NiSource (NI) 10-Q 2 May 18 2018 Q1 Quarterly report Financial data

Document And Entity Information

Document And Entity Information - shares	3 Months Ended
	Mar. 31, 2018	Apr. 24, 2018
Document Information [Line Items]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2018
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	Q1
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		337,737,392

Statements Of Consolidated Inco

Statements Of Consolidated Income - USD ($) shares in Thousands, $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Operating Revenues
Customer revenues	$ 1,717.2	$ 1,542.5
Other revenues	33.6	56.1
Total Operating Revenues	1,750.8	1,598.6
Operating Expenses
Cost of Sales (excluding depreciation and amortization)	724.4	552.3
Operation and maintenance	402.5	411.6
Depreciation and amortization	144.7	143.3
Gain on sale of assets	(0.3)	0
Other taxes	78.9	76
Total Operating Expenses	1,350.2	1,183.2
Operating Income	400.6	415.4
Other Income (Deductions)
Interest expense, net	(93.1)	(85.2)
Other, net	31.3	2.3
Total Other Deductions	(61.8)	(82.9)
Income before Income Taxes	338.8	332.5
Income Taxes	62.7	121.2
Net Income	$ 276.1	$ 211.3
Earnings Per Share
Basic Earnings Per Share	$ 0.82	$ 0.65
Diluted Earnings Per Share	0.81	0.65
Dividends Declared Per Common Share	$ 0.39	$ 0.35
Basic Average Common Shares Outstanding	338,012	323,681
Diluted Average Common Shares	338,991	325,306

Statements of Consolidated Comp

Statements of Consolidated Comprehensive Income - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2018	Mar. 31, 2017
Net Income		$ 276.1	$ 211.3
Other comprehensive income:
Net unrealized gain (loss) on available-for-sale securities	[1]	(1.7)	0.4
Net unrealized gain on cash flow hedges	[2]	35.4	4.9
Unrecognized pension and OPEB benefit	[3]	0.2	0.2
Total other comprehensive income	[4]	33.9	5.5
Comprehensive Income		$ 310	$ 216.8
[1]	Net unrealized gain (loss) on available-for-sale securities, net of $0.4 million tax benefit and $0.2 million tax expense in the first quarter of 2018 and 2017, respectively.
[2]	Net unrealized gain on cash flow hedges, net of $11.7 million and $3.0 million tax expense in the first quarter of 2018 and 2017, respectively.
[3]	Unrecognized pension and OPEB benefit, net of $0.1 million and $0.1 million tax expense in the first quarter of 2018 and 2017, respectively.
[4]	All amounts are net of tax. Amounts in parentheses indicate debits.

Statements of Consolidated Com4

Statements of Consolidated Comprehensive Income (Parenthetical) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Other Comprehensive Income (Loss), Unrealized Holding Gain (Loss) on Securities Arising During Period, Tax	$ (0.4)	$ 0.2
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Tax	11.7	3
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, Tax	$ (0.1)	$ (0.1)

Statements of Consolidated Bala

Statements of Consolidated Balance Sheets - USD ($) $ in Millions		Mar. 31, 2018	Dec. 31, 2017
Property, Plant and Equipment
Utility Plant		$ 21,374	$ 21,026.6
Accumulated depreciation and amortization		(7,048.1)	(6,953.6)
Net utility plant		14,325.9	14,073
Other property, at cost, less accumulated depreciation		130.7	286.5
Net Property, Plant and Equipment		14,456.6	14,359.5
Investments and Other Assets
Unconsolidated affiliates		5	5.5
Other investments		201.3	204.1
Total Investments and Other Assets		206.3	209.6
Current Assets
Cash and cash equivalents		35	29
Restricted Cash		9.7	9.4
Accounts receivable (less reserve of $28.0 and $18.3, respectively)		973.8	898.9
Gas inventory		71.9	285.1
Materials and supplies, at average cost		104.3	105.9
Electric production fuel, at average cost		69.1	80.1
Exchange gas receivable		53.6	45.8
Regulatory assets		160.9	176.3
Prepayments and other		155.5	132.8
Total Current Assets		1,633.8	1,763.3
Other Assets
Regulatory assets		1,784.2	1,624.9
Goodwill		1,690.7	1,690.7
Intangible assets		228.9	231.7
Deferred charges and other		98	82
Total Other Assets		3,801.8	3,629.3
Total Assets		20,098.5	19,961.7
Common Stockholders' Equity
Common stock - $0.01 par value, 400,000,000 shares authorized; 337,598,033 and 337,015,806 shares outstanding, respectively		3.4	3.4
Treasury stock		(99.5)	(95.9)
Additional paid-in capital		5,540.5	5,529.1
Retained deficit		(919.2)	(1,073.1)
Accumulated other comprehensive loss	[1]	(19)	(43.4)
Total Common Stockholders' Equity		4,506.2	4,320.1
Long-term debt, excluding amounts due within one year		7,286.8	7,512.2
Total Capitalization		11,793	11,832.3
Current Liabilities
Current portion of long-term debt		262.7	284.3
Short-term borrowings		1,567.3	1,205.7
Accounts payable		497.3	625.6
Dividends payable		65.8	0
Customer deposits and credits		154.7	262.6
Taxes accrued		212.8	208.1
Interest accrued		93.9	112.3
Derivative Instruments and Hedges, Liabilities		4.6	43.2
Exchange gas payable		11.5	59.6
Regulatory liabilities		97.3	58.7
Legal and environmental		33.6	32.1
Accrued compensation and employee benefits		115.2	195.4
Other accruals		109.5	90.8
Total Current Liabilities		3,226.2	3,178.4
Other Liabilities and Deferred Credits
Risk management liabilities		32.8	28.5
Deferred income taxes		1,384.8	1,292.9
Deferred investment tax credits		12.1	12.4
Accrued insurance liabilities		83.9	80.1
Accrued liability for postretirement and postemployment benefits		323.4	337.1
Regulatory liabilities		2,780.7	2,736.9
Asset retirement obligations		269.9	268.7
Other noncurrent liabilities		191.7	194.4
Total Other Liabilities and Deferred Credits		5,079.3	4,951
Commitments and Contingencies		0	0
Total Capitalization and Liabilities		$ 20,098.5	$ 19,961.7
[1]	All amounts are net of tax. Amounts in parentheses indicate debits.

Statements of Consolidated Bal6

Statements of Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Accounts receivable less reserve	$ 28	$ 18.3
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	400,000,000	400,000,000
Common Stock, Shares, Outstanding	337,598,033	337,015,806

Statements Of Consolidated Cash

Statements Of Consolidated Cash Flows - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Operating Activities
Net Income	$ 276.1	$ 211.3
Adjustments to Reconcile Net Income to Net Cash from Continuing Operations:
Depreciation and amortization	144.7	143.3
Deferred income taxes and investment tax credits	56.8	109.4
Other adjustments	(15.6)	11
Changes in Assets and Liabilities:
Components of working capital	(178.4)	(117.5)
Regulatory assets/liabilities	117.1	69.3
Deferred charges and other noncurrent assets	1.9	(1.2)
Other noncurrent liabilities	(14.4)	(14.5)
Net Cash Flows from Operating Activities	388.2	411.1
Investing Activities
Capital expenditures	(370)	(312)
Cost of removal	(19)	(31.4)
Other investing activities	(9.9)	0.4
Net Cash Flows used for Investing Activities	(398.9)	(343)
Financing Activities
Repayments of long-term debt and capital lease obligations	(279)	(36.6)
Change in short-term borrowings, net	361.6	26.2
Issuance of common stock	3.7	6.4
Acquisition of treasury stock	(3.6)	(4.4)
Dividends paid - common stock	(65.7)	(56.5)
Net Cash Flows from Financing Activities	17	(64.9)
Change in cash, cash equivalents and restricted cash	6.3	3.2
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	38.4	36
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	$ 44.7	$ 39.2

Statements Of Consolidated Cas8

Statements Of Consolidated Cash Flows (Supplemental Disclosures of Cash Flow Information) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2018	Mar. 31, 2017
Supplemental Cash Flow [Abstract]
Capital expenditures included in current liabilities		$ 145.4	$ 133.9
Dividends declared but not paid		65.8	56.7
Reclassification of other property to regulatory assets	[1]	$ 142.3	$ 0
[1]	See Note 16-D "Other Matters" for additional information.

Statements Of Consolidated Equi

Statements Of Consolidated Equity - USD ($) $ in Millions	Total	Common Stock	Treasury Stock	Additional Paid-in Capital	Retained Deficit	Accumulated Other Comprehensive Loss
Cumulative Effect of New Accounting Principle in Period of Adoption	$ 0	$ 0	$ 0	$ 0		$ (9.5)
Cumulative Effect of New Accounting Principle in Period of Adoption | Accounting Standards Update 2018-02					$ 9.5
Balance as of January 1, 2017 at Dec. 31, 2017	4,320.1	3.4	(95.9)	5,529.1	(1,073.1)	(43.4)
Net Income	276.1	0	0	0	276.1	0
Other comprehensive income, net of tax	33.9	0	0	0	0	33.9
Common stock dividends ($0.39 per share)	(131.7)	0	0	0	(131.7)	0
Treasury stock acquired	(3.6)	0	(3.6)	0	0	0
Stock Issuances:
Employee stock purchase plan	1.2	0	0	1.2	0	0
Long-term incentive plan	4	0	0	4	0	0
401(k) and profit sharing	6.2	0	0	6.2	0	0
Balance as of March 31, 2018 at Mar. 31, 2018	$ 4,506.2	$ 3.4	$ (99.5)	$ 5,540.5	$ (919.2)	$ (19)

Statements of Consolidated Eq10

Statements of Consolidated Equity (Shares) (Parenthetical) shares in Thousands	3 Months Ended
	Mar. 31, 2018shares
Balance as of January 1, 2018	337,016
Treasury Stock acquired	(149)
Issued:
Employee stock purchase plan	47
Long-term incentive plan	420
401(k) and profit sharing	264
Balance as of March 31, 2018	337,598
Common Stock
Balance as of January 1, 2018	340,813
Issued:
Employee stock purchase plan	47
Long-term incentive plan	420
401(k) and profit sharing	264
Balance as of March 31, 2018	341,544
Treasury Stock
Balance as of January 1, 2018	(3,797)
Treasury Stock acquired	(149)
Issued:
Employee stock purchase plan	0
Long-term incentive plan	0
401(k) and profit sharing	0
Balance as of March 31, 2018	3,946

Statements Of Consolidated Eq11

Statements Of Consolidated Equity (Parenthetical) - $ / shares	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Dividends Declared Per Common Share	$ 0.39	$ 0.35

