NiSource (NI) 10-Q 1 Nov 18 2018 Q3 Quarterly report Financial data

Document And Entity Information

Document And Entity Information - shares	9 Months Ended
	Sep. 30, 2018	Oct. 23, 2018
Document Information [Line Items]
Document Type	10-Q
Amendment Flag	false
Entity Emerging Growth Company	false
Entity Small Business	false
Document Period End Date	Sep. 30, 2018
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	Q3
Entity Registrant Name	NISOURCE INC/DE
Entity Central Index Key	1,111,711
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		363,286,952

Statements Of Consolidated Inco

Statements Of Consolidated Income - USD ($) shares in Thousands, $ in Millions	3 Months Ended			9 Months Ended
	Sep. 30, 2018		Sep. 30, 2017	Sep. 30, 2018		Sep. 30, 2017
Operating Revenues
Customer revenues	$ 855.8	[1]	$ 883.4	$ 3,555.1	[1]	$ 3,386
Other revenues	39.2		33.6	97.7		120.3
Total Operating Revenues	895		917	3,652.8		3,506.3
Operating Expenses
Cost of Sales (excluding depreciation and amortization)	222		233.6	1,259.7		1,062.7
Operation and maintenance	780.8		371.7	1,548.5		1,174.9
Depreciation and amortization	148.5		143	437.8		428.5
Loss (Gain) on sale of assets and impairments, net	0.7		0	0.4		(0.1)
Other taxes	58.9		57.5	203.3		189.7
Total Operating Expenses	1,210.9		805.8	3,449.7		2,855.7
Operating Income	(315.9)		111.2	203.1		650.6
Other Income (Deductions)
Interest expense, net	(83.4)		(87.9)	(265.2)		(260.8)
Other, net	(1.7)		(6.8)	42.4		(0.3)
Loss on early extinguishment of long-term debt	(33)		0	(45.5)		(111.5)
Total Other Deductions, Net	(118.1)		(94.7)	(268.3)		(372.6)
Income (Loss) before Income Taxes	(434)		16.5	(65.2)		278
Income Taxes	(94.5)		2.5	(26.3)		97.1
Net Income (Loss)	(339.5)		14	(38.9)		180.9
Preferred dividends	(5.6)		0	(6.9)		0
Net Income (Loss) Available to Common Shareholders	$ (345.1)		$ 14	$ (45.8)		$ 180.9
Earnings (Loss) Per Share
Basic Earnings (Loss) Per Share	$ (0.95)		$ 0.04	$ (0.13)		$ 0.55
Diluted Earnings (Loss) Per Share	(0.95)		0.04	(0.13)		0.55
Dividends Declared Per Common Share	$ 0.195		$ 0.175	$ 0.780		$ 0.700
Basic Average Common Shares Outstanding	363,900		331,139	352,115		326,662
Diluted Average Common Shares	363,900		332,396	352,115		328,031
[1]	Customer revenue amounts exclude intersegment revenues. See Note 19, "Business Segment Information," for discussion of intersegment revenues.

Statements of Consolidated Comp

Statements of Consolidated Comprehensive Income (Loss) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Net Income (Loss)		$ (339.5)	$ 14	$ (38.9)	$ 180.9
Other comprehensive income (loss):
Net unrealized gain (loss) on available-for-sale securities	[1]	0.1	0.1	(2.3)	1.1
Net unrealized gain (loss) on cash flow hedges	[2]	22.5	(9.3)	56.5	(21.2)
Unrecognized pension and OPEB benefit	[3]	0.8	1.1	1.2	1.5
Total other comprehensive income (loss)	[4]	23.4	(8.1)	55.4	(18.6)
Comprehensive Income (Loss)		$ (316.1)	$ 5.9	$ 16.5	$ 162.3
[1]	Net unrealized gain (loss) on available-for-sale securities, net of zero tax expense in the third quarter of 2018 and 2017, and $0.6 million tax benefit and $0.6 million tax expense for the nine months ended 2018 and 2017, respectively.
[2]	Net unrealized gain (loss) on cash flow hedges, net of $7.5 million tax expense and $5.8 million tax benefit in the third quarter of 2018 and 2017, respectively, and $18.7 million tax expense and $13.1 million tax benefit for the nine months ended 2018 and 2017, respectively. See Note 8, "Risk Management Activities," for additional information.
[3]	Unrecognized pension and OPEB benefit, net of zero and $0.5 million tax expense in the third quarter of 2018 and 2017, respectively, and $0.2 million and $0.8 million tax expense for the nine months ended 2018 and 2017, respectively.
[4]	All amounts are net of tax. Amounts in parentheses indicate debits.

Statements of Consolidated Co_2

Statements of Consolidated Comprehensive Income (Loss) (Parenthetical) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Other Comprehensive Income (Loss), Securities, Available-for-Sale, Unrealized Holding Gain (Loss) Arising During Period, Tax	$ 0	$ 0	$ (0.6)	$ 0.6
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Tax	7.5	(5.8)	18.7	(13.1)
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, Tax	$ 0	$ (0.5)	$ (0.2)	$ (0.8)

Statements of Consolidated Bala

Statements of Consolidated Balance Sheets - USD ($) $ in Millions		Sep. 30, 2018	Dec. 31, 2017
Property, Plant and Equipment
Utility Plant		$ 22,328.2	$ 21,026.6
Accumulated depreciation and amortization		(7,171)	(6,953.6)
Net utility plant		15,157.2	14,073
Other property, at cost, less accumulated depreciation		17.2	286.5
Net Property, Plant and Equipment		15,174.4	14,359.5
Investments and Other Assets
Unconsolidated affiliates		2.6	5.5
Other investments		214.5	204.1
Total Investments and Other Assets		217.1	209.6
Current Assets
Cash and cash equivalents		41.8	29
Restricted Cash		12	9.4
Accounts receivable (less reserve of $13.0 and $18.3, respectively)		500.4	898.9
Gas inventory		320.2	285.1
Materials and supplies, at average cost		97.7	105.9
Electric production fuel, at average cost		49	80.1
Exchange gas receivable		37.3	45.8
Regulatory assets		221	176.3
Prepayments and other		89.7	132.8
Total Current Assets		1,369.1	1,763.3
Other Assets
Regulatory assets		1,907.4	1,624.9
Goodwill		1,690.7	1,690.7
Intangible assets, net		223.5	231.7
Deferred charges and other		117.2	82
Total Other Assets		3,938.8	3,629.3
Total Assets		20,699.4	19,961.7
Common Stockholders' Equity
Common stock - $0.01 par value, 400,000,000 shares authorized; 363,167,067 and 337,015,806 shares outstanding, respectively		3.7	3.4
Preferred stock - $1,000 par value, 20,000,000 shares authorized; 400,000 shares outstanding		393.9	0
Treasury stock		(99.9)	(95.9)
Additional paid-in capital		6,161	5,529.1
Retained deficit		(1,387.5)	(1,073.1)
Accumulated other comprehensive loss	[1]	2.5	(43.4)
Total Common Stockholders' Equity		5,073.7	4,320.1
Long-term debt, excluding amounts due within one year		7,094.5	7,512.2
Total Capitalization		12,168.2	11,832.3
Current Liabilities
Current portion of long-term debt		48.6	284.3
Short-term borrowings		1,611	1,205.7
Accounts payable		433.7	625.6
Dividends payable - common stock		70.8	0
Dividends payable - preferred stock		11.6	0
Customer deposits and credits		238.4	262.6
Taxes accrued		150	208.1
Interest accrued		108	112.3
Derivative Instruments and Hedges, Liabilities		4.8	43.2
Exchange gas payable		58.2	59.6
Regulatory liabilities		81.9	58.7
Legal and environmental		20.4	32.1
Accrued compensation and employee benefits		153.4	195.4
Accrued Insurance, Current		365.9	12.5
Other accruals		54.5	78.3
Total Current Liabilities		3,411.2	3,178.4
Other Liabilities and Deferred Credits
Risk management liabilities		45.2	28.5
Deferred income taxes		1,291.7	1,292.9
Deferred investment tax credits		11.7	12.4
Accrued insurance liabilities		81.8	80.1
Accrued liability for postretirement and postemployment benefits		300.9	337.1
Regulatory liabilities		2,826.8	2,736.9
Asset retirement obligations		346.9	268.7
Other noncurrent liabilities		215	194.4
Total Other Liabilities and Deferred Credits		5,120	4,951
Commitments and Contingencies		0	0
Total Capitalization and Liabilities		$ 20,699.4	$ 19,961.7
[1]	All amounts are net of tax. Amounts in parentheses indicate debits.

Statements of Consolidated Ba_2

Statements of Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Accounts receivable less reserve	$ 13	$ 18.3
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	400,000,000	400,000,000
Common Stock, Shares, Outstanding	363,167,067	337,015,806
Preferred Stock, Par or Stated Value Per Share	$ 1,000
Preferred Stock, Shares Authorized	20,000,000
Preferred Stock, Shares Outstanding	400,000

Statements Of Consolidated Cash

Statements Of Consolidated Cash Flows - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Operating Activities
Net Income (Loss)	$ (38.9)	$ 180.9
Adjustments to Reconcile Net Income to Net Cash from Continuing Operations:
Loss on early extinguishment of debt	45.5	111.5
Depreciation and amortization	437.8	428.5
Deferred income taxes and investment tax credits	(26.4)	96.3
Other adjustments	15.6	28.5
Changes in Assets and Liabilities:
Components of working capital	442.9	32.6
Regulatory assets/liabilities	61.3	(12.9)
Postretirement and postemployment benefits	(41.4)	(314.5)
Deferred charges and other noncurrent assets	0.8	(3.7)
Other noncurrent liabilities	30	(17.6)
Net Cash Flows from Operating Activities	927.2	529.6
Investing Activities
Capital expenditures	(1,296.6)	(1,216.4)
Cost of removal	(72.6)	(78.9)
Purchases of available-for-sale securities	(71.4)	(139.4)
Sales of available-for-sale securities	58.5	129.4
Other investing activities	5.6	(1.4)
Net Cash Flows used for Investing Activities	(1,376.5)	(1,306.7)
Financing Activities
Issuance of long-term debt	350	2,750
Repayments of long-term debt and capital lease obligations	(1,044)	(1,352.4)
Premiums and other debt related costs	(46.1)	(139.8)
Issuance of short-term debt (maturity 90 days)	600	0
Change in short-term borrowings, net (maturity ≤ 90 days)	(194.6)	(644.9)
Issuance of common stock	611.6	332.6
Issuance of preferred stock	394.3	0
Acquisition of treasury stock	(4)	(5.9)
Dividends paid - common stock	(202.5)	(170.2)
Net Cash Flows from Financing Activities	464.7	769.4
Change in cash, cash equivalents and restricted cash	15.4	(7.7)
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	38.4	36
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	$ 53.8	$ 28.3

Statements Of Consolidated Ca_2

Statements Of Consolidated Cash Flows (Supplemental Disclosures of Cash Flow Information) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2018		Sep. 30, 2017
Supplemental Cash Flow [Abstract]
Capital expenditures included in current liabilities	$ 167.5		$ 219.1
Dividends declared but not paid	82.4		58.9
Reclassification of other property to regulatory assets	245.3	[1]	0
Asset Retirement Obligation, Revision of Estimate	$ 70.7	[2]	$ 0
[1]	See Note 16-D "Other Matters" for additional information.
[2]	See Note 6 "Asset Retirement Obligations" for additional information.

Statements Of Consolidated Equi

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	$ 9.5	$ (9.5)
Balance as of January 1, 2017 at Dec. 31, 2017		4,320.1	3.4	0	(95.9)	5,529.1	(1,073.1)	(43.4)
Net Loss		(38.9)	0	0	0	0	(38.9)	0
Other comprehensive income, net of tax		55.4	0	0	0	0	0	55.4
Common stock dividends ($0.78 per share)		(273.4)	0	0	0	0	(273.4)	0
Preferred stock dividends ($28.88 per share)		(11.6)	0	0	0	0	(11.6)	0
Treasury stock acquired		(4)	0	0	(4)	0	0	0
Stock Issuances:
Common stock - private placement	[2]	599.6	0.3	0	0	599.3	0	0
Preferred stock	[2]	393.9	0	393.9	0	0	0	0
Employee stock purchase plan		4.2	0	0	0	4.2	0	0
Long-term incentive plan		11.5	0	0	0	11.5	0	0
401(k) and profit sharing		16.9	0	0	0	16.9	0	0
Balance as of September 30, 2018 at Sep. 30, 2018		$ 5,073.7	$ 3.7	$ 393.9	$ (99.9)	$ 6,161	$ (1,387.5)	$ 2.5
[1]	See Note 2, "Recent Accounting Pronouncements," for additional information.
[2]	See Note 5, "Equity," for additional information.

Statements of Consolidated Eq_2

Statements of Consolidated Equity (Shares) (Parenthetical) shares in Thousands	9 Months Ended
	Sep. 30, 2018shares
Balance as of January 1, 2018	337,016
Treasury Stock acquired	(166)
Issued:
Stock Issued During Period, Shares, New Issues	24,964	[1]
Employee stock purchase plan	166
Long-term incentive plan	499
401(k) and profit sharing	688
Balance as of September 30, 2018	363,167
Preferred Stock
Balance as of January 1, 2018	0
Issued:
Stock Issued During Period, Shares, New Issues	400	[1]
Employee stock purchase plan	0
Long-term incentive plan	0
401(k) and profit sharing	0
Balance as of September 30, 2018	400
Common Stock
Balance as of January 1, 2018	340,813
Issued:
Stock Issued During Period, Shares, New Issues	24,964	[1]
Employee stock purchase plan	166
Long-term incentive plan	499
401(k) and profit sharing	688
Balance as of September 30, 2018	367,130
Treasury Stock
Balance as of January 1, 2018	(3,797)
Treasury Stock acquired	(166)
Issued:
Stock Issued During Period, Shares, New Issues	0	[1]
Employee stock purchase plan	0
Long-term incentive plan	0
401(k) and profit sharing	0
Balance as of September 30, 2018	3,963
[1]	See Note 5, "Equity," for additional information.

Statements Of Consolidated Eq_3

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

Basis of Accounting Presentatio

Basis of Accounting Presentation	9 Months Ended
	Sep. 30, 2018
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Basis of Accounting Presentation	Basis of Accounting Presentation Our accompanying Condensed Consolidated Financial Statements (unaudited) reflect all normal recurring adjustments that are necessary, in the opinion of management, to present fairly the results of operations in accordance with GAAP in the United States of America. The accompanying financial statements contain our accounts and that of our majority-owned or controlled subsidiaries. The accompanying financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2017 . Income for interim periods may not be indicative of results for the calendar year due to weather variations and other factors. The Condensed Consolidated Financial Statements (unaudited) have been prepared pursuant to the rules and regulations of the SEC. Certain information and note disclosures normally included in annual financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to those rules and regulations, although we believe that the disclosures made in this quarterly report on Form 10-Q are adequate to make the information herein not misleading.

Recent Accounting Pronouncement

Recent Accounting Pronouncements	9 Months Ended
	Sep. 30, 2018
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
New Accounting Pronouncements and Changes in Accounting Principles	Recent Accounting Pronouncements Recently Issued Accounting Pronouncements We are currently evaluating the impact of certain ASUs on our Condensed Consolidated Financial Statements (unaudited) and Notes to Condensed Consolidated Financial Statements (unaudited), which are described below: Standard Description Effective Date Effect on the financial statements or other significant matters ASU 2018-14, Compensation—Retirement Benefits—Defined Benefit Plans—General (Subtopic 715-20): Disclosure Framework—Changes to the Disclosure Requirements for Defined Benefit Plans The pronouncement modifies the disclosure requirements for defined benefit pension or other postretirement benefit plans. The guidance removes disclosures that are no longer considered cost beneficial, clarifies the specific requirements of disclosures and adds disclosure requirements identified as relevant. The modifications affect annual period disclosures and must be applied on a retrospective basis to all periods presented. Annual periods ending after December 15, 2020. Early adoption is permitted. We are currently evaluating the effects of this pronouncement on our Notes to Condensed Consolidated Financial Statements (unaudited), including potential early adoption in the fourth quarter of 2018. ASU 2016-13, Financial Instruments-Credit Losses (Topic 326) The pronouncement changes the impairment model for most financial assets, replacing the current "incurred loss" model. ASU 2016-13 will require the use of an "expected loss" model for instruments measured at amortized cost. It will also require entities to record allowances for available-for-sale debt securities rather than impair the carrying amount of the securities. Subsequent improvements to the estimated credit losses of available-for-sale securities will be recognized immediately in earnings instead of over time as they are under historic guidance. Annual periods beginning after December 15, 2019, including interim periods therein. Early adoption is permitted for annual or interim periods beginning after December 15, 2018. We maintain investments in U.S. Treasury, corporate and mortgage-backed debt securities, which are pledged as collateral for trust accounts related to our wholly-owned insurance company. These debt securities are classified as available for sale. We are currently evaluating the impact of adoption, if any, on our Condensed Consolidated Financial Statements (unaudited) and Notes to Condensed Consolidated Financial Statements (unaudited). Standard Description Effective Date Effect on the financial statements or other significant matters ASU 2018-11, Leases (Topic 842): Targeted Improvements The pronouncement allows entities the option to initially apply ASC 842 at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. Annual periods beginning after December 15, 2018, including interim periods therein. Early adoption is permitted. We are the lessee for substantially all of our current leasing activity. Upon adopting ASC 842 we will begin recognizing right-of-use assets and liabilities associated with operating leases (other than short term operating leases) on our Condensed Consolidated Balance Sheets (unaudited). The impact of this change on the balance sheet is not reasonably estimable at this time. We do not anticipate the adoption of ASC 842 will have a material impact to our results of operations or cash flows. We have undertaken efforts to outline mock footnote disclosures intended to satisfy ASC 842’s disclosure requirements, which will enhance our disclosures on lease accounting policies and elections. We are implementing a new lease accounting system, which we will utilize to capture, track, and account for lease data. The new system will also aid in automating the compilation of disclosure information. We expect to conclude final system tests in the fourth quarter of 2018, with full system implementation prior to the effective date of these standards. ASC 842 provides lessees the option of electing an accounting policy, by class of underlying asset, in which the lessee may choose not to separate nonlease components from lease components. We currently anticipate adopting this practical expedient for certain classes of leases. Further, we will elect the "practical expedient package" described in ASC 842-10-65-1. We maintain a substantial number of easements and will also elect the provisions of ASU 2018-01 to ease the process of implementing ASC 842. Lastly, we anticipate electing the transition method provided in ASU 2018-11 when we adopt these standards effective January 1, 2019. ASU 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842 The pronouncement offers a practical expedient for accounting for land easements under ASU 2016-02. This practical expedient allows an entity the option of not evaluating existing land easements under ASC 842. New or modified land easements will still require evaluation under ASC 842 on a prospective basis beginning on the date of adoption. ASU 2016-02, Leases (Topic 842) The pronouncement introduces a lessee model that brings most leases on the balance sheet. The standard requires that lessees recognize the following for all leases (with the exception of short-term leases, as that term is defined in the standard) at the lease commencement date: (1) a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and (2) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. Recently Adopted Accounting Pronouncements Standard Adoption ASU 2018-15, Intangibles—Goodwill and Other— Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract In August 2018, the FASB issued this ASU, which amends current guidance to align the accounting for costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing costs associated with developing or obtaining internal-use software. We elected to early adopt the ASU on a prospective basis, effective October 1, 2018. As a result of adopting this ASU, we will defer onto the balance sheet those up-front implementation costs of cloud computing arrangements if they would have been capitalized in a similar on-premise software solution. ASU 2018-02, Income Statement—Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income We adopted this ASU effective March 31, 2018. Upon adoption, $9.5 million of tax effects that were stranded in accumulated other comprehensive income (loss) as a result of the implementation of the TCJA were reclassified to retained deficit. This change is reflected on our Condensed Statements of Consolidated Equity (unaudited). ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force) We adopted this ASU effective January 1, 2018. The adoption of this standard did not have a material impact on our Condensed Consolidated Financial Statements (unaudited) or Notes to Condensed Consolidated Financial Statements (unaudited). ASU 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients See Note 3, "Revenue Recognition," for our discussion of the effects of implementing these standards. ASU 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations ASU 2014-09, Revenue from Contracts with Customers (Topic 606) We also adopted ASU 2017-07, Compensation - Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, effective January 1, 2018. We continue to present the service cost component of net periodic benefit cost within "Operation and maintenance;" however, other components of the net periodic benefit cost (including regulatory deferrals and settlement charges) are now presented separately within "Other, net" on our Condensed Statements of Consolidated Income (Loss) (unaudited). Changes in income statement presentation were implemented on a retrospective basis. The impact of this ASU on previously issued annual financial statements is summarized in the tables below: Year Ended December 31, 2016 (in millions) As Previously Reported Effect of Change (1) As Adjusted Operation and maintenance $ 1,453.7 $ (7.9 ) $ 1,445.8 Total Operating Expenses 3,634.3 (7.9 ) 3,626.4 Operating Income 858.2 7.9 866.1 Other Income (Deductions) Other, net 1.5 (7.9 ) (6.4 ) Total Other Deductions (348.0 ) (7.9 ) (355.9 ) Income before Income Taxes $ 510.2 $ — $ 510.2 (1) The effect of this change is attributable to our business segments: Gas Distribution Operations, Electric Operations, and Corporate and Other in the amounts of $4.3 million , $(9.8) million , and $(2.4) million , respectively. Year Ended December 31, 2017 (in millions) As Previously Reported Effect of Change (1) As Adjusted Operation and maintenance $ 1,612.3 $ (10.6 ) $ 1,601.7 Total Operating Expenses 3,964.0 (10.6 ) 3,953.4 Operating Income 910.6 10.6 921.2 Other Income (Deductions) Other, net (2.8 ) (10.6 ) (13.4 ) Total Other Deductions (467.5 ) (10.6 ) (478.1 ) Income before Income Taxes $ 443.1 $ — $ 443.1 (1) The effect of this change is attributable to our business segments: Gas Distribution Operations, Electric Operations, and Corporate and Other in the amounts of $(4.4) million , $(2.6) million , and $(3.6) million , respectively.

