
Amounts reclassified from accumulated other comprehensive loss	(0.2		)	1.4			0.1			1.3
Net current-period other comprehensive income (loss)	0.6			(16.8		)	0.2			(16.0		)
Balance as of June 30, 2017	$	0.4		$	(18.8	)	$	(17.2	)	$	(35.6	)
Six Months Ended June 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	1.0			(13.6		)	0.2			(12.4		)
Amounts reclassified from accumulated other comprehensive loss	—			1.7			0.2			1.9
Net current-period other comprehensive income (loss)	1.0			(11.9		)	0.4			(10.5		)
Balance as of June 30, 2017	$	0.4		$	(18.8	)	$	(17.2	)	$	(35.6	)

⁽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 9 "Risk Management Activities" for additional information.

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Other, Net

6 Months Ended

Jun. 30, 2018

Other, Net [Abstract]

Other Income and Other Expense Disclosure [Text Block]

Other, Net

	Three Months Ended June 30,					Six Months Ended June 30,
(in millions)	2018		2017			2018		2017
Interest Income	$	1.1	$	0.9		$	2.8	$	1.8
AFUDC Equity	3.9		3.7			7.6		6.2
Pension and other postretirement non-service cost	6.1		0.5			12.3		1.7
Interest rate swap settlement gain(1)	—		—			21.2		—
Miscellaneous	1.7		(0.9		)	0.2		(3.2		)
Total Other, net	$	12.8	$	4.2		$	44.1	$	6.5

⁽¹⁾See Note 9, "Risk Management Activities," for additional information.

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Business Segment Information

6 Months Ended

Jun. 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 June 30,						Six Months Ended June 30,
(in millions)	2018			2017			2018			2017
Operating Revenues
Gas Distribution Operations
Unaffiliated	$	601.9		$	532.5		$	1,929.2		$	1,708.8
Intersegment	3.2			3.6			6.5			7.1
Total	605.1			536.1			1,935.7			1,715.9
Electric Operations
Unaffiliated	404.9			458.0			828.2			879.7
Intersegment	0.2			0.2			0.4			0.4
Total	405.1			458.2			828.6			880.1
Corporate and Other
Unaffiliated	0.2			0.2			0.4			0.8
Intersegment	116.1			121.7			230.2			241.3
Total	116.3			121.9			230.6			242.1
Eliminations	(119.5		)	(125.5		)	(237.1		)	(248.8		)
Consolidated Operating Revenues	$	1,007.0		$	990.7		$	2,757.8		$	2,589.3
Operating Income (Loss)
Gas Distribution Operations	$	39.1		$	43.7		$	360.8		$	382.5
Electric Operations	82.4			85.6			165.5			163.2
Corporate and Other	(3.1		)	(5.3		)	(7.3		)	(6.3		)
Consolidated Operating Income	$	118.4		$	124.0		$	519.0		$	539.4

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Recent Accounting Pronouncements (Tables)

6 Months Ended

Jun. 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 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).
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 are implementing a new lease accounting system, which we will utilize to capture, track, and account for lease data. We began system testing at the end of June 2018 and anticipate 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 tentatively expect to elect the "practical expedient package" described in ASC 842-10-65-1. We maintain a substantial number of easements and expect the provisions of ASU 2018-01 will ease the process of implementing ASC 842. We tentatively plan to elect the transition method provided in ASU 2018-11. We intend to 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 2018-02, 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 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)

6 Months Ended

Jun. 30, 2018

Revenue from Contract with Customer [Abstract]

Revenue Recognition Under Previous Guidance

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

	Three Months Ended June 30,				Six Months Ended June 30,
(in millions)	2018		2017		2018		2017
Operating Revenues
Gas Distribution	$	384.2	$	327.1	$	1,368.0	$	1,163.6
Gas Transportation	216.9		204.9		559.1		543.5
Electric	405.0		458.0		828.3		879.7
Other	0.9		0.7		2.4		2.5
Total Operating Revenues	$	1,007.0	$	990.7	$	2,757.8	$	2,589.3

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 June 30, 2018 (in millions)	Gas Distribution Operations		Electric Operations		Corporate and Other		Total
Customer Revenues(1)
Residential	$	389.7	$	113.1	$	—	$	502.8
Commercial	127.0		116.6		—		243.6
Industrial	47.7		152.0		—		199.7
Off-system	20.9		—		—		20.9
Miscellaneous	10.2		4.7		0.2		15.1
Total Customer Revenues	$	595.5	$	386.4	$	0.2	$	982.1
Other Revenues	6.4		18.5		—		24.9
Total Operating Revenues	$	601.9	$	404.9	$	0.2	$	1,007.0

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

Six Months Ended June 30, 2018 (in millions)	Gas Distribution Operations		Electric Operations		Corporate and Other		Total
Customer Revenues(1)
Residential	$	1,283.3	$	227.6	$	—	$	1,510.9
Commercial	435.3		233.5		—		668.8
Industrial	122.3		314.5		—		436.8
Off-system	43.2		—		—		43.2
Miscellaneous	27.0		12.2		0.4		39.6
Total Customer Revenues	$	1,911.1	$	787.8	$	0.4	$	2,699.3
Other Revenues	18.1		40.4		—		58.5
Total Operating Revenues	$	1,929.2	$	828.2	$	0.4	$	2,757.8