Basis of Accounting Presentatio

Basis of Accounting Presentation	3 Months Ended
	Mar. 31, 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	3 Months Ended
	Mar. 31, 2018
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
New Accounting Pronouncements and Changes in Accounting Principles	Recent Accounting Pronouncements Recently Issued Accounting Pronouncements We are currently evaluating the impact of certain ASUs on our Condensed Consolidated Financial Statements (unaudited) and Notes to Condensed Consolidated Financial Statements (unaudited), which are described below: Standard Description Effective Date Effect on the financial statements or other significant matters ASU 2016-13, Financial Instruments-Credit Losses (Topic 326) The pronouncement changes the impairment model for most financial assets, replacing the current "incurred loss" model. ASU 2016-13 will require the use of an "expected loss" model for instruments measured at amortized cost. It will also require entities to record allowances for available-for-sale debt securities rather than impair the carrying amount of the securities. Subsequent improvements to the estimated credit losses of available-for-sale securities will be recognized immediately in earnings instead of over time as they are under historic guidance. Annual periods beginning after December 15, 2019, including interim periods therein. Early adoption is permitted for annual or interim periods beginning after December 15, 2018. We maintain investments in U.S. Treasury, corporate and mortgage-backed debt securities which are pledged as collateral for trust accounts related to our wholly-owned insurance company. These debt securities are classified as available for sale. We are currently evaluating the impact of adoption, if any, on our Condensed Consolidated Financial Statements (unaudited) and Notes to Condensed Consolidated Financial Statements (unaudited). ASU 2018-01, 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. Annual periods beginning after December 15, 2018, including interim periods therein. Early adoption is permitted. We formed an internal stakeholder group that meets periodically to share information and gather data related to our leasing activity. This includes compiling a list of all contracts that could meet the definition of a lease and evaluating the accounting for these contracts under the new standard to determine the ultimate impact the new standards will have on our financial statements. This procedure has identified process improvements to ensure data from newly initiated leases is captured to comply with the new standard. This work included the assistance of a third-party advisory firm. In addition, we are implementing a new lease accounting system, which we will utilize to capture, track, and record lease data. We maintain a substantial number of easements and expect ASU 2018-01 will ease the process of implementing ASC 842. We continue to monitor both FASB and industry updates related to the new leasing standards and intend to adopt these standards effective January 1, 2019. ASU 2016-02, Leases (Topic 842) The pronouncement introduces a lessee model that brings most leases on the balance sheet. The standard requires that lessees recognize the following for all leases (with the exception of short-term leases, as that term is defined in the standard) at the lease commencement date: (1) a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and (2) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. Recently Adopted Accounting Pronouncements Standard Adoption ASU 2018-02, Income Statement—Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income We elected to adopt this ASU effective March 31, 2018. Upon adoption, $9.5 million of tax effects that were stranded in accumulated other comprehensive loss as a result of the implementation of the TCJA have been 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) are now presented separately within "Other, net" on our Condensed Statements of Consolidated Income (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	3 Months Ended
	Mar. 31, 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 months ended March 31, 2018 as if they had been prepared under historic accounting guidance. We included operating revenue information for the three months ended March 31, 2017 for comparability. Three Months Ended (in millions) 2018 2017 Operating Revenues Gas Distribution $ 983.8 $ 836.5 Gas Transportation 342.2 338.6 Electric 423.3 421.7 Other 1.5 1.8 Total Operating Revenues $ 1,750.8 $ 1,598.6 Beginning in 2018 with the adoption of ASC 606, the Condensed Statements of Consolidated Income (unaudited) disaggregates “Customer revenues” (i.e. ASC 606 Revenues) from “Other revenues,” 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 (unaudited): Three Months Ended March 31, 2018 ( in millions) Gas Distribution Operations Electric Operations Corporate and Other Total Customer Revenues (1) Residential $ 893.6 $ 114.5 $ — $ 1,008.1 Commercial 308.3 116.9 — 425.2 Industrial 74.6 162.5 — 237.1 Off-system 22.3 — — 22.3 Miscellaneous 16.8 7.5 0.2 24.5 Total Customer Revenues $ 1,315.6 $ 401.4 $ 0.2 $ 1,717.2 Other Revenues 11.7 21.9 — 33.6 Total Operating Revenues $ 1,327.3 $ 423.3 $ 0.2 $ 1,750.8 (1) Customer revenue amounts exclude intersegment revenues. See Note 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 date through the last day of the month (balance sheet date). Factors taken into consideration when estimating unbilled revenue include historical usage, customer rates and weather. The opening and closing balances of customer receivables for the quarter ended March 31, 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 March 31, 2018 617.2 274.6 Increase (Decrease) $ 140.2 $ (81.4 ) (1) Customer billed receivables increased over the period due to the seasonal increase in customer usage during peak winter usage months. (2) Customer unbilled receivables decreased over the period due to the expected seasonal decrease in customer usage in March 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 (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	3 Months Ended
	Mar. 31, 2018
Earnings Per Share [Abstract]
Earnings Per Share	Earnings Per Share Basic EPS is computed by dividing net income by the weighted-average number of shares of common stock outstanding for the period. The weighted-average shares outstanding for diluted EPS includes the incremental effects of the various long-term incentive compensation plans. The calculation of diluted earnings per share excludes the impact of forward agreements (see Note 5, "Common Stock"), which had an anti-dilutive effect for the periods outstanding. The computation of diluted average common shares is as follows: Three Months Ended March 31, (in thousands) 2018 2017 Denominator Basic average common shares outstanding 338,012 323,681 Dilutive potential common shares: Shares contingently issuable under employee stock plans 715 360 Shares restricted under employee stock plans 264 1,265 Diluted Average Common Shares 338,991 325,306

Common Stock

Common Stock	3 Months Ended
	Mar. 31, 2018
Common Stock [Abstract]
Common Stock	Common Stock 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 March 31, 2018 , the ATM program (including impacts of forward sales agreements discussed below) had approximately $10.0 million of equity available for issuance. The program expires on December 31, 2018. On November 13, 2017, under the ATM program, we executed a forward agreement, which allows us to issue a fixed number of shares at a price to be settled in the future. From November 13, 2017 to December 8, 2017, 6,345,860 shares were borrowed from third parties and sold by the dealer at a weighted average price of $27.24 per share. We may settle this agreement in shares, cash, or net shares by November 12, 2018. Had we settled all 6,345,860 shares under the forward agreement at March 31, 2018, we would have received approximately $170.3 million , based on a net price of $26.83 per share.

Gas in Storage

Gas in Storage	3 Months Ended
	Mar. 31, 2018
Gas in Storage [Abstract]
Inventory Disclosure [Text Block]	Gas in Storage We use both the LIFO inventory methodology and the weighted-average cost methodology to value natural gas in storage. Gas Distribution Operations prices natural gas storage injections at the average of the costs of natural gas supply purchased during the year. For interim periods, the difference between current projected replacement cost and the LIFO cost for quantities of gas temporarily withdrawn from storage is recorded as a temporary LIFO liquidation credit or debit within the Condensed Consolidated Balance Sheets (unaudited). Due to seasonality requirements, we expect interim variances in LIFO layers to be replenished by year end. We had a temporary LIFO liquidation debit of $20.9 million and zero as of March 31, 2018 and December 31, 2017 , respectively, for certain gas distribution companies recorded within “Prepayments and other,” on the Condensed Consolidated Balance Sheets (unaudited).