Revenue Recognition

Revenue Recognition	9 Months Ended
	Sep. 30, 2018
Revenue from Contract with Customer [Abstract]
Revenue from Contract with Customer	Revenue Recognition ASC 606 Adoption. In 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (ASC 606). ASU 2014-09 outlines a single, comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance. The core principle of the new standard is that an entity should recognize revenue to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. In 2016, the FASB issued ASU 2016-08, Revenue from Contracts with Customers (ASC 606): Principal versus Agent Considerations, and ASU 2016-12, Revenue from Contracts with Customers (ASC 606): Narrow-Scope Improvements and Practical Expedients. We adopted the provisions of ASC 606 beginning on January 1, 2018 using a modified retrospective method, which was applied to all contracts. No material adjustments were made to January 1, 2018 opening balances as a result of the adoption. As required under the modified retrospective method of adoption, results for reporting periods beginning after January 1, 2018 are presented under ASC 606, while prior period amounts are not adjusted and continue to be reported in accordance with ASC 605. The table below provides results for the three and nine months ended September 30, 2018 as if they had been prepared under historic accounting guidance. We included operating revenue information for the three and nine months ended September 30, 2017 for comparability. Three Months Ended Nine Months Ended (in millions) 2018 2017 2018 2017 Operating Revenues Gas Distribution $ 232.3 $ 239.4 $ 1,600.3 $ 1,403.0 Gas Transportation 186.0 191.6 745.2 735.1 Electric 476.2 485.8 1,304.4 1,365.5 Other 0.5 0.2 2.9 2.7 Total Operating Revenues $ 895.0 $ 917.0 $ 3,652.8 $ 3,506.3 Beginning in 2018 with the adoption of ASC 606, the Condensed Statements of Consolidated Income (Loss) (unaudited) disaggregates “Customer revenues” (i.e. ASC 606 Revenues) from “Other revenues,” both of which are discussed in more detail below. Customer Revenues. Substantially all of our revenues are tariff-based, which we have concluded is within the scope of ASC 606. Under ASC 606, the recipients of our utility service meet the definition of a customer, while the operating company tariffs represent an agreement that meets the definition of a contract. ASC 606 defines a contract as an agreement between two or more parties, in this case us and the customer, which creates enforceable rights and obligations. In order to be considered a contract, we have determined that it is probable that substantially all of the consideration to which we are entitled from customers will be collected upon satisfaction of performance obligations. We maintain common utility credit risk mitigation practices, including requiring deposits and actively pursuing collection of past due amounts. In addition, our regulated operations utilize certain regulatory mechanisms that facilitate recovery of bad debt costs within tariff-based rates, which provides further evidence of collectibility. We have identified our performance obligations created under tariff-based sales as 1) the commodity (natural gas or electricity, which includes generation and capacity) and 2) delivery. These commodities are sold and / or delivered to and generally consumed by customers simultaneously, leading to satisfaction of our performance obligations over time as gas or electricity is delivered to customers. Due to the at-will nature of utility customers, performance obligations are limited to the services requested and received to date. Once complete, we generally maintain no additional performance obligations. Transaction prices for each performance obligation are generally prescribed by each operating company’s respective tariff. Rates include provisions to adjust billings for fluctuations in fuel and purchased power costs and cost of natural gas. Revenues are adjusted for differences between actual costs subject to reconciliation and the amounts billed in current rates. Under or over recovered revenues related to these cost recovery mechanisms are included in regulatory assets or liabilities on the Condensed Consolidated Balance Sheets (unaudited) and are recovered from or returned to customers through adjustments to tariff rates. As we provide and deliver service to customers, revenue is recognized based on the transaction price allocated to each performance obligation. In general, revenue recognized from tariff-based sales is equivalent to the value of natural gas or electricity supplied and billed each period, in addition to an estimate for deliveries completed during the period but not yet billed to the customer. In addition to tariff-based sales, our Gas Distribution Operations segment enters into balancing and exchange arrangements of natural gas as part of our operations and off-system sales programs. We have concluded that these sales are within the scope of ASC 606. Performance obligations for these types of sales include transportation and storage of natural gas and can be satisfied at a point in time or over a period of time, depending on the specific transaction. For those transactions that span a period of time, we record a receivable or payable for any cumulative gas imbalances, as well as for any gas inventory borrowed or lent under a Gas Distributions Operations exchange agreement. Revenue Disaggregation and Reconciliation. We disaggregate revenue from contracts with customers based upon reportable segment as well as by customer class. As our revenues are primarily earned over a period of time, and we do not earn a material amount of revenues at a point in time, revenues are not disaggregated as such below. The Gas Distribution Operations segment provides natural gas service and transportation for residential, commercial and industrial customers in Ohio, Pennsylvania, Virginia, Kentucky, Maryland, Indiana and Massachusetts. The Electric Operations segment provides electric service in 20 counties in the northern part of Indiana. The table below reconciles revenue disaggregation by customer class to segment revenue as well as to revenues reflected on the Condensed Statements of Consolidated Income (Loss) (unaudited): Three Months Ended September 30, 2018 (in millions) Gas Distribution Operations Electric Operations Corporate and Other Total Customer Revenues (1) Residential $ 257.0 $ 154.7 $ — $ 411.7 Commercial 80.9 140.7 — 221.6 Industrial 39.0 153.6 — 192.6 Off-system 20.4 — — 20.4 Miscellaneous 9.2 0.1 0.2 9.5 Total Customer Revenues $ 406.5 $ 449.1 $ 0.2 $ 855.8 Other Revenues 12.1 27.1 — 39.2 Total Operating Revenues $ 418.6 $ 476.2 $ 0.2 $ 895.0 (1) Customer revenue amounts exclude intersegment revenues. See Note 19 , "Business Segment Information," for discussion of intersegment revenues. Nine Months Ended September 30, 2018 (in millions) Gas Distribution Operations Electric Operations Corporate and Other Total Customer Revenues (1) Residential $ 1,540.3 $ 382.3 $ — $ 1,922.6 Commercial 516.2 374.2 — 890.4 Industrial 161.3 468.1 — 629.4 Off-system 63.6 — — 63.6 Miscellaneous 36.2 12.3 0.6 49.1 Total Customer Revenues $ 2,317.6 $ 1,236.9 $ 0.6 $ 3,555.1 Other Revenues 30.2 67.5 — 97.7 Total Operating Revenues $ 2,347.8 $ 1,304.4 $ 0.6 $ 3,652.8 (1) Customer revenue amounts exclude intersegment revenues. See Note 19 , "Business Segment Information," for discussion of intersegment revenues. Customer Accounts Receivable. Accounts receivable on our Condensed Consolidated Balance Sheets (unaudited) includes both billed and unbilled amounts as well as certain amounts that are not related to customer revenues. Unbilled amounts of accounts receivable relate to a portion of a customer’s consumption of gas or electricity from the date of the last cycle billing through the last day of the month (balance sheet date). Factors taken into consideration when estimating unbilled revenue include historical usage, customer rates and weather. The opening and closing balances of customer receivables for the nine months ended September 30, 2018 are presented in the table below. We had no significant contract assets or liabilities during the period. Additionally, we have not incurred any significant costs to obtain or fulfill contracts. (in millions) Customer Accounts Receivable, Billed (less reserve) (1) Customer Accounts Receivable, Unbilled (less reserve) (2) Balance as of December 31, 2017 $ 477.0 $ 356.0 Balance as of September 30, 2018 297.2 154.8 Increase (Decrease) $ (179.8 ) $ (201.2 ) (1) Customer billed receivables decreased over the period due to the expected seasonal decrease in customer usage in September when compared to December. (2) Customer unbilled receivables decreased over the period due to the expected seasonal decrease in customer usage in September when compared to December. Utility revenues are billed to customers monthly on a cycle basis. We generally expect that substantially all customer accounts receivable will be collected within the month following customer billing, as this revenue consists primarily of monthly, tariff-based billings for service and usage. Other Revenues. As permitted by accounting principles generally accepted in the United States, regulated utilities have the ability to earn certain types of revenue that are outside the scope of ASC 606. These revenues primarily represent revenue earned under Alternative Revenue Programs. Alternative Revenue Programs represent regulator-approved programs that allow for the adjustment of billings and revenue for certain broad, external factors, or for additional billings if the entity achieves certain objectives, such as a specified reduction of costs. We maintain a variety of these programs, including demand side management initiatives that recover costs associated with the implementation of energy efficiency programs, as well as normalization programs that adjust revenues for the effects of weather or other external factors. Additionally, we maintain certain programs with future test periods that operate similarly to FERC formula rate programs and allow for recovery of costs incurred to replace aging infrastructure. When the criteria to recognize Alternative Revenue have been met, we establish a regulatory asset and present revenue from Alternative Revenue Programs on the Condensed Statements of Consolidated Income (Loss) (unaudited) as “Other revenues.” When amounts previously recognized under Alternative Revenue accounting guidance are billed, we reduce the regulatory asset and record a customer account receivable.

Earnings Per Share

Earnings Per Share	9 Months Ended
	Sep. 30, 2018
Earnings Per Share [Abstract]
Earnings Per Share	Earnings Per Share Basic EPS is computed by dividing net income available to common shareholders by the weighted-average number of shares of common stock outstanding for the period. The weighted-average shares outstanding for diluted EPS includes the incremental effects of the various long-term incentive compensation plans. The computation of diluted average common shares for the three and nine months ended September 30, 2018 is not presented since we had a net loss on the Condensed Statements of Consolidated Income (Loss) (unaudited) during the periods, and any incremental shares would have had an anti-dilutive impact on EPS. The computation of diluted average common shares is as follows: Three Months Ended Nine Months Ended September 30, September 30, (in thousands) 2017 2017 Denominator Basic average common shares outstanding 331,139 326,662 Dilutive potential common shares: Shares contingently issuable under employee stock plans 604 503 Shares restricted under employee stock plans 653 866 Diluted Average Common Shares 332,396 328,031

Equity

Equity	9 Months Ended
	Sep. 30, 2018
Equity [Abstract]
Equity	Equity ATM Program and Forward Sale Agreement. On May 3, 2017, we entered into four separate equity distribution agreements, pursuant to which we may sell, from time to time, up to an aggregate of $500.0 million of our common stock. As of September 30, 2018 , the ATM program (including impacts of forward sales agreements discussed below) had $10.0 million of equity available for issuance. The program expires on December 31, 2018. The following table summarizes our activity under the ATM Program: Three Months Ended Nine Months Ended 2018 2017 2018 2017 Number of shares issued — 10,612,915 — 11,931,376 Average price per share $ — $ 26.67 $ — $ 26.58 Proceeds, net of fees (in millions) $ — $ 281.0 $ — $ 314.7 On November 13, 2017, under the ATM program, we executed a forward agreement, which allows us to issue a fixed number of shares at a price to be settled in the future. From November 13, 2017 to December 8, 2017, 6,345,860 shares were borrowed from third parties and sold by the dealer at a weighted average price of $27.24 per share. We may settle this agreement in shares, cash, or net shares by November 12, 2018. Had we settled all 6,345,860 shares under the forward agreement at September 30, 2018 , we would have received approximately $168.7 million , based on a net price of $26.59 per share. Private Placement of Common Stock. On May 4, 2018, we completed the sale of 24,964,163 shares of $0.01 par value common stock at a price of $24.28 per share in a private placement to selected institutional and accredited investors. The private placement resulted in $606.0 million of gross proceeds or $599.6 million of net proceeds, after deducting commissions and sale expenses. The common stock issued in connection with the private placement was registered on Form S-1, filed with the SEC on May 11, 2018. Private Placement of Preferred Stock. On June 11, 2018, we completed the sale of 400,000 shares of 5.650% Series A Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Stock (the "Series A Preferred Stock") at a price of $1,000 per share. The transaction resulted in $400.0 million of gross proceeds or $393.9 million of net proceeds, after deducting commissions and sales expenses. The Series A Preferred Stock was issued in a private placement pursuant to SEC Rule 144A. We agreed pursuant to a registration rights agreement to file with the SEC a registration statement enabling holders to exchange their unregistered shares of Series A Preferred Stock for publicly registered shares with substantially identical terms. Proceeds from the issuance of the Series A Preferred Stock were used to pay a portion of the notes tendered in June 2018 and the redemption of the remaining notes in July 2018. See Note 14 , “Long-term Debt” for additional information regarding the tender offer and redemption. Dividends on the Series A Preferred Stock accrue and are cumulative from the date the shares of Series A Preferred Stock were originally issued to, but not including, June 15, 2023 at a rate of 5.650% per annum of the $1,000 liquidation preference per share. On and after June 15, 2023, dividends on the Series A Preferred Stock will accumulate for each five year period at a percentage of the $1,000 liquidation preference equal to the five-year U.S. Treasury Rate plus (i) in respect of each five year period commencing on or after June 15, 2023 but before June 15, 2043, a spread of 2.843% (the “Initial Margin”), and (ii) in respect of each five year period commencing on or after June 15, 2043, the Initial Margin plus 1.000% . The Series A Preferred Stock may be redeemed by us at our option on June 15, 2023, or on each date falling on the fifth anniversary thereafter, or in connection with a ratings event (as defined in the Certificate of Designation of the Series A Preferred Stock). Holders of Series A Preferred Stock generally have no voting rights, except for limited voting rights with respect to (i) potential amendments to our certificate of incorporation that would have a material adverse effect on the existing preferences, rights, powers or duties of the Series A Preferred Stock, (ii) the creation or issuance of any security ranking on a parity with the Series A Preferred Stock if the cumulative dividends payable on then outstanding Series A Preferred Stock are in arrears, or (iii) the creation or issuance of any security ranking senior to the Series A Preferred Stock. The Series A Preferred Stock does not have a stated maturity and is not subject to mandatory redemption or any sinking fund. The Series A Preferred Stock will remain outstanding indefinitely unless repurchased or redeemed by us. Any such redemption would be effected only out of funds legally available for such purposes and will be subject to compliance with the provisions of our outstanding indebtedness.

Asset Retirement Obligations

Asset Retirement Obligations	9 Months Ended
	Sep. 30, 2018
Asset Retirement Obligations [Abstract]
Asset Retirement Obligation Disclosure [Text Block]	Asset Retirement Obligations During 2018, we made revisions to the estimated costs associated with refining the CCR compliance plan. The CCR rule requires the continued collection of data over time to determine the specific compliance solution. The change in estimated costs resulted in an increase to the asset retirement obligation liability of $70.7 million that was recorded in 2018. See Note 16 -C, "Environmental Matters," for additional information on CCRs.