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

Customer Accounts Receivable

The opening and closing balances of customer receivables for the six months endedJune 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 June 30, 2018	373.6			155.1
Increase (Decrease)	$	(103.4	)	$	(200.9	)

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

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

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Earnings Per Share (Tables)

6 Months Ended

Jun. 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	Six Months Ended
	June 30,	June 30,
(in thousands)	2018	2018	2017
Denominator
Basic average common shares outstanding	354,229	346,165	324,386
Dilutive potential common shares:
Shares contingently issuable under employee stock plans	861	789	452
Shares restricted under employee stock plans	71	167	975
Diluted Average Common Shares	355,161	347,121	325,813

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Risk Management Activities (Tables)

6 Months Ended

Jun. 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)	June 30, 2018		December 31, 2017
Risk Management Assets - Current(1)
Interest rate risk programs	$	1.7	$	14.0
Commodity price risk programs	0.5		0.5
Total	$	2.2	$	14.5
Risk Management Assets - Noncurrent(2)
Interest rate risk programs	$	23.5	$	5.6
Commodity price risk programs	1.8		1.0
Total	$	25.3	$	6.6
Risk Management Liabilities - Current
Interest rate risk programs	$	—	$	38.6
Commodity price risk programs	4.0		4.6
Total	$	4.0	$	43.2
Risk Management Liabilities - Noncurrent
Interest rate risk programs	$	—	$	—
Commodity price risk programs	44.9		28.5
Total	$	44.9	$	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)

6 Months Ended

Jun. 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 June 30, 2018 and December 31, 2017:

Recurring Fair Value Measurements June 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 June 30, 2018
Assets
Risk management assets	$	—	$	27.4	$	0.1	$	27.5
Available-for-sale securities	—		130.1		—		130.1
Total	$	—	$	157.5	$	0.1	$	157.6
Liabilities
Risk management liabilities	$	—	$	48.9	$	—	$	48.9
Total	$	—	$	48.9	$	—	$	48.9

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 June 30, 2018 and December 31, 2017 were:

June 30, 2018 (in millions)	Amortized Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
Available-for-sale securities
U.S. Treasury debt securities	$	16.8	$	—	$	(0.1	)	$	16.7
Corporate/Other debt securities	116.1		0.3		(3.0		)	113.4
Total	$	132.9	$	0.3	$	(3.1	)	$	130.1
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 June 30, 2018		Estimated Fair Value as of June 30, 2018		Carrying Amount as of Dec. 31, 2017		Estimated Fair Value as of Dec. 31, 2017
Long-term debt (including current portion)	$	7,690.2	$	7,996.1	$	7,796.5	$	8,603.4

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Transfers Of Financial Assets (Tables)

6 Months Ended

Jun. 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 June 30, 2018 and December 31, 2017:

(in millions)	June 30, 2018		December 31, 2017
Gross Receivables	$	470.7	$	635.3
Less: Receivables not transferred	470.7		298.6
Net receivables transferred	$	—	$	336.7
Short-term debt due to asset securitization	$	—	$	336.7

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Goodwill (Tables)

6 Months Ended

Jun. 30, 2018

Goodwill and Intangible Assets Disclosure [Abstract]

Schedule of Goodwill

The following presents our goodwill balance allocated by segment as of June 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)

6 Months Ended

Jun. 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 six months ended June 30, 2018 and 2017:

	Pension Benefits						Other Postretirement Benefits
Three Months Ended June 30, (in millions)	2018			2017			2018			2017
Components of Net Periodic Benefit Cost(1)
Service cost	$	7.9		$	7.5		$	1.3		$	1.2
Interest cost	16.6			17.2			4.4			4.4
Expected return on assets	(36.2		)	(30.2		)	(3.7		)	(3.9		)
Amortization of prior service credit	(0.1		)	(0.2		)	(1.0		)	(1.1		)
Recognized actuarial loss	10.2			13.4			0.9			0.7
Settlement loss	3.5			—			—			—
Total Net Periodic Benefit Cost	$	1.9		$	7.7		$	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
Six Months Ended June 30, (in millions)	2018			2017			2018			2017
Components of Net Periodic Benefit Cost(1)
Service cost	$	15.8		$	15.0		$	2.6		$	2.4
Interest cost	33.2			34.4			8.8			8.9
Expected return on assets	(72.5		)	(60.5		)	(7.4		)	(7.9		)
Amortization of prior service credit	(0.2		)	(0.4		)	(2.0		)	(2.2		)
Recognized actuarial loss	20.4			26.8			1.8			1.5
Settlement loss	3.5			—			—			—
Total Net Periodic Benefit Cost	$	0.2		$	15.3		$	3.8		$	2.7

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 account at the measurement dates of May 31, 2018 and December 31, 2017:

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

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Short-Term Borrowings (Tables)

6 Months Ended

Jun. 30, 2018

Short-term Debt [Abstract]

Schedule Of Short-Term Borrowings

Short-term borrowings were as follows:

(in millions)	June 30, 2018		December 31, 2017
Commercial paper weighted-average interest rate of 1.97% at December 31, 2017	$	—	$	869.0
Accounts receivable securitization facility borrowings	—		336.7
Term loan weighted-average interest rate of 2.64% at June 30, 2018	600.0		—
Total Short-Term Borrowings	$	600.0	$	1,205.7

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Accumulated Other Comprehensive Loss (Tables)