Regulatory Matters

Regulatory Matters	3 Months Ended
	Mar. 31, 2018
Regulatory Assets and Liabilities Disclosure [Abstract]
Regulatory Matters	Regulatory Matters Gas Distribution Operations Regulatory Matters Cost Recovery and Trackers. Comparability of Gas Distribution Operations line item operating results is impacted by regulatory trackers that allow for the recovery in rates of certain costs such as those described below. Increases in the expenses that are the subject of trackers generally result in a corresponding increase in operating revenues and therefore have essentially no impact on total operating income results. Certain operating costs of our distribution companies are significant, recurring in nature, and generally outside the control of the distribution companies. Some states allow the recovery of such costs through cost tracking mechanisms. Such tracking mechanisms allow for abbreviated regulatory proceedings in order for the distribution companies to implement charges and recover appropriate costs. Tracking mechanisms allow for more timely recovery of such costs as compared with more traditional cost recovery mechanisms. Examples of such mechanisms include GCR adjustment mechanisms, tax riders, and bad debt recovery mechanisms. A portion of the distribution companies' revenue is related to the recovery of gas costs, the review and recovery of which occurs through standard regulatory proceedings. All states in our operating area require periodic review of actual gas procurement activity to determine prudence and to permit the recovery of prudently incurred costs related to the supply of gas for customers. Our distribution companies have historically been found prudent in the procurement of gas supplies to serve customers. Certain of our distribution companies have completed rate proceedings involving infrastructure replacement or are embarking upon regulatory initiatives to replace significant portions of their operating systems that are nearing the end of their useful lives. Each LDC's approach to cost recovery may be unique, given the different laws, regulations and precedent that exist in each jurisdiction. Columbia of Ohio. On January 10, 2018, the PUCO issued an entry to investigate the impacts of the TCJA including an invitation to utilities and other interested stakeholders to file public comments including: (1) those components of utility rates that the PUCO will need to reconcile with the TCJA; and (2) the process and mechanics for how the PUCO should do so. The PUCO also directed utilities to record a regulatory liability for the estimated reduction in federal income tax resulting from the TCJA. On February 15, 2018, Columbia of Ohio filed comments proposing to: (1) reflect the impact of the TCJA on its application to adjust rates associated with its IRP rider, subsequently filed on February 27, 2018; and (2) file a reduction in other base rates no later than October 15, 2018 reflecting the impact of the TCJA. The matter is awaiting PUCO action. 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 has filed an application for rehearing, which was granted by the PUCO on March 28, 2018. The matter is awaiting PUCO action. 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. The order allows recovery to begin on approximately $207 million of infrastructure investments made in 2017. 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 $29 million in 2018, with biennial increases up to approximately $98 million in 2022. On April 18, 2018, the PUCO issued an entry directing commission staff to issue a request for proposal for audit services to assist the PUCO with the review of the accounting accuracy, prudency and compliance of Columbia of Ohio with its Commission-approved CEP. The audit of the CEP is expected to be completed in the second half of 2018 at which point a full procedural schedule will be established. NIPSCO Gas. On January 3, 2018, the IURC initiated an investigation to review and consider the possible implications of the TCJA on utility rates. The Commission ordered a two phase investigation. Phase 1 solely dealt with the prospective changes in rates to reflect the change in tax rates. In accordance with the procedural schedule, on March 26, 2018, NIPSCO filed revised gas tariffs reflecting the impact of the change in tax rate for its applicable rates and charges. The IURC approved NIPSCO's Phase 1 filing on April 26, 2018. The revised tariffs are effective May 1, 2018. The stipulation and settlement agreement filed on April 20, 2018, in NIPSCO’s gas rate case resolved all issues in Phase 2. On September 27, 2017, NIPSCO filed a base rate case with the IURC, seeking an annual revenue increase of $143.5 million (inclusive of amounts being recovered through various tracker programs). As part of this filing and among other items, NIPSCO proposed to update base rates for ongoing infrastructure improvements, revised depreciation rates and ongoing level of expenses to reflect the current costs of providing natural gas service. NIPSCO submitted a rebuttal on March 28, 2018 updating its request, including the impact of the TCJA, seeking a revised annual revenue increase of $138.1 million . On April 20, 2018, a settlement agreement was filed with the IURC seeking, among other items, an annual revenue increase of $107.3 million . An order from the IURC is expected in the second half of 2018. On April 30, 2013, then Indiana Governor Pence 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 February 27, 2018, NIPSCO filed TDSIC-8 requesting to recover an incremental increase to revenue of $0.8 million associated with incremental capital investment of $77.9 million made in the second half of 2017. An IURC order is expected in the second quarter of 2018, with new rates effective in July. On April 2, 2018, NIPSCO filed a new seven-year gas TDSIC plan with the IURC beginning in 2019. The filing seeks approval of a total capital expenditure level of approximately $1.25 billion . An IURC order is expected in the second half of 2018. On November 8, 2017, NIPSCO filed a petition with the IURC seeking approval of NIPSCO’s federally mandated pipeline safety compliance plan. As part of the aforementioned settlement agreement filed in NIPSCO’s gas base rate case proceeding, NIPSCO and the parties to the settlement agreement settled all issues in this proceeding as well, including moving certain costs from the base rate proceeding to this pipeline safety compliance plan. The updated four year compliance plan includes a total estimated $91.5 million of capital costs and $35.5 million of expected operating and maintenance costs. NIPSCO is requesting all associated accounting and ratemaking relief, including establishment of a periodic rate adjustment mechanism. An IURC order is expected in the second half 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 are 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. 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 change in operating revenues of $24.1 million . Included in the filing is a proposal to adjust rates and address the regulatory liability disposition related to the TCJA. Rates are expected to go into effect March 1, 2019, upon approval from the Massachusetts DPU. On July 7, 2014, the Governor of Massachusetts signed into law Chapter 149 of the Acts of 2014, An Act Relative to Natural Gas Leaks (“the Act”). The Act authorizes natural gas distribution companies to file gas infrastructure replacement plans with the Massachusetts DPU to address the replacement of aging natural gas pipeline infrastructure. In addition, the Act provides that the Massachusetts DPU may, after review of the plans, allow the proposed estimated costs of the plan into rates as of May 1 of the subsequent year. On October 31, 2017, Columbia of Massachusetts filed its GSEP for the 2018 construction year. Columbia of Massachusetts proposed to recover incremental revenue of $9.7 million associated with incremental capital investment of $83.9 million to be made during calendar year 2018. The filing included a request for approval of an alternative calculation or a waiver to allow collection of the $3.1 million revenue requirement that exceeds the GSEP cap provision as previously calculated. On January 29, 2018 Columbia of Massachusetts filed a revision to its GSEP tracker for the 2018 construction season reducing the proposed revenue requirement to reflect the impact of the TCJA. The revenue requirement was reduced by $2.4 million due to the TCJA. An order was received from the Massachusetts DPU on April 30, 2018, approving an incremental revenue requirement of $6.1 million associated with the incremental capital investment of $83.9 million , with new rates effective May 1, 2018. The order did not approve the alternative cap calculation and the portion of the revenue requirement that exceeds the GSEP cap provision. Columbia of Pennsylvania. On February 12, 2018, the Pennsylvania PUC established a docket to investigate the impact of the TCJA on customer rates. The Pennsylvania PUC directed Pennsylvania utilities to account for any revenues associated with the difference between previous and current income tax rates and excess deferred income taxes as regulatory liabilities effective January 1, 2018. On March 15, 2018, the Pennsylvania PUC issued an order declaring jurisdictional utilities’ rates to be temporary, unless currently in the midst of a general rate proceeding, while it investigates whether pre-TCJA rates are just and reasonable. On March 16, 2018, Columbia of Pennsylvania filed a rate case with the Pennsylvania PUC, seeking approval for an annual revenue increase of $46.9 million . Included in the filing is a proposal to adjust rates as a result of the TCJA. On March 21, 2018, Columbia of Pennsylvania filed a supplement to the rate case, under which it proposes to hold the overcollection of taxes during 2018 until the effective date of new base rates as credit to rate base for a period beginning January 2019 not to exceed three years. A decision on Columbia of Pennsylvania’s request is expected in the fourth quarter of 2018 with new rates to be implemented in December 2018. Columbia of Virginia. On January 8, 2018, the VSCC issued an order regarding the TCJA requiring Columbia of Virginia and other Virginia utilities subject to the TCJA to accrue regulatory liabilities reflecting the impacts of the reduced corporate income tax rate effective January 1, 2018. In addition, pursuant to the order, Columbia of Virginia is required to reflect the impacts of the TCJA in its annual informational filing, including: (1) the expected cost of service impacts through calendar year 2018; (2) the amount of protected and unprotected excess accumulated deferred income taxes as of December 31, 2017, and the estimated reversal of such excess deferred income taxes during calendar year 2018; and (3) such additional information that the utility wishes to include addressing the financial and cost of service impacts of the TCJA and the appropriate treatment of the accrued regulatory liabilities. On April 25, 2018 the VSCC, by order, supplemented the above annual informational filing requirements of the January 8, 2018 order to include a proposed rate reduction that reflects the cost savings from the TCJA. This April 25, 2018 order directs that if a utility desires to propose an alternative method for returning the tax savings to customers, then it may instead file a rate case that incorporates the income tax savings. On April 25, 2018 the VSCC issued a separate order extending Columbia of Virginia’s annual informational filing due date to August 28, 2018. Columbia of Kentucky. On January 26, 2018, in accordance with the Kentucky PSC investigation related to the TCJA, Columbia of Kentucky filed testimony and proposed a reduction to base rates effective May 1, 2018, to reflect the tax expense reduction as a result of the TCJA. Columbia of Kentucky was directed to account for any revenues associated with the difference between previous and current income tax rates and excess deferred income taxes as regulatory liabilities effective January 1, 2018. Columbia of Kentucky proposed to include the impact of the excess deferred taxes in rates effective October 2018 and to return the revenue related to the regulatory liability subsequent to this date. On April 30, 2018 Columbia of Kentucky received an order from the Kentucky PSC requiring implementation of interim proposed rates that are subject to future adjustment effective May 1, 2018. The order directs Columbia of Kentucky to file by September 1, 2018 revised tax act adjustment factors reflecting the tax expense savings from January 1, 2018, through April 30, 2018, and an actual or estimate of the annual reduction due to the excess deferred accumulated taxes to be effective with the first billing cycle of October 2018. Columbia of Maryland. On February 13, 2018, Columbia of Maryland filed a proposal with the Maryland PSC to reduce rates as a result of TCJA with an annual revenue decrease of $1.3 million . Columbia of Maryland was directed to account for any revenues associated with the difference between previous and current income tax rates and excess deferred income taxes as regulatory liabilities effective January 1, 2018. On March 14, 2018, Columbia of Maryland received approval, effective April 2, 2018, to implement new rates and pass-back the overcollection of taxes from the first quarter of 2018. On April 13, 2018, Columbia of Maryland filed a request with the Maryland PSC to adjust base rates. If approved as filed, the rate adjustment would result in an annual revenue increase of $6.0 million . An order is expected in the fourth quarter of 2018 with new rates effective in November 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 possible implications of the TCJA on utility rates. The commission ordered a two phase investigation. Phase 1 solely dealt with the prospective changes in rates to reflect the change in tax rates. In accordance with the procedural schedule, on March 26, 2018, NIPSCO filed revised 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 are effective May 1, 2018. Phase 2 will be started with an attorneys conference on May 3, 2018, and is intended to address all other issues arising from the TCJA. The impact on NIPSCO electric of the Phase 2 investigation is unknown at this time. 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. However, the proposed TDSIC-2 rates revised for tax reform filed on March 26, 2018 represent an approximate decrease in revenue of $1.2 million from January through May 2018. An order approving the request is expected in May 2018 with new rates expected to go into effect with the first billing cycle of June 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, which should be completed with 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 MVP projects. Material Updates to Regulatory Assets and Liabilities Since December 31, 2017 TCJA-Related Regulatory Liabilities. As referenced above, during the first quarter of 2018, we recorded additional TCJA-related regulatory liabilities of $49.7 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 income taxes which resulted in a $10.4 million income tax benefit for the three months ended March 31, 2018. Related to this activity, we recorded an offsetting reserve of $7.7 million (net of tax) in "Customer revenues" to reflect the probable future passback of this earnings benefit to customers. 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 March 31, 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). These amounts continue to be amortized at a rate consistent with their inclusion in customer rates. NIPSCO expects to complete the retirement of Units 7 and 8 by May 31, 2018. Refer to Note 16 -D, "Other Matters," in the Notes to Condensed Consolidated Financial Statements (unaudited) for information.

Risk Management Activities

Risk Management Activities	3 Months Ended
	Mar. 31, 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) March 31, 2018 December 31, 2017 Risk Management Assets - Current (1) Interest rate risk programs $ 9.4 $ 14.0 Commodity price risk programs 0.4 0.5 Total $ 9.8 $ 14.5 Risk Management Assets - Noncurrent (2) Interest rate risk programs $ 18.6 $ 5.6 Commodity price risk programs 2.8 1.0 Total $ 21.4 $ 6.6 Risk Management Liabilities - Current Interest rate risk programs $ — $ 38.6 Commodity price risk programs 4.6 4.6 Total $ 4.6 $ 43.2 Risk Management Liabilities - Noncurrent Interest rate risk programs $ — $ — Commodity price risk programs 32.8 28.5 Total $ 32.8 $ 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 March 31, 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." During the three months ended March 31, 2018 , we initiated settlement of forward-starting interest rate swaps with a notional value of $250.0 million . These derivative contracts were accounted for as cash flow hedges. As part of the transaction, the associated net unrealized gain position of $21.2 million was recognized immediately in "Other, net" on the Condensed Statements of Consolidated Income (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 March 31, 2018 and December 31, 2017 . Our derivative instruments measured at fair value as of March 31, 2018 and December 31, 2017 do not contain any credit-risk-related contingent features.

Fair Value

Fair Value	3 Months Ended
	Mar. 31, 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 March 31, 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 March 31, 2018 Assets Risk management assets $ — $ 31.0 $ 0.2 $ 31.2 Available-for-sale securities — 132.5 — 132.5 Total $ — $ 163.5 $ 0.2 $ 163.7 Liabilities Risk management liabilities $ — $ 37.4 $ — $ 37.4 Total $ — $ 37.4 $ — $ 37.4 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 March 31, 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 March 31, 2018 and December 31, 2017 were: March 31, 2018 (in millions) Amortized Cost Gross Unrealized Gains Gross Unrealized Losses Fair Value Available-for-sale securities U.S. Treasury debt securities $ 22.3 $ — $ (0.1 ) $ 22.2 Corporate/Other debt securities 112.2 0.3 (2.2 ) 110.3 Total $ 134.5 $ 0.3 $ (2.3 ) $ 132.5 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 months ended March 31, 2018 and 2017 . The cost of maturities sold is based upon specific identification. At March 31, 2018 , approximately $7.7 million of U.S. Treasury debt securities and approximately $1.6 million of Corporate/Other debt securities have maturities of less than a year. There are no material items in the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis for the three months ended March 31, 2018 and 2017 . Non-recurring Fair Value Measurements. There were no significant non-recurring fair value measurements recorded during the three months ended March 31, 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 three months ended March 31, 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) $ 7,549.5 $ 7,862.3 $ 7,796.5 $ 8,603.4

Transfers Of Financial Assets

Transfers Of Financial Assets	3 Months Ended
	Mar. 31, 2018
Transfers and Servicing [Abstract]
Transfers Of Financial Assets	Transfers of Financial Assets Columbia of Ohio, NIPSCO and Columbia of Pennsylvania each maintain a receivables agreement whereby they transfer their customer accounts receivables to third party financial institutions through wholly-owned and consolidated special purpose entities. The three agreements expire between August 2018 and March 2019 and may be further extended if mutually agreed to by the parties thereto. All receivables transferred to third parties are valued at face value, which approximates fair value due to their short-term nature. The amount of the undivided percentage ownership interest in the accounts receivables transferred is determined in part by required loss reserves under the agreements. Transfers of accounts receivable are accounted for as secured borrowings resulting in the recognition of short-term borrowings on the Condensed Consolidated Balance Sheets (unaudited). As of March 31, 2018 , the maximum amount of debt that could be recognized related to our accounts receivable programs is $540.0 million . The following table reflects the gross receivables balance and net receivables transferred as well as short-term borrowings related to the securitization transactions as of March 31, 2018 and December 31, 2017 : (in millions) March 31, 2018 December 31, 2017 Gross Receivables $ 683.4 $ 635.3 Less: Receivables not transferred 170.0 298.6 Net receivables transferred $ 513.4 $ 336.7 Short-term debt due to asset securitization $ 513.4 $ 336.7 For the three months ended March 31, 2018 and 2017, $176.7 million and $129.0 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 $0.8 million and $0.7 million for the three months ended March 31, 2018 and 2017, respectively. We remain responsible for collecting on the receivables securitized and the receivables cannot be transferred to another party.