Regulatory Matters

Regulatory Matters	9 Months Ended
	Sep. 30, 2018
Regulatory Assets and Liabilities Disclosure [Abstract]
Regulatory Matters	Regulatory Matters Gas Distribution Operations Regulatory Matters Cost Recovery and Trackers. Comparability of Gas Distribution Operations line item operating results is impacted by regulatory trackers that allow for the recovery in rates of certain costs such as those described below. Increases in the expenses that are the subject of trackers generally result in a corresponding increase in operating revenues and therefore have essentially no impact on total operating income results. Certain operating costs of our distribution companies are significant, recurring in nature and generally outside the control of the distribution companies. Some states allow the recovery of such costs through cost tracking mechanisms. Such tracking mechanisms allow for abbreviated regulatory proceedings in order for the distribution companies to implement charges and recover appropriate costs. Tracking mechanisms allow for more timely recovery of such costs as compared with more traditional cost recovery mechanisms. Examples of such mechanisms include GCR adjustment mechanisms, tax riders and bad debt recovery mechanisms. A portion of the distribution companies' revenue is related to the recovery of gas costs, the review and recovery of which occurs through standard regulatory proceedings. All states in our operating area require periodic review of actual gas procurement activity to determine prudence and to permit the recovery of prudently incurred costs related to the supply of gas for customers. Our distribution companies have historically been found prudent in the procurement of gas supplies to serve customers. Certain of our distribution companies have completed rate proceedings involving infrastructure replacement or are embarking upon regulatory initiatives to replace significant portions of their operating systems that are nearing the end of their useful lives. Each LDC's approach to cost recovery may be unique, given the different laws, regulations and precedent that exist in each jurisdiction. Columbia of Ohio. On January 10, 2018, the PUCO issued an entry to investigate the impacts of the TCJA including an invitation to utilities and other interested stakeholders to file public comments including: (1) those components of utility rates that the PUCO will need to reconcile with the TCJA; and (2) the process and mechanics for how the PUCO should do so. The PUCO also directed utilities to record a regulatory liability for the estimated reduction in federal income tax resulting from the TCJA. On February 15, 2018, Columbia of Ohio filed comments proposing to: (1) reflect the impact of the TCJA on its application to adjust rates associated with its IRP rider, subsequently filed on February 27, 2018; and (2) file a reduction in other base rates reflecting the impact of the TCJA. The PUCO issued a procedural schedule on May 24, 2018 and a hearing was held on July 10, 2018. As discussed in further detail below, on October 25, 2018, Columbia of Ohio filed a joint stipulation and recommendation with the PUCO related to its CEP. Included in that stipulation were terms that would serve to resolve all remaining TCJA-related considerations for Columbia of Ohio. On January 31, 2018, the PUCO approved Columbia of Ohio’s application to extend its IRP for an additional five years (2018-2022), allowing Columbia of Ohio to continue to invest and recover on its accelerated main replacements. The Office of the Ohio Consumers’ Counsel filed an application for rehearing asserting certain issues with Columbia of Ohio's application. On May 9, 2018, the PUCO issued an order denying the application for rehearing. As referred to above, Columbia of Ohio filed its most recent application to adjust rates associated with its IRP rider on February 27, 2018, which requested authority to increase annual billings by approximately $2.3 million (net of the impact of the TCJA) reflecting recovery of and return on approximately $207 million of incremental IRP capital additions in 2017. A stipulation was filed with the PUCO on March 28, 2018. On April 25, 2018, the PUCO approved Columbia of Ohio’s annual IRP tracker adjustment with rates effective May 1, 2018. On December 1, 2017, Columbia of Ohio filed an application that requested authority to implement a rider to begin recovering plant and associated deferrals related to its CEP. The CEP was established in 2011 and allows for deferral of interest, depreciation and property taxes on certain plant investments not recovered through its IRP modernization tracker. The application requested authority to increase annual revenues, through the requested rider, by approximately $70 million , with biennial increases up to approximately $98 million in 2022. On May 9, 2018, the PUCO appointed an independent auditor to assist the PUCO with the review of the accounting accuracy, prudency and compliance of Columbia of Ohio with its PUCO-approved CEP deferrals. The independent audit report was filed on September 4, 2018 and the PUCO Staff's Report on the investigation was filed on September 14, 2018. On October 25, 2018, a joint stipulation and recommendation was filed recommending an initial revenue requirement of $74.5 million to recover CEP investments and deferrals through December 31, 2017, with annual adjustments for capital investments made in subsequent years. Additionally, the signatory parties to the stipulation agreed to a reduction in rates to adjust for the impacts of the TCJA and for a base rate case filing to be made by Columbia of Ohio with a test period of calendar year 2021. A hearing on the stipulation is expected to occur on November 6, 2018. NIPSCO Gas. On January 3, 2018, the IURC initiated an investigation to review and consider the possible implications of the TCJA on utility rates. The IURC ordered a two phase investigation. Phase 1 solely dealt with the prospective changes in rates to reflect the change in tax rates. In accordance with the procedural schedule, on March 26, 2018, NIPSCO filed revised gas tariffs reflecting the impact of the change in tax rate for its applicable rates and charges. The IURC approved NIPSCO's Phase 1 filing on April 26, 2018. The revised tariffs were effective May 1, 2018. The stipulation and settlement agreement filed on April 20, 2018, in NIPSCO’s gas rate case (discussed immediately below) resolved all issues in Phase 2. On September 27, 2017, NIPSCO filed a base rate case with the IURC, seeking an annual revenue increase of $143.5 million (inclusive of amounts being recovered through various tracker programs). As part of this filing and among other items, NIPSCO proposed to update base rates for ongoing infrastructure improvements, revised depreciation rates and ongoing level of expenses to reflect the current costs of providing natural gas service. NIPSCO submitted a rebuttal on March 28, 2018 updating its request, including the impact of the TCJA, seeking a revised annual revenue increase of $138.1 million . On April 20, 2018, a settlement agreement was filed with the IURC seeking, among other items, an annual revenue increase of $107.3 million . An order approving the settlement agreement, as filed, was issued by the IURC on September 19, 2018. Rates will be implemented in three steps, with implementation of step 1 rates effective October 1, 2018, reflecting an annual revenue increase of $84.3 million . Step 2 rates will be effective on or about March 1, 2019, and step 3 rates will be effective on January 1, 2020. The IURC’s order also approved NIPSCO’s dismissal from phase 2 of the IURC’s TCJA investigation. On November 8, 2017, NIPSCO filed a petition with the IURC seeking approval of NIPSCO’s federally mandated pipeline safety compliance plan. As part of the aforementioned settlement agreement filed in NIPSCO’s gas base rate case proceeding, NIPSCO and the parties to the settlement agreement settled all issues in this proceeding as well, including moving certain costs from the base rate proceeding to this pipeline safety compliance plan. The updated four year compliance plan includes a total estimated $91.5 million of capital costs and $35.5 million of expected operating and maintenance costs. NIPSCO received approval for accounting and ratemaking relief, including establishment of a periodic rate adjustment mechanism. NIPSCO anticipates filing the first tracker proceeding in this case on or around December 1, 2018. On April 30, 2013, the Governor of Indiana signed Senate Enrolled Act 560, the TDSIC statute, into law. Among other provisions, this legislation provides for cost recovery outside of a base rate proceeding for new or replacement electric and gas transmission, distribution and storage projects that a public utility undertakes for the purposes of safety, reliability, system modernization or economic development. Provisions of the TDSIC statute require that, among other things, requests for recovery include a seven-year plan of eligible investments. Once the plan is approved by the IURC, eighty percent of eligible costs can be recovered using a periodic rate adjustment mechanism. The cost recovery mechanism is referred to as a TDSIC mechanism. Recoverable costs include a return on, and of, the investment, including AFUDC, post-in-service carrying charges, operation and maintenance expenses, depreciation and property taxes. The remaining twenty percent of recoverable costs are to be deferred for future recovery in the public utility’s next general rate case. The periodic rate adjustment mechanism is capped at an annual increase of no more than two percent of total retail revenues. On April 2, 2018, NIPSCO filed a new seven-year gas TDSIC plan with the IURC beginning in 2019 seeking approval of a total capital expenditure level of approximately $1.25 billion . On September 4, 2018, the IURC dismissed the filing without prejudice. The initial seven-year gas TDSIC plan, approving a total capital expenditure level of approximately $767 million remains in effect as approved by the IURC in April 2014 . A new seven-year gas TDSIC plan may be filed with IURC once the considerations in the pending TDSIC tracker appeal discussed below are resolved. On February 27, 2018, NIPSCO filed TDSIC-8 requesting to recover an incremental increase to revenue of $0.8 million (net of the impacts of TCJA) associated with incremental capital investment of $77.9 million made in the second half of 2017. On June 20, 2018, the Indiana Supreme Court issued an order reversing the IURC and the Court of Appeals in NIPSCO’s gas TDSIC-4 proceeding. The Indiana Supreme Court order stated that periodic rate increases are available only for specific projects designated in the threshold proceeding and multiple-unit-projects not identified with particularity are not recoverable through the tracker. In the second quarter of 2018, NIPSCO recorded a liability of $2.5 million associated with the TDSIC-4 through TDSIC-8 filings for a related passback of revenue previously billed to customers. A revised TDSIC-8 was filed on July 18, 2018 and reduced the previous February 27, 2018 request by $0.2 million associated with incremental capital investment of approximately $54 million . On August 22, 2018, the IURC issued an order approving the requested rates, subject to refund. On August 28, 2018, NIPSCO filed TDSIC-9 requesting an incremental decrease to revenue of $0.5 million associated with incremental capital investment of $72.9 million through June 30, 2018. The filing included the pass back of the revenue associated with multiple-unit-projects from prior TDSIC filings and the pass back of TCJA revenues of $7.1 million for associated tax expense collected from January 1, 2018 through April 30, 2018. On September 26, 2018, NIPSCO filed a revised TDSIC-9 decreasing the requested revenue amount by an additional $7.6 million to reflect assets being included in the base rate amounts for the step 1 rate implementation discussed above. An IURC order is expected in the fourth quarter of 2018. Columbia of Massachusetts. On February 2, 2018, the Massachusetts DPU opened an investigation into the effect of the reduction in federal income tax rates on the rates charged by utility companies. Columbia of Massachusetts was directed to account for any revenues associated with the difference between previous and current income tax rates and excess deferred income taxes as regulatory liabilities effective January 1, 2018. Companies were ordered to submit a proposal to revise rates by May 1, 2018. The order indicates that if a company files a base rate case prior to the conclusion of the investigation, it must address the TCJA issues as part of the case. Since CMA filed a base rate case on April 13, 2018, the changes in base rates and the regulatory liability disposition related to the TCJA are reflected in the case. On June 29, 2018, the Massachusetts DPU required companies in a rate case to reduce rates as of July 1, 2018 or, in the alternative, defer this rate reduction to coincide with the effective date of new rates in a rate case, provided that tax savings from July 1, 2018 through the effective date of new rates accrue interest at prime rate. On July 2, 2018, Columbia of Massachusetts filed tariffs reflecting revised rates incorporating the lower federal corporate income tax rate for effect July 1, 2018. In the filing, Columbia of Massachusetts noted the Massachusetts DPU stated it would address the refund of any tax savings accrued from January 1, 2018, through June 30, 2018, in a separate phase of its investigation. On July 10, 2018, the Massachusetts DPU approved the tariffs effective July 1, 2018, finding the adjustment is in the public interest, as it provides an immediate benefit to ratepayers. As noted above, on April 13, 2018, Columbia of Massachusetts filed a rate case with the Massachusetts DPU, seeking approval for an annual revenue increase of approximately $43.8 million which is offset by revenue decreases in other rate factors of $19.7 million , representing a net increase in operating revenues of $24.1 million . Included in the filing was a proposal to adjust rates and address the regulatory liability disposition related to the TCJA. As a result of the incident that occurred on September 13, 2018, involving a series of fires and explosions that occurred in Lawrence, Andover and North Andover, Massachusetts related to the delivery of natural gas by Columbia of Massachusetts (the “Greater Lawrence Incident”), Columbia of Massachusetts filed a motion with the Massachusetts DPU on September 19, 2018, seeking to withdraw its petition for a base rate revenue increase in the interest of focusing its efforts on the on-going service restoration and customer assistance in the area. Refer to Note 16 , "Other Commitments and Contingencies," in the Notes to Condensed Consolidated Financial Statements (unaudited) for additional information regarding the Greater Lawrence Incident. On October 9, 2018, Columbia of Massachusetts filed an application with the Massachusetts DPU, seeking authority to pass back approximately $95.8 million in excess deferred taxes with an effective date of rates to be determined by the Massachusetts DPU. On July 7, 2014, the Governor of Massachusetts signed into law Chapter 149 of the Acts of 2014, An Act Relative to Natural Gas Leaks (“the Act”). The Act authorizes natural gas distribution companies to file gas infrastructure replacement plans with the Massachusetts DPU to address the replacement of aging natural gas pipeline infrastructure. In addition, the Act provides that the Massachusetts DPU may, after review of the plans, allow the proposed estimated costs of the plan into rates as of May 1 of the subsequent year. On October 31, 2017, Columbia of Massachusetts filed its GSEP for the 2018 construction year which proposed to recover incremental revenue of $9.7 million associated with incremental capital investment of $83.9 million to be made during calendar year 2018. The filing included a request for approval of a waiver to allow collection of the $3.1 million revenue requirement that exceeds the GSEP cap provision. On January 29, 2018, Columbia of Massachusetts filed a revision to its GSEP tracker for the 2018 construction season reducing the proposed revenue requirement by $2.4 million to reflect the impact of the TCJA. On June 21, 2018, the Massachusetts DPU issued an order granting the waiver on the revenue cap allowing an incremental revenue requirement of $6.5 million with new rates effective July 1, 2018. On October 31, 2018, Columbia of Massachusetts filed its GSEP for the 2019 construction year, proposing to recover an incremental revenue requirement of $10.7 million associated with incremental capital of $64.0 million . The filing included a request for approval of a waiver to allow collection of the $2.9 million revenue requirement that exceeds the GSEP cap provision. An order is expected from the Massachusetts DPU in the second quarter of 2019, with new rates effective May 1, 2019. Columbia of Pennsylvania. On February 12, 2018, the Pennsylvania PUC established a docket to investigate the impact of the TCJA on customer rates. The Pennsylvania PUC directed Pennsylvania utilities to account for any revenues associated with the difference between previous and current income tax rates and excess deferred taxes as regulatory liabilities effective January 1, 2018. On May 17, 2018, the Pennsylvania PUC issued an order directing utilities that do not have a pending rate case to implement a negative surcharge in their billings to reflect the annual reduction in federal tax expense and associated revenue requirement for each utility, effective July 1, 2018. On March 16, 2018, Columbia of Pennsylvania filed a rate case with the Pennsylvania PUC, incorporating the impacts of the TCJA and seeking approval for an annual revenue increase of $46.9 million . On March 21, 2018, Columbia of Pennsylvania filed a supplement to the rate case, under which it proposed to hold the overcollection of taxes during 2018 until the effective date of new base rates as credit to rate base for a period beginning January 2019 not to exceed three years. On August 31, 2018 a partial settlement was filed with the Pennsylvania PUC which included a revenue increase of $26.0 million and provided for the TCJA federal tax expense reduction of $22.5 million to be returned to customers over an 18 month period beginning December 16, 2018. On September 18, 2018 the administrative law judge issued a recommended decision approving the partial settlement without modification. A final order is expected in the fourth quarter of 2018 with new rates anticipated to be implemented in December 2018. Columbia of Virginia. On January 8, 2018, the VSCC issued an order regarding the TCJA requiring Columbia of Virginia and other Virginia utilities subject to the TCJA to accrue regulatory liabilities reflecting the impacts of the reduced corporate income tax rate effective January 1, 2018. On August 28, 2018 Columbia of Virginia filed a request with the VSCC requesting a $22.2 million increase in base rates. The filing seeks to recover costs associated with ongoing infrastructure investment programs and incorporates the impacts of the TCJA. Columbia of Virginia proposed that the TCJA regulatory liability associated with lower federal income tax expense accrued prior to the implementation of new rates be considered in future VSCC reviews that assess earnings for the associated time period. Rates will be implemented on an interim basis, subject to refund, effective February 1, 2019, with a final order expected from the VSCC in the second half of 2019. Columbia of Kentucky. On January 26, 2018, in accordance with the Kentucky PSC investigation related to the TCJA, Columbia of Kentucky filed testimony and proposed a reduction to base rates effective May 1, 2018, to reflect the tax expense reduction as a result of the TCJA. Columbia of Kentucky was directed to account for any revenues associated with the difference between previous and current income tax rates and excess deferred taxes as regulatory liabilities effective January 1, 2018. Columbia of Kentucky proposed to include the impact of the excess deferred taxes in rates effective October 2018 and to return the revenue related to the regulatory liability subsequent to this date. On April 30, 2018 Columbia of Kentucky received an order from the Kentucky PSC requiring implementation of interim proposed rates that are subject to future adjustment effective May 1, 2018. The order directed Columbia of Kentucky to file, by September 1, 2018, revised TCJA adjustment factors reflecting the tax expense savings from January 1, 2018, through April 30, 2018, and an estimate of the annual reduction due to the excess deferred taxes to be effective with the first billing cycle of October 2018. On August 31, 2018, Columbia of Kentucky filed updated rate schedules with the Kentucky PSC for rates proposed to be effective October 1, 2018. On September 27, 2018, Columbia of Kentucky received a PSC order suspending the filing for five months. No procedural time line beyond the five month suspension period has been set. On October 15, 2018, Columbia of Kentucky filed an application to adjust rates associated with its AMRP, requesting authority to increase annual revenues by $3.6 million associated with incremental capital investment of $30.1 million to be made during calendar year 2019. An order is anticipated from the Kentucky PSC in December 2018, with new rates effective January 2019. Columbia of Maryland. On February 13, 2018, Columbia of Maryland filed a proposal with the Maryland PSC to reduce rates as a result of TCJA with an annual revenue decrease of $1.3 million . Columbia of Maryland was directed to account for any revenues associated with the difference between previous and current income tax rates and excess deferred taxes as regulatory liabilities effective January 1, 2018. On March 14, 2018, Columbia of Maryland received approval, effective April 2, 2018, to implement new rates and pass-back the overcollection of taxes from the first quarter of 2018. On April 13, 2018, Columbia of Maryland filed a request with the Maryland PSC to increase base rates by $6.1 million , inclusive of the impacts of the TCJA. On July 31, 2018, Columbia of Maryland filed a settlement with the Maryland PSC. If approved as filed, the settlement would result in an annual revenue increase of $3.7 million . On October 2, 2018, the assigned judge issued a proposed order which recommended that the settlement be approved. A final order from the Maryland PSC is expected in the fourth quarter of 2018 with rates anticipated to be effective November 2018. On April 6, 2018, Columbia of Maryland filed an application requesting authority to extend its STRIDE plan for an additional five years (2019-2023). The proposed order issued on August 28, 2018 was not appealed or modified and therefore it became final on September 28, 2018. Electric Operations Regulatory Matters Cost Recovery and Trackers . Comparability of Electric Operations line item operating results is impacted by regulatory trackers that allow for the recovery in rates of certain costs such as those described below. Increases in the expenses that are the subject of trackers result in a corresponding increase in operating revenues and therefore have essentially no impact on total operating income results. Certain operating costs of the Electric Operations are significant, recurring in nature, and generally outside the control of NIPSCO. The IURC allows for recovery of such costs through cost tracking mechanisms. Such tracking mechanisms allow for abbreviated regulatory proceedings in order for NIPSCO to implement charges and recover appropriate costs. Tracking mechanisms allow for more timely recovery of such costs as compared with more traditional cost recovery mechanisms. Examples of such mechanisms include electric energy efficiency programs, MISO non-fuel costs and revenues, resource capacity charges, federally mandated costs and environmental-related costs. A portion of NIPSCO's revenue is related to the recovery of fuel costs to generate power and the fuel costs related to purchased power. These costs are recovered through a FAC, a quarterly regulatory proceeding in Indiana. As noted above in the NIPSCO Gas regulatory matters, the IURC initiated an investigation on January 3, 2018, to review and consider the implications of the TCJA on utility rates. The commission ordered a two phase investigation. Phase 1 solely dealt with the prospective changes in rates to reflect the change in tax rates. On March 26, 2018, NIPSCO filed revised electric tariffs reflecting the impact of the change in tax rate for its applicable rates and charges. The IURC approved NIPSCO's phase 1 filing on April 26, 2018. The revised tariffs were effective May 1, 2018. On July 31, 2018, NIPSCO filed an unopposed motion requesting that the over-collection of income taxes from January 1, 2018 through April 30, 2018 be passed back in NIPSCO’s TDSIC-4 filing, also filed on July 31, 2018, and requesting that all other phase 2 issues be handled in a rate case filing to be made in the fourth quarter of 2018. On August 15, 2018, the IURC approved the motion to pass back the over-collection and stated that all other phase 2 issues will be addressed in the to-be-filed base rate case, as discussed below. On October 31, 2018 NIPSCO filed a request for an increase in base rates with the IURC for a proposed $21.4 million increase in revenues in part, to address anticipated revenue loss resulting from the WCE filing discussed below, as well as to address phase 2 issues of the TCJA. The filing also addresses the appropriate depreciation rates for the accelerated retirement of NIPSCO’s aging coal fleet, as discussed in the 2018 Integrated Resource Plan below. An order is expected from the IURC in the third quarter of 2019 with rates anticipated to be effective September 2019. Also on October 31, 2018, NIPSCO submitted its 2018 Integrated Resource Plan with the IURC. The plan evaluated demand-side and supply-side resource alternatives to reliably and cost effectively meet NIPSCO customers' future energy requirements over the ensuing 20 years. Refer to Note 16 -D, "Other Matters," in the Notes to Condensed Consolidated Financial Statements (unaudited) for additional information. On March 29, 2018, WCE, which is currently owned by BP p.l.c ("BP") and BP Products North America, which operates the BP Refinery, filed a petition at the IURC asking that the combined operations of WCE and BP be treated as a single premise, and the WCE generation be dedicated primarily to BP Refinery operations beginning in May 2019 as WCE has self-certified as a qualifying facility at FERC. BP Refinery planned to continue to purchase electric service from NIPSCO at a reduced demand level beginning in May 2019. NIPSCO is currently in discussions with BP. On January 30, 2018, NIPSCO made a TDSIC-3 rate adjustment mechanism filing requesting a revenue decrease of $1.8 million to be billed over six months, associated with $75.0 million of incremental capital expenditures made from May 1, 2017 to November 30, 2017. The decrease was due to the impact of the TCJA as well as a shorter billing period compared to TDSIC-2. TDSIC-3 was approved on May 30, 2018 and became effective for the first billing cycle of June. Additionally, the TDSIC-2 rates revised for tax reform approved as a part of NIPSCO’s Phase 1 filing described above were made effective on May 1, 2018, until TDSIC-3 rates went into effect. The impact of TCJA on TDSIC-2 was an approximate decrease in revenue of $1.2 million for the period from January through May 2018. NIPSCO made a TDSIC-4 rate adjustment mechanism filing on July 31, 2018, which was modified on October 25, 2018, seeking an incremental semi-annual revenue decrease of $11.2 million due primarily to the pass back of a $14.1 million TCJA electric base rate customer refund for the period January through May 2018. The TCJA refund offsets a $2.8 million increase associated with $72.2 million of incremental capital expenditures from December 2017 through May 2018. An order approving the request is expected in the fourth quarter of 2018. On February 1, 2018, NIPSCO and certain other MISO transmission owners filed with the FERC a request for waiver of tariff provisions to allow for implementation of TCJA provisions into 2018 transmission formula rates as soon as possible. On March 15, 2018, the FERC issued an order granting the request for waiver and set the effective date of the waiver at January 1, 2018. In the March billing cycle, the MISO began billing the new transmission rates reflecting the lower federal tax rate. In addition, the MISO began to re-bill January and February 2018 affected revenues and costs in the March 2018 billing cycle, and completed the re-settlement in the April 2018 billing cycle. The new 2018 transmission formula rates will lower revenue by approximately $8.5 million in 2018 associated with NIPSCO's multi-value projects. Material Updates to Regulatory Assets and Liabilities Since December 31, 2017 TCJA-Related Regulatory Liabilities. As referenced above, during the nine months ended September 30, 2018 , we recorded additional TCJA-related regulatory liabilities of $69.9 million to reflect 2018 collections from customers which we believe are probable of being refunded back to customers once new customer rates are approved by our regulators. As discussed in Note 12 , "Income Taxes," in 2018 we began amortizing regulatory liabilities associated with excess deferred taxes, which resulted in a $6.8 million and $24.6 million income tax benefit for the three and nine months ended September 30, 2018 , respectively. Related to this activity, we recorded an offsetting reserve of $3.6 million and $15.9 million (net of tax) in "Customer revenues" to reflect the probable future passback of this earnings benefit to customers for the three and nine months ended September 30, 2018 , respectively. In certain jurisdictions, we received additional regulatory guidance on the treatment and passback period of excess deferred income taxes, indicating that such a reserve was not required as of September 30, 2018 . Bailly Generating Station. On February 1, 2018, as previously approved by the MISO, NIPSCO commenced a four-month outage of Bailly Generating Station Unit 8 in order to begin work on converting the unit to a synchronous condenser (a piece of equipment designed to maintain voltage to ensure continued reliability on the transmission system). Approximately $15 million of net book value of Unit 8 remained in “Net Utility Plant” as it is expected to remain used and useful upon completion of the synchronous condenser, while the remaining net book value of approximately $142 million was reclassified to “Regulatory assets (noncurrent)” on the Condensed Consolidated Balance Sheets (unaudited). On May 31, 2018, Units 7 and 8 were retired from service. As a result, the remaining net book value of Unit 7 of approximately $103 million was reclassified to “Regulatory assets (noncurrent)” on the Condensed Consolidated Balance Sheets (unaudited).These amounts continue to be amortized at a rate consistent with their inclusion in customer rates.

Risk Management Activities

Risk Management Activities	9 Months Ended
	Sep. 30, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Risk Management Activities	Risk Management Activities We are exposed to certain risks relating to our ongoing business operations, namely commodity price risk and interest rate risk. We recognize that the prudent and selective use of derivatives may help to lower our cost of debt capital, manage our interest rate exposure and limit volatility in the price of natural gas. Risk management assets and liabilities on our derivatives are presented on the Condensed Consolidated Balance Sheets (unaudited) as shown below: (in millions) September 30, 2018 December 31, 2017 Risk Management Assets - Current (1) Interest rate risk programs $ 21.4 $ 14.0 Commodity price risk programs 1.0 0.5 Total $ 22.4 $ 14.5 Risk Management Assets - Noncurrent (2) Interest rate risk programs $ 32.6 $ 5.6 Commodity price risk programs 2.6 1.0 Total $ 35.2 $ 6.6 Risk Management Liabilities - Current Interest rate risk programs $ — $ 38.6 Commodity price risk programs 4.8 4.6 Total $ 4.8 $ 43.2 Risk Management Liabilities - Noncurrent Interest rate risk programs $ — $ — Commodity price risk programs 45.2 28.5 Total $ 45.2 $ 28.5 (1) Presented in "Prepayments and other" on the Condensed Consolidated Balance Sheets (unaudited). (2) Presented in "Deferred charges and other" on the Condensed Consolidated Balance Sheets (unaudited). Commodity Price Risk Management We, along with our utility customers, are exposed to variability in cash flows associated with natural gas purchases and volatility in natural gas prices. We purchase natural gas for sale and delivery to our retail, commercial and industrial customers, and for most customers the variability in the market price of gas is passed through in their rates. Some of our utility subsidiaries offer programs whereby variability in the market price of gas is assumed by the respective utility. The objective of our commodity price risk programs is to mitigate the gas cost variability, for us or on behalf of our customers, associated with natural gas purchases or sales by economically hedging the various gas cost components using a combination of futures, options, forwards or other derivative contracts. NIPSCO received IURC approval to lock in a fixed price for its natural gas customers using long-term forward purchase instruments. The term of these instruments may range from five to ten years and is limited to twenty percent of NIPSCO’s average annual GCA purchase volume. Gains and losses on these derivative contracts are deferred as regulatory liabilities or assets and are remitted to or collected from customers through NIPSCO’s quarterly GCA mechanism. These instruments are not designated as accounting hedges. Interest Rate Risk Management As of September 30, 2018 , we have forward-starting interest rate swaps with an aggregate notional value totaling $750.0 million to hedge the variability in cash flows attributable to changes in the benchmark interest rate during the periods from the effective dates of the swaps to the anticipated dates of forecasted debt issuances, which are expected to take place by the end of 2019. These interest rate swaps are designated as cash flow hedges. The effective portions of the gains and losses related to these swaps are recorded to AOCI and are recognized in "Interest expense, net" concurrently with the recognition of interest expense on the associated debt, once issued. If it becomes probable that a hedged forecasted transaction will no longer occur, the accumulated gains or losses on the derivative will be recognized currently in "Other, net." In April 2018, we settled forward-starting interest rate swaps with a notional value of $250.0 million . These derivative contracts were accounted for as cash flow hedges. As part of the transaction, the associated net unrealized gain of $21.2 million was recognized immediately in "Other, net" on the Condensed Statements of Consolidated Income (Loss) (unaudited) due to the probability associated with the forecasted borrowing transaction no longer occurring. There were no amounts excluded from effectiveness testing for derivatives in cash flow hedging relationships at September 30, 2018 and December 31, 2017 . Our derivative instruments measured at fair value as of September 30, 2018 and December 31, 2017 do not contain any credit-risk-related contingent features.