6 Months Ended

Jun. 30, 2018

Other Comprehensive Income (Loss), Tax [Abstract]

Components Of Accumulated Other Comprehensive Loss

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

Three Months Ended June 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 Loss(1)
Balance as of April 1, 2018	$	(1.5	)	$	(0.3	)	$	(17.2	)	$	(19.0	)
Other comprehensive income (loss) before reclassifications	(0.6		)	(2.0		)	0.6			(2.0		)
Amounts reclassified from accumulated other comprehensive loss	(0.1		)	0.6			(0.4		)	0.1
Net current-period other comprehensive income (loss)	(0.7		)	(1.4		)	0.2			(1.9		)
Balance as of June 30, 2018	$	(2.2	)	$	(1.7	)	$	(17.0	)	$	(20.9	)
Six Months Ended June 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 Loss(1)
Balance as of January 1, 2018	$	0.2		$	(29.4	)	$	(14.2	)	$	(43.4	)
Other comprehensive income (loss) before reclassifications	(2.5		)	49.1			—			46.6
Amounts reclassified from accumulated other comprehensive loss(2)	0.1			(15.1		)	0.4			(14.6		)
Net current-period other comprehensive income (loss)	(2.4		)	34.0			0.4			32.0
Reclassification due to adoption of ASU 2018-02 (Refer to Note 2)	—			(6.3		)	(3.2		)	(9.5		)
Balance as of June 30, 2018	$	(2.2	)	$	(1.7	)	$	(17.0	)	$	(20.9	)

Three Months Ended June 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 April 1, 2017	$	(0.2	)	$	(2.0	)	$	(17.4	)	$	(19.6	)
Other comprehensive income (loss) before reclassifications	0.8			(18.2		)	0.1			(17.3		)
Amounts reclassified from accumulated other comprehensive loss	(0.2		)	1.4			0.1			1.3
Net current-period other comprehensive income (loss)	0.6			(16.8		)	0.2			(16.0		)
Balance as of June 30, 2017	$	0.4		$	(18.8	)	$	(17.2	)	$	(35.6	)
Six Months Ended June 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	1.0			(13.6		)	0.2			(12.4		)
Amounts reclassified from accumulated other comprehensive loss	—			1.7			0.2			1.9
Net current-period other comprehensive income (loss)	1.0			(11.9		)	0.4			(10.5		)
Balance as of June 30, 2017	$	0.4		$	(18.8	)	$	(17.2	)	$	(35.6	)

⁽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 9 "Risk Management Activities" for additional information.

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Other, Net (Tables)

6 Months Ended

Jun. 30, 2018

Other, Net [Abstract]

Schedule of Other Nonoperating Income (Expense)

	Three Months Ended June 30,					Six Months Ended June 30,
(in millions)	2018		2017			2018		2017
Interest Income	$	1.1	$	0.9		$	2.8	$	1.8
AFUDC Equity	3.9		3.7			7.6		6.2
Pension and other postretirement non-service cost	6.1		0.5			12.3		1.7
Interest rate swap settlement gain(1)	—		—			21.2		—
Miscellaneous	1.7		(0.9		)	0.2		(3.2		)
Total Other, net	$	12.8	$	4.2		$	44.1	$	6.5

⁽¹⁾See Note 9, "Risk Management Activities," for additional information.

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Business Segment Information (Tables)

6 Months Ended

Jun. 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 June 30,						Six Months Ended June 30,
(in millions)	2018			2017			2018			2017
Operating Revenues
Gas Distribution Operations
Unaffiliated	$	601.9		$	532.5		$	1,929.2		$	1,708.8
Intersegment	3.2			3.6			6.5			7.1
Total	605.1			536.1			1,935.7			1,715.9
Electric Operations
Unaffiliated	404.9			458.0			828.2			879.7
Intersegment	0.2			0.2			0.4			0.4
Total	405.1			458.2			828.6			880.1
Corporate and Other
Unaffiliated	0.2			0.2			0.4			0.8
Intersegment	116.1			121.7			230.2			241.3
Total	116.3			121.9			230.6			242.1
Eliminations	(119.5		)	(125.5		)	(237.1		)	(248.8		)
Consolidated Operating Revenues	$	1,007.0		$	990.7		$	2,757.8		$	2,589.3
Operating Income (Loss)
Gas Distribution Operations	$	39.1		$	43.7		$	360.8		$	382.5
Electric Operations	82.4			85.6			165.5			163.2
Corporate and Other	(3.1		)	(5.3		)	(7.3		)	(6.3		)
Consolidated Operating Income	$	118.4		$	124.0		$	519.0		$	539.4

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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		6 Months Ended		12 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017		Dec. 31, 2016
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Operation and maintenance	$ 365.2	$ 391.6	$ 767.7	$ 803.2
Total Operating Expenses	888.6	866.7	2,238.8	2,049.9
Operating Income	118.4	124.0	519.0	539.4
Other, net	12.8	4.2	44.1	6.5
Total Other Deductions	(88.4)	(195.0)	(150.2)	(277.9)
Income before Income Taxes	30.0	(71.0)	368.8	261.5
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
As Adjusted
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
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	39.1	43.7	360.8	382.5
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	82.4	85.6	165.5	163.2
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	$ (3.1)	$ (5.3)	$ (7.3)	$ (6.3)
New Accounting Pronouncement or Change in Accounting Principle, Effect of Change on Operating Results					$ (3.6)		$ (2.4)