Goodwill

Goodwill	3 Months Ended
	Mar. 31, 2018
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill	Goodwill The following presents our goodwill balance allocated by segment as of March 31, 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, 2017. 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 its 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.

Income Taxes

Income Taxes	3 Months Ended
	Mar. 31, 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 three months ended March 31, 2018 and 2017 were 18.5% and 36.5% , respectively. These effective tax rates differ from the Federal statutory tax rate of 21% , in 2018, and 35% , in 2017, primarily due to the effects of tax credits, state income taxes, utility ratemaking, and other permanent book-to-tax differences. The decrease in the three month effective tax rate in 2018 versus the same period in 2017 is primarily due to the change in the Federal statutory rate due to the enactment of the TCJA. Additionally, in 2018 we began amortizing a portion of our regulatory liability associated with excess deferred taxes which resulted in a current year income tax benefit of $10.4 million . 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	3 Months Ended
	Mar. 31, 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 three months ended March 31, 2018 , we contributed $0.7 million to our pension plans and $5.5 million to our other postretirement benefit plans. The following table provides the components of the plans’ actuarially determined net periodic benefit (income) cost for the three months ended March 31, 2018 and 2017 : Pension Benefits Other Postretirement Benefits Three Months Ended March 31, (in millions) 2018 2017 2018 2017 Components of Net Periodic Benefit (Income) Cost (1) Service cost $ 7.9 $ 7.5 $ 1.3 $ 1.2 Interest cost 16.6 17.2 4.4 4.5 Expected return on assets (36.3 ) (30.3 ) (3.7 ) (4.0 ) Amortization of prior service credit (0.1 ) (0.2 ) (1.0 ) (1.1 ) Recognized actuarial loss 10.2 13.4 0.9 0.8 Total Net Periodic Benefit (Income) Cost $ (1.7 ) $ 7.6 $ 1.9 $ 1.4 (1) The service cost component, and all non-service cost components, of net periodic benefit (income) cost are presented in "Operation and maintenance" and "Other, net", respectively, on the Condensed Statements of Consolidated Income (unaudited).

Long-Term Debt

Long-Term Debt	3 Months Ended
	Mar. 31, 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.

Short-Term Borrowings

Short-Term Borrowings	3 Months Ended
	Mar. 31, 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 and accounts receivable transfer programs. 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 March 31, 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. As of March 31, 2018 and December 31, 2017 , we had commercial paper outstanding of $1,053.9 million and $869.0 million , respectively. As of March 31, 2018 and December 31, 2017 , we had $10.7 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) in the amount of $513.4 million and $336.7 million as of March 31, 2018 and December 31, 2017 , respectively. Refer to Note 10 , "Transfers of Financial Assets," for additional information. Short-term borrowings were as follows: (in millions) March 31, December 31, Commercial Paper weighted-average interest rate of 2.51% and 1.97% at March 31, 2018 and December 31, 2017, respectively $ 1,053.9 $ 869.0 Accounts receivable securitization facility borrowings 513.4 336.7 Total Short-Term Borrowings $ 1,567.3 $ 1,205.7 Given their maturities are less than 90 days, 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). On April 18, 2018, we entered into a multiple-draw $600.0 million term loan agreement with a syndicate of banks. 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 elect at the time of each borrowing. The available variable rate structures from which NiSource may choose are defined in the term loan agreement. Under the agreement, we borrowed an initial tranche of $150.0 million on April 18, 2018 with an interest rate of LIBOR plus fifty basis points and may borrow a second tranche up to $450.0 million at any time prior to June 15, 2018.

Other Commitments And Contingen

Other Commitments And Contingencies	3 Months Ended
	Mar. 31, 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 March 31, 2018 and December 31, 2017, we had issued stand-by letters of credit of $10.7 million and $11.1 million , respectively. B. Legal Proceedings. We are party to certain claims and legal proceedings arising in the ordinary course of business, none of which is deemed to be individually material at this time. Due to the inherent uncertainty of litigation, there can be no assurance that the resolution of any particular claim or proceeding would not have a material adverse effect on our results of operations, financial position or liquidity. If one or more of such matters were decided against us, the effects could be material to our results of operations in the period in which we would be required to record or adjust the related liability and could also be material to our cash flows in the periods that we would be required to pay such liability. C. Environmental Matters. Our operations are subject to environmental statutes and regulations related to air quality, water quality, hazardous waste and solid waste. We believe that we are in substantial compliance with the environmental regulations currently applicable to our operations. It is management's continued intent to address environmental issues in cooperation with regulatory authorities in such a manner as to achieve mutually acceptable compliance plans. However, there can be no assurance that fines and penalties will not be incurred. Management expects a significant portion of environmental assessment and remediation costs to be recoverable through rates for certain of our companies. As of March 31, 2018 and December 31, 2017 , we had recorded a liability of approximately $109.9 million and $111.4 million , respectively, to cover environmental remediation at various sites. The current portion of this liability is included in "Legal and environmental" in the Condensed Consolidated Balance Sheets (unaudited). The noncurrent portion is included in "Other noncurrent liabilities" in the Condensed Consolidated Balance Sheets (unaudited). We recognize costs associated with environmental remediation obligations when the incurrence of such costs is probable and the amounts can be reasonably estimated. The original estimates for remediation activities may differ materially from the amount ultimately expended. The actual future expenditures depend on many factors, including currently enacted laws and regulations, the nature and extent of impact and the method of remediation. These expenditures are not currently estimable at some sites. We periodically adjust our liability as information is collected and estimates become more refined. Electric Operations' compliance estimates disclosed below are reflective of NIPSCO's Integrated Resource Plan submitted to the IURC on November 1, 2016. See section D , "Other Matters," below for additional information. Air The actions listed below could require further reductions in emissions from various emission sources. We will continue to closely monitor developments in these matters. Future legislative and regulatory programs could significantly limit allowed GHG emissions or impose a cost or tax on GHG emissions. Additionally, rules that increase methane leak detection, require emission reductions or impose additional requirements for natural gas facilities could restrict GHG emissions and impose additional costs. We carefully monitor all GHG reduction proposals and regulations. Clean Power Plan. On October 23, 2015, the EPA issued a final rule to regulate CO2 emissions from existing fossil-fuel EGUs under section 111(d) of the CAA. The final rule establishes national CO2 emission-rate standards that are applied to each state’s mix of affected EGUs to establish state-specific emission-rate and mass-emission limits. The final rule requires each state to submit a plan indicating how the state will meet the EPA's emission-rate or mass-emission limit, including possibly imposing reduction obligations on specific units. If a state does not submit a satisfactory plan, the EPA will impose a federal plan on that state. On February 9, 2016, the U.S. Supreme Court stayed implementation of the CPP until litigation is decided on its merits. On October 16, 2017, the EPA published in the Federal Register a Notice of Proposed Rulemaking that would repeal the CPP. On December 28, 2017, in a separate but related action, the EPA published an Advanced Notice of Proposed Rulemaking in the Federal Register to solicit information from the public about a potential future rulemaking to limit greenhouse gas emissions from existing fossil-fuel EGUs. NIPSCO will continue to monitor this matter and cannot estimate its impact at this time. Should costs be incurred to comply with the CPP, NIPSCO believes such costs will be eligible for recovery through customer rates. Waste CERCLA. Our subsidiaries are potentially responsible parties at waste disposal sites under the CERCLA (commonly known as Superfund) and similar state laws. Under CERCLA, each potentially responsible party can be held jointly, severally and strictly liable for the remediation costs as the EPA, or state, can allow the parties to pay for remedial action or perform remedial action themselves and request reimbursement from the potentially responsible parties. Our affiliates have retained CERCLA environmental liabilities, including remediation liabilities, associated with certain current and former operations. These liabilities are not material to the Condensed Consolidated Financial Statements ( unaudited ). MGP. A program has been instituted to identify and investigate former MGP sites where Gas Distribution Operations subsidiaries or predecessors may have liability. The program has identified 64 such sites where liability is probable. Remedial actions at many of these sites are being overseen by state or federal environmental agencies through consent agreements or voluntary remediation agreements. We utilize a probabilistic model to estimate future remediation costs related to our MGP sites. The model was prepared with the assistance of a third party and incorporates our experience and general industry experience with remediating MGP sites. We complete an annual refresh of the model in the second quarter of each fiscal year. No material changes to the estimated future remediation costs were noted as a result of the refresh completed as of June 30, 2017. Our total estimated liability related to the facilities subject to remediation was $105.5 million and $106.9 million at March 31, 2018 and December 31, 2017 , respectively. The liability represents our best estimate of the probable cost to remediate the facilities. We believe that it is reasonably possible that remediation costs could vary by as much as $25 million in addition to the costs noted above. Remediation costs are estimated based on the best available information, applicable remediation standards at the balance sheet date, and experience with similar facilities. CCRs. On April 17, 2015, the EPA issued a final rule for regulation of CCRs. The rule regulates CCRs under the RCRA Subtitle D, which determines them to be nonhazardous. The rule is implemented in phases and requires increased groundwater monitoring, reporting, recordkeeping and posting of related information to the Internet. The rule also establishes requirements related to CCR management and disposal. The rule will allow NIPSCO to continue its byproduct beneficial use program. The publication of the CCR rule resulted in revisions to previously recorded legal obligations associated with the retirement of certain NIPSCO facilities. The actual asset retirement costs related to the CCR rule may vary substantially from the estimates used to record the increased asset retirement obligation due to the uncertainty about the compliance strategies that will be used and the preliminary nature of available data used to estimate costs. In addition, to comply with the rule, NIPSCO will be required to incur future capital expenditures to modify its infrastructure and manage CCRs. Capital compliance costs are currently expected to total approximately $193 million . As allowed by the EPA, NIPSCO will continue to collect data over time to determine the specific compliance solutions and associated costs and, as a result, the actual costs may vary. NIPSCO filed a petition on November 1, 2016 with the IURC seeking approval of the projects and recovery of the costs associated with CCR compliance. On June 9, 2017, NIPSCO filed with the IURC a settlement reached with certain parties regarding the CCR projects and treatment of associated costs. The IURC approved the settlement in an order on December 13, 2017. Water ELG. On November 3, 2015, the EPA issued a final rule to amend the ELG and standards for the Steam Electric Power Generating category. The final rule became effective January 4, 2016. The rule imposes new water treatment and discharge requirements on NIPSCO's electric generating facilities to be applied between 2018 and 2023. On April 25, 2017, the EPA published notice in the Federal Register that the EPA is reconsidering the ELG in response to several petitions for reconsideration. On September 18, 2017, the EPA postponed the earliest compliance dates for flue gas desulfurization wastewater and bottom ash transport water requirements from 2018 to 2020 to potentially consider revisions to technology and numeric limits achievable. NIPSCO is unable to estimate the financial impact of the EPA reconsideration at this time. Based upon a preliminary study of the November 3, 2015 final rule, capital compliance costs were expected to be approximately $170 million . On November 1, 2016, NIPSCO filed a petition with the IURC seeking approval of the projects and recovery of the costs associated with ELG compliance. Given the current postponement of certain compliance dates under the ELG rule, NIPSCO has agreed with the settling parties as part of the settlement agreement discussed in the "CCRs" subsection above, that these ELG projects and related costs would be addressed in a later proceeding. D . Other Matters. NIPSCO 2016 Integrated Resource Plan. Environmental, regulatory and economic factors, including low natural gas prices and aging coal-fired units, have led NIPSCO to pursue modification of its current electric generation supply mix to include less coal-fired generation. Due to enacted CCR and ELG (subsequently postponed) regulations, NIPSCO would expect to have incurred over $1 billion in operating, maintenance, environmental and other costs if the current fleet of coal-fired generating were to remain operational. On November 1, 2016, NIPSCO submitted its 2016 Integrated Resource Plan with the IURC. The plan evaluated demand-side and supply-side resource alternatives to reliably and cost effectively meet NIPSCO customers' future energy requirements over the ensuing 20 years. The 2016 Integrated Resource Plan indicated that the most viable option for customers and NIPSCO involves the retirement of Bailly Generating Station (Units 7 and 8) as soon as mid-2018 and two units (Units 17 and 18) at the R.M. Schahfer Generating Station by the end of 2023. It is projected over the long term that the cost to customers to retire these units at these dates will be lower than maintaining and upgrading them for continuing generation. We, as well as NIPSCO, committed to the retirement of the Bailly Generating Station units in connection with the filing of the 2016 Integrated Resource Plan, pending approval by the MISO. In the fourth quarter of 2016, the MISO approved NIPSCO's plan to retire the Bailly Generating Station units by May 31, 2018. On February 1, 2018, as previously approved by the MISO, NIPSCO commenced a four-month outage of Bailly Generating Station Unit 8 in order to begin work on converting the unit to a synchronous condenser (a piece of equipment designed to maintain voltage to ensure continued reliability on the transmission system). Approximately $15 million of net book value of Unit 8 remained in “Net Utility Plant” as it is expected to remain used and useful upon completion of the synchronous condenser, while the remaining net book value of approximately $142 million was reclassified to “Regulatory assets (noncurrent)” on the Condensed Consolidated Balance Sheets (unaudited). These amounts continue to be amortized at a rate consistent with their inclusion in customer rates. NIPSCO expects to complete the retirement of Units 7 and 8 by May 31, 2018. NIPSCO Pure Air. NIPSCO has a service agreement with Pure Air, a general partnership between Air Products and Chemicals, Inc. and First Air Partners LP, under which Pure Air provides 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 have made an exhaustive effort to obtain information needed from Pure Air to determine the status of Pure Air as a VIE. However, NIPSCO has not been able to obtain this information and, as a result, it is unclear whether Pure Air is a VIE and if NIPSCO is the primary beneficiary. NIPSCO will continue to request the information required to determine whether Pure Air is a VIE. NIPSCO has no exposure to loss related to the service agreement with Pure Air and payments under this agreement were $ 5.1 million and $ 5.5 million for the three months ended March 31, 2018 and 2017 , respectively. In accordance with GAAP, the renewed agreement was evaluated to determine whether the arrangement qualifies as a lease. Based on the terms of the agreement, the arrangement qualified for capital lease accounting. As the effective date of the new agreement was July 1, 2012, we capitalized this lease beginning in the third quarter of 2012. As further discussed above in this Note 16 under the heading "NIPSCO 2016 Integrated Resource Plan," NIPSCO plans to retire the generation station units serviced by Pure Air by 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. Payment of this liability is not due until NIPSCO ceases use of the scrubber services. The liability is presented in "Other accruals" on the Condensed Consolidated Balance Sheets (unaudited). In addition, NIPSCO remeasured the remaining capital lease asset and obligation to reflect the change in estimated remaining minimum lease payments. This remeasurement was a non-cash transaction that had no impact on the Statements of Consolidated Income.