Fair Value

Fair Value	9 Months Ended
	Sep. 30, 2018
Fair Value Disclosures [Abstract]
Fair Value	Fair Value A. Fair Value Measurements Recurring Fair Value Measurements. The following tables present financial assets and liabilities measured and recorded at fair value on our Condensed Consolidated Balance Sheets (unaudited) on a recurring basis and their level within the fair value hierarchy as of September 30, 2018 and December 31, 2017 : Recurring Fair Value Measurements (in millions) Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Balance as of September 30, 2018 Assets Risk management assets $ — $ 57.6 $ — $ 57.6 Available-for-sale securities — 143.8 — 143.8 Total $ — $ 201.4 $ — $ 201.4 Liabilities Risk management liabilities $ — $ 50.0 $ — $ 50.0 Total $ — $ 50.0 $ — $ 50.0 Recurring Fair Value Measurements (in millions) Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Balance as of December 31, 2017 Assets Risk management assets $ — $ 21.1 $ — $ 21.1 Available-for-sale securities — 133.9 — 133.9 Total $ — $ 155.0 $ — $ 155.0 Liabilities Risk management liabilities $ — $ 71.4 $ 0.3 $ 71.7 Total $ — $ 71.4 $ 0.3 $ 71.7 Risk management assets and liabilities include interest rate swaps, exchange-traded NYMEX futures and NYMEX options and non-exchange-based forward purchase contracts. When utilized, exchange-traded derivative contracts are based on unadjusted quoted prices in active markets and are classified within Level 1. These financial assets and liabilities are secured with cash on deposit with the exchange; therefore, nonperformance risk has not been incorporated into these valuations. Certain non-exchange-traded derivatives are valued using broker or over-the-counter, on-line exchanges. In such cases, these non-exchange-traded derivatives are classified within Level 2. Non-exchange-based derivative instruments include swaps, forwards, options and treasury lock agreements. In certain instances, these instruments may utilize models to measure fair value. We use a similar model to value similar instruments. Valuation models utilize various inputs that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, other observable inputs for the asset or liability and market-corroborated inputs, (i.e., inputs derived principally from or corroborated by observable market data by correlation or other means). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized within Level 2. Certain derivatives trade in less active markets with a lower availability of pricing information and models may be utilized in the valuation. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized within Level 3. Credit risk is considered in the fair value calculation of derivative instruments that are not exchange-traded. Credit exposures are adjusted to reflect collateral agreements which reduce exposures. As of September 30, 2018 and December 31, 2017 , there were no material transfers between fair value hierarchies. Additionally, there were no changes in the method or significant assumptions used to estimate the fair value of our financial instruments. We have entered into forward-starting interest rate swaps to hedge the interest rate risk on coupon payments of forecasted issuances of long-term debt. These derivatives are designated as cash flow hedges. Credit risk is considered in the fair value calculation of each agreement. As they are based on observable data and valuations of similar instruments, the hedges are categorized within Level 2 of the fair value hierarchy. There was no exchange of premium at the initial date of the swaps, and we can settle the contracts at any time. For additional information, see Note 8 , "Risk Management Activities." NIPSCO has entered into long-term forward natural gas purchase instruments that range from five to ten years to lock in a fixed price for its natural gas customers. We value these contracts using a pricing model that incorporates market-based information when available, as these instruments trade less frequently and are classified within Level 2 of the fair value hierarchy. For additional information, see Note 8 , “Risk Management Activities.” Available-for-sale securities are investments pledged as collateral for trust accounts related to our wholly-owned insurance company. Available-for-sale securities are included within “Other investments” in the Condensed Consolidated Balance Sheets (unaudited). We value U.S. Treasury, corporate debt and mortgage-backed securities using a matrix pricing model that incorporates market-based information. These securities trade less frequently and are classified within Level 2. Total unrealized gains and losses from available-for-sale securities are included in other comprehensive income. The amortized cost, gross unrealized gains and losses and fair value of available-for-sale securities at September 30, 2018 and December 31, 2017 were: September 30, 2018 (in millions) Amortized Cost Gross Unrealized Gains Gross Unrealized Losses Fair Value Available-for-sale securities U.S. Treasury debt securities $ 29.7 $ — $ (0.2 ) $ 29.5 Corporate/Other debt securities 116.8 0.4 (2.9 ) 114.3 Total $ 146.5 $ 0.4 $ (3.1 ) $ 143.8 December 31, 2017 (in millions) Amortized Cost Gross Unrealized Gains Gross Unrealized Losses Fair Value Available-for-sale securities U.S. Treasury debt securities $ 26.9 $ — $ (0.1 ) $ 26.8 Corporate/Other debt securities 106.8 0.9 (0.6 ) 107.1 Total $ 133.7 $ 0.9 $ (0.7 ) $ 133.9 Realized gains and losses on available-for-sale securities were immaterial for the three and nine months ended September 30, 2018 and 2017 . The cost of maturities sold is based upon specific identification. At September 30, 2018 , approximately $14.9 million of U.S. Treasury debt securities and approximately $3.0 million of Corporate/Other debt securities have maturities of less than a year. There are no material items in the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis for the three and nine months ended September 30, 2018 and 2017 . Non-recurring Fair Value Measurements. There were no significant non-recurring fair value measurements recorded during the three and nine months ended September 30, 2018 . B. Other Fair Value Disclosures for Financial Instruments. The carrying amount of cash and cash equivalents, restricted cash, customer deposits and short-term borrowings is a reasonable estimate of fair value due to their liquid or short-term nature. Our long-term borrowings are recorded at historical amounts. The following method and assumptions were used to estimate the fair value of each class of financial instruments. Long-term Debt. The fair value of outstanding long-term debt is estimated based on the quoted market prices for the same or similar securities. Certain premium costs associated with the early settlement of long-term debt are not taken into consideration in determining fair value. These fair value measurements are classified within Level 2 of the fair value hierarchy. For the nine months ended September 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 Estimated Fair Carrying Amount as of Dec. 31, 2017 Estimated Fair Value as of Dec. 31, 2017 Long-term debt (including current portion) $ 7,143.1 $ 7,280.1 $ 7,796.5 $ 8,603.4

Transfers Of Financial Assets

Transfers Of Financial Assets	9 Months Ended
	Sep. 30, 2018
Transfers and Servicing [Abstract]
Transfers Of Financial Assets	Transfers of Financial Assets Columbia of Ohio, NIPSCO and Columbia of Pennsylvania each maintain a receivables agreement whereby they transfer their customer accounts receivables to third party financial institutions through wholly-owned and consolidated special purpose entities. The three agreements expire between March 2019 and October 2019 and may be further extended if mutually agreed to by the parties thereto. All receivables transferred to third parties are valued at face value, which approximates fair value due to their short-term nature. The amount of the undivided percentage ownership interest in the accounts receivables transferred is determined in part by required loss reserves under the agreements. Transfers of accounts receivable are accounted for as secured borrowings resulting in the recognition of short-term borrowings on the Condensed Consolidated Balance Sheets (unaudited). As of September 30, 2018 , the maximum amount of debt that could be recognized related to our accounts receivable programs is $265.0 million . The following table reflects the gross receivables balance and net receivables transferred as well as short-term borrowings related to the securitization transactions as of September 30, 2018 and December 31, 2017 : (in millions) September 30, 2018 December 31, 2017 Gross Receivables $ 410.9 $ 635.3 Less: Receivables not transferred 145.9 298.6 Net receivables transferred $ 265.0 $ 336.7 Short-term debt due to asset securitization $ 265.0 $ 336.7 For the nine months ended September 30, 2018 and 2017 , $71.7 million and $47.8 million , respectively, was recorded as cash flows used for financing activities related to the change in short-term borrowings due to securitization transactions. Fees associated with the securitization transactions were $0.4 million and $0.6 million for the three months ended September 30, 2018 and 2017 , respectively, and $1.9 million for the nine months ended September 30, 2018 and 2017 , respectively. We remain responsible for collecting on the receivables securitized, and the receivables cannot be transferred to another party.

Goodwill

Goodwill	9 Months Ended
	Sep. 30, 2018
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill	Goodwill The following presents our goodwill balance allocated by segment as of September 30, 2018 : (in millions) Gas Distribution Operations Electric Operations Corporate and Other Total Goodwill $ 1,690.7 $ — $ — $ 1,690.7 We applied the qualitative "step 0" analysis to our reporting units for the annual impairment test performed as of May 1, 2018. For this test, we assessed various assumptions, events and circumstances that would have affected the estimated fair value of the reporting units as compared to their base line May 1, 2016 "step 1" fair value measurement. The results of this assessment indicated that it was not more likely than not that our reporting unit fair values were less than the reporting unit carrying values, accordingly, no "step 1" analysis was required. In the third quarter of 2018, we determined the Greater Lawrence Incident (see FN 16 , "Other Commitments and Contingencies") represents a triggering event that requires an impairment analysis of goodwill. This incident specifically impacts our Columbia of Massachusetts reporting unit in which the associated goodwill totaled $204.8 million immediately prior to the incident. We performed a quantitative impairment analysis as of September 30, 2018 and determined that the fair value of the Columbia of Massachusetts reporting unit continues to exceed its carrying value. Therefore, no goodwill impairment charges were recorded in the third quarter of 2018. This interim analysis was performed using updated cash flow projections reflecting the estimated ongoing impacts of the Greater Lawrence Incident on Columbia of Massachusetts' operations. We also updated other significant inputs to the fair value calculation (e.g. discount rate, market multiples) to reflect current market conditions and the increased risk and uncertainty resulting from the incident. We will continue to monitor the impacts of the Greater Lawrence Incident for events that could trigger a new impairment analysis including, but not limited to, unfavorable regulatory outcomes, extended customer impacts, and NTSB investigation results.

Income Taxes

Income Taxes	9 Months Ended
	Sep. 30, 2018
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes Our interim effective tax rates reflect the estimated annual effective tax rates for 2018 and 2017, adjusted for tax expense associated with certain discrete items. The effective tax rates for the three months ended September 30, 2018 and 2017 were 21.8% and 15.2% , respectively. The effective tax rates for the nine months ended September 30, 2018 and 2017 were 40.3% and 34.9% , respectively. These effective tax rates differ from the federal statutory tax rate of 21% in 2018 and 35% in 2017, primarily due to the effects of tax credits, state income taxes, utility ratemaking and other permanent book-to-tax differences. The increase in the three month effective tax rate of 6.6% in 2018 compared to 2017 is due to state tax apportionment benefits recorded in the third quarter of 2017 that were not recorded in the current year period along with the impact of the Greater Lawrence Incident on consolidated state income taxes. These increases were partially offset by the change in the federal statutory rate due to the enactment of the TCJA. The increase in the nine month effective tax rate of 5.4% in 2018 versus the same period in 2017 is primarily due to the impact of the Greater Lawrence Incident on consolidated state income taxes, partially offset by the change in the federal statutory rate due to the enactment of the TCJA. In 2018 we began amortizing a portion of our regulatory liability associated with excess deferred taxes which resulted in a current year income tax benefit of $6.8 million and $24.6 million for the three and nine months ended September 30, 2018 , respectively. Additionally, we continue to work with the public utility commissions in each of our seven states on the appropriate treatment and resolution of TCJA impacts. Final regulatory orders from our public utility commissions in ongoing proceedings may decrease our TCJA-related regulatory liabilities by up to approximately $150 million . Such decreases would be recorded in the period the respective orders are received. Refer to Note 7 , "Regulatory Matters," for additional information. There were no material changes recorded in 2018 to our uncertain tax positions as of December 31, 2017 .

Pension And Other Postretiremen

Pension And Other Postretirement Benefits	9 Months Ended
	Sep. 30, 2018
Pension and Other Postretirement Benefits Cost (Reversal of Cost) [Abstract]
Pension And Other Postretirement Benefits	Pension and Other Postretirement Benefits We provide defined contribution plans and noncontributory defined benefit retirement plans that cover certain of our employees. Benefits under the defined benefit retirement plans reflect the employees’ compensation, years of service and age at retirement. Additionally, we provide health care and life insurance benefits for certain retired employees. The majority of employees may become eligible for these benefits if they reach retirement age while working for us. The expected cost of such benefits is accrued during the employees’ years of service. For most plans, cash contributions are remitted to grantor trusts. For the nine months ended September 30, 2018 , we contributed $2.1 million to our pension plans and $16.8 million to our other postretirement benefit plans. The following table provides the components of the plans’ actuarially determined net periodic benefit cost for the three and nine months ended September 30, 2018 and 2017 : Pension Benefits Other Postretirement Benefits Three Months Ended September 30, (in millions) 2018 2017 2018 2017 Components of Net Periodic Benefit Cost (1) Service cost $ 7.8 $ 7.4 $ 1.3 $ 1.2 Interest cost 16.8 17.1 4.4 4.4 Expected return on assets (35.4 ) (30.8 ) (3.7 ) (3.9 ) Amortization of prior service credit (0.1 ) (0.1 ) (1.0 ) (1.1 ) Recognized actuarial loss 10.2 13.2 0.9 0.7 Settlement loss 8.3 10.6 — — Total Net Periodic Benefit Cost $ 7.6 $ 17.4 $ 1.9 $ 1.3 (1) The service cost component, and all non-service cost components, of net periodic benefit cost are presented in "Operation and maintenance" and "Other, net", respectively, on the Condensed Statements of Consolidated Income (Loss) (unaudited). Pension Benefits Other Postretirement Benefits Nine Months Ended September 30, (in millions) 2018 2017 2018 2017 Components of Net Periodic Benefit Cost (1) Service cost $ 23.6 $ 22.4 $ 3.9 $ 3.6 Interest cost 50.0 51.5 13.2 13.4 Expected return on assets (107.9 ) (91.3 ) (11.1 ) (11.9 ) Amortization of prior service credit (0.3 ) (0.5 ) (3.0 ) (3.3 ) Recognized actuarial loss 30.6 40.0 2.7 2.2 Settlement loss 11.8 10.6 — — Total Net Periodic Benefit Cost $ 7.8 $ 32.7 $ 5.7 $ 4.0 (1) The service cost component, and all non-service cost components, of net periodic benefit cost are presented in "Operation and maintenance" and "Other, net", respectively, on the Condensed Statements of Consolidated Income (Loss) (unaudited). As of May 31, 2018, two of our qualified pension plans paid lump sums in excess of the respective plan's 2018 service cost plus interest cost, thereby meeting the requirement for settlement accounting. A settlement charge of $3.5 million was recorded during the second quarter of 2018. As a result of these settlements, the two pension plans were remeasured. The remeasurements led to an increase to the pension benefit obligation, net of plan assets, of $1.1 million , a net decrease to regulatory assets of $2.3 million , and a net credit to accumulated other comprehensive income (loss) of $0.1 million . Net periodic pension benefit cost for 2018 increased by $1.1 million as a result of the second quarter remeasurement. As of August 31, 2018, an additional qualified pension plan paid lump sums in excess of its 2018 service cost plus interest cost, thereby meeting the requirement for settlement accounting. A settlement charge of $8.3 million was recorded during the third quarter of 2018. As a result of this settlement, the plan was remeasured, leading to a decrease to the net pension asset of $2.5 million , a net decrease to regulatory assets of $5.3 million , and a net credit to accumulated other comprehensive income (loss) of $0.5 million . Net periodic pension benefit cost for 2018 increased by $1.9 million as a result of the third quarter remeasurement. The following table provides the key assumptions that were used to calculate the pension benefit obligation and the net periodic benefit cost for the plans that triggered settlement accounting at the measurement dates of August 31, 2018, May 31, 2018 and December 31, 2017 : August 31, 2018 May 31, 2018 December 31, 2017 Weighted-average Assumption to Determine Benefit Obligation: Discount rate 4.08 % 4.03 % 3.58 % Weighted-average Assumptions to Determine Net Periodic Benefit Costs for the period ended: Discount rate - service cost 3.79 % 3.79 % 4.40 % Discount rate - interest cost 3.15 % 3.15 % 3.31 % Expected return on assets 6.30 % 6.30 % 7.25 %

Long-Term Debt

Long-Term Debt	9 Months Ended
	Sep. 30, 2018
Long-term Debt, Current and Noncurrent [Abstract]
Long-term Debt	Long-Term Debt On March 15, 2018, we redeemed $275.1 million of 6.40% senior unsecured notes at maturity. In June 2018, we executed a tender offer for $209.0 million of outstanding notes consisting of a combination of our 6.80% notes due 2019, 5.45% notes due 2020 and 6.125% notes due 2022. In conjunction with the debt retired, we recorded a $12.5 million loss on early extinguishment of long-term debt, primarily attributable to early redemption premiums. On June 11, 2018, we closed our private placement of $350.0 million of 3.65% senior unsecured notes maturing in 2023 which resulted in approximately $346.6 million of net proceeds after deducting commissions and expenses. We used the net proceeds from this private placement to pay a portion of the redemption price for the notes subject to the tender offer described above. In July 2018, we redeemed $551.1 million of outstanding notes representing the remainder of our 6.80% notes due 2019, 5.45% notes due 2020 and 6.125% notes due 2022. During the third quarter of 2018, we recorded a $33.0 million loss on early extinguishment of long-term debt, primarily attributable to early redemption premiums.

Short-Term Borrowings

Short-Term Borrowings	9 Months Ended
	Sep. 30, 2018
Short-term Debt [Abstract]
Short-Term Borrowings	Short-Term Borrowings We generate short-term borrowings from our revolving credit facility, commercial paper program, letter of credit issuances, accounts receivable transfer programs and term loan borrowings. Each of these borrowing sources is described further below. We maintain a revolving credit facility to fund ongoing working capital requirements, including the provision of liquidity support for our commercial paper program, provide for issuance of letters of credit and also for general corporate purposes. Our revolving credit facility has a program limit of $1.85 billion and is comprised of a syndicate of banks led by Barclays. At September 30, 2018 and December 31, 2017 , we had no outstanding borrowings under this facility. Our commercial paper program has a program limit of up to $1.5 billion with a dealer group comprised of Barclays, Citigroup, Credit Suisse and Wells Fargo. We had $746.0 million and $869.0 million of commercial paper outstanding as of September 30, 2018 and December 31, 2017 , respectively. As of September 30, 2018 and December 31, 2017 , we had $10.2 million and $11.1 million of stand-by letters of credit, respectively. All stand-by letters of credit were under the revolving credit facility. Transfers of accounts receivable are accounted for as secured borrowings resulting in the recognition of short-term borrowings on the Condensed Consolidated Balance Sheets (unaudited). We had $265.0 million in transfers as of September 30, 2018 and $336.7 million as of December 31, 2017 . Refer to Note 10 , "Transfers of Financial Assets," for additional information. On April 18, 2018, we entered into a multiple-draw $600.0 million term loan agreement with a syndicate of banks led by MUFG Bank, Ltd. The term loan matures April 17, 2019, at which point any and all outstanding borrowings under the agreement are due. Interest charged on borrowings depends on the variable rate structure we elected at the time of each borrowing. Under the agreement, we borrowed an initial tranche of $150.0 million on April 18, 2018 with an interest rate of LIBOR plus 50 basis points and a second tranche of $450.0 million on May 31, 2018 with an interest rate of LIBOR plus 55 basis points. Short-term borrowings were as follows: (in millions) September 30, December 31, Commercial paper weighted-average interest rate of 2.57% and 1.97% at September 30, 2018 and December 31, 2017, respectively $ 746.0 $ 869.0 Accounts receivable securitization facility borrowings 265.0 336.7 Term loan weighted-average interest rate of 2.79% at September 30, 2018 600.0 — Total Short-Term Borrowings $ 1,611.0 $ 1,205.7 Other than for the term loan, cash flows related to the borrowings and repayments of the items listed above are presented net in the Condensed Statements of Consolidated Cash Flows (unaudited) as their maturities are less than 90 days.