[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)	6 Months Ended
	Jun. 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		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Revenue Recognition Under Previous Guidance [Line Items]
Other Revenues	$ 24.9	$ 30.6	$ 58.5	$ 86.7
Total Operating Revenues	1,007.0	990.7	2,757.8	2,589.3
Previous Accounting Guidance
Revenue Recognition Under Previous Guidance [Line Items]
Gas Distribution	384.2	327.1	1,368.0	1,163.6
Gas Transportation	216.9	204.9	559.1	543.5
Electric	405.0	458.0	828.3	879.7
Other Revenues	0.9	0.7	2.4	2.5
Total Operating Revenues	$ 1,007.0	$ 990.7	$ 2,757.8	$ 2,589.3

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Revenue Recognition (Disaggregation of Revenue) (Details) - USD ($) $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Disaggregation of Revenue [Line Items]
Customer Revenues	[1]	$ 982.1		$ 2,699.3
Other Revenues		24.9	$ 30.6	58.5	$ 86.7
Total Operating Revenues		1,007.0	990.7	2,757.8	2,589.3
Misc.
Disaggregation of Revenue [Line Items]
Customer Revenues	[1]	15.1		39.6
Off-system
Disaggregation of Revenue [Line Items]
Customer Revenues	[1]	20.9		43.2
Industrial
Disaggregation of Revenue [Line Items]
Customer Revenues	[1]	199.7		436.8
Commercial
Disaggregation of Revenue [Line Items]
Customer Revenues	[1]	243.6		668.8
Residential
Disaggregation of Revenue [Line Items]
Customer Revenues	[1]	502.8		1,510.9
Gas Distribution Operations
Disaggregation of Revenue [Line Items]
Customer Revenues	[1]	595.5		1,911.1
Other Revenues		6.4		18.1
Total Operating Revenues		605.1	536.1	1,935.7	1,715.9
Gas Distribution Operations | Misc.
Disaggregation of Revenue [Line Items]
Customer Revenues	[1]	10.2		27.0
Gas Distribution Operations | Off-system
Disaggregation of Revenue [Line Items]
Customer Revenues	[1]	20.9		43.2
Gas Distribution Operations | Industrial
Disaggregation of Revenue [Line Items]
Customer Revenues	[1]	47.7		122.3
Gas Distribution Operations | Commercial
Disaggregation of Revenue [Line Items]
Customer Revenues	[1]	127.0		435.3
Gas Distribution Operations | Residential
Disaggregation of Revenue [Line Items]
Customer Revenues	[1]	389.7		1,283.3
Electric Operations
Disaggregation of Revenue [Line Items]
Customer Revenues	[1]	386.4		787.8
Other Revenues		18.5		40.4
Total Operating Revenues		405.1	458.2	828.6	880.1
Electric Operations | Misc.
Disaggregation of Revenue [Line Items]
Customer Revenues	[1]	4.7		12.2
Electric Operations | Off-system
Disaggregation of Revenue [Line Items]
Customer Revenues	[1]	0.0		0.0
Electric Operations | Industrial
Disaggregation of Revenue [Line Items]
Customer Revenues	[1]	152.0		314.5
Electric Operations | Commercial
Disaggregation of Revenue [Line Items]
Customer Revenues	[1]	116.6		233.5
Electric Operations | Residential
Disaggregation of Revenue [Line Items]
Customer Revenues	[1]	113.1		227.6
Corporate and Other
Disaggregation of Revenue [Line Items]
Customer Revenues	[1]	0.2		0.4
Other Revenues		0.0		0.0
Total Operating Revenues		116.3	$ 121.9	230.6	$ 242.1
Corporate and Other | Misc.
Disaggregation of Revenue [Line Items]
Customer Revenues	[1]	0.2		0.4
Corporate and Other | Off-system
Disaggregation of Revenue [Line Items]
Customer Revenues	[1]	0.0		0.0
Corporate and Other | Industrial
Disaggregation of Revenue [Line Items]
Customer Revenues	[1]	0.0		0.0
Corporate and Other | Commercial
Disaggregation of Revenue [Line Items]
Customer Revenues	[1]	0.0		0.0
Corporate and Other | Residential
Disaggregation of Revenue [Line Items]
Customer Revenues	[1]	$ 0.0		$ 0.0

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

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Revenue Recognition (Customer Accounts Receivable) (Details) - USD ($) $ in Millions		6 Months Ended
		Jun. 30, 2018	Dec. 31, 2017
Revenue from Contract with Customer [Abstract]
Customer Accounts Receivable, Billed (Less Reserve)	[1]	$ 373.6	$ 477.0
Customer Accounts Receivable, Unbilled (Less Reserve)	[2]	155.1	$ 356.0
Increase (Decrease) in Customer Accounts Receivable, Billed (Less Reserve)	[1]	(103.4)
Increase (Decrease) in Customer Accounts Receivable, Unbilled (Less Reserve)	[2]	$ (200.9)

[1] Customer billed receivables decreased over the period due to the expected seasonal decrease in customer usage in June when compared to December.

[2] Customer unbilled receivables decreased over the period due to the expected seasonal decrease in customer usage in June when compared to December.