Accumulated Other Comprehensive

Accumulated Other Comprehensive Loss	3 Months Ended
	Mar. 31, 2018
Other Comprehensive Income (Loss), Tax [Abstract]
Accumulated Other Comprehensive Loss	Accumulated Other Comprehensive Loss The following tables display the components of Accumulated Other Comprehensive Loss: Three Months Ended March 31, 2018 (in millions) Gains and Losses on Securities (1) Gains and Losses on Cash Flow Hedges (1) Pension and OPEB Items (1) Accumulated Other Comprehensive Loss (1) Balance as of January 1, 2018 $ 0.2 $ (29.4 ) $ (14.2 ) $ (43.4 ) Other comprehensive income (loss) before reclassifications (1.9 ) 51.1 (0.6 ) 48.6 Amounts reclassified from accumulated other comprehensive loss (2) 0.2 (15.7 ) 0.8 (14.7 ) Net current-period other comprehensive income (loss) (1.7 ) 35.4 0.2 33.9 Reclassification due to adoption of ASU 2018-02 (Refer to Note 2) — (6.3 ) (3.2 ) $ (9.5 ) Balance as of March 31, 2018 $ (1.5 ) $ (0.3 ) $ (17.2 ) $ (19.0 ) Three Months Ended March 31, 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 January 1, 2017 $ (0.6 ) $ (6.9 ) $ (17.6 ) $ (25.1 ) Other comprehensive income before reclassifications 0.2 4.6 0.1 4.9 Amounts reclassified from accumulated other comprehensive loss 0.2 0.3 0.1 0.6 Net current-period other comprehensive income 0.4 4.9 0.2 5.5 Balance as of March 31, 2017 $ (0.2 ) $ (2.0 ) $ (17.4 ) $ (19.6 ) (1) All amounts are net of tax. Amounts in parentheses indicate debits. (2) Reclassification from accumulated other comprehensive loss for cash flow hedges relates primarily to the interest rate swap settlement gain. Refer to Note 8 "Risk Management Activities" for additional information.

Other, Net

Other, Net	3 Months Ended
	Mar. 31, 2018
Other, Net [Abstract]
Other Income and Other Expense Disclosure [Text Block]	Other, Net Three Months Ended March 31, (in millions) 2018 2017 Interest Income $ 1.7 $ 0.9 AFUDC Equity 3.7 2.5 Pension and other postretirement non-service cost 6.2 1.2 Interest rate swap settlement gain (1) 21.2 — Miscellaneous (1.5 ) (2.3 ) Total Other, net $ 31.3 $ 2.3 (1) See Note 8 , "Risk Management Activities," for additional information.

Business Segment Information

Business Segment Information	3 Months Ended
	Mar. 31, 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 (in millions) 2018 2017 Operating Revenues Gas Distribution Operations Unaffiliated $ 1,327.3 $ 1,176.3 Intersegment 3.3 3.5 Total 1,330.6 1,179.8 Electric Operations Unaffiliated 423.3 421.7 Intersegment 0.2 0.2 Total 423.5 421.9 Corporate and Other Unaffiliated 0.2 0.6 Intersegment 114.1 119.6 Total 114.3 120.2 Eliminations (117.6 ) (123.3 ) Consolidated Operating Revenues $ 1,750.8 $ 1,598.6 Operating Income (Loss) Gas Distribution Operations $ 321.7 $ 338.8 Electric Operations 83.1 77.6 Corporate and Other (4.2 ) (1.0 ) Consolidated Operating Income $ 400.6 $ 415.4

Recent Accounting Pronounceme31

Recent Accounting Pronouncements (Tables)	3 Months Ended
	Mar. 31, 2018
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
Description of New Accounting Pronouncements Not yet Adopted	currently evaluating the impact of certain ASUs on our Condensed Consolidated Financial Statements (unaudited) and Notes to Condensed Consolidated Financial Statements (unaudited), which are described below: Standard Description Effective Date Effect on the financial statements or other significant matters ASU 2016-13, Financial Instruments-Credit Losses (Topic 326) The pronouncement changes the impairment model for most financial assets, replacing the current "incurred loss" model. ASU 2016-13 will require the use of an "expected loss" model for instruments measured at amortized cost. It will also require entities to record allowances for available-for-sale debt securities rather than impair the carrying amount of the securities. Subsequent improvements to the estimated credit losses of available-for-sale securities will be recognized immediately in earnings instead of over time as they are under historic guidance. Annual periods beginning after December 15, 2019, including interim periods therein. Early adoption is permitted for annual or interim periods beginning after December 15, 2018. We maintain investments in U.S. Treasury, corporate and mortgage-backed debt securities which are pledged as collateral for trust accounts related to our wholly-owned insurance company. These debt securities are classified as available for sale. We are currently evaluating the impact of adoption, if any, on our Condensed Consolidated Financial Statements (unaudited) and Notes to Condensed Consolidated Financial Statements (unaudited). ASU 2018-01, 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. Annual periods beginning after December 15, 2018, including interim periods therein. Early adoption is permitted. We formed an internal stakeholder group that meets periodically to share information and gather data related to our leasing activity. This includes compiling a list of all contracts that could meet the definition of a lease and evaluating the accounting for these contracts under the new standard to determine the ultimate impact the new standards will have on our financial statements. This procedure has identified process improvements to ensure data from newly initiated leases is captured to comply with the new standard. This work included the assistance of a third-party advisory firm. In addition, we are implementing a new lease accounting system, which we will utilize to capture, track, and record lease data. We maintain a substantial number of easements and expect ASU 2018-01 will ease the process of implementing ASC 842. We continue to monitor both FASB and industry updates related to the new leasing standards and intend to adopt these standards effective January 1, 2019. ASU 2016-02, Leases (Topic 842) The pronouncement introduces a lessee model that brings most leases on the balance sheet. The standard requires that lessees recognize the following for all leases (with the exception of short-term leases, as that term is defined in the standard) at the lease commencement date: (1) a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and (2) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term.
Schedule of Prospective Adoption of New Accounting Pronouncements	Recently Adopted Accounting Pronouncements Standard Adoption ASU 2018-02, Income Statement—Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income We elected to adopt this ASU effective March 31, 2018. Upon adoption, $9.5 million of tax effects that were stranded in accumulated other comprehensive loss as a result of the implementation of the TCJA have been 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)	3 Months Ended
	Mar. 31, 2018
Revenue from Contract with Customer [Abstract]
Revenue Recognition Under Previous Guidance	The table below provides results for the three months ended March 31, 2018 as if they had been prepared under historic accounting guidance. We included operating revenue information for the three months ended March 31, 2017 for comparability. Three Months Ended (in millions) 2018 2017 Operating Revenues Gas Distribution $ 983.8 $ 836.5 Gas Transportation 342.2 338.6 Electric 423.3 421.7 Other 1.5 1.8 Total Operating Revenues $ 1,750.8 $ 1,598.6
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 (unaudited): Three Months Ended March 31, 2018 ( in millions) Gas Distribution Operations Electric Operations Corporate and Other Total Customer Revenues (1) Residential $ 893.6 $ 114.5 $ — $ 1,008.1 Commercial 308.3 116.9 — 425.2 Industrial 74.6 162.5 — 237.1 Off-system 22.3 — — 22.3 Miscellaneous 16.8 7.5 0.2 24.5 Total Customer Revenues $ 1,315.6 $ 401.4 $ 0.2 $ 1,717.2 Other Revenues 11.7 21.9 — 33.6 Total Operating Revenues $ 1,327.3 $ 423.3 $ 0.2 $ 1,750.8
Customer Accounts Receivable	(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 March 31, 2018 617.2 274.6 Increase (Decrease) $ 140.2 $ (81.4 ) (1) Customer billed receivables increased over the period due to the seasonal increase in customer usage during peak winter usage months. (2) Customer unbilled receivables decreased over the period due to the expected seasonal decrease in customer usage in March when compared to December.