Other Commitments And Contingen

Other Commitments And Contingencies	9 Months Ended
	Sep. 30, 2018
Other Commitments and Contingencies [Abstract]
Commitments and Contingencies	Other Commitments and Contingencies A. Guarantees and Indemnities. We and certain of our subsidiaries enter into various agreements providing financial or performance assurance to third parties on behalf of certain subsidiaries as a part of normal business. Such agreements include guarantees and stand-by letters of credit. These agreements are entered into primarily to support or enhance the creditworthiness otherwise attributed to a subsidiary on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish the subsidiaries’ intended commercial purposes. As of September 30, 2018 and December 31, 2017, we had issued stand-by letters of credit of $10.2 million and $11.1 million , respectively. B. Legal Proceedings. On September 13, 2018, a series of fires and explosions occurred in Lawrence, Andover and North Andover, Massachusetts related to the delivery of natural gas by Columbia of Massachusetts (referred to herein as the “Greater Lawrence Incident”). The Greater Lawrence Incident resulted in one fatality and a number of injuries, damaged multiple homes and businesses, and caused the temporary evacuation of significant portions of each municipality. The Massachusetts Governor’s office declared a state of emergency, authorizing the Massachusetts DPU to order another utility company to coordinate the restoration of utility services in Lawrence, Andover and North Andover. The incident resulted in the interruption of gas and other utility service for approximately 8,500 gas meters, of which approximately 700 serve businesses. Columbia of Massachusetts is currently in the process of replacing the cast iron and bare steel gas pipeline system to restore service to these meters. See “ - D. Other Matters - Greater Lawrence Pipeline Replacement” below for more information. The NTSB is investigating the Greater Lawrence Incident. The parties to the investigation include the PHMSA, the Massachusetts DPU, Columbia of Massachusetts, and police and fire first responders. The Company and Columbia of Massachusetts are cooperating with the NTSB and have provided information to assist in its ongoing investigation into relevant facts related to the event, the probable cause, and its development of safety recommendations. According to the preliminary public report that the NTSB issued on October 11, 2018, an over pressurization of a low pressure gas distribution system occurred which appears to have been related to work being done on behalf of Columbia of Massachusetts on a pipeline replacement project in Lawrence. In addition, according to the report, sensing lines detected a drop in pressure in a portion of mainline that was being abandoned, causing a regulator to open up and increase pressure in the system to a level that exceeded the maximum allowable operating pressure of the distribution system. While the NTSB investigation is pending, the Company and Columbia of Massachusetts are prohibited from disclosing information related to the investigation without approval from the NTSB. The Massachusetts DPU has announced its intent to hire an independent evaluator to conduct a statewide examination of the safety of the natural gas distribution systems within the Commonwealth of Massachusetts. Through authority granted by the Massachusetts Governor under the state of emergency, the Chair of the Massachusetts DPU will direct all natural gas distribution companies operating in the Commonwealth to fund the statewide examination. The examination is expected to complement, but not duplicate, the NTSB’s investigation. Following the release of the NTSB's preliminary report, the Massachusetts DPU placed a moratorium on Columbia of Massachusetts, which prohibits the company from performing any work in the state through at least December 1, 2018. The ban does not apply to compliance and emergency work, including the restoration of service in Lawrence, Andover and North Andover. Under Massachusetts law, the DPU is authorized to investigate potential violations of pipeline safety regulations and to assess a civil penalty of up to $209,000 for a violation of federal pipeline safety regulations. A separate violation occurs for each day of violation up to $2.1 million for a related series of violations. The Massachusetts DPU also is authorized to investigate potential violations of the Columbia of Massachusetts emergency response plan and to assess penalties of up to $250,000 per violation, or up to $20 million per related series of violations. Further, as a result of the declaration of emergency by the Governor, the DPU is authorized to investigate potential violations of the DPU's operational directives during the restoration efforts and assess penalties of up to $1 million per violation. The timing and outcome of any such investigations are uncertain at this time. Various lawsuits, including several purported class action lawsuits, have been filed by various affected residents or businesses in Massachusetts state courts against the Company and/or Columbia of Massachusetts in connection with the Greater Lawrence Incident. The class action lawsuits allege varying causes of action, including those for strict liability for ultra-hazardous activity, negligence, private nuisance, public nuisance, premises liability, trespass, breach of implied warranty of merchantability, breach of contract and gross negligence, and seek punitive damages. Many residents and business owners have submitted individual damage claims to Columbia of Massachusetts. We also have received notice from two parties indicating an intent to assert wrongful death claims. In addition, the Commonwealth of Massachusetts and the municipalities of Lawrence, Andover and North Andover are seeking reimbursement from Columbia of Massachusetts for their respective expenses incurred in connection with the Greater Lawrence Incident. The Company and Columbia of Massachusetts are subject to a criminal investigation being conducted under the supervision of the U.S. Attorney's Office for the District of Massachusetts. The initial grand jury subpoenas were served on the Company and Columbia of Massachusetts on September 24, 2018. The Company and Columbia of Massachusetts are cooperating with the investigation. During the quarter ended September 30, 2018, Columbia of Massachusetts expensed approximately $415 million for estimated third-party claims related to the Greater Lawrence Incident, including personal injury and property damage claims, damage to infrastructure, and other damage claims, which include mutual aid payments to other utilities assisting with the restoration effort, gas-fueled appliance replacement and related services for impacted customers, temporary lodging for displaced customers, and claims-related legal fees. We estimate that total costs related to third-party claims resulting from the incident will range from $415 million to $450 million , depending on the final outcome of open investigations and the number, nature, and value of third-party claims. We also expect to incur losses for third party business interruption claims, the costs for which are not included in the amounts disclosed above due to insufficient information to reasonably estimate the damages from such claims. The amounts set forth above do not include non-claims related expenses resulting from the incident or the estimated capital cost of the pipeline replacement, which are set forth in " - D. Other Matters - Greater Lawrence Incident Restoration" and " - Greater Lawrence Pipeline Replacement," respectively, below. The process for estimating costs associated with third-party claims relating to the Greater Lawrence Incident requires management to exercise significant judgment based on a number of assumptions and subjective factors. As more information becomes known, including information resulting from the NTSB investigation, management’s estimates and assumptions regarding the financial impact of the Greater Lawrence Incident may change. Further, it is not possible at this time to reasonably estimate the amount of any fines, penalties or settlements with governmental authorities, including the Massachusetts DPU and other regulators, that the Company or Columbia of Massachusetts may incur in connection with the Greater Lawrence Incident. Therefore, the foregoing amounts do not include estimates for any such fines, penalties or settlements. The current and noncurrent portions of the remaining liability as of September 30, 2018 are presented within “Claims accrued” and “Other noncurrent liabilities,” respectively, in the Company’s Condensed Consolidated Balance Sheets (unaudited). The expenses above are presented within “Operation and maintenance” in our Condensed Statement of Consolidated Income (unaudited). The Company maintains liability insurance for damages in the approximate amount of $800 million . The Company and Columbia of Massachusetts believe that third-party claims related to the Greater Lawrence Incident will be substantially covered by this insurance, other than any fines, penalties or settlements with governmental authorities that the Company or Columbia of Massachusetts may incur. However, no amounts for insurance recoveries have been recorded as of September 30, 2018. The Company and Columbia of Massachusetts are currently unable to predict the amount and timing of insurance recoveries. In addition, we are party to certain other claims and legal proceedings arising in the ordinary course of business, none of which are deemed to be individually material at this time. Due to the inherent uncertainty of litigation, there can be no assurance that the resolution of any particular claim or proceeding would not have a material adverse effect on our results of operations, financial position or liquidity. If one or more of such matters were decided against us, the effects could be material to our results of operations in the period in which we would be required to record or adjust the related liability and could also be material to our cash flows in the periods that we would be required to pay such liability. C. Environmental Matters. Our operations are subject to environmental statutes and regulations related to air quality, water quality, hazardous waste and solid waste. We believe that we are in substantial compliance with the environmental regulations currently applicable to our operations. It is management's continued intent to address environmental issues in cooperation with regulatory authorities in such a manner as to achieve mutually acceptable compliance plans. However, there can be no assurance that fines and penalties will not be incurred. Management expects a significant portion of environmental assessment and remediation costs to be recoverable through rates for certain of our companies. As of September 30, 2018 and December 31, 2017 , we had recorded a liability of approximately $107.1 million and $111.4 million , respectively, to cover environmental remediation at various sites. The current portion of this liability is included in "Legal and environmental" in the Condensed Consolidated Balance Sheets (unaudited). The noncurrent portion is included in "Other noncurrent liabilities" in the Condensed Consolidated Balance Sheets (unaudited). We recognize costs associated with environmental remediation obligations when the incurrence of such costs is probable and the amounts can be reasonably estimated. The original estimates for remediation activities may differ materially from the amount ultimately expended. The actual future expenditures depend on many factors, including currently enacted laws and regulations, the nature and extent of impact and the method of remediation. These expenditures are not currently estimable at some sites. We periodically adjust our liability as information is collected and estimates become more refined. Electric Operations' compliance estimates disclosed below are reflective of NIPSCO's Integrated Resource Plan submitted to the IURC on October 31, 2018. See section D , "Other Matters," below for additional information. Air The actions listed below could require further reductions in emissions from various emission sources. We will continue to closely monitor developments in these matters. Future legislative and regulatory programs could significantly limit allowed GHG emissions or impose a cost or tax on GHG emissions. Additionally, rules that increase methane leak detection, require emission reductions or impose additional requirements for natural gas facilities could restrict GHG emissions and impose additional costs. We carefully monitor all GHG reduction proposals and regulations. CPP and ACE Rules. On October 23, 2015, the EPA issued the CPP to regulate CO 2 emissions from existing fossil-fuel EGUs under section 111(d) of the CAA. The U.S. Supreme Court has stayed implementation of the CPP until litigation is decided on its merits, and the EPA has proposed to repeal the CPP. On August 31, 2018, the EPA published a proposal to replace the CPP with the ACE rule, which establishes guidelines for states to use when developing plans to reduce CO 2 emissions from existing coal-fired EGUs. The proposal would provide states three years after a final rule is issued to develop state-specific plans, and the EPA would have twelve months to act on a complete state plan submittal. Within two years after a finding of failure to submit a complete plan, or disapproval of a state plan, the EPA would issue a federal plan. NIPSCO will continue to monitor this matter and cannot estimate its impact at this time. Waste CERCLA. Our subsidiaries are potentially responsible parties at waste disposal sites under the CERCLA (commonly known as Superfund) and similar state laws. Under CERCLA, each potentially responsible party can be held jointly, severally and strictly liable for the remediation costs as the EPA, or state, can allow the parties to pay for remedial action or perform remedial action themselves and request reimbursement from the potentially responsible parties. Our affiliates have retained CERCLA environmental liabilities, including remediation liabilities, associated with certain current and former operations. These liabilities are not material to the Condensed Consolidated Financial Statements ( unaudited ). MGP. A program has been instituted to identify and investigate former MGP sites where Gas Distribution Operations subsidiaries or predecessors may have liability. The program has identified 64 such sites where liability is probable. Remedial actions at many of these sites are being overseen by state or federal environmental agencies through consent agreements or voluntary remediation agreements. We utilize a probabilistic model to estimate future remediation costs related to our MGP sites. The model was prepared with the assistance of a third party and incorporates our experience and general industry experience with remediating MGP sites. We complete an annual refresh of the model in the second quarter of each fiscal year. No material changes to the estimated future remediation costs were noted as a result of the refresh completed as of June 30, 2018. Our total estimated liability related to the facilities subject to remediation was $103.3 million and $106.9 million at September 30, 2018 and December 31, 2017 , respectively. The liability represents our best estimate of the probable cost to remediate the facilities. We believe that it is reasonably possible that remediation costs could vary by as much as $25 million in addition to the costs noted above. Remediation costs are estimated based on the best available information, applicable remediation standards at the balance sheet date and experience with similar facilities. CCRs. On April 17, 2015, the EPA issued a final rule for regulation of CCRs. The rule regulates CCRs under the RCRA Subtitle D, which determines them to be nonhazardous. The rule is implemented in phases and requires increased groundwater monitoring, reporting, recordkeeping and posting of related information to the Internet. The rule also establishes requirements related to CCR management and disposal. The rule will allow NIPSCO to continue its byproduct beneficial use program. The publication of the CCR rule resulted in revisions to previously recorded legal obligations associated with the retirement of certain NIPSCO facilities. The actual asset retirement costs related to the CCR rule may vary substantially from the estimates used to record the increased asset retirement obligation due to the uncertainty about the compliance strategies that will be used and the preliminary nature of available data used to estimate costs. In addition, to comply with the rule, NIPSCO is incurring capital expenditures to modify its infrastructure and manage CCRs. Capital compliance costs are currently expected to total approximately $193 million . As allowed by the EPA, NIPSCO will continue to collect data over time to determine the specific compliance solutions and associated costs and, as a result, the actual costs may vary. NIPSCO filed a petition on November 1, 2016 with the IURC seeking approval of the projects and recovery of the costs associated with CCR compliance. On June 9, 2017, NIPSCO filed with the IURC a settlement reached with certain parties regarding the CCR projects and treatment of associated costs. The IURC approved the settlement in an order on December 13, 2017. Water ELG. On November 3, 2015, the EPA issued a final rule to amend the ELG and standards for the Steam Electric Power Generating category. The final rule became effective January 4, 2016. The rule imposes new water treatment and discharge requirements on NIPSCO's electric generating facilities to be applied between 2018 and 2023. On April 25, 2017, the EPA published notice in the Federal Register that the EPA is reconsidering the ELG in response to several petitions for reconsideration. On September 18, 2017, the EPA postponed the earliest compliance dates for flue gas desulfurization wastewater and bottom ash transport water requirements from 2018 to 2020 to potentially consider revisions to technology and numeric limits achievable. NIPSCO is unable to estimate the financial impact of the EPA reconsideration at this time. Based upon a preliminary study of the November 3, 2015 final rule, capital compliance costs were expected to be approximately $170 million . However, NIPSCO does not anticipate material ELG compliance costs based on the most viable option for customers announced as part of NIPSCO's 2018 Integrated Resource Plan (discussed below). D . Other Matters. NIPSCO 2018 Integrated Resource Plan. Multiple factors, but primarily economic ones, including low natural gas prices, advancing cost effective renewable technology and increasing capital and operating costs associated with existing coal plants, have led NIPSCO to conclude in its Integrated Resource Plan submission that NIPSCO’s current fleet of coal generation facilities will be retired earlier than previous Integrated Resource Plan’s had indicated. On October 31, 2018, NIPSCO submitted its 2018 Integrated Resource Plan to the IURC. The plan evaluated demand-side and supply-side resource alternatives to reliably and cost effectively meet NIPSCO customers' future energy requirements over the ensuing 20 years. The preferred option within the Integrated Resource Plan retires R.M. Schahfer Generating Station (Units 14, 15, 17, and 18) by 2023 and Michigan City Generating Station (Unit 12) by 2028. The replacement plan is still being defined, but currently points to renewable sources of energy, including wind, solar, and battery storage. NIPSCO Pure Air. NIPSCO had a service agreement with Pure Air, a general partnership between Air Products and Chemicals, Inc. and First Air Partners LP, under which Pure Air provided scrubber services to reduce sulfur dioxide emissions for Units 7 and 8 at the Bailly Generating Station. Services under this contract commenced on July 1, 1992 and expired on June 30, 2012. The agreement was renewed effective July 1, 2012 for ten years, requiring NIPSCO to pay for the services under a combination of fixed and variable charges. We made an exhaustive effort to obtain information needed from Pure Air to determine the status of Pure Air as a VIE. However, NIPSCO was not able to obtain this information and, as a result, it was not determined whether Pure Air was a VIE and whether NIPSCO was the primary beneficiary. Payments under this agreement were $ 8.3 million and $ 16.5 million for the nine months ended September 30, 2018 and 2017 , respectively. In accordance with GAAP, the renewed agreement was evaluated to determine whether the arrangement qualified as a lease. Based on the terms of the agreement, the arrangement qualified for capital lease accounting. As the effective date of the new agreement was July 1, 2012, we capitalized this lease beginning in the third quarter of 2012. NIPSCO retired the generation station units serviced by Pure Air on May 31, 2018. In December 2016, as allowed by the provisions of the service agreement, NIPSCO provided Pure Air formal notice of intent to terminate the service agreement, effective May 31, 2018. Providing this notice to Pure Air triggered a contract termination liability of $16 million , which was recorded in fourth quarter of 2016. In connection with the closure of Bailly Units 7 and 8, NIPSCO paid the termination payment to Pure Air during the second quarter of 2018. Cash flows associated with this payment are presented within operating activities on the Condensed Statements of Consolidated Cash Flows (unaudited). Greater Lawrence Incident Restoration . During the quarter ended September 30, 2018, Columbia of Massachusetts recorded a loss of approximately $460 million in connection with the Greater Lawrence Incident. This amount includes approximately $415 million for estimated third-party claims associated with the incident as described above in " - B. Legal Proceedings." The additional $45 million included in the loss recorded includes certain consulting costs, administration costs, charitable contributions, and other labor and related expenses in connection with the incident. We expect to incur a total of $180 million to $210 million in such incident-related costs, depending on the incurrence of future restoration work, substantially all of which we expect to incur by the end of 2018. The amounts set forth above do not include the estimated capital cost of the pipeline replacement, which is set forth below. The Company maintains liability insurance for damages in the approximate amount of $800 million . The Company and Columbia of Massachusetts believe that third-party claims and other expenses related to the Greater Lawrence Incident will be substantially covered by insurance, other than any fines, penalties or settlements with governmental authorities that the Company or Columbia of Massachusetts may incur. However, no amounts for insurance recoveries have been recorded as of September 30, 2018. The Company and Columbia of Massachusetts are currently unable to predict the amount and timing of insurance recoveries. The current and noncurrent portions of the remaining liability as of September 30, 2018 are presented within “Claims accrued” and “Other noncurrent liabilities,” respectively, in the Company’s Condensed Consolidated Balance Sheets (unaudited). Costs associated with charitable contributions are presented within “Other, Net” in our Condensed Statement of Consolidated Income (unaudited). All other losses incurred are presented within “Operation and maintenance.” Greater Lawrence Pipeline Replacement . In connection with the Greater Lawrence Incident, Columbia of Massachusetts, in cooperation with the Massachusetts Governor’s office, replaced the entire affected 45 -mile cast iron and bare steel pipeline system that delivers gas to approximately 8,500 gas meters, of which approximately 700 serve businesses impacted in the Greater Lawrence Incident. This system was replaced with plastic distribution mains and service lines, as well as enhanced safety features such as pressure regulation and excess flow valves at each premise. Columbia of Massachusetts is aiming to restore gas service to all homes and workplaces by December 16, 2018. At the request of the Massachusetts DPU, which was instructed by the Massachusetts Governor through his executive authority under a state of emergency, Columbia of Massachusetts has hired an outside contractor to serve as the Chief Recovery Officer for the Greater Lawrence Incident, responsible for command, control and communications. The estimated capital cost of the pipeline replacement is between $135 - $165 million . The recovery of this capital investment will be addressed in a future regulatory proceeding.

Accumulated Other Comprehensive

Accumulated Other Comprehensive Loss	9 Months Ended
	Sep. 30, 2018
Other Comprehensive Income (Loss), Tax [Abstract]
Accumulated Other Comprehensive Loss	Accumulated Other Comprehensive Income (Loss) The following tables display the components of Accumulated Other Comprehensive Income (Loss): Three Months Ended September 30, 2018 (in millions) Gains and Losses on Securities (1) Gains and Losses on Cash Flow Hedges (1) Pension and OPEB Items (1) Accumulated (1) Balance as of July 1, 2018 $ (2.2 ) $ (1.7 ) $ (17.0 ) $ (20.9 ) Other comprehensive income before reclassifications — 21.6 1.0 22.6 Amounts reclassified from accumulated other comprehensive loss 0.1 0.9 (0.2 ) 0.8 Net current-period other comprehensive income 0.1 22.5 0.8 23.4 Balance as of September 30, 2018 $ (2.1 ) $ 20.8 $ (16.2 ) $ 2.5 Nine Months Ended September 30, 2018 (in millions) Gains and Losses on Securities (1) Gains and Losses on Cash Flow Hedges (1) Pension and OPEB Items (1) Accumulated Other Comprehensive Income (Loss) (1) Balance as of January 1, 2018 $ 0.2 $ (29.4 ) $ (14.2 ) $ (43.4 ) Other comprehensive income (loss) before reclassifications (2.5 ) 70.8 1.0 69.3 Amounts reclassified from accumulated other comprehensive loss (2) 0.2 (14.3 ) 0.2 (13.9 ) Net current-period other comprehensive income (loss) (2.3 ) 56.5 1.2 55.4 Reclassification due to adoption of ASU 2018-02 (Refer to Note 2) — (6.3 ) (3.2 ) (9.5 ) Balance as of September 30, 2018 $ (2.1 ) $ 20.8 $ (16.2 ) $ 2.5 Three Months Ended September 30, 2017 (in millions) Gains and Losses on Securities (1) Gains and Losses on Cash Flow Hedges (1) Pension and OPEB Items (1) Accumulated (1) Balance as of July 1, 2017 $ 0.4 $ (18.8 ) $ (17.2 ) $ (35.6 ) Other comprehensive income (loss) before reclassifications 0.1 (9.7 ) — (9.6 ) Amounts reclassified from accumulated other comprehensive loss — 0.4 1.1 1.5 Net current-period other comprehensive income (loss) 0.1 (9.3 ) 1.1 (8.1 ) Balance as of September 30, 2017 $ 0.5 $ (28.1 ) $ (16.1 ) $ (43.7 ) Nine Months Ended September 30, 2017 (in millions) Gains and Losses on Securities (1) Gains and Losses on Cash Flow Hedges (1) Pension and OPEB Items (1) Accumulated Other Comprehensive (Loss) (1) Balance as of January 1, 2017 $ (0.6 ) $ (6.9 ) $ (17.6 ) $ (25.1 ) Other comprehensive income (loss) before reclassifications 1.1 (23.3 ) 0.2 (22.0 ) Amounts reclassified from accumulated other comprehensive loss — 2.1 1.3 3.4 Net current-period other comprehensive income (loss) 1.1 (21.2 ) 1.5 (18.6 ) Balance as of September 30, 2017 $ 0.5 $ (28.1 ) $ (16.1 ) $ (43.7 ) (1) All amounts are net of tax. Amounts in parentheses indicate debits. (2) Reclassification from accumulated other comprehensive loss for cash flow hedges relates primarily to the interest rate swap settlement gain. Refer to Note 8 "Risk Management Activities" for additional information.

Other, Net

Other, Net	9 Months Ended
	Sep. 30, 2018
Other, Net [Abstract]
Other Income and Other Expense Disclosure [Text Block]	Other, Net Three Months Ended Nine Months Ended (in millions) 2018 2017 2018 2017 Interest Income $ 1.4 $ 1.4 $ 4.2 $ 3.2 AFUDC Equity 5.0 4.3 12.6 10.5 Charitable Contributions (11.1 ) (0.8 ) (13.9 ) (3.5 ) Pension and other postretirement non-service cost 2.4 (11.8 ) 14.7 (10.1 ) Interest rate swap settlement gain (1) — — 21.2 — Miscellaneous 0.6 0.1 3.6 (0.4 ) Total Other, net $ (1.7 ) $ (6.8 ) $ 42.4 $ (0.3 ) (1) See Note 8 , "Risk Management Activities," for additional information.