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Earnings Per Share (Details) - shares shares in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Denominator
Basic Average Common Shares Outstanding	354,229	325,084	346,165	324,386
Dilutive potential common shares
Shares contingently issuable under employee stock plans	861		789	452
Shares restricted under stock plans	71		167	975
Diluted Average Common Shares	355,161	325,084	347,121	325,813

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Equity (Narrative) (Details) $ / shares in Units, $ in Millions			1 Months Ended	6 Months Ended
	Jun. 11, 2018 USD ($) $ / shares shares	May 04, 2018 USD ($) $ / shares shares	Dec. 08, 2017 $ / shares	Jun. 30, 2018 USD ($) $ / shares shares	Jun. 30, 2017 USD ($) $ / shares shares	Dec. 31, 2017 $ / shares shares
Shares, Issued | shares				362,915,000		337,016,000
Proceeds from Issuance of Common Stock				$ 607.7	$ 46.2
Common Stock, Par or Stated Value Per Share | $ / shares				$ 0.01		$ 0.01
Preferred Stock, Par or Stated Value Per Share | $ / shares				$ 1,000
At The Market Program
Number Of Equity Distribution Agreements				4
Common Stock Aggregate Sale Price				$ 500.0
Shares, Issued | shares					1,318,461
Shares Issued, Price Per Share | $ / shares					$ 25.88
Proceeds from Issuance of Common Stock					$ 33.8
ATM Program Equity Remaining Available for Issuance				$ 10.0
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	$ 26.70
Forward Contract Indexed to Issuer's Equity, Settlement Alternatives, Shares, at Fair Value				$ 169.4
Common Stock
Shares, Issued | shares		24,964,163		366,878,000		340,813,000
Sale of Stock, Price Per Share | $ / shares		$ 24.28
Common Stock, Par or Stated Value Per Share | $ / shares		$ 0.01
Gross Proceeds | Common Stock
Proceeds from Issuance of Private Placement		$ 606.0
Net Proceeds | Common Stock
Proceeds from Issuance of Private Placement		$ 599.6
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%
Series A Preferred Stock | Gross Proceeds
Proceeds from Issuance of Private Placement	$ 400.0
Series A Preferred Stock | Net Proceeds
Proceeds from Issuance of Private Placement	$ 394.4

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Gas in Storage (Narrative) (Details) - USD ($) $ in Millions	Jun. 30, 2018	Dec. 31, 2017
Gas in Storage [Abstract]
LIFO Inventory Amount	$ 12.9	$ 0.0

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Asset Retirement Obligations (Details) $ in Millions	6 Months Ended
	Jun. 30, 2018 USD ($)
Asset Retirement Obligations [Abstract]
Asset Retirement Obligation, Revision of Estimate	$ 62.5	[1]

[1] See Note 7 "Asset Retirement Obligations" for additional information.

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Regulatory Matters (Narrative) (Details) - USD ($) $ in Millions																		3 Months Ended	6 Months Ended
	Jul. 31, 2018	Jul. 18, 2018	Jun. 21, 2018	Apr. 30, 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	Jun. 30, 2018	Jun. 30, 2018	May 31, 2018	May 21, 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																		$ 65.0	$ 65.0
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
Tax Benefit From Excess Deferred Tax Amortization Related To Regulatory LIabilities																		7.4	17.8
TCJA Related Revenue Reserve, Net of Tax																		4.7	12.4
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															$ 91.5	$ (8.5)
Regulatory Net Capital Expenditures Included In Filing															$ 35.5			1,250.0	1,250.0
Bailly Reclassification to Regulatory Assets																		245.0	245.0
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
Regulatory Net Capital Expenditures Included In Filing											$ 77.9
Public Utilities, Passback Liability for Revenues Previously Billed to Customers																		$ 2.5	$ 2.5
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), Cumulative Amount, In excess of cap														$ (2.4)
Public Utilities, Requested Rate Increase (Decrease), Amount																$ 9.7
Public Utilities, Approved Rate Increase (Decrease), Amount				$ 6.1
Regulatory Net Capital Expenditures Included In Filing				$ 83.9
Public Utilities, Requested Waiver Revenue Cap Calculation Percentage																					1.50%
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										$ 46.9
Columbia Of Maryland
Regulatory Matters [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount							$ 6.1
Public Utilities, Approved Rate Increase (Decrease), Amount												$ (1.3)
Subsequent Event
Regulatory Matters [Line Items]
Regulatory Net Capital Expenditures Included In Filing	$ 77.1
Subsequent Event | NIPSCO | TDSIC 8 Gas
Regulatory Matters [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount		$ (0.2)
Regulatory Net Capital Expenditures Included In Filing		$ 54.0
Subsequent Event | NIPSCO | TDSIC-4
Regulatory Matters [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Net of TCJA	3.5
Public Utilities, Requested Biennial Rate Increase (Decrease), Amount increases	(10.6)
Public Utilities, Customer Refund for Tax Rate Change Due to TCJA	14.1
Subsequent Event | Columbia Of Maryland
Regulatory Matters [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount	$ 3.7