Earnings Per Share (Tables)

Earnings Per Share (Tables)	3 Months Ended
	Mar. 31, 2018
Earnings Per Share [Abstract]
Computation Of Diluted Average Common Shares	The computation of diluted average common shares is as follows: Three Months Ended March 31, (in thousands) 2018 2017 Denominator Basic average common shares outstanding 338,012 323,681 Dilutive potential common shares: Shares contingently issuable under employee stock plans 715 360 Shares restricted under employee stock plans 264 1,265 Diluted Average Common Shares 338,991 325,306

Risk Management Activities (Tab

Risk Management Activities (Tables)	3 Months Ended
	Mar. 31, 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) March 31, 2018 December 31, 2017 Risk Management Assets - Current (1) Interest rate risk programs $ 9.4 $ 14.0 Commodity price risk programs 0.4 0.5 Total $ 9.8 $ 14.5 Risk Management Assets - Noncurrent (2) Interest rate risk programs $ 18.6 $ 5.6 Commodity price risk programs 2.8 1.0 Total $ 21.4 $ 6.6 Risk Management Liabilities - Current Interest rate risk programs $ — $ 38.6 Commodity price risk programs 4.6 4.6 Total $ 4.6 $ 43.2 Risk Management Liabilities - Noncurrent Interest rate risk programs $ — $ — Commodity price risk programs 32.8 28.5 Total $ 32.8 $ 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)	3 Months Ended
	Mar. 31, 2018
Fair Value Disclosures [Abstract]
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis	Recurring Fair Value Measurements. The following tables present financial assets and liabilities measured and recorded at fair value on our Condensed Consolidated Balance Sheets (unaudited) on a recurring basis and their level within the fair value hierarchy as of March 31, 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 March 31, 2018 Assets Risk management assets $ — $ 31.0 $ 0.2 $ 31.2 Available-for-sale securities — 132.5 — 132.5 Total $ — $ 163.5 $ 0.2 $ 163.7 Liabilities Risk management liabilities $ — $ 37.4 $ — $ 37.4 Total $ — $ 37.4 $ — $ 37.4 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 March 31, 2018 and December 31, 2017 were: March 31, 2018 (in millions) Amortized Cost Gross Unrealized Gains Gross Unrealized Losses Fair Value Available-for-sale securities U.S. Treasury debt securities $ 22.3 $ — $ (0.1 ) $ 22.2 Corporate/Other debt securities 112.2 0.3 (2.2 ) 110.3 Total $ 134.5 $ 0.3 $ (2.3 ) $ 132.5 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) $ 7,549.5 $ 7,862.3 $ 7,796.5 $ 8,603.4

Transfers Of Financial Assets (

Transfers Of Financial Assets (Tables)	3 Months Ended
	Mar. 31, 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 March 31, 2018 and December 31, 2017 : (in millions) March 31, 2018 December 31, 2017 Gross Receivables $ 683.4 $ 635.3 Less: Receivables not transferred 170.0 298.6 Net receivables transferred $ 513.4 $ 336.7 Short-term debt due to asset securitization $ 513.4 $ 336.7

Goodwill (Tables)

Goodwill (Tables)	3 Months Ended
	Mar. 31, 2018
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule of Goodwill	The following presents our goodwill balance allocated by segment as of March 31, 2018 : (in millions) Gas Distribution Operations Electric Operations Corporate and Other Total Goodwill $ 1,690.7 $ — $ — $ 1,690.7

Pension And Other Postretirem38

Pension And Other Postretirement Benefits (Tables)	3 Months Ended
	Mar. 31, 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 (income) cost for the three months ended March 31, 2018 and 2017 : Pension Benefits Other Postretirement Benefits Three Months Ended March 31, (in millions) 2018 2017 2018 2017 Components of Net Periodic Benefit (Income) Cost (1) Service cost $ 7.9 $ 7.5 $ 1.3 $ 1.2 Interest cost 16.6 17.2 4.4 4.5 Expected return on assets (36.3 ) (30.3 ) (3.7 ) (4.0 ) Amortization of prior service credit (0.1 ) (0.2 ) (1.0 ) (1.1 ) Recognized actuarial loss 10.2 13.4 0.9 0.8 Total Net Periodic Benefit (Income) Cost $ (1.7 ) $ 7.6 $ 1.9 $ 1.4 (1) The service cost component, and all non-service cost components, of net periodic benefit (income) cost are presented in "Operation and maintenance" and "Other, net", respectively, on the Condensed Statements of Consolidated Income (unaudited).

Short-Term Borrowings (Tables)

Short-Term Borrowings (Tables)	3 Months Ended
	Mar. 31, 2018
Short-term Debt [Abstract]
Schedule Of Short-Term Borrowings	Short-term borrowings were as follows: (in millions) March 31, December 31, Commercial Paper weighted-average interest rate of 2.51% and 1.97% at March 31, 2018 and December 31, 2017, respectively $ 1,053.9 $ 869.0 Accounts receivable securitization facility borrowings 513.4 336.7 Total Short-Term Borrowings $ 1,567.3 $ 1,205.7

Accumulated Other Comprehensi40

Accumulated Other Comprehensive Loss (Tables)	3 Months Ended
	Mar. 31, 2018
Other Comprehensive Income (Loss), Tax [Abstract]
Components Of Accumulated Other Comprehensive Loss	The following tables display the components of Accumulated Other Comprehensive Loss: Three Months Ended March 31, 2018 (in millions) Gains and Losses on Securities (1) Gains and Losses on Cash Flow Hedges (1) Pension and OPEB Items (1) Accumulated Other Comprehensive Loss (1) Balance as of January 1, 2018 $ 0.2 $ (29.4 ) $ (14.2 ) $ (43.4 ) Other comprehensive income (loss) before reclassifications (1.9 ) 51.1 (0.6 ) 48.6 Amounts reclassified from accumulated other comprehensive loss (2) 0.2 (15.7 ) 0.8 (14.7 ) Net current-period other comprehensive income (loss) (1.7 ) 35.4 0.2 33.9 Reclassification due to adoption of ASU 2018-02 (Refer to Note 2) — (6.3 ) (3.2 ) $ (9.5 ) Balance as of March 31, 2018 $ (1.5 ) $ (0.3 ) $ (17.2 ) $ (19.0 ) Three Months Ended March 31, 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 January 1, 2017 $ (0.6 ) $ (6.9 ) $ (17.6 ) $ (25.1 ) Other comprehensive income before reclassifications 0.2 4.6 0.1 4.9 Amounts reclassified from accumulated other comprehensive loss 0.2 0.3 0.1 0.6 Net current-period other comprehensive income 0.4 4.9 0.2 5.5 Balance as of March 31, 2017 $ (0.2 ) $ (2.0 ) $ (17.4 ) $ (19.6 ) (1) All amounts are net of tax. Amounts in parentheses indicate debits. (2) Reclassification from accumulated other comprehensive loss for cash flow hedges relates primarily to the interest rate swap settlement gain. Refer to Note 8 "Risk Management Activities" for additional information.

Other, Net (Tables)

Other, Net (Tables)	3 Months Ended
	Mar. 31, 2018
Other, Net [Abstract]
Schedule of Other Nonoperating Income (Expense)	Three Months Ended March 31, (in millions) 2018 2017 Interest Income $ 1.7 $ 0.9 AFUDC Equity 3.7 2.5 Pension and other postretirement non-service cost 6.2 1.2 Interest rate swap settlement gain (1) 21.2 — Miscellaneous (1.5 ) (2.3 ) Total Other, net $ 31.3 $ 2.3 (1) See Note 8 , "Risk Management Activities," for additional information.

Business Segment Information (T

Business Segment Information (Tables)	3 Months Ended
	Mar. 31, 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 (in millions) 2018 2017 Operating Revenues Gas Distribution Operations Unaffiliated $ 1,327.3 $ 1,176.3 Intersegment 3.3 3.5 Total 1,330.6 1,179.8 Electric Operations Unaffiliated 423.3 421.7 Intersegment 0.2 0.2 Total 423.5 421.9 Corporate and Other Unaffiliated 0.2 0.6 Intersegment 114.1 119.6 Total 114.3 120.2 Eliminations (117.6 ) (123.3 ) Consolidated Operating Revenues $ 1,750.8 $ 1,598.6 Operating Income (Loss) Gas Distribution Operations $ 321.7 $ 338.8 Electric Operations 83.1 77.6 Corporate and Other (4.2 ) (1.0 ) Consolidated Operating Income $ 400.6 $ 415.4

Recent Accounting Pronounceme43

Recent Accounting Pronouncements Recent Accounting Pronouncements (Schedule of Prospective Adoption of New Accounting Pronouncements) (Details) $ in Millions	Dec. 31, 2017USD ($)
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Cumulative Effect of New Accounting Principle in Period of Adoption	$ 0
Retained Deficit | Accounting Standards Update 2018-02
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Cumulative Effect of New Accounting Principle in Period of Adoption	$ 9.5

Recent Accounting Pronounceme44

Recent Accounting Pronouncements (Schedule of New Accounting Pronouncements and Changes in Accounting Princicples) (Details) - USD ($) $ in Millions	3 Months Ended		12 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017		Dec. 31, 2016
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Operation and maintenance	$ 402.5	$ 411.6
Total Operating Expenses	1,350.2	1,183.2
Operating Income	400.6	415.4
Other, net	31.3	2.3
Total Other Deductions	(61.8)	(82.9)
Income before Income Taxes	338.8	332.5
Previously Reported
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Operation and maintenance			$ 1,612.3		$ 1,453.7
Total Operating Expenses			3,964		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
As Adjusted
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Operation and maintenance			1,601.7		1,445.8
Total Operating Expenses			3,953.4		3,626.4
Operating Income			921.2		866.1
Other, net			(13.4)		(6.4)
Total Other Deductions			(478.1)		(355.9)
Income before Income Taxes			443.1		510.2
Accounting Standards Update 2017-07
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Operation and maintenance			(10.6)	[1]	(7.9)	[2]
Total Operating Expenses			(10.6)	[1]	(7.9)	[2]
Operating Income			10.6	[1]	7.9	[2]
Other, net			(10.6)	[1]	(7.9)	[2]
Total Other Deductions			(10.6)	[1]	(7.9)	[2]
Income before Income Taxes			0	[1]	0	[2]
Gas Distribution Operations
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Operating Income	321.7	338.8
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	83.1	77.6
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	$ (4.2)	$ (1)
New Accounting Pronouncement or Change in Accounting Principle, Effect of Change on Operating Results			$ (3.6)		$ (2.4)
[1]	The effect of this change is attributable to our business segments: Gas Distribution Operations, Electric Operations, and Corporate and Other in the amounts of $(4.4) million, $(2.6) million, and $(3.6) million, respectively.
[2]	The effect of this change is attributable to our business segments: Gas Distribution Operations, Electric Operations, and Corporate and Other in the amounts of $4.3 million, $(9.8) million, and $(2.4) million, respectively.