Business Segment Information

Business Segment Information	9 Months Ended
	Sep. 30, 2018
Segment Reporting [Abstract]
Business Segment Information	Business Segment Information Our operations are divided into two primary reportable segments. The Gas Distribution Operations segment provides natural gas service and transportation for residential, commercial and industrial customers in Ohio, Pennsylvania, Virginia, Kentucky, Maryland, Indiana and Massachusetts. The Electric Operations segment provides electric service in 20 counties in the northern part of Indiana. The following table provides information about our business segments. We use operating income as our primary measurement for each of the reported segments and make decisions on finance, dividends and taxes at the corporate level on a consolidated basis. Segment revenues include intersegment sales to affiliated subsidiaries, which are eliminated in consolidation. Affiliated sales are recognized on the basis of prevailing market, regulated prices or at levels provided for under contractual agreements. Operating income is derived from revenues and expenses directly associated with each segment. Three Months Ended Nine Months Ended (in millions) 2018 2017 2018 2017 Operating Revenues Gas Distribution Operations Unaffiliated $ 418.6 $ 431.1 $ 2,347.8 $ 2,139.9 Intersegment 3.3 3.5 9.8 10.6 Total 421.9 434.6 2,357.6 2,150.5 Electric Operations Unaffiliated 476.2 485.8 1,304.4 1,365.5 Intersegment 0.2 0.2 0.6 0.6 Total 476.4 486.0 1,305.0 1,366.1 Corporate and Other Unaffiliated 0.2 0.1 0.6 0.9 Intersegment 116.4 126.4 346.6 367.7 Total 116.6 126.5 347.2 368.6 Eliminations (119.9 ) (130.1 ) (357.0 ) (378.9 ) Consolidated Operating Revenues $ 895.0 $ 917.0 $ 3,652.8 $ 3,506.3 Operating Income (Loss) Gas Distribution Operations $ (455.2 ) $ (15.4 ) $ (94.4 ) $ 367.1 Electric Operations 134.9 125.1 300.4 288.3 Corporate and Other 4.4 1.5 (2.9 ) (4.8 ) Consolidated Operating Income $ (315.9 ) $ 111.2 $ 203.1 $ 650.6

Recent Accounting Pronounceme_2

Recent Accounting Pronouncements (Tables)	9 Months Ended
	Sep. 30, 2018
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
Description of New Accounting Pronouncements Not yet Adopted	We are currently evaluating the impact of certain ASUs on our Condensed Consolidated Financial Statements (unaudited) and Notes to Condensed Consolidated Financial Statements (unaudited), which are described below: Standard Description Effective Date Effect on the financial statements or other significant matters ASU 2018-14, Compensation—Retirement Benefits—Defined Benefit Plans—General (Subtopic 715-20): Disclosure Framework—Changes to the Disclosure Requirements for Defined Benefit Plans The pronouncement modifies the disclosure requirements for defined benefit pension or other postretirement benefit plans. The guidance removes disclosures that are no longer considered cost beneficial, clarifies the specific requirements of disclosures and adds disclosure requirements identified as relevant. The modifications affect annual period disclosures and must be applied on a retrospective basis to all periods presented. Annual periods ending after December 15, 2020. Early adoption is permitted. We are currently evaluating the effects of this pronouncement on our Notes to Condensed Consolidated Financial Statements (unaudited), including potential early adoption in the fourth quarter of 2018. ASU 2016-13, Financial Instruments-Credit Losses (Topic 326) The pronouncement changes the impairment model for most financial assets, replacing the current "incurred loss" model. ASU 2016-13 will require the use of an "expected loss" model for instruments measured at amortized cost. It will also require entities to record allowances for available-for-sale debt securities rather than impair the carrying amount of the securities. Subsequent improvements to the estimated credit losses of available-for-sale securities will be recognized immediately in earnings instead of over time as they are under historic guidance. Annual periods beginning after December 15, 2019, including interim periods therein. Early adoption is permitted for annual or interim periods beginning after December 15, 2018. We maintain investments in U.S. Treasury, corporate and mortgage-backed debt securities, which are pledged as collateral for trust accounts related to our wholly-owned insurance company. These debt securities are classified as available for sale. We are currently evaluating the impact of adoption, if any, on our Condensed Consolidated Financial Statements (unaudited) and Notes to Condensed Consolidated Financial Statements (unaudited). Standard Description Effective Date Effect on the financial statements or other significant matters ASU 2018-11, Leases (Topic 842): Targeted Improvements The pronouncement allows entities the option to initially apply ASC 842 at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. Annual periods beginning after December 15, 2018, including interim periods therein. Early adoption is permitted. We are the lessee for substantially all of our current leasing activity. Upon adopting ASC 842 we will begin recognizing right-of-use assets and liabilities associated with operating leases (other than short term operating leases) on our Condensed Consolidated Balance Sheets (unaudited). The impact of this change on the balance sheet is not reasonably estimable at this time. We do not anticipate the adoption of ASC 842 will have a material impact to our results of operations or cash flows. We have undertaken efforts to outline mock footnote disclosures intended to satisfy ASC 842’s disclosure requirements, which will enhance our disclosures on lease accounting policies and elections. We are implementing a new lease accounting system, which we will utilize to capture, track, and account for lease data. The new system will also aid in automating the compilation of disclosure information. We expect to conclude final system tests in the fourth quarter of 2018, with full system implementation prior to the effective date of these standards. ASC 842 provides lessees the option of electing an accounting policy, by class of underlying asset, in which the lessee may choose not to separate nonlease components from lease components. We currently anticipate adopting this practical expedient for certain classes of leases. Further, we will elect the "practical expedient package" described in ASC 842-10-65-1. We maintain a substantial number of easements and will also elect the provisions of ASU 2018-01 to ease the process of implementing ASC 842. Lastly, we anticipate electing the transition method provided in ASU 2018-11 when we adopt these standards effective January 1, 2019. ASU 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842 The pronouncement offers a practical expedient for accounting for land easements under ASU 2016-02. This practical expedient allows an entity the option of not evaluating existing land easements under ASC 842. New or modified land easements will still require evaluation under ASC 842 on a prospective basis beginning on the date of adoption. ASU 2016-02, Leases (Topic 842) The pronouncement introduces a lessee model that brings most leases on the balance sheet. The standard requires that lessees recognize the following for all leases (with the exception of short-term leases, as that term is defined in the standard) at the lease commencement date: (1) a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and (2) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term.
Schedule of Prospective Adoption of New Accounting Pronouncements	Recently Adopted Accounting Pronouncements Standard Adoption ASU 2018-15, Intangibles—Goodwill and Other— Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract In August 2018, the FASB issued this ASU, which amends current guidance to align the accounting for costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing costs associated with developing or obtaining internal-use software. We elected to early adopt the ASU on a prospective basis, effective October 1, 2018. As a result of adopting this ASU, we will defer onto the balance sheet those up-front implementation costs of cloud computing arrangements if they would have been capitalized in a similar on-premise software solution. ASU 2018-02, Income Statement—Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income We adopted this ASU effective March 31, 2018. Upon adoption, $9.5 million of tax effects that were stranded in accumulated other comprehensive income (loss) as a result of the implementation of the TCJA were reclassified to retained deficit. This change is reflected on our Condensed Statements of Consolidated Equity (unaudited). ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force) We adopted this ASU effective January 1, 2018. The adoption of this standard did not have a material impact on our Condensed Consolidated Financial Statements (unaudited) or Notes to Condensed Consolidated Financial Statements (unaudited). ASU 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients See Note 3, "Revenue Recognition," for our discussion of the effects of implementing these standards. ASU 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations ASU 2014-09, Revenue from Contracts with Customers (Topic 606)
Schedule of New Accounting Pronouncements and Changes in Accounting Principles	Changes in income statement presentation were implemented on a retrospective basis. The impact of this ASU on previously issued annual financial statements is summarized in the tables below: Year Ended December 31, 2016 (in millions) As Previously Reported Effect of Change (1) As Adjusted Operation and maintenance $ 1,453.7 $ (7.9 ) $ 1,445.8 Total Operating Expenses 3,634.3 (7.9 ) 3,626.4 Operating Income 858.2 7.9 866.1 Other Income (Deductions) Other, net 1.5 (7.9 ) (6.4 ) Total Other Deductions (348.0 ) (7.9 ) (355.9 ) Income before Income Taxes $ 510.2 $ — $ 510.2 (1) The effect of this change is attributable to our business segments: Gas Distribution Operations, Electric Operations, and Corporate and Other in the amounts of $4.3 million , $(9.8) million , and $(2.4) million , respectively. Year Ended December 31, 2017 (in millions) As Previously Reported Effect of Change (1) As Adjusted Operation and maintenance $ 1,612.3 $ (10.6 ) $ 1,601.7 Total Operating Expenses 3,964.0 (10.6 ) 3,953.4 Operating Income 910.6 10.6 921.2 Other Income (Deductions) Other, net (2.8 ) (10.6 ) (13.4 ) Total Other Deductions (467.5 ) (10.6 ) (478.1 ) Income before Income Taxes $ 443.1 $ — $ 443.1 (1) The effect of this change is attributable to our business segments: Gas Distribution Operations, Electric Operations, and Corporate and Other in the amounts of $(4.4) million , $(2.6) million , and $(3.6) million , respectively.

Revenue Recognition (Tables)

Revenue Recognition (Tables)	9 Months Ended
	Sep. 30, 2018
Revenue from Contract with Customer [Abstract]
Revenue Recognition Under Previous Guidance	The table below provides results for the three and nine months ended September 30, 2018 as if they had been prepared under historic accounting guidance. We included operating revenue information for the three and nine months ended September 30, 2017 for comparability. Three Months Ended Nine Months Ended (in millions) 2018 2017 2018 2017 Operating Revenues Gas Distribution $ 232.3 $ 239.4 $ 1,600.3 $ 1,403.0 Gas Transportation 186.0 191.6 745.2 735.1 Electric 476.2 485.8 1,304.4 1,365.5 Other 0.5 0.2 2.9 2.7 Total Operating Revenues $ 895.0 $ 917.0 $ 3,652.8 $ 3,506.3
Disaggregation of Revenue	The table below reconciles revenue disaggregation by customer class to segment revenue as well as to revenues reflected on the Condensed Statements of Consolidated Income (Loss) (unaudited): Three Months Ended September 30, 2018 (in millions) Gas Distribution Operations Electric Operations Corporate and Other Total Customer Revenues (1) Residential $ 257.0 $ 154.7 $ — $ 411.7 Commercial 80.9 140.7 — 221.6 Industrial 39.0 153.6 — 192.6 Off-system 20.4 — — 20.4 Miscellaneous 9.2 0.1 0.2 9.5 Total Customer Revenues $ 406.5 $ 449.1 $ 0.2 $ 855.8 Other Revenues 12.1 27.1 — 39.2 Total Operating Revenues $ 418.6 $ 476.2 $ 0.2 $ 895.0 (1) Customer revenue amounts exclude intersegment revenues. See Note 19 , "Business Segment Information," for discussion of intersegment revenues. Nine Months Ended September 30, 2018 (in millions) Gas Distribution Operations Electric Operations Corporate and Other Total Customer Revenues (1) Residential $ 1,540.3 $ 382.3 $ — $ 1,922.6 Commercial 516.2 374.2 — 890.4 Industrial 161.3 468.1 — 629.4 Off-system 63.6 — — 63.6 Miscellaneous 36.2 12.3 0.6 49.1 Total Customer Revenues $ 2,317.6 $ 1,236.9 $ 0.6 $ 3,555.1 Other Revenues 30.2 67.5 — 97.7 Total Operating Revenues $ 2,347.8 $ 1,304.4 $ 0.6 $ 3,652.8 (1) Customer revenue amounts exclude intersegment revenues. See Note 19 , "Business Segment Information," for discussion of intersegment revenues.
Customer Accounts Receivable	The opening and closing balances of customer receivables for the nine months ended September 30, 2018 are presented in the table below. We had no significant contract assets or liabilities during the period. Additionally, we have not incurred any significant costs to obtain or fulfill contracts. (in millions) Customer Accounts Receivable, Billed (less reserve) (1) Customer Accounts Receivable, Unbilled (less reserve) (2) Balance as of December 31, 2017 $ 477.0 $ 356.0 Balance as of September 30, 2018 297.2 154.8 Increase (Decrease) $ (179.8 ) $ (201.2 ) (1) Customer billed receivables decreased over the period due to the expected seasonal decrease in customer usage in September when compared to December. (2) Customer unbilled receivables decreased over the period due to the expected seasonal decrease in customer usage in September when compared to December.

Earnings Per Share (Tables)

Earnings Per Share (Tables)	9 Months Ended
	Sep. 30, 2018
Earnings Per Share [Abstract]
Computation Of Diluted Average Common Shares	The computation of diluted average common shares is as follows: Three Months Ended Nine Months Ended September 30, September 30, (in thousands) 2017 2017 Denominator Basic average common shares outstanding 331,139 326,662 Dilutive potential common shares: Shares contingently issuable under employee stock plans 604 503 Shares restricted under employee stock plans 653 866 Diluted Average Common Shares 332,396 328,031

Equity (Tables)

Equity (Tables)	9 Months Ended
	Sep. 30, 2018
Equity [Abstract]
Schedule Of Stock Offering Program [Table Text Block]	The following table summarizes our activity under the ATM Program: Three Months Ended Nine Months Ended 2018 2017 2018 2017 Number of shares issued — 10,612,915 — 11,931,376 Average price per share $ — $ 26.67 $ — $ 26.58 Proceeds, net of fees (in millions) $ — $ 281.0 $ — $ 314.7

Risk Management Activities (Tab

Risk Management Activities (Tables)	9 Months Ended
	Sep. 30, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block]	Risk management assets and liabilities on our derivatives are presented on the Condensed Consolidated Balance Sheets (unaudited) as shown below: (in millions) September 30, 2018 December 31, 2017 Risk Management Assets - Current (1) Interest rate risk programs $ 21.4 $ 14.0 Commodity price risk programs 1.0 0.5 Total $ 22.4 $ 14.5 Risk Management Assets - Noncurrent (2) Interest rate risk programs $ 32.6 $ 5.6 Commodity price risk programs 2.6 1.0 Total $ 35.2 $ 6.6 Risk Management Liabilities - Current Interest rate risk programs $ — $ 38.6 Commodity price risk programs 4.8 4.6 Total $ 4.8 $ 43.2 Risk Management Liabilities - Noncurrent Interest rate risk programs $ — $ — Commodity price risk programs 45.2 28.5 Total $ 45.2 $ 28.5 (1) Presented in "Prepayments and other" on the Condensed Consolidated Balance Sheets (unaudited). (2) Presented in "Deferred charges and other" on the Condensed Consolidated Balance Sheets (unaudited).

Fair Value (Tables)

Fair Value (Tables)	9 Months Ended
	Sep. 30, 2018
Fair Value Disclosures [Abstract]
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis	The following tables present financial assets and liabilities measured and recorded at fair value on our Condensed Consolidated Balance Sheets (unaudited) on a recurring basis and their level within the fair value hierarchy as of September 30, 2018 and December 31, 2017 : Recurring Fair Value Measurements (in millions) Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Balance as of September 30, 2018 Assets Risk management assets $ — $ 57.6 $ — $ 57.6 Available-for-sale securities — 143.8 — 143.8 Total $ — $ 201.4 $ — $ 201.4 Liabilities Risk management liabilities $ — $ 50.0 $ — $ 50.0 Total $ — $ 50.0 $ — $ 50.0 Recurring Fair Value Measurements (in millions) Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Balance as of December 31, 2017 Assets Risk management assets $ — $ 21.1 $ — $ 21.1 Available-for-sale securities — 133.9 — 133.9 Total $ — $ 155.0 $ — $ 155.0 Liabilities Risk management liabilities $ — $ 71.4 $ 0.3 $ 71.7 Total $ — $ 71.4 $ 0.3 $ 71.7
Schedule of Available-For-Sale Securities	The amortized cost, gross unrealized gains and losses and fair value of available-for-sale securities at September 30, 2018 and December 31, 2017 were: September 30, 2018 (in millions) Amortized Cost Gross Unrealized Gains Gross Unrealized Losses Fair Value Available-for-sale securities U.S. Treasury debt securities $ 29.7 $ — $ (0.2 ) $ 29.5 Corporate/Other debt securities 116.8 0.4 (2.9 ) 114.3 Total $ 146.5 $ 0.4 $ (3.1 ) $ 143.8 December 31, 2017 (in millions) Amortized Cost Gross Unrealized Gains Gross Unrealized Losses Fair Value Available-for-sale securities U.S. Treasury debt securities $ 26.9 $ — $ (0.1 ) $ 26.8 Corporate/Other debt securities 106.8 0.9 (0.6 ) 107.1 Total $ 133.7 $ 0.9 $ (0.7 ) $ 133.9
Carrying Amount And Estimated Fair Values Of Financial Instruments	The carrying amount and estimated fair values of these financial instruments were as follows: (in millions) Carrying Estimated Fair Carrying Amount as of Dec. 31, 2017 Estimated Fair Value as of Dec. 31, 2017 Long-term debt (including current portion) $ 7,143.1 $ 7,280.1 $ 7,796.5 $ 8,603.4

Transfers Of Financial Assets (

Transfers Of Financial Assets (Tables)	9 Months Ended
	Sep. 30, 2018
Transfers and Servicing [Abstract]
Schedule Of Gross And Net Receivables Transferred As Well As Short-Term Borrowings Related To The Securitization Transactions	The following table reflects the gross receivables balance and net receivables transferred as well as short-term borrowings related to the securitization transactions as of September 30, 2018 and December 31, 2017 : (in millions) September 30, 2018 December 31, 2017 Gross Receivables $ 410.9 $ 635.3 Less: Receivables not transferred 145.9 298.6 Net receivables transferred $ 265.0 $ 336.7 Short-term debt due to asset securitization $ 265.0 $ 336.7

Goodwill (Tables)

Goodwill (Tables)	9 Months Ended
	Sep. 30, 2018
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule of Goodwill	The following presents our goodwill balance allocated by segment as of September 30, 2018 : (in millions) Gas Distribution Operations Electric Operations Corporate and Other Total Goodwill $ 1,690.7 $ — $ — $ 1,690.7

Pension And Other Postretirem_2

Pension And Other Postretirement Benefits (Tables)	9 Months Ended
	Sep. 30, 2018
Pension and Other Postretirement Benefits Cost (Reversal of Cost) [Abstract]
Components Of The Plans' Net Periodic Benefits Cost	The following table provides the components of the plans’ actuarially determined net periodic benefit cost for the three and nine months ended September 30, 2018 and 2017 : Pension Benefits Other Postretirement Benefits Three Months Ended September 30, (in millions) 2018 2017 2018 2017 Components of Net Periodic Benefit Cost (1) Service cost $ 7.8 $ 7.4 $ 1.3 $ 1.2 Interest cost 16.8 17.1 4.4 4.4 Expected return on assets (35.4 ) (30.8 ) (3.7 ) (3.9 ) Amortization of prior service credit (0.1 ) (0.1 ) (1.0 ) (1.1 ) Recognized actuarial loss 10.2 13.2 0.9 0.7 Settlement loss 8.3 10.6 — — Total Net Periodic Benefit Cost $ 7.6 $ 17.4 $ 1.9 $ 1.3 (1) The service cost component, and all non-service cost components, of net periodic benefit cost are presented in "Operation and maintenance" and "Other, net", respectively, on the Condensed Statements of Consolidated Income (Loss) (unaudited). Pension Benefits Other Postretirement Benefits Nine Months Ended September 30, (in millions) 2018 2017 2018 2017 Components of Net Periodic Benefit Cost (1) Service cost $ 23.6 $ 22.4 $ 3.9 $ 3.6 Interest cost 50.0 51.5 13.2 13.4 Expected return on assets (107.9 ) (91.3 ) (11.1 ) (11.9 ) Amortization of prior service credit (0.3 ) (0.5 ) (3.0 ) (3.3 ) Recognized actuarial loss 30.6 40.0 2.7 2.2 Settlement loss 11.8 10.6 — — Total Net Periodic Benefit Cost $ 7.8 $ 32.7 $ 5.7 $ 4.0 (1) The service cost component, and all non-service cost components, of net periodic benefit cost are presented in "Operation and maintenance" and "Other, net", respectively, on the Condensed Statements of Consolidated Income (Loss) (unaudited).
Schedule of Assumptions Used	The following table provides the key assumptions that were used to calculate the pension benefit obligation and the net periodic benefit cost for the plans that triggered settlement accounting at the measurement dates of August 31, 2018, May 31, 2018 and December 31, 2017 : August 31, 2018 May 31, 2018 December 31, 2017 Weighted-average Assumption to Determine Benefit Obligation: Discount rate 4.08 % 4.03 % 3.58 % Weighted-average Assumptions to Determine Net Periodic Benefit Costs for the period ended: Discount rate - service cost 3.79 % 3.79 % 4.40 % Discount rate - interest cost 3.15 % 3.15 % 3.31 % Expected return on assets 6.30 % 6.30 % 7.25 %

Short-Term Borrowings (Tables)

Short-Term Borrowings (Tables)	9 Months Ended
	Sep. 30, 2018
Short-term Debt [Abstract]
Schedule Of Short-Term Borrowings	Short-term borrowings were as follows: (in millions) September 30, December 31, Commercial paper weighted-average interest rate of 2.57% and 1.97% at September 30, 2018 and December 31, 2017, respectively $ 746.0 $ 869.0 Accounts receivable securitization facility borrowings 265.0 336.7 Term loan weighted-average interest rate of 2.79% at September 30, 2018 600.0 — Total Short-Term Borrowings $ 1,611.0 $ 1,205.7

Accumulated Other Comprehensi_2

Accumulated Other Comprehensive Loss (Tables)	9 Months Ended
	Sep. 30, 2018
Other Comprehensive Income (Loss), Tax [Abstract]
Components Of Accumulated Other Comprehensive Loss	The following tables display the components of Accumulated Other Comprehensive Income (Loss): Three Months Ended September 30, 2018 (in millions) Gains and Losses on Securities (1) Gains and Losses on Cash Flow Hedges (1) Pension and OPEB Items (1) Accumulated (1) Balance as of July 1, 2018 $ (2.2 ) $ (1.7 ) $ (17.0 ) $ (20.9 ) Other comprehensive income before reclassifications — 21.6 1.0 22.6 Amounts reclassified from accumulated other comprehensive loss 0.1 0.9 (0.2 ) 0.8 Net current-period other comprehensive income 0.1 22.5 0.8 23.4 Balance as of September 30, 2018 $ (2.1 ) $ 20.8 $ (16.2 ) $ 2.5 Nine Months Ended September 30, 2018 (in millions) Gains and Losses on Securities (1) Gains and Losses on Cash Flow Hedges (1) Pension and OPEB Items (1) Accumulated Other Comprehensive Income (Loss) (1) Balance as of January 1, 2018 $ 0.2 $ (29.4 ) $ (14.2 ) $ (43.4 ) Other comprehensive income (loss) before reclassifications (2.5 ) 70.8 1.0 69.3 Amounts reclassified from accumulated other comprehensive loss (2) 0.2 (14.3 ) 0.2 (13.9 ) Net current-period other comprehensive income (loss) (2.3 ) 56.5 1.2 55.4 Reclassification due to adoption of ASU 2018-02 (Refer to Note 2) — (6.3 ) (3.2 ) (9.5 ) Balance as of September 30, 2018 $ (2.1 ) $ 20.8 $ (16.2 ) $ 2.5 Three Months Ended September 30, 2017 (in millions) Gains and Losses on Securities (1) Gains and Losses on Cash Flow Hedges (1) Pension and OPEB Items (1) Accumulated (1) Balance as of July 1, 2017 $ 0.4 $ (18.8 ) $ (17.2 ) $ (35.6 ) Other comprehensive income (loss) before reclassifications 0.1 (9.7 ) — (9.6 ) Amounts reclassified from accumulated other comprehensive loss — 0.4 1.1 1.5 Net current-period other comprehensive income (loss) 0.1 (9.3 ) 1.1 (8.1 ) Balance as of September 30, 2017 $ 0.5 $ (28.1 ) $ (16.1 ) $ (43.7 ) Nine Months Ended September 30, 2017 (in millions) Gains and Losses on Securities (1) Gains and Losses on Cash Flow Hedges (1) Pension and OPEB Items (1) Accumulated Other Comprehensive (Loss) (1) Balance as of January 1, 2017 $ (0.6 ) $ (6.9 ) $ (17.6 ) $ (25.1 ) Other comprehensive income (loss) before reclassifications 1.1 (23.3 ) 0.2 (22.0 ) Amounts reclassified from accumulated other comprehensive loss — 2.1 1.3 3.4 Net current-period other comprehensive income (loss) 1.1 (21.2 ) 1.5 (18.6 ) Balance as of September 30, 2017 $ 0.5 $ (28.1 ) $ (16.1 ) $ (43.7 ) (1) All amounts are net of tax. Amounts in parentheses indicate debits. (2) Reclassification from accumulated other comprehensive loss for cash flow hedges relates primarily to the interest rate swap settlement gain. Refer to Note 8 "Risk Management Activities" for additional information.