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Risk Management Activities (Narrative) (Details) - USD ($) $ in Millions	3 Months Ended			6 Months Ended
	Jun. 30, 2018		Jun. 30, 2017	Jun. 30, 2018		Jun. 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 9, "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		Jun. 30, 2018	Dec. 31, 2017
Risk Management Assets Current
Derivatives, Fair Value [Line Items]
Derivative Asset	[1]	$ 2.2	$ 14.5
Risk Management Assets Noncurrent
Derivatives, Fair Value [Line Items]
Derivative Asset	[2]	25.3	6.6
Risk Management Liabilities Current
Derivatives, Fair Value [Line Items]
Derivative Liability		4.0	43.2
Risk Management Liabilities Noncurrent
Derivatives, Fair Value [Line Items]
Derivative Liability		44.9	28.5
Interest Rate Risk | Risk Management Assets Current
Derivatives, Fair Value [Line Items]
Derivative Asset	[1]	1.7	14.0
Interest Rate Risk | Risk Management Assets Noncurrent
Derivatives, Fair Value [Line Items]
Derivative Asset	[2]	23.5	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]	0.5	0.5
Commodity Price Risk Programs | Risk Management Assets Noncurrent
Derivatives, Fair Value [Line Items]
Derivative Asset	[2]	1.8	1.0
Commodity Price Risk Programs | Risk Management Liabilities Current
Derivatives, Fair Value [Line Items]
Derivative Liability		4.0	4.6
Commodity Price Risk Programs | Risk Management Liabilities Noncurrent
Derivatives, Fair Value [Line Items]
Derivative Liability		$ 44.9	$ 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	6 Months Ended
	Jun. 30, 2018	Jun. 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	$ 3.2
Corporate/Other debt securities
Fair Value Disclosure [Line Items]
Available-for-sale Securities, Maturities, Next Twelve Months, Fair Value	$ 3.7

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Fair Value (Fair Value Of Financial Assets And Liabilities Measured On A Recurring Basis) (Details) - USD ($) $ in Millions	Jun. 30, 2018	Dec. 31, 2017
Assets
Available-for-sale securities	$ 130.1	$ 133.9
Total	157.6	155.0
Liabilities
Total	48.9	71.7
Fair Value, Inputs, Level 1
Assets
Risk management assets	0.0	0.0
Available-for-sale securities	0.0	0.0
Total	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	27.4	21.1
Available-for-sale securities	130.1	133.9
Total	157.5	155.0
Liabilities
Risk management liabilities	48.9	71.4
Total	48.9	71.4
Significant Unobservable Inputs (Level 3)
Assets
Risk management assets	0.1	0.0
Available-for-sale securities	0.0	0.0
Total	0.1	0.0
Liabilities
Risk management liabilities	0.0	0.3
Total	0.0	0.3
Available-for-sale Securities
Assets
Available-for-sale securities	130.1	133.9
Risk management assets
Assets
Risk management assets	27.5	21.1
Liabilities
Risk management liabilities	$ 48.9	$ 71.7

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Fair Value (Available-For-Sale Securities) (Details) - USD ($) $ in Millions	Jun. 30, 2018	Dec. 31, 2017
Fair Value Disclosure [Line Items]
Amortized Cost	$ 132.9	$ 133.7
Gross Unrealized Gains	0.3	0.9
Gross Unrealized Losses	(3.1)	(0.7)
Fair Value	130.1	133.9
U.S. Treasury debt securities
Fair Value Disclosure [Line Items]
Amortized Cost	16.8	26.9
Gross Unrealized Gains	0.0	0.0
Gross Unrealized Losses	(0.1)	(0.1)
Fair Value	16.7	26.8
Corporate/Other debt securities
Fair Value Disclosure [Line Items]
Amortized Cost	116.1	106.8
Gross Unrealized Gains	0.3	0.9
Gross Unrealized Losses	(3.0)	(0.6)
Fair Value	$ 113.4	$ 107.1

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Fair Value (Carrying Amount And Estimated Fair Values Of Financial Instruments) (Details) - USD ($) $ in Millions	Jun. 30, 2018	Dec. 31, 2017
Fair Value Disclosures [Abstract]
Long-term Debt (including current portion), Gross	$ 7,690.2	$ 7,796.5
Long-term debt (including current portion), Estimated Fair Value	$ 7,996.1	$ 8,603.4

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Transfers Of Financial Assets (Narrative) (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 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			$ 336.7	$ 11.7
Securitization Transaction Fees	$ 0.7	$ 0.6	1.5	$ 1.3
Accounts Receivable Program
Assets and Associated Liabilities of Transfers Accounted for as Secured Borrowings [Line Items]
Seasonal Limit	$ 320.0		$ 320.0

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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	Jun. 30, 2018	Dec. 31, 2017
Gross Receivables	$ 470.7	$ 635.3
Less: Receivables not transferred	470.7	298.6
Net receivables transferred	0.0	336.7
Accounts receivable securitization facility borrowings	$ 0.0	$ 336.7

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Goodwill (Details) - USD ($) $ in Millions	Jun. 30, 2018	Dec. 31, 2017
Goodwill [Line Items]
Goodwill	$ 1,690.7	$ 1,690.7
Gas Distribution Operations
Goodwill [Line Items]
Goodwill	1,690.7
Electric Operations
Goodwill [Line Items]
Goodwill	0.0
Corporate and Other
Goodwill [Line Items]
Goodwill	$ 0.0