Revenue Recognition (Narrative)

Revenue Recognition (Narrative) (Details)	3 Months Ended
	Mar. 31, 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
	Mar. 31, 2018	Mar. 31, 2017
Revenue Recognition Under Previous Guidance [Line Items]
Other Revenues	$ 33.6	$ 56.1
Total Operating Revenues	1,750.8	1,598.6
Previous Accounting Guidance
Revenue Recognition Under Previous Guidance [Line Items]
Gas Distribution	983.8	836.5
Gas Transportation	342.2	338.6
Electric	423.3	421.7
Other Revenues	1.5	1.8
Total Operating Revenues	$ 1,750.8	$ 1,598.6

Revenue Recognition (Disaggrega

Revenue Recognition (Disaggregation of Revenue) (Details) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2018	Mar. 31, 2017
Disaggregation of Revenue [Line Items]
Customer Revenues	[1]	$ 1,717.2
Other Revenues		33.6	$ 56.1
Total Operating Revenues		1,750.8	1,598.6
Misc.
Disaggregation of Revenue [Line Items]
Customer Revenues	[1]	24.5
Off-system
Disaggregation of Revenue [Line Items]
Customer Revenues	[1]	22.3
Industrial
Disaggregation of Revenue [Line Items]
Customer Revenues	[1]	237.1
Commercial
Disaggregation of Revenue [Line Items]
Customer Revenues	[1]	425.2
Residential
Disaggregation of Revenue [Line Items]
Customer Revenues	[1]	1,008.1
Gas Distribution Operations
Disaggregation of Revenue [Line Items]
Customer Revenues	[1]	1,315.6
Other Revenues		11.7
Total Operating Revenues		1,330.6	1,179.8
Gas Distribution Operations | Misc.
Disaggregation of Revenue [Line Items]
Customer Revenues	[1]	16.8
Gas Distribution Operations | Off-system
Disaggregation of Revenue [Line Items]
Customer Revenues	[1]	22.3
Gas Distribution Operations | Industrial
Disaggregation of Revenue [Line Items]
Customer Revenues	[1]	74.6
Gas Distribution Operations | Commercial
Disaggregation of Revenue [Line Items]
Customer Revenues	[1]	308.3
Gas Distribution Operations | Residential
Disaggregation of Revenue [Line Items]
Customer Revenues	[1]	893.6
Electric Operations
Disaggregation of Revenue [Line Items]
Customer Revenues	[1]	401.4
Other Revenues		21.9
Total Operating Revenues		423.5	421.9
Electric Operations | Misc.
Disaggregation of Revenue [Line Items]
Customer Revenues	[1]	7.5
Electric Operations | Off-system
Disaggregation of Revenue [Line Items]
Customer Revenues	[1]	0
Electric Operations | Industrial
Disaggregation of Revenue [Line Items]
Customer Revenues	[1]	162.5
Electric Operations | Commercial
Disaggregation of Revenue [Line Items]
Customer Revenues	[1]	116.9
Electric Operations | Residential
Disaggregation of Revenue [Line Items]
Customer Revenues	[1]	114.5
Corporate and Other
Disaggregation of Revenue [Line Items]
Customer Revenues	[1]	0.2
Other Revenues		0
Total Operating Revenues		114.3	$ 120.2
Corporate and Other | Misc.
Disaggregation of Revenue [Line Items]
Customer Revenues	[1]	0.2
Corporate and Other | Off-system
Disaggregation of Revenue [Line Items]
Customer Revenues	[1]	0
Corporate and Other | Industrial
Disaggregation of Revenue [Line Items]
Customer Revenues	[1]	0
Corporate and Other | Commercial
Disaggregation of Revenue [Line Items]
Customer Revenues	[1]	0
Corporate and Other | Residential
Disaggregation of Revenue [Line Items]
Customer Revenues	[1]	$ 0
[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		3 Months Ended
		Mar. 31, 2018	Dec. 31, 2017
Revenue from Contract with Customer [Abstract]
Customer Accounts Receivable, Billed (Less Reserve)	[1]	$ 617.2	$ 477
Customer Accounts Receivable, Unbilled (Less Reserve)	[2]	274.6	$ 356
Increase (Decrease) in Customer Accounts Receivable, Billed (Less Reserve)	[1]	140.2
Increase (Decrease) in Customer Accounts Receivable, Unbilled (Less Reserve)	[2]	$ (81.4)
[1]	Customer billed receivables increased over the period due to the seasonal increase in customer usage during peak winter usage months.
[2]	Customer unbilled receivables decreased over the period due to the expected seasonal decrease in customer usage in March when compared to December.

Earnings Per Share (Details)

Earnings Per Share (Details) - shares shares in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Denominator
Basic Average Common Shares Outstanding	338,012	323,681
Dilutive potential common shares
Shares contingently issuable under employee stock plans	715	360
Shares restricted under stock plans	264	1,265
Diluted Average Common Shares	338,991	325,306

Common Stock (Narrative) (Detai

Common Stock (Narrative) (Details) $ / shares in Units, $ in Millions	1 Months Ended	3 Months Ended
	Dec. 08, 2017$ / shares	Mar. 31, 2018USD ($)$ / sharesshares
At The Market Stock Offering [Line Items]
Number Of Equity Distribution Agreements		4
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	$ 26.83
Forward Contract Indexed to Issuer's Equity, Settlement Alternatives, Shares, at Fair Value		$ 170.3
At The Market Program
At The Market Stock Offering [Line Items]
Common Stock Aggregate Sale Price		500
ATM Program Equity Remaining Available for Issuance		$ 10

Gas in Storage (Narrative) (Det

Gas in Storage (Narrative) (Details) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Gas in Storage [Abstract]
LIFO Inventory Amount	$ 20.9	$ 0

Regulatory Matters (Narrative)

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

Apr. 30, 2018

Apr. 20, 2018

Apr. 18, 2018

Apr. 13, 2018

Mar. 28, 2018

Mar. 26, 2018

Mar. 16, 2018

Feb. 27, 2018

Feb. 13, 2018

Jan. 30, 2018

Jan. 29, 2018

Nov. 08, 2017

Oct. 31, 2017

Sep. 27, 2017

Apr. 25, 2018

Mar. 31, 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

$ 49.7

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

$ 15

Liability Associated with Bailey Generating Station Retirement

$ 142

TDSIC 8 Gas

Regulatory Matters [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amount

$ 0.8

Regulatory Net Capital Expenditures Included In Filing

77.9

Columbia Of Ohio

Regulatory Matters [Line Items]

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

$ 2.3

NIPSCO

Regulatory Matters [Line Items]

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

$ 138.1

Public Utilities, Requested Rate Increase (Decrease), Amount

$ 143.5

Public Utilities, Approved Rate Increase (Decrease), Amount

$ 91.5

$ (8.5)

Regulatory Net Capital Expenditures Included In Filing

$ 35.5

$ 1,250

NIPSCO | TDSIC-3

Regulatory Matters [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amount

$ (1.8)

Regulatory Net Capital Expenditures Included In Filing

$ 75

Columbia Of Massachusetts | 2018 GSEP

Regulatory Matters [Line Items]

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

3.1

Public Utilities, Requested Rate Increase (Decrease), Cumulative Amount, In excess of cap

$ (2.4)

Public Utilities, Requested Rate Increase (Decrease), Amount

$ 9.7

Columbia Of Pennsylvania [Member]

Regulatory Matters [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amount

$ 46.9

Columbia Of Maryland

Regulatory Matters [Line Items]

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

$ 29

Regulatory Net Capital Expenditures Included In Filing

$ 207

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

$ 98

Subsequent Event | NIPSCO

Regulatory Matters [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amount

$ 107.3

Subsequent Event | 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

Subsequent Event | Columbia Of Massachusetts | 2018 GSEP

Regulatory Matters [Line Items]

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

43.8

Public Utilities, Approved Rate Increase (Decrease), Amount

$ 6.1

Regulatory Net Capital Expenditures Included In Filing

$ 83.9

Subsequent Event | Columbia Of Maryland

Regulatory Matters [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amount

$ 6

Risk Management Activities (Nar

Risk Management Activities (Narrative) (Details) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2018	Mar. 31, 2017
Derivative [Line Items]
Gain (Loss) on Sale of Derivatives	[1]	$ 21.2	$ 0
Risk management assets
Derivative [Line Items]
Gain (Loss) on Cash Flow Hedge Ineffectiveness, Net		0	$ 0
Interest Rate Swap [Member]
Derivative [Line Items]
Derivative, Notional Amount		750
Interest Rate Swap Settled
Derivative [Line Items]
Derivative, Notional Amount		$ 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		Mar. 31, 2018	Dec. 31, 2017
Risk Management Assets Current
Derivatives, Fair Value [Line Items]
Derivative Asset	[1]	$ 9.8	$ 14.5
Risk Management Assets Noncurrent
Derivatives, Fair Value [Line Items]
Derivative Asset	[2]	21.4	6.6
Risk Management Liabilities Current
Derivatives, Fair Value [Line Items]
Derivative Liability		4.6	43.2
Risk Management Liabilities Noncurrent
Derivatives, Fair Value [Line Items]
Derivative Liability		32.8	28.5
Interest Rate Risk | Risk Management Assets Current
Derivatives, Fair Value [Line Items]
Derivative Asset	[1]	9.4	14
Interest Rate Risk | Risk Management Assets Noncurrent
Derivatives, Fair Value [Line Items]
Derivative Asset	[2]	18.6	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]	0.4	0.5
Commodity Price Risk Programs | Risk Management Assets Noncurrent
Derivatives, Fair Value [Line Items]
Derivative Asset	[2]	2.8	1
Commodity Price Risk Programs | Risk Management Liabilities Current
Derivatives, Fair Value [Line Items]
Derivative Liability		4.6	4.6
Commodity Price Risk Programs | Risk Management Liabilities Noncurrent
Derivatives, Fair Value [Line Items]
Derivative Liability		$ 32.8	$ 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	3 Months Ended
	Mar. 31, 2018	Mar. 31, 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	$ 7.7
Corporate/Other debt securities
Fair Value Disclosure [Line Items]
Available-for-sale Securities, Maturities, Next Twelve Months, Fair Value	$ 1.6

Fair Value (Fair Value Of Finan

Fair Value (Fair Value Of Financial Assets And Liabilities Measured On A Recurring Basis) (Details) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Assets
Available-for-sale securities	$ 132.5	$ 133.9
Total	163.7	155
Liabilities
Total	37.4	71.7
Fair Value, Inputs, Level 1
Assets
Risk management assets	0	0
Available-for-sale securities	0	0
Total	0	0
Liabilities
Risk management liabilities	0	0
Total	0	0
Significant Other Observable Inputs (Level 2)
Assets
Risk management assets	31	21.1
Available-for-sale securities	132.5	133.9
Total	163.5	155
Liabilities
Risk management liabilities	37.4	71.4
Total	37.4	71.4
Significant Unobservable Inputs (Level 3)
Assets
Risk management assets	0.2	0
Available-for-sale securities	0	0
Total	0.2	0
Liabilities
Risk management liabilities	0	0.3
Total	0	0.3
Available-for-sale Securities
Assets
Available-for-sale securities	132.5	133.9
Risk management assets
Assets
Risk management assets	31.2	21.1
Liabilities
Risk management liabilities	$ 37.4	$ 71.7