Other, Net (Tables)

Other, Net (Tables)	9 Months Ended
	Sep. 30, 2018
Other, Net [Abstract]
Schedule of Other Nonoperating Income (Expense)	Three Months Ended Nine Months Ended (in millions) 2018 2017 2018 2017 Interest Income $ 1.4 $ 1.4 $ 4.2 $ 3.2 AFUDC Equity 5.0 4.3 12.6 10.5 Charitable Contributions (11.1 ) (0.8 ) (13.9 ) (3.5 ) Pension and other postretirement non-service cost 2.4 (11.8 ) 14.7 (10.1 ) Interest rate swap settlement gain (1) — — 21.2 — Miscellaneous 0.6 0.1 3.6 (0.4 ) Total Other, net $ (1.7 ) $ (6.8 ) $ 42.4 $ (0.3 ) (1) See Note 8 , "Risk Management Activities," for additional information.

Business Segment Information (T

Business Segment Information (Tables)	9 Months Ended
	Sep. 30, 2018
Segment Reporting [Abstract]
Schedule Of Operating Income Derived From Revenues And Expenses By Segment	The following table provides information about our business segments. We use operating income as our primary measurement for each of the reported segments and make decisions on finance, dividends and taxes at the corporate level on a consolidated basis. Segment revenues include intersegment sales to affiliated subsidiaries, which are eliminated in consolidation. Affiliated sales are recognized on the basis of prevailing market, regulated prices or at levels provided for under contractual agreements. Operating income is derived from revenues and expenses directly associated with each segment. Three Months Ended Nine Months Ended (in millions) 2018 2017 2018 2017 Operating Revenues Gas Distribution Operations Unaffiliated $ 418.6 $ 431.1 $ 2,347.8 $ 2,139.9 Intersegment 3.3 3.5 9.8 10.6 Total 421.9 434.6 2,357.6 2,150.5 Electric Operations Unaffiliated 476.2 485.8 1,304.4 1,365.5 Intersegment 0.2 0.2 0.6 0.6 Total 476.4 486.0 1,305.0 1,366.1 Corporate and Other Unaffiliated 0.2 0.1 0.6 0.9 Intersegment 116.4 126.4 346.6 367.7 Total 116.6 126.5 347.2 368.6 Eliminations (119.9 ) (130.1 ) (357.0 ) (378.9 ) Consolidated Operating Revenues $ 895.0 $ 917.0 $ 3,652.8 $ 3,506.3 Operating Income (Loss) Gas Distribution Operations $ (455.2 ) $ (15.4 ) $ (94.4 ) $ 367.1 Electric Operations 134.9 125.1 300.4 288.3 Corporate and Other 4.4 1.5 (2.9 ) (4.8 ) Consolidated Operating Income $ (315.9 ) $ 111.2 $ 203.1 $ 650.6

Recent Accounting Pronounceme_3

Recent Accounting Pronouncements (Schedule of Prospective Adoption of New Accounting Pronouncements) (Details) - Accounting Standards Update 2018-02 $ in Millions	Dec. 31, 2017USD ($)	[1]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Cumulative Effect of New Accounting Principle in Period of Adoption	$ 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.

Recent Accounting Pronounceme_4

Recent Accounting Pronouncements (Schedule of New Accounting Pronouncements and Changes in Accounting Princicples) (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017		Dec. 31, 2016
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Operation and maintenance	$ 780.8	$ 371.7	$ 1,548.5	$ 1,174.9
Total Operating Expenses	1,210.9	805.8	3,449.7	2,855.7
Operating Income	(315.9)	111.2	203.1	650.6
Other, net	(1.7)	(6.8)	42.4	(0.3)
Total Other Deductions	(118.1)	(94.7)	(268.3)	(372.6)
Income before Income Taxes	(434)	16.5	(65.2)	278
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	[1]	0	[2]
Gas Distribution Operations
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Operating Income	(455.2)	(15.4)	(94.4)	367.1
New Accounting Pronouncement or Change in Accounting Principle, Effect of Change on Operating Results					(4.4)		4.3
Electric Operations
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Operating Income	134.9	125.1	300.4	288.3
New Accounting Pronouncement or Change in Accounting Principle, Effect of Change on Operating Results					(2.6)		(9.8)
Corporate and Other
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Operating Income	$ 4.4	$ 1.5	$ (2.9)	$ (4.8)
New Accounting Pronouncement or Change in Accounting Principle, Effect of Change on Operating Results					(3.6)		(2.4)
Previously Reported
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Operation and maintenance					1,612.3		1,453.7
Total Operating Expenses					3,964		3,634.3
Operating Income					910.6		858.2
Other, net					(2.8)		1.5
Total Other Deductions					(467.5)		(348)
Income before Income Taxes					443.1		510.2
Restatement Adjustment
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Operation and maintenance					1,601.7		1,445.8
Total Operating Expenses					3,953.4		3,626.4
Operating Income					921.2		866.1
Other, net					(13.4)		(6.4)
Total Other Deductions					(478.1)		(355.9)
Income before Income Taxes					$ 443.1		$ 510.2
[1]	The effect of this change is attributable to our business segments: Gas Distribution Operations, Electric Operations, and Corporate and Other in the amounts of $(4.4) million, $(2.6) million, and $(3.6) million, respectively.
[2]	The effect of this change is attributable to our business segments: Gas Distribution Operations, Electric Operations, and Corporate and Other in the amounts of $4.3 million, $(9.8) million, and $(2.4) million, respectively.

Revenue Recognition (Narrative)

Revenue Recognition (Narrative) (Details)	9 Months Ended
	Sep. 30, 2018
Revenue from Contract with Customer [Abstract]
Service Area By County	20

Revenue Recognition (Revenue Re

Revenue Recognition (Revenue Recognition Under Previous Guidance) (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Revenue Recognition Under Previous Guidance [Line Items]
Regulated Operating Revenue	$ 895	$ 917	$ 3,652.8	$ 3,506.3
Previous Accounting Guidance
Revenue Recognition Under Previous Guidance [Line Items]
Regulated Operating Revenue	895	917	3,652.8	3,506.3
Previous Accounting Guidance | Gas Distribution
Revenue Recognition Under Previous Guidance [Line Items]
Regulated Operating Revenue	232.3	239.4	1,600.3	1,403
Previous Accounting Guidance | Gas Transportation
Revenue Recognition Under Previous Guidance [Line Items]
Regulated Operating Revenue	186	191.6	745.2	735.1
Previous Accounting Guidance | Electric
Revenue Recognition Under Previous Guidance [Line Items]
Regulated Operating Revenue	476.2	485.8	1,304.4	1,365.5
Previous Accounting Guidance | Other
Revenue Recognition Under Previous Guidance [Line Items]
Regulated Operating Revenue	$ 0.5	$ 0.2	$ 2.9	$ 2.7

Revenue Recognition (Disaggrega

Revenue Recognition (Disaggregation of Revenue) (Details) - USD ($) $ in Millions		3 Months Ended			9 Months Ended
		Sep. 30, 2018		Sep. 30, 2017	Sep. 30, 2018		Sep. 30, 2017
Disaggregation of Revenue [Line Items]
Customer revenues		$ 855.8	[1]	$ 883.4	$ 3,555.1	[1]	$ 3,386
Other revenues		39.2		33.6	97.7		120.3
Total Operating Revenues		895		$ 917	3,652.8		$ 3,506.3
Gas Distribution Operations
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	406.5			2,317.6
Other revenues		12.1			30.2
Total Operating Revenues		418.6			2,347.8
Electric Operations
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	449.1			1,236.9
Other revenues		27.1			67.5
Total Operating Revenues		476.2			1,304.4
Corporate and Other
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	0.2			0.6
Other revenues		0			0
Total Operating Revenues		0.2			0.6
Residential
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	411.7
Residential | Gas Distribution Operations
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	257			1,540.3
Residential | Electric Operations
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	154.7			382.3
Residential | Corporate and Other
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	0			0
Commercial | Gas Distribution Operations
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	80.9			516.2
Commercial | Electric Operations
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	140.7			374.2
Commercial | Corporate and Other
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	0			0
Industrial | Gas Distribution Operations
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	39			161.3
Industrial | Electric Operations
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	153.6			468.1
Industrial | Corporate and Other
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	0			0
Off-system | Gas Distribution Operations
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	20.4			63.6
Off-system | Electric Operations
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	0			0
Off-system | Corporate and Other
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	0			0
Miscellaneous | Gas Distribution Operations
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	9.2			36.2
Miscellaneous | Electric Operations
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	0.1			12.3
Miscellaneous | Corporate and Other
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	0.2			0.6
Residential
Disaggregation of Revenue [Line Items]
Customer revenues	[1]				1,922.6
Commercial
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	221.6			890.4
Industrial
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	192.6			629.4
Off-system
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	20.4			63.6
Miscellaneous
Disaggregation of Revenue [Line Items]
Customer revenues	[1]	$ 9.5			$ 49.1
[1]	Customer revenue amounts exclude intersegment revenues. See Note 19, "Business Segment Information," for discussion of intersegment revenues.

Revenue Recognition (Customer A

Revenue Recognition (Customer Accounts Receivable) (Details) - USD ($) $ in Millions		9 Months Ended
		Sep. 30, 2018	Dec. 31, 2017
Revenue from Contract with Customer [Abstract]
Customer Accounts Receivable, Billed (Less Reserve)	[1]	$ 297.2	$ 477
Customer Accounts Receivable, Unbilled (Less Reserve)	[2]	154.8	$ 356
Increase (Decrease) in Customer Accounts Receivable, Billed (Less Reserve)	[1]	(179.8)
Increase (Decrease) in Customer Accounts Receivable, Unbilled (Less Reserve)	[2]	$ (201.2)
[1]	Customer billed receivables decreased over the period due to the expected seasonal decrease in customer usage in September when compared to December.
[2]	Customer unbilled receivables decreased over the period due to the expected seasonal decrease in customer usage in September when compared to December.

Earnings Per Share (Details)

Earnings Per Share (Details) - shares shares in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Denominator
Basic Average Common Shares Outstanding	363,900	331,139	352,115	326,662
Dilutive potential common shares
Shares contingently issuable under employee stock plans		604		503
Shares restricted under stock plans		653		866
Diluted Average Common Shares	363,900	332,396	352,115	328,031

Equity (Narrative) (Details)

Equity (Narrative) (Details) $ / shares in Units, $ in Millions	Jun. 11, 2018USD ($)$ / sharesshares	May 04, 2018USD ($)$ / sharesshares	Dec. 08, 2017$ / shares	Sep. 30, 2018USD ($)$ / sharesshares	Sep. 30, 2017USD ($)$ / shares	Sep. 30, 2018USD ($)$ / sharesshares	Sep. 30, 2017USD ($)$ / shares	Dec. 31, 2017$ / sharesshares
Shares, Issued | shares				363,167,000		363,167,000		337,016,000
Common Stock, Par or Stated Value Per Share | $ / shares				$ 0.01		$ 0.01		$ 0.01
Preferred Stock, Par or Stated Value Per Share | $ / shares				$ 1,000		$ 1,000
Proceeds from Issuance of Common Stock						$ 611.6	$ 332.6
At The Market Program
Number Of Equity Distribution Agreements						4
Common Stock Aggregate Sale Price				$ 500		$ 500
ATM Program Equity Remaining Available for Issuance						$ 10
Common Stock Issued Average Price Per Share | $ / shares				$ 0	$ 26.67	$ 0	$ 26.58
Proceeds from Issuance of Common Stock				$ 0	$ 281	$ 0	$ 314.7
Forward Agreement
Forward Contract Indexed to Issuer's Equity, Shares | shares						6,345,860
Forward Contract Indexed to Issuer's Equity, Forward Rate Per Share | $ / shares			$ 27.24			$ 26.59
Forward Contract Indexed to Issuer's Equity, Settlement Alternatives, Shares, at Fair Value				$ 168.7		$ 168.7
Common Stock
Shares, Issued | shares		24,964,163		367,130,000		367,130,000		340,813,000
Sale of Stock, Price Per Share | $ / shares		$ 24.28
Common Stock, Par or Stated Value Per Share | $ / shares		$ 0.01
Series A Preferred Stock
Preferred Stock, Par or Stated Value Per Share | $ / shares	$ 1,000
Preferred Stock, Dividend Rate, Initial Margin	2.843%
Preferred Stock, Shares Issued | shares	400,000
Preferred Stock, Dividend Rate, Percentage	5.65%
Preferred Stock, Dividend Rate, Initial Margin Plus 1.000%	1.00%
Gross Proceeds | Common Stock
Proceeds from Issuance of Private Placement		$ 606
Gross Proceeds | Series A Preferred Stock
Proceeds from Issuance of Private Placement	$ 400
Net Proceeds | Common Stock
Proceeds from Issuance of Private Placement		$ 599.6
Net Proceeds | Series A Preferred Stock
Proceeds from Issuance of Private Placement	$ 393.9

Equity (Schedule of Stock Offer

Equity (Schedule of Stock Offering Program) (Details) - USD ($) $ / shares in Units, $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Class of Stock [Line Items]
Stock Issued During Period, Shares, New Issues	[1]			24,964,000
Proceeds from Issuance of Common Stock				$ 611.6	$ 332.6
At The Market Program
Class of Stock [Line Items]
Stock Issued During Period, Shares, New Issues		0	10,612,915	0	11,931,376
Common Stock Issued Average Price Per Share		$ 0	$ 26.67	$ 0	$ 26.58
Proceeds from Issuance of Common Stock		$ 0	$ 281	$ 0	$ 314.7
[1]	See Note 5, "Equity," for additional information.

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2018		Sep. 30, 2017
Asset Retirement Obligations [Abstract]
Asset Retirement Obligation, Revision of Estimate	$ 70.7	[1]	$ 0
[1]	See Note 6 "Asset Retirement Obligations" for additional information.

Regulatory Matters (Narrative)

Regulatory Matters (Narrative) (Details) - USD ($) $ in Millions

Oct. 31, 2018

Oct. 25, 2018

Oct. 15, 2018

Oct. 09, 2018

Sep. 26, 2018

Sep. 19, 2018

Aug. 31, 2018

Aug. 28, 2018

Jul. 31, 2018

Jul. 18, 2018

Jun. 21, 2018

Apr. 20, 2018

Apr. 18, 2018

Apr. 13, 2018

Mar. 28, 2018

Mar. 26, 2018

Mar. 16, 2018

Feb. 27, 2018

Feb. 13, 2018

Jan. 30, 2018

Jan. 29, 2018

Nov. 08, 2017

Oct. 31, 2017

Sep. 27, 2017

Sep. 30, 2018

Sep. 30, 2018

Sep. 04, 2018

May 31, 2018

Apr. 30, 2018

Apr. 25, 2018

Feb. 01, 2018

Regulatory Matters [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Net of TCJA

$ (1.2)

Regulatory Liability Adjustment From Tax Reform

$ 69.9

$ 69.9

Tax Benefit From Excess Deferred Tax Amortization Related To Regulatory LIabilities

6.8

24.6

TCJA Related Revenue Reserve, Net of Tax

3.6

15.9

Columbia Of Ohio

Regulatory Matters [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Net of TCJA

$ 2.3

Public Utilities, Requested Rate Increase (Decrease), Amount

$ 70

Regulatory Net Capital Expenditures Included In Filing

$ 207

Public Utilities, Requested Biennial Rate Increase (Decrease), Amount increases

$ 98

NIPSCO

Regulatory Matters [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Net of TCJA

$ 138.1

Public Utilities, Requested Rate Increase (Decrease), Amount

$ 107.3

$ 143.5

Public Utilities, Approved Rate Increase (Decrease), Amount

$ 84.3

$ 91.5

$ (8.5)

Regulatory Net Capital Expenditures Included In Filing

$ 35.5

1,250

1,250

$ 767

Bailly Unit 8 Portion of Net Book Value in Net Utility Plant

$ 15

Regulatory Asset Associated with Bailly Generating Station Retirement

$ 103

$ 142

NIPSCO | TDSIC-3

Regulatory Matters [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amount

$ (1.8)

Regulatory Net Capital Expenditures Included In Filing

$ 75

NIPSCO | TDSIC 8 Gas

Regulatory Matters [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Net of TCJA

0.8

Public Utilities, Requested Rate Increase (Decrease), Amount

$ (0.2)

Regulatory Net Capital Expenditures Included In Filing

$ 54

$ 77.9

Public Utilities, Passback Liability for Revenues Previously Billed to Customers

$ 2.5

$ 2.5

NIPSCO | TDSIC-9 [Member]

Regulatory Matters [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amount

$ (7.6)

$ (0.5)

Regulatory Net Capital Expenditures Included In Filing

72.9

Public Utilities, Customer Refund for Tax Rate Change Due to TCJA

7.1

NIPSCO | TDSIC-4

Regulatory Matters [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Net of TCJA

$ 2.8

Regulatory Net Capital Expenditures Included In Filing

72.2

Public Utilities, Requested Biennial Rate Increase (Decrease), Amount increases

(11.2)

Public Utilities, Customer Refund for Tax Rate Change Due to TCJA

14.1

Columbia Of Massachusetts

Regulatory Matters [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amount

$ (19.7)

Public Utilities, Approved Rate Increase (Decrease), Cumulative Amount

24.1

Columbia Of Massachusetts | 2018 GSEP

Regulatory Matters [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Cumulative Amount

43.8

Public Utilities, Requested Rate Increase (Decrease), Waiver Amount in excess of Cap

3.1

Public Utilities, Requested Rate Increase (Decrease), Amount

$ (2.4)

$ 9.7

Regulatory Net Capital Expenditures Included In Filing

$ 83.9

Public Utilities, Requested Rate Increase (Decrease), Incremental Revenue Requirement from Waiver on Revenue Cap

$ 6.5

Columbia Of Pennsylvania

Regulatory Matters [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amount

$ 26

$ 46.9

Public Utilities, Customer Refund for Tax Rate Change Due to TCJA

$ 22.5

Columbia Of Virginia [Member]

Regulatory Matters [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amount

$ 22.2

Columbia Of Maryland

Regulatory Matters [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amount

$ 3.7

$ 6.1

Public Utilities, Approved Rate Increase (Decrease), Amount

$ (1.3)

Subsequent Event | Columbia Of Ohio

Regulatory Matters [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amount

$ 74.5

Subsequent Event | NIPSCO

Regulatory Matters [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amount

$ 21.4

Subsequent Event | Columbia Of Massachusetts

Regulatory Matters [Line Items]

Public Utilities, Customer Refund for Tax Rate Change Due to TCJA

$ 95.8

Subsequent Event | Columbia Of Massachusetts | 2018 GSEP

Regulatory Matters [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Waiver Amount in excess of Cap

2.9

Public Utilities, Requested Rate Increase (Decrease), Amount

10.7

Regulatory Net Capital Expenditures Included In Filing

$ 64

Subsequent Event | Columbia Of Kentucky [Member]

Regulatory Matters [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amount

$ 3.6

Public Utilities, Requested Incremental Capital Investment

$ 30.1

Risk Management Activities (Nar

Risk Management Activities (Narrative) (Details) - USD ($) $ in Millions	3 Months Ended			9 Months Ended
	Sep. 30, 2018		Sep. 30, 2017	Sep. 30, 2018		Sep. 30, 2017	[1]
Derivative [Line Items]
Gain (Loss) on Sale of Derivatives	$ 0	[1]	$ 0	$ 21.2	[1]	$ 0
Interest Rate Swap
Derivative [Line Items]
Derivative, Notional Amount	750			750
Interest Rate Swap Settled
Derivative [Line Items]
Derivative, Notional Amount	$ 250			$ 250
[1]	See Note 8, "Risk Management Activities," for additional information.