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Income Taxes (Narrative) (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Income Tax Disclosure [Abstract]
Effective income tax rates	18.30%	37.50%	18.50%	36.20%
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate			21.00%	35.00%
Tax Benefit From Excess Deferred Tax Amortization Related To Regulatory LIabilities	$ 7.4		$ 17.8
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
		Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	May 31, 2018
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Employer contributions				$ 1.4
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement	[1]	$ (3.5)	$ 0.0	(3.5)	$ 0.0
Defined Benefit Plan, Benefit Obligation, (Increase) Decrease for Remeasurement due to Settlement				1.1
Change in Regulatory Assets Due To Interim Measurement						$ 2.3
Change in Accumulated Other Comprehensive Income Due To Interim Measurement						0.1
Defined Benefit Plan Net Periodic Benefit Costs						$ 1.1
Other Postretirement Benefit Plan
Defined Benefit Plan Disclosure [Line Items]
Employer contributions				11.3
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		6 Months Ended
		Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Service Cost	[1]	$ 7.9	$ 7.5	$ 15.8	$ 15.0
Interest cost	[1]	16.6	17.2	33.2	34.4
Expected return on assets	[1]	(36.2)	(30.2)	(72.5)	(60.5)
Amortization of prior service credit	[1]	(0.1)	(0.2)	(0.2)	(0.4)
Recognized actuarial loss	[1]	10.2	13.4	20.4	26.8
Settlement loss	[1]	3.5	0.0	3.5	0.0
Total Net Periodic Benefits Cost		1.9	7.7	0.2	15.3
Other Postretirement Benefit Plan
Defined Benefit Plan Disclosure [Line Items]
Service Cost	[1]	1.3	1.2	2.6	2.4
Interest cost	[1]	4.4	4.4	8.8	8.9
Expected return on assets	[1]	(3.7)	(3.9)	(7.4)	(7.9)
Amortization of prior service credit	[1]	(1.0)	(1.1)	(2.0)	(2.2)
Recognized actuarial loss	[1]	0.9	0.7	1.8	1.5
Settlement loss	[1]	0.0	0.0	0.0	0.0
Total Net Periodic Benefits Cost		$ 1.9	$ 1.3	$ 3.8	$ 2.7

[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	12 Months Ended
	May 31, 2018	Dec. 31, 2017
Defined Benefit Plan Disclosure [Line Items]
Discount rate	4.03%	3.58%
Discount rate - service cost	3.79%	4.40%
Discount rate - interest cost	3.15%	3.31%
Expected return on assets	6.30%	7.25%

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Long-Term Debt (Narrative) (Details) - USD ($) $ in Millions		6 Months Ended
	Jul. 16, 2018	Jun. 30, 2018	Jun. 30, 2017	Jun. 11, 2018	Mar. 15, 2018
Debt Instrument [Line Items]
Debt Instrument Tendered		$ 209.0
Payment for Debt Extinguishment or Debt Prepayment Cost		$ 12.5	$ 111.5
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%
6.125% Notes Due 2022
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		6.125%
3.65% Notes Due 2023
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		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%
Subsequent Event | Senior Note Redeemed 2018 Note 2
Debt Instrument [Line Items]
Payment for Debt Extinguishment or Debt Prepayment Cost	$ 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	Jun. 30, 2018	Dec. 31, 2017
Short-term Debt [Line Items]
Commercial paper outstanding			$ 0.0	$ 869.0
Accounts receivable securitization facility borrowings			0.0	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	Jun. 30, 2018	Dec. 31, 2017
Short-term Debt [Line Items]
Commercial paper weighted-average interest rate of 1.97% at December 31, 2017	$ 0.0	$ 869.0
Accounts receivable securitization facility borrowings	0.0	336.7
Term loan weighted-average interest rate of 2.64% at June 30, 2018	600.0	0.0
Total short-term borrowings	$ 600.0	$ 1,205.7
Commercial Paper
Short-term Debt [Line Items]
Short-term Debt, Weighted Average Interest Rate, at Point in Time	0.00%	1.97%
Term Loan
Short-term Debt [Line Items]
Short-term Debt, Weighted Average Interest Rate, at Point in Time	2.64%

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Other Commitments And Contingencies (Narrative) (Details) $ in Millions	6 Months Ended
	Jun. 30, 2018 USD ($)	Jun. 30, 2017 USD ($)	May 31, 2018 USD ($)	Feb. 01, 2018 USD ($)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)
Other Commitments And Contingencies [Line Items]
Proposed Pipeline Safety Rule, time period for investigation and repair/replace activity on facilities	15 years
Recorded reserves to cover environmental remediation at various sites	$ 109.7				$ 111.4
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
Payments Pure Air	$ 7.6	$ 10.4
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
Liability for Estimated Remediation Costs	$ 105.5				106.9
Reasonably possible remediation costs variance from reserve	25.0
Minimum | NIPSCO
Other Commitments And Contingencies [Line Items]
Cost to Maintain and Operate Current Fleet of Coal-Fired Generating Units	1,000.0
Standby Letters of Credit
Other Commitments And Contingencies [Line Items]
Long-term Line of Credit	$ 10.2				$ 11.1