Fair Value (Available-For-Sale

Fair Value (Available-For-Sale Securities) (Details) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Fair Value Disclosure [Line Items]
Amortized Cost	$ 134.5	$ 133.7
Gross Unrealized Gains	0.3	0.9
Gross Unrealized Losses	(2.3)	(0.7)
Fair Value	132.5	133.9
U.S. Treasury debt securities
Fair Value Disclosure [Line Items]
Amortized Cost	22.3	26.9
Gross Unrealized Gains	0	0
Gross Unrealized Losses	(0.1)	(0.1)
Fair Value	22.2	26.8
Corporate/Other debt securities
Fair Value Disclosure [Line Items]
Amortized Cost	112.2	106.8
Gross Unrealized Gains	0.3	0.9
Gross Unrealized Losses	(2.2)	(0.6)
Fair Value	$ 110.3	$ 107.1

Fair Value (Carrying Amount And

Fair Value (Carrying Amount And Estimated Fair Values Of Financial Instruments) (Details) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Fair Value Disclosures [Abstract]
Long-term Debt (including current portion), Gross	$ 7,549.5	$ 7,796.5
Long-term debt (including current portion), Estimated Fair Value	$ 7,862.3	$ 8,603.4

Transfers Of Financial Assets59

Transfers Of Financial Assets (Narrative) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 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	$ 176.7	$ 129
Securitization Transaction Fees	0.8	$ 0.7
Accounts Receivable Program
Assets and Associated Liabilities of Transfers Accounted for as Secured Borrowings [Line Items]
Seasonal Limit	$ 540

Transfers Of Financial Assets60

Transfers Of Financial Assets (Schedule Of Gross And Net Receivables Transferred As Well As Short-Term Borrowings Related To The Securitization Transactions) (Details) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Gross Receivables	$ 683.4	$ 635.3
Less: Receivables not transferred	170	298.6
Net receivables transferred	513.4	336.7
Accounts receivable securitization facility borrowings	$ 513.4	$ 336.7

Goodwill (Details)

Goodwill (Details) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Goodwill [Line Items]
Goodwill	$ 1,690.7	$ 1,690.7
Gas Distribution Operations
Goodwill [Line Items]
Goodwill	1,690.7
Electric Operations
Goodwill [Line Items]
Goodwill	0
Corporate and Other
Goodwill [Line Items]
Goodwill	$ 0

Income Taxes (Narrative) (Detai

Income Taxes (Narrative) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Income Tax Disclosure [Abstract]
Effective income tax rates	18.50%	36.50%
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate	21.00%	35.00%
Tax Benefit From Excess Deferred Tax Amortization Related To Regulatory LIabilities	$ 10.4
Changes to Liability for Uncertain Tax Positions	$ 0

Pension And Other Postretirem63

Pension And Other Postretirement Benefits (Narrative) (Details) $ in Millions	3 Months Ended
	Mar. 31, 2018USD ($)
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Employer contributions	$ 0.7
Other Postretirement Benefit Plan
Defined Benefit Plan Disclosure [Line Items]
Employer contributions	$ 5.5

Pension And Other Postretirem64

Pension And Other Postretirement Benefits (Components Of The Plans' Net Periodic Benefits Cost) (Details) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2018	Mar. 31, 2017
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Service Cost	[1]	$ 7.9	$ 7.5
Interest cost	[1]	16.6	17.2
Expected return on assets		(36.3)	(30.3)
Amortization of prior service credit		(0.1)	(0.2)
Recognized actuarial loss		10.2	13.4
Total Net Periodic Benefits Cost		(1.7)	7.6
Other Postretirement Benefit Plan
Defined Benefit Plan Disclosure [Line Items]
Service Cost	[1]	1.3	1.2
Interest cost	[1]	4.4	4.5
Expected return on assets		(3.7)	(4)
Amortization of prior service credit		(1)	(1.1)
Recognized actuarial loss		0.9	0.8
Total Net Periodic Benefits Cost		$ 1.9	$ 1.4
[1]	The service cost component, and all non-service cost components, of net periodic benefit (income) cost are presented in "Operation and maintenance" and "Other, net", respectively, on the Condensed Statements of Consolidated Income (unaudited).

Long-Term Debt (Narrative) (Det

Long-Term Debt (Narrative) (Details) - Senior Note Redeemed 2018 Note 1 - Senior Notes $ in Millions	Mar. 15, 2018USD ($)
Debt Instrument [Line Items]
Debt Instrument, Repurchase Amount	$ 275.1
Debt Instrument, Interest Rate, Stated Percentage	6.40%

Short-Term Borrowings (Narrativ

Short-Term Borrowings (Narrative) (Details) - USD ($) $ in Millions	Apr. 18, 2018	Mar. 31, 2018	Dec. 31, 2017
Short-term Debt [Line Items]
Commercial paper outstanding		$ 1,053.9	$ 869
Accounts receivable securitization facility borrowings		513.4	336.7
Short-term borrowings		1,567.3	1,205.7
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		$ 10.7	$ 11.1
Subsequent Event | Term Loan [Member] | Debt Oustanding [Member]
Short-term Debt [Line Items]
Short-term borrowings	$ 150
Subsequent Event | Term Loan [Member] | Debt Available for Issuance [Member]
Short-term Debt [Line Items]
Short-term borrowings	450
Subsequent Event | Maximum | Term Loan [Member]
Short-term Debt [Line Items]
Short-term borrowings	$ 600

Short-Term Borrowings (Schedule

Short-Term Borrowings (Schedule Of Short-Term Borrowings) (Details) - USD ($) $ in Millions	Apr. 18, 2018	Mar. 31, 2018	Dec. 31, 2017
Short-term Debt [Line Items]
Commercial paper outstanding		$ 1,053.9	$ 869
Accounts receivable securitization facility borrowings		513.4	336.7
Total short-term borrowings		$ 1,567.3	$ 1,205.7
Commercial Paper
Short-term Debt [Line Items]
Short-term Debt, Weighted Average Interest Rate, at Point in Time		2.51%	1.97%
Subsequent Event | Term Loan [Member]
Short-term Debt [Line Items]
Debt Instrument, Basis Spread on Variable Rate	0.50%

Other Commitments And Conting68

Other Commitments And Contingencies (Narrative) (Details) $ in Millions	3 Months Ended
	Mar. 31, 2018USD ($)	Mar. 31, 2017USD ($)	Feb. 01, 2018USD ($)	Dec. 31, 2017USD ($)
Other Commitments And Contingencies [Line Items]
Proposed Pipeline Safety Rule, time period for investigation and repair/replace activity on facilities	15 years
Recorded reserves to cover environmental remediation at various sites	$ 109.9			$ 111.4
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
Liability Associated with Bailey Generating Station Retirement			$ 142
Variable Interest Entity, Reporting Entity Involvement, Maximum Loss Exposure, Amount	0
Payments Pure Air	$ 5.1	$ 5.5
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
Liability for Estimated Remediation Costs	$ 105.5			106.9
Reasonably possible remediation costs variance from reserve	25
Minimum | NIPSCO
Other Commitments And Contingencies [Line Items]
Cost to Maintain and Operate Current Fleet of Coal-Fired Generating Units	1,000
Standby Letters of Credit
Other Commitments And Contingencies [Line Items]
Long-term Line of Credit	$ 10.7			$ 11.1

Accumulated Other Comprehensi69

Accumulated Other Comprehensive Loss (Components Of Accumulated Other Comprehensive Loss) (Details) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2018		Mar. 31, 2017	Dec. 31, 2017
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance	[1]	$ (43.4)		$ (25.1)
Other Comprehensive Income before reclassifications	[1]	48.6		4.9
Amounts reclassified from accumulated other comprehensive loss	[1]	(14.7)	[2]	0.6
Net current-period other comprehensive income (loss)	[1]	33.9		5.5
New Accounting Pronouncement or Change in Accounting Principle, Cumulative Effect of Change on Equity or Net Assets					$ (9.5)
Ending Balance	[1]	(19)		(19.6)
Gains and Losses on Securities
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance	[1]	0.2		(0.6)
Other Comprehensive Income before reclassifications	[1]	(1.9)		0.2
Amounts reclassified from accumulated other comprehensive loss	[1]	0.2	[2]	0.2
Net current-period other comprehensive income (loss)	[1]	(1.7)		0.4
New Accounting Pronouncement or Change in Accounting Principle, Cumulative Effect of Change on Equity or Net Assets					0
Ending Balance	[1]	(1.5)		(0.2)
Gains and Losses on Cash Flow Hedges
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance	[1]	(29.4)		(6.9)
Other Comprehensive Income before reclassifications	[1]	51.1		4.6
Amounts reclassified from accumulated other comprehensive loss	[1]	(15.7)	[2]	0.3
Net current-period other comprehensive income (loss)	[1]	35.4		4.9
New Accounting Pronouncement or Change in Accounting Principle, Cumulative Effect of Change on Equity or Net Assets					(6.3)
Ending Balance	[1]	(0.3)		(2)
Pension and OPEB Items
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance	[1]	(14.2)		(17.6)
Other Comprehensive Income before reclassifications	[1]	(0.6)		0.1
Amounts reclassified from accumulated other comprehensive loss	[1]	0.8	[2]	0.1
Net current-period other comprehensive income (loss)	[1]	0.2		0.2
New Accounting Pronouncement or Change in Accounting Principle, Cumulative Effect of Change on Equity or Net Assets					$ (3.2)
Ending Balance	[1]	$ (17.2)		$ (17.4)
[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
		Mar. 31, 2018	Mar. 31, 2017
Other, Net [Abstract]
Interest Income (Expense), Nonoperating, Net		$ 1.7	$ 0.9
Allowance for Funds Used During Construction, Capitalized Interest		3.7	2.5
Pension and Other Postretirement Non Service Cost		6.2	1.2
Gain (Loss) on Sale of Derivatives	[1]	21.2	0
Miscellaneous Non-Operating Income (Expense)		(1.5)	(2.3)
Other Nonoperating Income		$ 31.3	$ 2.3
[1]	See Note 8, "Risk Management Activities," for additional information.

Business Segment Information (N

Business Segment Information (Narrative) (Details)	3 Months Ended
	Mar. 31, 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
	Mar. 31, 2018	Mar. 31, 2017
Segment Reporting Information [Line Items]
Revenues	$ 1,750.8	$ 1,598.6
Consolidated Operating Income (Loss)	400.6	415.4
Gas Distribution Operations
Segment Reporting Information [Line Items]
Revenues	1,330.6	1,179.8
Consolidated Operating Income (Loss)	321.7	338.8
Gas Distribution Operations | Unaffiliated
Segment Reporting Information [Line Items]
Revenues	1,327.3	1,176.3
Gas Distribution Operations | Intersegment
Segment Reporting Information [Line Items]
Revenues	3.3	3.5
Electric Operations
Segment Reporting Information [Line Items]
Revenues	423.5	421.9
Consolidated Operating Income (Loss)	83.1	77.6
Electric Operations | Unaffiliated
Segment Reporting Information [Line Items]
Revenues	423.3	421.7
Electric Operations | Intersegment
Segment Reporting Information [Line Items]
Revenues	0.2	0.2
Corporate and Other
Segment Reporting Information [Line Items]
Revenues	114.3	120.2
Consolidated Operating Income (Loss)	(4.2)	(1)
Corporate and Other | Unaffiliated
Segment Reporting Information [Line Items]
Revenues	0.2	0.6
Corporate and Other | Intersegment
Segment Reporting Information [Line Items]
Revenues	114.1	119.6
Eliminations
Segment Reporting Information [Line Items]
Revenues	$ (117.6)	$ (123.3)