NISOURCE INC., 10-K filed on 2/28/2020
Annual Report
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Document And Entity Information - USD ($)
 12 Months Ended
Dec. 31, 2019
Feb. 18, 2020
Jun. 28, 2019
Document Information [Line Items]      
Document Type 10-K    
Document Annual Report true    
Document Period End Date Dec. 31, 2019    
Document Transition Report false    
Entity File Number 001-16189    
Entity Registrant Name NiSource Inc.    
Entity Incorporation, State or Country Code DE    
Entity Tax Identification Number 35-2108964    
Entity Address, Address Line One 801 East 86th Avenue    
Entity Address, City or Town Merrillville,    
Entity Address, State or Province IN    
Entity Address, Postal Zip Code 46410    
City Area Code (877)    
Local Phone Number 647-5990    
Entity Well-known Seasoned Issuer Yes    
Entity Voluntary Filers No    
Entity Current Reporting Status Yes    
Entity Interactive Data Current Yes    
Entity Filer Category Large Accelerated Filer    
Entity Emerging Growth Company false    
Entity Small Business false    
Entity Shell Company false    
Entity Public Float     $ 10,713,311,150
Entity Common Stock, Shares Outstanding   382,263,348  
Entity Central Index Key 0001111711    
Current Fiscal Year End Date --12-31    
Document Fiscal Year Focus 2019    
Document Fiscal Period Focus FY    
Amendment Flag false    
Documents Incorporated by Reference [Text Block]
Part III of this report incorporates by reference specific portions of the Registrant’s Notice of Annual Meeting and Proxy Statement relating to the Annual Meeting of Stockholders to be held on May 19, 2020.
    