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Accumulated Other Comprehensive Loss (Components Of Accumulated Other Comprehensive Loss) (Details) - USD ($) $ in Millions		3 Months Ended			6 Months Ended
		Jun. 30, 2018		Jun. 30, 2017	Jun. 30, 2018		Jun. 30, 2017	Dec. 31, 2017
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance	[1]	$ (19.0)		$ (19.6)	$ (43.4)		$ (25.1)
Other Comprehensive Income before reclassifications	[1]	(2.0)		(17.3)	46.6		(12.4)
Amounts reclassified from accumulated other comprehensive loss	[1]	0.1	[2]	1.3	(14.6)	[2]	1.9
Net current-period other comprehensive income (loss)	[1]	(1.9)		(16.0)	32.0		(10.5)
New Accounting Pronouncement or Change in Accounting Principle, Cumulative Effect of Change on Equity or Net Assets	[1]							$ (9.5)
Ending Balance	[1]	(20.9)		(35.6)	(20.9)		(35.6)
Gains and Losses on Securities
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance	[1]	(1.5)		(0.2)	0.2		(0.6)
Other Comprehensive Income before reclassifications	[1]	(0.6)		0.8	(2.5)		1.0
Amounts reclassified from accumulated other comprehensive loss	[1]	(0.1)	[2]	(0.2)	0.1	[2]	0.0
Net current-period other comprehensive income (loss)	[1]	(0.7)		0.6	(2.4)		1.0
New Accounting Pronouncement or Change in Accounting Principle, Cumulative Effect of Change on Equity or Net Assets	[1]							0.0
Ending Balance	[1]	(2.2)		0.4	(2.2)		0.4
Gains and Losses on Cash Flow Hedges
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance	[1]	(0.3)		(2.0)	(29.4)		(6.9)
Other Comprehensive Income before reclassifications	[1]	(2.0)		(18.2)	49.1		(13.6)
Amounts reclassified from accumulated other comprehensive loss	[1]	0.6	[2]	1.4	(15.1)	[2]	1.7
Net current-period other comprehensive income (loss)	[1]	(1.4)		(16.8)	34.0		(11.9)
New Accounting Pronouncement or Change in Accounting Principle, Cumulative Effect of Change on Equity or Net Assets	[1]							(6.3)
Ending Balance	[1]	(1.7)		(18.8)	(1.7)		(18.8)
Pension and OPEB Items
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance	[1]	(17.2)		(17.4)	(14.2)		(17.6)
Other Comprehensive Income before reclassifications	[1]	0.6		0.1	0.0		0.2
Amounts reclassified from accumulated other comprehensive loss	[1]	(0.4)	[2]	0.1	0.4	[2]	0.2
Net current-period other comprehensive income (loss)	[1]	0.2		0.2	0.4		0.4
New Accounting Pronouncement or Change in Accounting Principle, Cumulative Effect of Change on Equity or Net Assets	[1]							$ (3.2)
Ending Balance	[1]	$ (17.0)		$ (17.2)	$ (17.0)		$ (17.2)

[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 9 "Risk Management Activities" for additional information.

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Other, Net (Details) - USD ($) $ in Millions	3 Months Ended			6 Months Ended
	Jun. 30, 2018		Jun. 30, 2017	Jun. 30, 2018		Jun. 30, 2017
Other, Net [Abstract]
Interest Income	$ 1.1		$ 0.9	$ 2.8		$ 1.8
AFUDC Equity	3.9		3.7	7.6		6.2
Pension and other postretirement non-service cost	6.1		0.5	12.3		1.7
Interest rate swap settlement gain	0.0	[1]	0.0	21.2	[1]	0.0	[1]
Miscellaneous	1.7		(0.9)	0.2		(3.2)
Total Other, net	$ 12.8		$ 4.2	$ 44.1		$ 6.5

[1] See Note 9, "Risk Management Activities," for additional information.

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Business Segment Information (Narrative) (Details)	6 Months Ended
	Jun. 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		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Segment Reporting Information [Line Items]
Revenues	$ 1,007.0	$ 990.7	$ 2,757.8	$ 2,589.3
Consolidated Operating Income (Loss)	118.4	124.0	519.0	539.4
Gas Distribution Operations
Segment Reporting Information [Line Items]
Revenues	605.1	536.1	1,935.7	1,715.9
Consolidated Operating Income (Loss)	39.1	43.7	360.8	382.5
Gas Distribution Operations | Unaffiliated
Segment Reporting Information [Line Items]
Revenues	601.9	532.5	1,929.2	1,708.8
Gas Distribution Operations | Intersegment
Segment Reporting Information [Line Items]
Revenues	3.2	3.6	6.5	7.1
Electric Operations
Segment Reporting Information [Line Items]
Revenues	405.1	458.2	828.6	880.1
Consolidated Operating Income (Loss)	82.4	85.6	165.5	163.2
Electric Operations | Unaffiliated
Segment Reporting Information [Line Items]
Revenues	404.9	458.0	828.2	879.7
Electric Operations | Intersegment
Segment Reporting Information [Line Items]
Revenues	0.2	0.2	0.4	0.4
Corporate and Other
Segment Reporting Information [Line Items]
Revenues	116.3	121.9	230.6	242.1
Consolidated Operating Income (Loss)	(3.1)	(5.3)	(7.3)	(6.3)
Corporate and Other | Unaffiliated
Segment Reporting Information [Line Items]
Revenues	0.2	0.2	0.4	0.8
Corporate and Other | Intersegment
Segment Reporting Information [Line Items]
Revenues	116.1	121.7	230.2	241.3
Eliminations
Segment Reporting Information [Line Items]
Revenues	$ (119.5)	$ (125.5)	$ (237.1)	$ (248.8)