Risk Management Activities (Sch

Risk Management Activities (Schedule of Derivative Instruments in Statement of Financial Position, Fair Value) (Details) - USD ($) $ in Millions		Sep. 30, 2018	Dec. 31, 2017
Risk Management Assets Current
Derivatives, Fair Value [Line Items]
Derivative Asset	[1]	$ 22.4	$ 14.5
Risk Management Assets Noncurrent
Derivatives, Fair Value [Line Items]
Derivative Asset	[2]	35.2	6.6
Risk Management Liabilities Current
Derivatives, Fair Value [Line Items]
Derivative Liability		4.8	43.2
Risk Management Liabilities Noncurrent
Derivatives, Fair Value [Line Items]
Derivative Liability		45.2	28.5
Interest Rate Risk | Risk Management Assets Current
Derivatives, Fair Value [Line Items]
Derivative Asset	[1]	21.4	14
Interest Rate Risk | Risk Management Assets Noncurrent
Derivatives, Fair Value [Line Items]
Derivative Asset	[2]	32.6	5.6
Interest Rate Risk | Risk Management Liabilities Current
Derivatives, Fair Value [Line Items]
Derivative Liability		0	38.6
Interest Rate Risk | Risk Management Liabilities Noncurrent
Derivatives, Fair Value [Line Items]
Derivative Liability		0	0
Commodity Price Risk Programs | Risk Management Assets Current
Derivatives, Fair Value [Line Items]
Derivative Asset	[1]	1	0.5
Commodity Price Risk Programs | Risk Management Assets Noncurrent
Derivatives, Fair Value [Line Items]
Derivative Asset	[2]	2.6	1
Commodity Price Risk Programs | Risk Management Liabilities Current
Derivatives, Fair Value [Line Items]
Derivative Liability		4.8	4.6
Commodity Price Risk Programs | Risk Management Liabilities Noncurrent
Derivatives, Fair Value [Line Items]
Derivative Liability		$ 45.2	$ 28.5
[1]	Presented in "Prepayments and other" on the Condensed Consolidated Balance Sheets (unaudited).
[2]	Presented in "Deferred charges and other" on the Condensed Consolidated Balance Sheets (unaudited).

Fair Value (Narrative) (Details

Fair Value (Narrative) (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Fair Value Disclosure [Line Items]
Transfers between Fair Value Hierarchies	0	0
Material Level 3 Changes	$ 0	$ 0
Fair Value, Assets and Liabilities Measured on a Non-Recurring Basis	0	0
U.S. Treasury debt securities
Fair Value Disclosure [Line Items]
Available-for-sale Securities, Maturities, Next Twelve Months, Fair Value	$ 14.9
Corporate/Other debt securities
Fair Value Disclosure [Line Items]
Available-for-sale Securities, Maturities, Next Twelve Months, Fair Value	$ 3

Fair Value (Fair Value Of Finan

Fair Value (Fair Value Of Financial Assets And Liabilities Measured On A Recurring Basis) (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Assets
Assets, Fair Value Disclosure	$ 201.4	$ 155
Liabilities
Total	50	71.7
Fair Value, Inputs, Level 1
Assets
Risk management assets	0	0
Available-for-sale securities	0	0
Assets, Fair Value Disclosure	0	0
Liabilities
Risk management liabilities	0	0
Total	0	0
Significant Other Observable Inputs (Level 2)
Assets
Risk management assets	57.6	21.1
Available-for-sale securities	143.8	133.9
Assets, Fair Value Disclosure	201.4	155
Liabilities
Risk management liabilities	50	71.4
Total	50	71.4
Significant Unobservable Inputs (Level 3)
Assets
Risk management assets	0	0
Available-for-sale securities	0	0
Assets, Fair Value Disclosure	0	0
Liabilities
Risk management liabilities	0	0.3
Total	0	0.3
Available-for-sale Securities
Assets
Available-for-sale securities	143.8	133.9
Risk management assets
Assets
Risk management assets	57.6	21.1
Liabilities
Risk management liabilities	$ 50	$ 71.7

Fair Value (Available-For-Sale

Fair Value (Available-For-Sale Securities) (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Debt Securities, Available-for-sale [Line Items]
Amortized cost	$ 146.5	$ 133.7
Gross unrealized gains	0.4	0.9
Gross unrealized losses	3.1	0.7
Fair value	143.8	133.9
U.S. Treasury debt securities
Debt Securities, Available-for-sale [Line Items]
Amortized cost	29.7	26.9
Gross unrealized gains	0	0
Gross unrealized losses	0.2	0.1
Fair value	29.5	26.8
Corporate/Other debt securities
Debt Securities, Available-for-sale [Line Items]
Amortized cost	116.8	106.8
Gross unrealized gains	0.4	0.9
Gross unrealized losses	2.9	0.6
Fair value	$ 114.3	$ 107.1

Fair Value (Carrying Amount And

Fair Value (Carrying Amount And Estimated Fair Values Of Financial Instruments) (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Fair Value Disclosures [Abstract]
Long-term Debt (including current portion), Gross	$ 7,143.1	$ 7,796.5
Long-term debt (including current portion), Estimated Fair Value	$ 7,280.1	$ 8,603.4

Transfers Of Financial Assets_2

Transfers Of Financial Assets (Narrative) (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Assets and Associated Liabilities of Transfers Accounted for as Secured Borrowings [Line Items]
Cash From Financing Activities Related To The Change In Short-Term Borrowings Due To The Securitization Transactions			$ 71.7	$ 47.8
Securitization Transaction Fees	$ 0.4	$ 0.6		$ 1.9
Accounts Receivable Program
Assets and Associated Liabilities of Transfers Accounted for as Secured Borrowings [Line Items]
Seasonal Limit	$ 265		$ 265

Transfers Of Financial Assets_3

Transfers Of Financial Assets (Schedule Of Gross And Net Receivables Transferred As Well As Short-Term Borrowings Related To The Securitization Transactions) (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Gross Receivables	$ 410.9	$ 635.3
Less: Receivables not transferred	145.9	298.6
Net receivables transferred	265	336.7
Accounts receivable securitization facility borrowings	$ 265	$ 336.7

Goodwill (Details)

Goodwill (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2018	Dec. 31, 2017
Goodwill [Line Items]
Goodwill, Impairment Loss	$ 0
Goodwill	1,690.7	$ 1,690.7
Gas Distribution Operations
Goodwill [Line Items]
Goodwill	1,690.7
Electric Operations
Goodwill [Line Items]
Goodwill	0
Corporate and Other
Goodwill [Line Items]
Goodwill	0
Columbia Of Massachusetts
Goodwill [Line Items]
Goodwill	$ 204.8

Income Taxes (Narrative) (Detai

Income Taxes (Narrative) (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Income Tax Disclosure [Abstract]
Effective income tax rates	21.80%	15.20%	40.30%	34.90%
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate			21.00%	35.00%
Increase (Decrease) in Effective Tax Rate	6.60%		5.40%
Tax Benefit From Excess Deferred Tax Amortization Related To Regulatory LIabilities	$ 6.8		$ 24.6
Potential Decrease in TCJA-Related Regulatory Liabilities			150
Changes to Liability for Uncertain Tax Positions			$ 0

Pension And Other Postretirem_3

Pension And Other Postretirement Benefits (Narrative) (Details) - USD ($) $ in Millions		3 Months Ended			6 Months Ended	9 Months Ended
		Sep. 30, 2018	Jun. 30, 2018	Sep. 30, 2017	Jun. 30, 2018	Sep. 30, 2018	Sep. 30, 2017	Aug. 31, 2018	May 31, 2018
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Employer contributions						$ 2.1
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement	[1]	$ (8.3)	$ (3.5)	$ (10.6)		(11.8)	$ (10.6)
Defined Benefit Plan, Benefit Obligation, (Increase) Decrease for Remeasurement due to Settlement					$ 1.1	2.5
Change in Regulatory Assets Due To Interim Measurement								$ 5.3	$ 2.3
Change in Accumulated Other Comprehensive Income Due To Interim Measurement								0.5	0.1
Defined Benefit Plan Net Periodic Benefit Costs								$ 1.9	$ 1.1
Other Postretirement Benefit Plan
Defined Benefit Plan Disclosure [Line Items]
Employer contributions						16.8
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement	[1]	$ 0		$ 0		$ 0	$ 0
[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 And Other Postretirem_4

Pension And Other Postretirement Benefits (Components Of The Plans' Net Periodic Benefits Cost) (Details) - USD ($) $ in Millions		3 Months Ended			9 Months Ended
		Sep. 30, 2018	Jun. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Service Cost	[1]	$ 7.8		$ 7.4	$ 23.6	$ 22.4
Interest cost	[1]	16.8		17.1	50	51.5
Expected return on assets	[1]	(35.4)		(30.8)	(107.9)	(91.3)
Amortization of prior service credit	[1]	(0.1)		(0.1)	(0.3)	(0.5)
Recognized actuarial loss	[1]	10.2		13.2	30.6	40
Settlement loss	[1]	8.3	$ 3.5	10.6	11.8	10.6
Total Net Periodic Benefits Cost		7.6		17.4	7.8	32.7
Other Postretirement Benefit Plan
Defined Benefit Plan Disclosure [Line Items]
Service Cost	[1]	1.3		1.2	3.9	3.6
Interest cost	[1]	4.4		4.4	13.2	13.4
Expected return on assets	[1]	(3.7)		(3.9)	(11.1)	(11.9)
Amortization of prior service credit	[1]	(1)		(1.1)	(3)	(3.3)
Recognized actuarial loss	[1]	0.9		0.7	2.7	2.2
Settlement loss	[1]	0		0	0	0
Total Net Periodic Benefits Cost		$ 1.9		$ 1.3	$ 5.7	$ 4
[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 and Other Postretirem_5

Pension and Other Postretirement Benefits (Schedule of Assumptions Used) (Details) - Pension Plan	5 Months Ended	8 Months Ended	12 Months Ended
	May 31, 2018	Aug. 31, 2018	Dec. 31, 2017
Defined Benefit Plan Disclosure [Line Items]
Discount rate	4.03%	4.08%	3.58%
Discount rate - service cost	3.79%	3.79%	4.40%
Discount rate - interest cost	3.15%	3.15%	3.31%
Expected return on assets	6.30%	6.30%	7.25%

Long-Term Debt (Narrative) (Det

Long-Term Debt (Narrative) (Details) - USD ($) $ in Millions	Jul. 16, 2018	Sep. 30, 2018	Sep. 30, 2017	Jun. 30, 2018	Sep. 30, 2018	Sep. 30, 2017	Jun. 11, 2018	Mar. 15, 2018
Debt Instrument [Line Items]
Loss on early extinguishment of long-term debt		$ (33)	$ 0	$ 12.5	$ (45.5)	$ (111.5)
Debt Instrument Tendered					$ 209
Senior Notes
Debt Instrument [Line Items]
Debt Instrument, Face Amount							$ 350
Senior Note Redeemed 2018 Note 1 | Senior Notes
Debt Instrument [Line Items]
Debt Instrument, Repurchase Amount								$ 275.1
Debt Instrument, Interest Rate, Stated Percentage								6.40%
6.80% Notes Due 2019
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		6.80%			6.80%
6.125% Notes Due 2022
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		6.125%			6.125%
3.65% Notes Due 2023
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		3.65%			3.65%
3.65% Notes Due 2023 | Senior Notes
Debt Instrument [Line Items]
Proceeds from Debt, Net of Issuance Costs					$ 346.6
5.45% Notes due 2020
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		5.45%			5.45%
Senior Note Redeemed 2018 Note 2
Debt Instrument [Line Items]
Loss on early extinguishment of long-term debt	$ 33
Debt Instrument, Repurchased Face Amount	$ 551.1

Short-Term Borrowings (Narrativ

Short-Term Borrowings (Narrative) (Details) - USD ($) $ in Millions	May 31, 2018	Apr. 18, 2018	Sep. 30, 2018	Dec. 31, 2017
Short-term Debt [Line Items]
Commercial paper outstanding			$ 746	$ 869
Accounts receivable securitization facility borrowings			265	336.7
Term Loan			600	0
Revolving Credit Facility
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity			1,850
Long-term Line of Credit			0
Commercial Paper
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity			1,500
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	$ 150
Maximum | Term Loan
Short-term Debt [Line Items]
Term Loan		$ 600

Short-Term Borrowings (Schedule

Short-Term Borrowings (Schedule Of Short-Term Borrowings) (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Short-term Debt [Line Items]
Commercial paper weighted-average interest rate of 2.57% and 1.97% at September 30, 2018 and December 31, 2017, respectively	$ 746	$ 869
Accounts receivable securitization facility borrowings	265	336.7
Term loan weighted-average interest rate of 2.79% at September 30, 2018	600	0
Total short-term borrowings	$ 1,611	$ 1,205.7
Commercial Paper
Short-term Debt [Line Items]
Short-term Debt, Weighted Average Interest Rate, at Point in Time	2.57%	1.97%
Term Loan
Short-term Debt [Line Items]
Short-term Debt, Weighted Average Interest Rate, at Point in Time	2.79%

Other Commitments And Conting_2

Other Commitments And Contingencies (Narrative) (Details) $ in Millions	3 Months Ended	9 Months Ended		12 Months Ended
	Sep. 30, 2018USD ($)	Sep. 30, 2018USD ($)	Sep. 30, 2017USD ($)	Dec. 31, 2018USD ($)	May 31, 2018USD ($)	Feb. 01, 2018USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)
Other Commitments And Contingencies [Line Items]
Liability Insurance for Damages	$ 800	$ 800
Recorded reserves to cover environmental remediation at various sites	$ 107.1	107.1					$ 111.4
Payments Pure Air		$ 8.3	$ 16.5
Liability Associated with Bailly Generating Station Retirement - Pure Air Contract Termination Portion								$ 16
MGP Sites
Other Commitments And Contingencies [Line Items]
Number of waste disposal sites identified by program	64	64
Liability for Estimated Remediation Costs	$ 103.3	$ 103.3					106.9
Reasonably possible remediation costs variance from reserve	$ 25	25
Columbia Of Massachusetts
Other Commitments And Contingencies [Line Items]
Gas Meters Affected	8,500
Businesses Impacted by Incident	700
Expenses Related to Third-Party Claims	$ 415
Loss from Consulting Costs, Administration Costs, Charitable Contributions, and Other Labor and Related Expenses	45
Loss Recorded During Period	$ 460
Miles of Affected Cast Iron and Bare Steel Pipeline System	45
NIPSCO
Other Commitments And Contingencies [Line Items]
Estimated Cost of Compliance with Coal Combustion Residuals, Maximum		193
Estimated Cost of Compliance with Effluent Limitations Guidelines		170
Bailly Unit 8 Portion of Net Book Value in Net Utility Plant						$ 15
Regulatory Asset Associated with Bailly Generating Station Retirement					$ 103	$ 142
Maximum | Columbia Of Massachusetts
Other Commitments And Contingencies [Line Items]
Civil Penalty Assessed for Violation of Federal Pipeline Safety Regulations		0.2
Civil Penalty Assessed for Series of Violations of Federal Pipeline Safety Regulations		2.1
Penalty Per Violation of Emergency Response Plan		0.3
Penalty for Violations of Emergency Response Plan		20
Penalty Per Violation of Operational Directives During Restoration Efforts		1
Third-Party Claims Resulting from the Greater Lawrence Incident		450
Estimated Capital Cost of the Pipeline Replacement	$ 165	165
Minimum | Columbia Of Massachusetts
Other Commitments And Contingencies [Line Items]
Third-Party Claims Resulting from the Greater Lawrence Incident		415
Estimated Capital Cost of the Pipeline Replacement	135	135
Standby Letters of Credit
Other Commitments And Contingencies [Line Items]
Long-term Line of Credit	$ 10.2	$ 10.2					$ 11.1
Scenario, Forecast [Member] | Maximum
Other Commitments And Contingencies [Line Items]
Incident-Related Costs				$ 210
Scenario, Forecast [Member] | Minimum
Other Commitments And Contingencies [Line Items]
Incident-Related Costs				$ 180

Accumulated Other Comprehensi_3

Accumulated Other Comprehensive Loss (Components Of Accumulated Other Comprehensive Loss) (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018		Sep. 30, 2017	Dec. 31, 2017
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance	[1]	$ (20.9)	$ (35.6)	$ (43.4)		$ (25.1)
Other Comprehensive Income before reclassifications	[1]	22.6	(9.6)	69.3		(22)
Amounts reclassified from accumulated other comprehensive loss	[1]	0.8	1.5	(13.9)	[2]	3.4
Net current-period other comprehensive income (loss)	[1]	23.4	(8.1)	55.4		(18.6)
New Accounting Pronouncement or Change in Accounting Principle, Cumulative Effect of Change on Equity or Net Assets	[1]						$ (9.5)
Ending Balance	[1]	2.5	(43.7)	2.5		(43.7)
Gains and Losses on Securities
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance	[1]	(2.2)	0.4	0.2		(0.6)
Other Comprehensive Income before reclassifications	[1]	0	0.1	(2.5)		1.1
Amounts reclassified from accumulated other comprehensive loss	[1]	0.1	0	0.2	[2]	0
Net current-period other comprehensive income (loss)	[1]	0.1	0.1	(2.3)		1.1
New Accounting Pronouncement or Change in Accounting Principle, Cumulative Effect of Change on Equity or Net Assets	[1]						0
Ending Balance	[1]	(2.1)	0.5	(2.1)		0.5
Gains and Losses on Cash Flow Hedges
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance	[1]	(1.7)	(18.8)	(29.4)		(6.9)
Other Comprehensive Income before reclassifications	[1]	21.6	(9.7)	70.8		(23.3)
Amounts reclassified from accumulated other comprehensive loss	[1]	0.9	0.4	(14.3)	[2]	2.1
Net current-period other comprehensive income (loss)	[1]	22.5	(9.3)	56.5		(21.2)
New Accounting Pronouncement or Change in Accounting Principle, Cumulative Effect of Change on Equity or Net Assets	[1]						(6.3)
Ending Balance	[1]	20.8	(28.1)	20.8		(28.1)
Pension and OPEB Items
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance	[1]	(17)	(17.2)	(14.2)		(17.6)
Other Comprehensive Income before reclassifications	[1]	1	0	1		0.2
Amounts reclassified from accumulated other comprehensive loss	[1]	(0.2)	1.1	0.2	[2]	1.3
Net current-period other comprehensive income (loss)	[1]	0.8	1.1	1.2		1.5
New Accounting Pronouncement or Change in Accounting Principle, Cumulative Effect of Change on Equity or Net Assets	[1]						$ (3.2)
Ending Balance	[1]	$ (16.2)	$ (16.1)	$ (16.2)		$ (16.1)
[1]	All amounts are net of tax. Amounts in parentheses indicate debits.
[2]	Reclassification from accumulated other comprehensive loss for cash flow hedges relates primarily to the interest rate swap settlement gain. Refer to Note 8 "Risk Management Activities" for additional information.

Other, Net (Details)

Other, Net (Details) - USD ($) $ in Millions	3 Months Ended			9 Months Ended
	Sep. 30, 2018		Sep. 30, 2017	Sep. 30, 2018		Sep. 30, 2017
Other, Net [Abstract]
Interest Income	$ 1.4		$ 1.4	$ 4.2		$ 3.2
AFUDC Equity	5		4.3	12.6		10.5
Charitable Contributions	(11.1)		(0.8)	(13.9)		(3.5)
Pension and other postretirement non-service cost	2.4		(11.8)	14.7		(10.1)
Interest rate swap settlement gain	0	[1]	0	21.2	[1]	0	[1]
Miscellaneous	0.6		0.1	3.6		(0.4)
Other, net	$ (1.7)		$ (6.8)	$ 42.4		$ (0.3)
[1]	See Note 8, "Risk Management Activities," for additional information.

Business Segment Information (N

Business Segment Information (Narrative) (Details)	9 Months Ended
	Sep. 30, 2018
Segment Reporting [Abstract]
Primary business segments	2
Number of counties in which electric service provided by Electric Operations	20

Business Segment Information (S

Business Segment Information (Schedule Of Operating Income Derived From Revenues And Expenses By Segment) (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Segment Reporting Information [Line Items]
Regulated Operating Revenue	$ 895	$ 917	$ 3,652.8	$ 3,506.3
Revenues	895	917	3,652.8	3,506.3
Consolidated Operating Income (Loss)	(315.9)	111.2	203.1	650.6
Gas Distribution Operations
Segment Reporting Information [Line Items]
Regulated Operating Revenue	418.6		2,347.8
Revenues	421.9	434.6	2,357.6	2,150.5
Consolidated Operating Income (Loss)	(455.2)	(15.4)	(94.4)	367.1
Gas Distribution Operations | Unaffiliated
Segment Reporting Information [Line Items]
Revenues		431.1		2,139.9
Gas Distribution Operations | Intersegment
Segment Reporting Information [Line Items]
Revenues	3.3	3.5	9.8	10.6
Electric Operations
Segment Reporting Information [Line Items]
Regulated Operating Revenue	476.2		1,304.4
Revenues	476.4	486	1,305	1,366.1
Consolidated Operating Income (Loss)	134.9	125.1	300.4	288.3
Electric Operations | Unaffiliated
Segment Reporting Information [Line Items]
Revenues		485.8		1,365.5
Electric Operations | Intersegment
Segment Reporting Information [Line Items]
Revenues	0.2	0.2	0.6	0.6
Corporate and Other
Segment Reporting Information [Line Items]
Regulated Operating Revenue	0.2		0.6
Revenues	116.6	126.5	347.2	368.6
Consolidated Operating Income (Loss)	4.4	1.5	(2.9)	(4.8)
Corporate and Other | Unaffiliated
Segment Reporting Information [Line Items]
Revenues		0.1		0.9
Corporate and Other | Intersegment
Segment Reporting Information [Line Items]
Revenues	116.4	126.4	346.6	367.7
Eliminations
Segment Reporting Information [Line Items]
Revenues	$ (119.9)	$ (130.1)	$ (357)	$ (378.9)