Common Stock      
Document Information [Line Items]      
Title of 12(b) Security Common Stock, par value $0.01 per share    
Trading Symbol NI    
Security Exchange Name NYSE    
Preferred Stock      
Document Information [Line Items]      
Title of 12(b) Security Depositary Shares, each representing a 1/1,000th ownership interest in a share of 6.50% Series B    
Trading Symbol NI PR B    
Security Exchange Name NYSE    
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Statements Of Consolidated Income (Loss) - USD ($)
shares in Thousands, $ in Millions
 12 Months Ended
Dec. 31, 2019
Dec. 31, 2018
Dec. 31, 2017
Operating Revenues      
Customer revenues $ 5,053.4 [1] $ 4,991.1 [1] $ 4,730.2
Other revenues 155.5 123.4 144.4
Total Operating Revenues 5,208.9 5,114.5 4,874.6
Operating Expenses      
Cost of Sales (excluding depreciation and amortization) 1,534.8 1,761.3 1,518.7
Operation and maintenance 1,354.7 2,352.9 1,601.7
Depreciation and amortization 717.4 599.6 570.3
Goodwill and Intangible Asset Impairment 414.5 0.0 0.0
Loss on sale of fixed assets and impairments, net 0.0 1.2 5.5
Other taxes 296.8 274.8 257.2
Total Operating Expenses 4,318.2 4,989.8 3,953.4
Operating Income (Loss) 890.7 124.7 921.2
Other Income (Deductions)      
Interest expense, net (378.9) (353.3) (353.2)
Other, net (5.2) 43.5 (13.5)
Loss on early extinguishment of long-term debt 0.0 (45.5) (111.5)
Total Other Deductions, Net (384.1) (355.3) (478.2)
Income (Loss) before Income Taxes 506.6 (230.6) 443.0
Income Taxes 123.5 (180.0) 314.5
Net Income (Loss) 383.1 (50.6) 128.5
Preferred dividends (55.1) (15.0) 0.0
Net Income (Loss) Available to Common Shareholders $ 328.0 $ (65.6) $ 128.5
Earnings Per Share      
Basic Earnings (Loss) Per Share $ 0.88 $ (0.18) $ 0.39
Diluted Earnings (Loss) Per Share $ 0.87 $ (0.18) $ 0.39
Basic Average Common Shares Outstanding 374,650 356,491 329,388
Diluted Average Common Shares 375,986 356,491 330,756
[1] Customer revenue amounts exclude intersegment revenues. See Note 23, "Segments of Business," for discussion of intersegment revenues.
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Statements of Consolidated Comprehensive Income (Loss) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2019
Dec. 31, 2018
Dec. 31, 2017
Net Income (Loss) $ 383.1 $ (50.6) $ 128.5
Other comprehensive income (loss):      
Net unrealized gain (loss) on available-for-sale securities [1] 5.7 (2.6) 0.8
Net unrealized gain (loss) on cash flow hedges [2] (64.2) 22.7 (22.5)
Unrecognized pension and OPEB benefit (costs) [3] 3.1 (4.4) 3.4
Total other comprehensive income (loss) [4] (55.4) 15.7 (18.3)
Total Comprehensive Income (Loss) $ 327.7 $ (34.9) $ 110.2
[1] Net unrealized gain (loss) on available-for-sale securities, net of $1.5 million tax expense, $0.6 million tax benefit and $0.4 million tax expense in 2019, 2018 and 2017, respectively.
[2] Net unrealized gain (loss) on derivatives qualifying as cash flow hedges, net of $21.2 million tax benefit, $7.5 million tax expense and $13.9 million tax benefit in 2019, 2018 and 2017, respectively.
[3] Unrecognized pension and OPEB benefit (costs), net of $1.6 million tax expense, $1.5 million tax benefit and $2.1 million tax expense in 2019, 2018 and 2017, respectively.
[4] All amounts are net of tax. Amounts in parentheses indicate debits.
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Statements of Consolidated Comprehensive Income (Loss) (Parenthetical) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2019
Dec. 31, 2018
Dec. 31, 2017
Other Comprehensive Income (Loss), Securities, Available-for-Sale, Unrealized Holding Gain (Loss) Arising During Period, Tax $ 1.5 $ (0.6) $ 0.4
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Tax (21.2) 7.5 (13.9)
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, Tax $ (1.6) $ 1.5 $ (2.1)
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Consolidated Balance Sheets - USD ($)
$ in Millions
Dec. 31, 2019
Dec. 31, 2018
Property, Plant and Equipment    
Utility Plant $ 24,502.6 $ 22,780.8
Accumulated depreciation and amortization (7,609.3) (7,257.9)
Net utility plant 16,893.3 15,522.9
Other property, at cost, less accumulated depreciation 18.9 19.6
Net Property, Plant and Equipment 16,912.2 15,542.5
Investments and Other Assets    
Unconsolidated affiliates 1.3 2.1
Other investments 228.9 204.0
Total Investments and Other Assets 230.2 206.1
Current Assets    
Cash and cash equivalents 139.3 112.8
Restricted cash 9.1 8.3
Accounts receivable (less reserve of $19.2 and $21.1, respectively) 856.9 1,058.5
Gas inventory 250.9 286.8
Materials and supplies, at average cost 120.2 101.0
Electric production fuel, at average cost 53.6 34.7
Exchange gas receivable 48.5 88.4
Regulatory assets 225.7 235.4
Prepayments and other 149.7 129.5
Total Current Assets 1,853.9 2,055.4
Other Assets    
Regulatory assets 2,013.9 2,002.1
Goodwill 1,485.9 1,690.7
Intangible assets 0.0 220.7
Deferred charges and other 163.7 86.5
Total Other Assets 3,663.5 4,000.0
Total Assets 22,659.8 21,804.0
Common Stockholders' Equity    
Common stock - $0.01 par value, 600,000,000 shares authorized; 382,135,680 and 372,363,656 shares outstanding, respectively 3.8 3.8
Preferred stock - $0.01 par value, 20,000,000 shares authorized; 440,000 and 420,000 shares outstanding, respectively 880.0 880.0
Treasury stock (99.9) (99.9)
Additional paid-in capital 6,666.2 6,403.5
Retained deficit (1,370.8) (1,399.3)
Accumulated other comprehensive loss [1] (92.6) (37.2)
Total Common Stockholders' Equity 5,986.7 5,750.9
Long-term debt, excluding amounts due within one year 7,856.2 7,105.4
Total Capitalization 13,842.9 12,856.3
Current Liabilities    
Current portion of long-term debt 13.4 50.0
Short-term borrowings 1,773.2 1,977.2
Accounts payable 666.0 883.8
Customer deposits and credits 256.4 238.9
Taxes accrued 231.6 222.7
Interest accrued 99.4 90.7
Exchange gas payable 59.7 85.5
Regulatory liabilities 160.2 140.9
Legal and environmental 20.1 18.9
Accrued compensation and employee benefits 156.3 149.7
Claims accrued 165.4 114.7
Other accruals 144.1 63.8
Total Current Liabilities 3,745.8 4,036.8
Other Liabilities    
Risk management liabilities 134.0 46.7
Deferred income taxes 1,485.3 1,330.5
Deferred investment tax credits 9.7 11.2
Accrued insurance liabilities 81.5 84.4
Accrued liability for postretirement and postemployment benefits 373.2 389.1
Regulatory liabilities 2,352.0 2,519.1
Asset retirement obligations 416.9 352.0
Other noncurrent liabilities 218.5 177.9
Total Other Liabilities 5,071.1 4,910.9
Commitments and Contingencies (Refer to Note 19, Other Commitments and Contingencies) 0.0 0.0
Total Capitalization and Liabilities $ 22,659.8 $ 21,804.0
[1] All amounts are net of tax. Amounts in parentheses indicate debits.
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Consolidated Balance Sheets (Parenthetical) - USD ($)
$ in Millions
Dec. 31, 2019
Dec. 31, 2018
Accounts receivable less reserve $ 19.2 $ 21.1
Common stock, par value $ 0.01 $ 0.01
Common stock, shares authorized 600,000,000 400,000,000
Common stock, shares outstanding 382,135,680 372,363,656
Preferred Stock, Par or Stated Value Per Share $ 0.01 $ 0.01
Preferred Stock, Shares Authorized 20,000,000 20,000,000
Preferred Stock, Shares Outstanding 440,000 420,000
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Statements Of Consolidated Cash Flows - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2019
Dec. 31, 2018
Dec. 31, 2017
Operating Activities      
Net Income (Loss) $ 383.1 $ (50.6) $ 128.5
Adjustments to Reconcile Net Income (Loss) to Net Cash from Operating Activities:      
Loss on early extinguishment of debt 0.0 45.5 111.5
Depreciation and amortization 717.4 599.6 570.3
Deferred income taxes and investment tax credits 118.2 (188.2) 306.7
Stock compensation expense and 401(k) profit sharing contribution 25.9 28.6 40.1
Impairment of goodwill and other intangible assets 414.5 0.0 0.0
Amortization of discount/premium on debt 8.2 7.5 7.4
AFUDC equity (8.0) (14.2) (12.6)
Other adjustments (0.9) 1.7 6.6
Changes in Assets and Liabilities:      
Accounts receivable 187.8 (186.2) (52.3)
Inventories (2.0) 41.4 19.0
Accounts payable (299.9) 268.4 49.0
Customer deposits and credits 16.9 (25.4) (2.5)
Taxes accrued 7.3 20.2 10.2
Interest accrued 8.8 (21.7) (33.9)
Exchange gas receivable/payable 55.5 (21.5) (64.5)
Other accruals 105.3 43.5 31.8
Prepayments and other current assets (33.6) (14.5) (13.3)
Regulatory assets/liabilities (85.6) (53.2) 57.5
Postretirement and postemployment benefits (21.1) 58.2 (380.9)
Deferred charges and other noncurrent assets (76.1) 3.8 (2.0)
Other noncurrent liabilities 61.6 (2.8) (34.4)
Net Cash Flows from Operating Activities 1,583.3 540.1 742.2
Investing Activities      
Capital expenditures (1,802.4) (1,818.2) (1,695.8)
Cost of removal (113.2) (104.3) (109.0)
Purchases of available-for-sale securities (140.4) (90.0) (168.4)
Sales of available-for-sale securities 132.1 82.3 163.1
Other investing activities 1.5 4.1 1.6
Net Cash Flows used for Investing Activities (1,922.4) (1,926.1) (1,808.5)
Financing Activities      
Issuance of long-term debt 750.0 350.0 3,250.0
Repayments of long-term debt and finance lease obligations (51.6) (1,046.1) (1,855.0)
Issuance of short-term debt (maturity 90 days) 600.0 950.0 0.0
Repayments of short-term debt (maturity 90 days) (700.0) 0.0 0.0
Change in short-term borrowings, net (maturity ≤ 90 days) (104.0) (178.5) (282.4)
Issuance of common stock, net of issuance costs 244.4 848.2 336.7
Issuance of preferred stock, net of issuance costs 0.0 880.0 0.0
Equity costs, premiums and other debt related costs (17.8) (46.0) (144.3)
Acquisition of treasury stock 0.0 (4.0) (7.2)
Dividends paid - common stock (298.5) (273.3) (229.1)
Dividends paid - preferred stock (56.1) (11.6) 0.0
Net Cash Flows from Financing Activities 366.4 1,468.7 1,068.7
Change in cash, cash equivalents and restricted cash 27.3 82.7 2.4
Cash, cash equivalents and restricted cash at beginning of period 121.1 38.4 36.0
Cash, Cash Equivalents and Restricted Cash at End of Period $ 148.4 $ 121.1 $ 38.4
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Statements Of Consolidated Stockholders' Equity - USD ($)
$ in Millions
Total
Common Stock
Preferred Stock
Treasury Stock
Additional Paid-in Capital
Retained Deficit
Accumulated Other Comprehensive Loss
Beginning Balance at Dec. 31, 2016 $ 4,071.2 $ 3.3 $ 0.0 [1] $ (88.7) $ 5,153.9 $ (972.2) $ (25.1)
Comprehensive Income (Loss):              
Net Income (Loss) 128.5 0.0 0.0 [1] 0.0 0.0 128.5 0.0
Other Comprehensive Income (Loss), Net of Tax (18.3) [2] 0.0 0.0 [1] 0.0 0.0 0.0 (18.3)
Dividends:              
Common stock (229.4) 0.0 0.0 [1] 0.0 0.0 (229.4) 0.0
Treasury stock acquired (7.2) 0.0 0.0 [1] (7.2) 0.0 0.0 0.0
Stock issuances:              
Employee stock purchase plan 5.0 0.0 0.0 [1] 0.0 5.0 0.0 0.0
Long-term incentive plan 14.9 0.0 0.0 [1] 0.0 14.9 0.0 0.0
401(k) and profit sharing 34.3 0.0 0.0 [1] 0.0 34.3 0.0 0.0
Dividend reinvestment plan 6.4 0.0 0.0 [1] 0.0 6.4 0.0 0.0
ATM Program 314.7 0.1 0.0 [1] 0.0 314.6 0.0 0.0
Ending Balance at Dec. 31, 2017 4,320.1 3.4 0.0 [1] (95.9) 5,529.1 (1,073.1) (43.4)
Dividends:              
Cumulative effect of change in accounting principle | Accounting Standards Update 2018-02 0.0 0.0 0.0 [1] 0.0 0.0 (9.5) 9.5
Net Income (Loss) (50.6) 0.0 0.0 [1] 0.0 0.0 (50.6) 0.0
Other Comprehensive Income (Loss), Net of Tax 15.7 [2] 0.0 0.0 [1] 0.0 0.0 0.0 15.7
Common stock (273.5) 0.0 0.0 [1] 0.0 0.0 (273.5) 0.0
Preferred stock (11.6) 0.0 0.0 [1] 0.0 0.0 (11.6) 0.0
Treasury stock acquired (4.0) 0.0 0.0 [1] (4.0) 0.0 0.0 0.0
Stock issuances:              
Common stock 599.6 0.3 0.0 [1] 0.0 599.3 0.0 0.0
Preferred stock 880.0 0.0 880.0 [1] 0.0 0.0 0.0 0.0
Employee stock purchase plan 5.5 0.0 0.0 [1] 0.0 5.5 0.0 0.0
Long-term incentive plan 15.4 0.0 0.0 [1] 0.0 15.4 0.0 0.0
401(k) and profit sharing 21.8 0.0 0.0 0.0 21.8 0.0 0.0
ATM Program 232.5 0.1 0.0 [1] 0.0 232.4 0.0 0.0
Ending Balance at Dec. 31, 2018 5,750.9 3.8 880.0 [1] (99.9) 6,403.5 (1,399.3) (37.2)
Comprehensive Income (Loss):              
Net Income (Loss) 383.1 0.0 0.0 [1] 0.0 0.0 383.1 0.0
Other Comprehensive Income (Loss), Net of Tax (55.4) [2] 0.0 0.0 [1] 0.0 0.0 0.0 (55.4)
Dividends:              
Common stock (298.5) 0.0 0.0 [1] 0.0 0.0 (298.5) 0.0
Preferred stock (56.1) 0.0 0.0 [1] 0.0 0.0 (56.1) 0.0
Stock issuances:              
Employee stock purchase plan 5.6 0.0 0.0 [1] 0.0 5.6 0.0 0.0
Long-term incentive plan 10.4 0.0 0.0 [1] 0.0 10.4 0.0 0.0
401(k) and profit sharing 17.6 0.0 0.0 [1] 0.0 17.6 0.0 0.0
ATM Program 229.1 0.0 0.0 [1] 0.0 229.1 0.0 0.0
Ending Balance at Dec. 31, 2019 $ 5,986.7 $ 3.8 $ 880.0 [1] $ (99.9) $ 6,666.2 $ (1,370.8) $ (92.6)
[1] Series A and Series B shares have an aggregate liquidation preference of $400M and $500M, respectively. See Note 12, "Equity" for additional information.
[2] All amounts are net of tax. Amounts in parentheses indicate debits.
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Statements Of Consolidated Stockholders' Equity (Shares) - shares
shares in Thousands
Total
Common Stock
Treasury Stock
Preferred Stock
Beginning Balance at Dec. 31, 2016 323,160 326,664 3,504 0
Treasury stock acquired (293) 0 (293) 0
Issued:        
Employee stock purchase plan 207 207 0 0
Long-term incentive plan 351 351 0 0
401(k) and profit sharing plan 1,396 1,396 0 0
Dividend reinvestment plan 264 264 0 0
ATM Program 11,931 11,931 0 0
Ending Balance at Dec. 31, 2017 337,016 340,813 3,797 0
Treasury stock acquired (166) 0 (166) 0
Issued:        
Common stock - private placement 24,964 24,964 0 0
Preferred 0 0 0 420
Employee stock purchase plan 223 223 0 0
Long-term incentive plan 561 561 0 0
401(k) and profit sharing plan 882 882 0 0
ATM Program 8,883 8,883 0 0
Ending Balance at Dec. 31, 2018 372,363 376,326 3,963 420
Issued:        
Preferred 0 0 0 20 [1]
Employee stock purchase plan 201 201 0 0
Long-term incentive plan 518 518 0 0
401(k) and profit sharing plan 631 631 0 0
ATM Program 8,423 8,423 0 0
Ending Balance at Dec. 31, 2019 382,136 386,099 3,963 440
[1] See Note 12, "Equity," for additional information.
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Statements of Consolidated Stockholders' Equity (Parenthetical) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2019
Dec. 31, 2018
Dec. 31, 2017
Common Stock, Dividends, Per Share, Declared $ 0.80 $ 0.78 $ 0.70
Preferred Stock, Dividends Per Share, Declared 0.00 28.88 0.00
Series A Preferred Stock      
Preferred Stock, Dividends Per Share, Declared $ 56.50 28.88 0
Preferred Stock, Liquidation Preference, Value $ 400    
Series B Preferred Stock      
Preferred Stock, Dividends Per Share, Declared $ 1,674.65 $ 0 $ 0
Preferred Stock, Liquidation Preference, Value $ 500    
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Nature of Operations And Summary of Significant Accounting Policies
 12 Months Ended
Dec. 31, 2019
Organization, Consolidation and Presentation of Financial Statements [Abstract]  
Nature of Operations and Summary of Significant Accounting Policies Nature of Operations and Summary of Significant Accounting Policies
A.       Company Structure and Principles of Consolidation.  We are an energy holding company incorporated in Delaware and headquartered in Merrillville, Indiana. Our subsidiaries are fully regulated natural gas and electric utility companies serving approximately 4.0 million customers in seven states. We generate substantially all of our operating income through these rate-regulated businesses. The consolidated financial statements include the accounts of us and our majority-owned subsidiaries after the elimination of all intercompany accounts and transactions.
On February 26, 2020, NiSource and Columbia of Massachusetts entered into the Asset Purchase Agreement with Eversource, a Massachusetts voluntary association. Upon the terms and subject to the conditions set forth in the Asset Purchase Agreement, NiSource and Columbia of Massachusetts agreed to sell to Eversource, with certain additions and exceptions, (1) substantially all of the assets of Columbia of Massachusetts and (2) all of the assets held by any of Columbia of Massachusetts’ affiliates that primarily relate to the business of storing, distributing or transporting natural gas to residential, commercial and industrial customers in Massachusetts, as conducted by Columbia of Massachusetts, and Eversource agreed to assume certain liabilities of Columbia of Massachusetts and its affiliates. For additional information, see Note 26, “Subsequent Event.”
B.       Use of Estimates.    The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
C.       Cash, Cash Equivalents and Restricted Cash.    We consider all highly liquid investments with original maturities of three months or less to be cash equivalents. We report amounts deposited in brokerage accounts for margin requirements as restricted cash. In addition, we have amounts deposited in trust to satisfy requirements for the provision of various property, liability, workers compensation, and long-term disability insurance, which is classified as restricted cash on the Consolidated Balance Sheets and disclosed with cash and cash equivalents on the Statements of Consolidated Cash Flows.
D. Accounts Receivable and Unbilled Revenue.    Accounts receivable on the Consolidated Balance Sheets includes both billed and unbilled amounts. Unbilled amounts of accounts receivable relate to a portion of a customer’s consumption of gas or electricity from 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. Accounts receivable fluctuates from year to year depending in large part on weather impacts and price volatility. Our accounts receivable on the Consolidated Balance Sheets include unbilled revenue, less reserves, in the amounts of $350.5 million and $324.2 million as of December 31, 2019 and 2018, respectively. The reserve for uncollectible receivables is our best estimate of the amount of probable credit losses in the existing accounts receivable. We determined the reserve based on historical experience and in consideration of current market conditions. Account balances are charged against the allowance when it is anticipated the receivable will not be recovered. Refer to Note 3, "Revenue Recognition," for additional information on customer-related accounts receivable.
E.        Investments in Debt Securities.    Our investments in debt securities are carried at fair value and are designated as available-for-sale. These investments are included within “Other investments” on the Consolidated Balance Sheets. Unrealized gains and losses, net of deferred income taxes, are recorded to accumulated other comprehensive income or loss. These investments are monitored for other than temporary declines in market value. Realized gains and losses and permanent impairments are reflected in the Statements of Consolidated Income (Loss). No material impairment charges were recorded for the years ended December 31, 2019, 2018 or 2017. Refer to Note 17, "Fair Value," for additional information.
F.        Basis of Accounting for Rate-Regulated Subsidiaries.    Rate-regulated subsidiaries account for and report assets and liabilities consistent with the economic effect of the way in which regulators establish rates, if the rates established are designed to recover the costs of providing the regulated service and it is probable that such rates can be charged and collected. Certain expenses and credits subject to utility regulation or rate determination normally reflected in income are deferred on the Consolidated Balance Sheets and are later recognized in income as the related amounts are included in customer rates and recovered from or refunded to customers.
In the event that regulation significantly changes the opportunity for us to recover our costs in the future, all or a portion of our regulated operations may no longer meet the criteria for regulatory accounting. In such an event, a write-down of all or a portion of our existing regulatory assets and liabilities could result. If transition cost recovery was approved by the appropriate regulatory bodies that would meet the requirements under GAAP for continued accounting as regulatory assets and liabilities during such recovery period, the regulatory assets and liabilities would be reported at the recoverable amounts. If unable to continue to apply
the provisions of regulatory accounting, we would be required to apply the provisions of ASC 980-20, Discontinuation of Rate-Regulated Accounting. In management’s opinion, our regulated subsidiaries will be subject to regulatory accounting for the foreseeable future. Refer to Note 8, "Regulatory Matters," for additional information.
G.       Plant and Other Property and Related Depreciation and Maintenance.    Property, plant and equipment (principally utility plant) is stated at cost. The rate-regulated subsidiaries record depreciation using composite rates on a straight-line basis over the remaining service lives of the electric, gas and common properties as approved by the appropriate regulators.
Non-utility property is generally depreciated on a straight-line basis over the life of the associated asset. Refer to Note 5, "Property, Plant and Equipment," for additional information related to depreciation expense.
For rate-regulated companies, AFUDC is capitalized on all classes of property except organization costs, land, autos, office equipment, tools and other general property purchases. The allowance is applied to construction costs for that period of time between the date of the expenditure and the date on which such project is placed in service. Our pre-tax rate for AFUDC was 3.0% in 2019, 3.5% in 2018 and 4.0% in 2017.
Generally, our subsidiaries follow the practice of charging maintenance and repairs, including the cost of removal of minor items of property, to expense as incurred. When our subsidiaries retire regulated property, plant and equipment, original cost plus the cost of retirement, less salvage value, is charged to accumulated depreciation. However, when it becomes probable a regulated asset will be retired substantially in advance of its original expected useful life or is abandoned, the cost of the asset and the corresponding accumulated depreciation is recognized as a separate asset. If the asset is still in operation, the net amount is classified as "Other property, at cost, less accumulated depreciation" on the Consolidated Balance Sheets. If the asset is no longer operating, the net amount is classified in "Regulatory assets" on the Consolidated Balance Sheets. If we are able to recover a full return of and on investment, the carrying value of the asset is based on historical cost. If we are not able to recover a full return on investment, a loss on impairment is recognized to the extent the net book value of the asset exceeds the present value of future revenues discounted at the incremental borrowing rate.
When our subsidiaries sell entire regulated operating units, or retire or sell nonregulated properties, the original cost and accumulated depreciation and amortization balances are removed from "Property, Plant and Equipment" on the Consolidated Balance Sheets. Any gain or loss is recorded in earnings, unless otherwise required by the applicable regulatory body. Refer to Note 5, "Property, Plant and Equipment," for further information.
External and internal costs associated with computer software developed for internal use are capitalized. Capitalization of such costs commences upon the completion of the preliminary stage of each project. Once the installed software is ready for its intended use, such capitalized costs are amortized on a straight-line basis generally over a period of five years, except for certain significant enterprise-wide technology investments which are amortized over a ten-year period.
External and internal up-front implementation costs associated with cloud computing arrangements that are service contracts are deferred on the Consolidated Balance Sheets. Once the installed software is ready for its intended use, such deferred costs are amortized on a straight-line basis to "Operation and maintenance," over the minimum term of the contract plus contractually-provided renewal periods that are reasonable expected to be exercised -- generally up to a maximum of five years.
H.        Goodwill and Other Intangible Assets.    Substantially all of our goodwill relates to the excess of cost over the fair value of the net assets acquired in the Columbia acquisition on November 1, 2000. We test our goodwill for impairment annually as of May 1, or more frequently if events and circumstances indicate that goodwill might be impaired. Fair value of our reporting units is determined using a combination of income and market approaches.
We had other intangible assets consisting primarily of franchise rights apart from goodwill that were identified as part of the purchase price allocations associated with the acquisition of Columbia of Massachusetts, which were being amortized on a straight-line basis over forty years from the date of acquisition.
During the fourth quarter of 2019, we impaired goodwill and intangible assets related to Columbia of Massachusetts. See Note 6, "Goodwill and Other Intangible Assets," for additional information.
I.         Accounts Receivable Transfer Program.    Certain of our subsidiaries have agreements with third parties to transfer certain accounts receivable without recourse. These transfers of accounts receivable are accounted for as secured borrowings. The entire gross receivables balance remains on the December 31, 2019 and 2018 Consolidated Balance Sheets and short-term debt is recorded
in the amount of proceeds received from the transferees involved in the transactions. Refer to Note 18, "Transfers of Financial Assets," for further information.
J.        Gas Cost and Fuel Adjustment Clause.    Our regulated subsidiaries defer most differences between gas and fuel purchase costs and the recovery of such costs in revenues, and adjust future billings for such deferrals on a basis consistent with applicable state-approved tariff provisions. These deferred balances are recorded as "Regulatory assets" or "Regulatory liabilities," as appropriate, on the Consolidated Balance Sheets. Refer to Note 8, "Regulatory Matters," for additional information.
K.        Inventory.    Both the LIFO inventory methodology and the weighted average cost methodology are used to value natural gas in storage, as approved by regulators for all of our regulated subsidiaries. Inventory valued using LIFO was $47.2 million and $47.5 million at December 31, 2019 and 2018, respectively. Based on the average cost of gas using the LIFO method, the estimated replacement cost of gas in storage was less than the stated LIFO cost by $25.5 million and $12.2 million at December 31, 2019 and 2018, respectively. Gas inventory valued using the weighted average cost methodology was $203.7 million at December 31, 2019 and $239.3 million at December 31, 2018.
Electric production fuel is valued using the weighted average cost inventory methodology, as approved by NIPSCO's regulator.
Materials and supplies are valued using the weighted average cost inventory methodology.
L.        Accounting for Exchange and Balancing Arrangements of Natural Gas.    Our Gas Distribution Operations segment enters into balancing and exchange arrangements of natural gas as part of its operations and off-system sales programs. We record a receivable or payable for any of our respective cumulative gas imbalances, as well as for any gas inventory borrowed or lent under a Gas Distribution Operations exchange agreement. Exchange gas is valued based on individual regulatory jurisdiction requirements (for example, historical spot rate, spot at the beginning of the month). These receivables and payables are recorded as “Exchange gas receivable” or “Exchange gas payable” on our Consolidated Balance Sheets, as appropriate.
M.         Accounting for Risk Management Activities.    We account for our derivatives and hedging activities in accordance with ASC 815. We recognize all derivatives as either assets or liabilities on the Consolidated Balance Sheets at fair value, unless such contracts are exempted as a normal purchase normal sale under the provisions of the standard. The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and resulting designation.
We have elected not to net fair value amounts for any of our derivative instruments or the fair value amounts recognized for the right to receive cash collateral or obligation to pay cash collateral arising from those derivative instruments recognized at fair value, which are executed with the same counterparty under a master netting arrangement. See Note 9, "Risk Management Activities," for additional information.
N.        Income Taxes and Investment Tax Credits.    We record income taxes to recognize full interperiod tax allocations. Under the asset and liability method, deferred income taxes are provided for the tax consequences of temporary differences by applying enacted statutory tax rates applicable to future years to differences between the financial statement carrying amount and the tax basis of existing assets and liabilities. Investment tax credits associated with regulated operations are deferred and amortized as a reduction to income tax expense over the estimated useful lives of the related properties.
To the extent certain deferred income taxes of the regulated companies are recoverable or payable through future rates, regulatory assets and liabilities have been established. Regulatory assets for income taxes are primarily attributable to property-related tax timing differences for which deferred taxes had not been provided in the past, when regulators did not recognize such taxes as costs in the rate-making process. Regulatory liabilities for income taxes are primarily attributable to the regulated companies’ obligation to refund to ratepayers deferred income taxes provided at rates higher than the current Federal income tax rate. Such property-related amounts are credited to ratepayers using either the average rate assumption method or the reverse South Georgia method. Non property-related amounts are credited to ratepayers consistent with state utility commission direction.
Pursuant to the Internal Revenue Code and relevant state taxing authorities, we and our subsidiaries file consolidated income tax returns for federal and certain state jurisdictions. We and our subsidiaries are parties to a tax sharing agreement. Income taxes recorded by each party represent amounts that would be owed had the party been separately subject to tax.
O.       Environmental Expenditures.    We accrue for costs associated with environmental remediation obligations when the incurrence of such costs is probable and the amounts can be reasonably estimated, regardless of when the expenditures are actually made. The undiscounted estimated future expenditures are based on currently enacted laws and regulations, existing technology and estimated site-specific costs where assumptions may be made about the nature and extent of site contamination, the extent of
cleanup efforts, costs of alternative cleanup methods and other variables. The liability is adjusted as further information is discovered or circumstances change. The accruals for estimated environmental expenditures are recorded on the Consolidated Balance Sheets in “Legal and environmental” for short-term portions of these liabilities and “Other noncurrent liabilities” for the respective long-term portions of these liabilities. Rate-regulated subsidiaries applying regulatory accounting establish regulatory assets on the Consolidated Balance Sheets to the extent that future recovery of environmental remediation costs is probable through the regulatory process. Refer to Note 19, "Other Commitments and Contingencies," for further information.
P.        Excise Taxes. As an agent for some state and local governments, we invoice and collect certain excise taxes levied by state and local governments on customers and record these amounts as liabilities payable to the applicable taxing jurisdiction. Such balances are presented within "Other accruals" on the Consolidated Balance Sheets. These types of taxes collected from customers, comprised largely of sales taxes, are presented on a net basis affecting neither revenues nor cost of sales. We account for excise taxes for which we are liable by recording a liability for the expected tax with a corresponding charge to “Other taxes” expense on the Statements of Consolidated Income (Loss).
Q.        Accrued Insurance Liabilities. We accrue for insurance costs related to workers compensation, automobile, property, general and employment practices liabilities based on the most probable value of each claim. In general, claim values are determined by professional, licensed loss adjusters who consider the facts of the claim, anticipated indemnification and legal expenses, and respective state rules. Claims are reviewed by us at least quarterly and an adjustment is made to the accrual based on the most current information. Refer to Note 19-E "Other Matters" for further information on accrued insurance liabilities related to the Greater Lawrence Incident.
v3.19.3.a.u2
Recent Accounting Pronouncements
 12 Months Ended
Dec. 31, 2019
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]  
New Accounting Pronouncements and Changes in Accounting Principles Recent Accounting Pronouncements
Recently Issued Accounting Pronouncements
We are currently evaluating the impact of certain ASUs on our Consolidated Financial Statements or Notes to Consolidated Financial Statements, which are described below:
Standard
Description
Effective Date
Effect on the financial statements or other significant matters
ASU 2018-14, Compensation—Retirement Benefits—Defined Benefit Plans—General (Subtopic 715-20): Disclosure Framework—Changes to the Disclosure Requirements for Defined Benefit Plans
The pronouncement modifies the disclosure requirements for defined benefit pension or other postretirement benefit plans. The guidance removes disclosures that are no longer considered cost beneficial, clarifies the specific requirements of disclosures and adds disclosure requirements identified as relevant. The modifications affect annual period disclosures and must be applied on a retrospective basis to all periods presented.
Annual periods ending after December 15, 2020. Early adoption is permitted.
We are currently evaluating the effects of this pronouncement on our Notes to Consolidated Financial Statements. We expect to adopt this ASU on its effective date.

ASU 2019-12,
Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes
This pronouncement simplifies the accounting for income taxes by eliminating certain exceptions to the general principles in ASC 740, income taxes. It also improves consistency of application for other areas of the guidance by clarifying and amending existing guidance.
 
Annual periods beginning after December 15, 2020. Early adoption is permitted.
We are currently evaluating the effects of this pronouncement on our Consolidated Financial Statements and Notes to Consolidated Financial Statements. We tentatively expect to adopt this ASU on its effective date.


Recently Adopted Accounting Pronouncements
Standard
Adoption
ASU 2019-01, Leases (Topic 842): Codification Improvements
See Note 16, "Leases," for our discussion of the effects of implementing these standards.
ASU 2018-11, Leases (Topic 842): Targeted Improvements
ASU 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842
ASU 2016-02, Leases (Topic 842)
ASU 2019-04, Codification Improvements to Topic 326, Financial Instruments-Credit Losses, Topic 815, Derivatives and Hedging, and Topic 825, Financial Instruments
In June 2016, the FASB issued ASU 2016-13 that revised the guidance on the impairment of most financial assets and certain other instruments that are not measured at fair value through net income. This ASU replaces the current "incurred loss" model with an "expected loss" model for instruments measured at amortized cost. It also requires entities to record allowances for available-for-sale securities rather than impair the carrying amount of the securities. Subsequent improvements to the estimated credit losses of available-for-sale securities will be recognized immediately in earnings instead of over time as they are under historic guidance.

We adopted this ASU effective January 1, 2020, using a modified retrospective method. Adoption of this standard did not have a material impact on our Consolidated Financial Statements. No material adjustments were made to January 1, 2020 opening balances as a result of adoption. For our investments that are classified as available for sale debt securities, we will recognize impairment using an allowance approach instead of an 'other than temporary' impairment (OTTI) model. Since we do not have amounts previously recognized in other comprehensive income related to previous OTTI charges, provisions of this ASU are adopted prospectively. In regards to our recorded balances of trade receivables that fall within the scope of this ASU, the ASU did not result in any significant modifications to our policies related to recognizing an allowance on our trade receivables. Based on shared risk characteristics, we segregate our trade receivables into separate pools. We will apply separate models to calculate reserves for uncollectible receivables, as well as consider factors other than time to determine whether a credit loss exists. ASC 326 also prescribes additional presentation and disclosure requirements. For reporting periods beginning after January 1, 2020, we will include additional disclosures in our Notes to Consolidated Financial Statements based on qualitative and quantitative assessment of materiality.
ASU 2016-13,  Financial Instruments-Credit Losses (Topic 326)
v3.19.3.a.u2
Revenue Recognition
 12 Months Ended
Dec. 31, 2019
Revenue from Contract with Customer [Abstract]  
Revenue from Contract with Customer Revenue Recognition
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 years ended December 31, 2019 and 2018 as if it had been prepared under historic accounting guidance. We included operating revenue information for the year ended December 31, 2017 for comparability.
Year Ended December 31, (in millions)
 
2019
 
2018
 
2017
Operating Revenues
 
 
 
 
 
 
Gas Distribution
 
$
2,336.1

 
$
2,348.4

 
$
2,063.2

Gas Transportation
 
1,171.3

 
1,055.2

 
1,021.5

Electric
 
1,698.5

 
1,707.4

 
1,785.5

Other
 
3.0

 
3.5

 
4.4

Total Operating Revenues
 
$
5,208.9

 
$
5,114.5

 
$
4,874.6


Beginning in 2018 with the adoption of ASC 606, the Statements of Consolidated Income (Loss) disaggregates “Customer revenues” (i.e. ASC 606 Revenues) from “Other revenues,” both of which are discussed in more detail below.
Customer Revenues. Substantially all of our revenues are tariff-based, which we have concluded is within the scope of ASC 606. Under ASC 606, the recipients of our utility service meet the definition of a customer, while the operating company tariffs represent an agreement that meets the definition of a contract. ASC 606 defines a contract as an agreement between two or more parties, in this case us and the customer, which creates enforceable rights and obligations. In order to be considered a contract, we have determined that it is probable that substantially all of the consideration to which we are entitled from customers will be collected upon satisfaction of performance obligations. We maintain common utility credit risk mitigation practices, including requiring deposits and actively pursuing collection of past due amounts. In addition, our regulated operations utilize certain regulatory mechanisms that facilitate recovery of bad debt costs within tariff-based rates, which provides further evidence of collectibility.
Customers in certain of our jurisdictions participate in programs that allow for a fixed payment each month regardless of usage. Payments received that exceed the value of gas or electricity actually delivered are recorded as a liability and presented in "Customer Deposits and Credits" on the Consolidated Balance Sheets. Amounts in this account are reduced and revenue is recorded when customer usage begins to exceed payments received.
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 "Regulatory Liabilities" on the Consolidated Balance Sheets 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 Statements of Consolidated Income (Loss):
Year Ended December 31, 2019 (in millions)
Gas Distribution Operations
 
Electric Operations
 
Corporate and Other
 
Total
Customer Revenues(1)
 
 
 
 
 
 
 
Residential
$
2,309.0

 
$
481.6

 
$
—

 
$
2,790.6

Commercial
771.3

 
486.6

 
—

 
1,257.9

Industrial
245.2

 
607.7

 
—

 
852.9

Off-system
77.7

 
—

 
—

 
77.7

Miscellaneous
52.0

 
21.5

 
0.8

 
74.3

Total Customer Revenues
$
3,455.2

 
$
1,597.4

 
$
0.8

 
$
5,053.4

Other Revenues
54.5

 
101.0

 
—

 
155.5

Total Operating Revenues
$
3,509.7

 
$
1,698.4

 
$
0.8

 
$
5,208.9

(1) Customer revenue amounts exclude intersegment revenues. See Note 23, "Segments of Business," for discussion of intersegment revenues.
Year Ended December 31, 2018 (in millions)
Gas Distribution Operations
 
Electric Operations
 
Corporate and Other
 
Total
Customer Revenues(1)
 
 
 
 
 
 
 
Residential
$
2,250.0

 
$
494.7

 
$
—

 
$
2,744.7

Commercial
751.9

 
492.7

 
—

 
1,244.6

Industrial
228.0

 
613.6

 
—

 
841.6

Off-system
92.4

 
—

 
—

 
92.4

Miscellaneous
49.7

 
17.4

 
0.7

 
67.8

Total Customer Revenues
$
3,372.0

 
$
1,618.4

 
$
0.7

 
$
4,991.1

Other Revenues
34.4

 
89.0

 
—

 
123.4

Total Operating Revenues
$
3,406.4

 
$
1,707.4

 
$
0.7

 
$
5,114.5

(1) Customer revenue amounts exclude intersegment revenues. See Note 23, "Segments of Business," for discussion of intersegment revenues.
Customer Accounts Receivable. Accounts receivable on our Consolidated Balance Sheets includes both billed and unbilled amounts, as well as certain amounts that are not related to customer revenues. Unbilled amounts of accounts receivable relate to a portion of a customer’s consumption of gas or electricity from the date of the last cycle billing through the last day of the month (balance sheet date). Factors taken into consideration when estimating unbilled revenue include historical usage, customer rates and weather. The opening and closing balances of customer receivables for the years ended December 31, 2019 and 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)
Balance as of December 31, 2018
$
540.5

 
$
349.1

Balance as of December 31, 2019
466.6

 
346.6

Decrease
$
(73.9
)
 
$
(2.5
)
(1) Customer billed receivables decreased due to decreased natural gas costs and warmer weather in 2019 compared to 2018.
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 Statements of Consolidated Income (Loss) 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.
v3.19.3.a.u2
Earnings Per Share
 12 Months Ended
Dec. 31, 2019
Earnings Per Share [Abstract]  
Earnings Per Share Earnings Per Share

Basic EPS is computed by dividing net income attributable to common shareholders by the weighted-average number of shares of common stock outstanding for the period. The weighted-average shares outstanding for diluted EPS includes the incremental effects of the various long-term incentive compensation plans and forward agreements when the impact of such plans and agreements would be dilutive. The calculation of diluted earnings per share for the year ended December 31, 2018 does not include any dilutive potential common shares as we had a net loss on the Statements of Consolidated Income (Loss) for that period, and any incremental shares would have had an anti-dilutive impact on EPS. The calculation of diluted earnings per share for the year ended December 31, 2017 excludes the impact of forward agreements, which had an anti-dilutive effect for that period. The computation of diluted average common shares is as follows:
Year Ended December 31, (in thousands)
2019
 
2018
 
2017
Denominator
 
 
 
 
 
Basic average common shares outstanding
374,650

 
356,491

 
329,388

Dilutive potential common shares:
 
 
 
 
 
Shares contingently issuable under employee stock plans
929

 
—

 
547

Shares restricted under stock plans
154

 
—

 
821

Forward agreements
253

 
—

 
—

Diluted Average Common Shares
375,986

 
356,491

 
330,756
v3.19.3.a.u2
Property, Plant And Equipment
 12 Months Ended
Dec. 31, 2019
Property, Plant and Equipment [Abstract]  
Property, Plant And Equipment Property, Plant and Equipment
Our property, plant and equipment on the Consolidated Balance Sheets are classified as follows: 
At December 31, (in millions)
2019
 
2018
Property, Plant and Equipment
 
 
 
Gas Distribution Utility(1)
$
14,989.7

 
$
13,776.0

Electric Utility(1)
8,902.3

 
8,374.2

Corporate
153.3

 
155.8

Construction Work in Process
457.3

 
474.8

Non-Utility and Other
39.3

 
38.7

Total Property, Plant and Equipment
$
24,541.9

 
$
22,819.5

Accumulated Depreciation and Amortization
 
 
 
Gas Distribution Utility(1)
$
(3,556.0
)
 
$
(3,373.8
)
Electric Utility(1)
(3,973.8
)
 
(3,809.5
)
Corporate
(79.5
)
 
(74.6
)
Non-Utility and Other
(20.4
)
 
(19.1
)
Total Accumulated Depreciation and Amortization
$
(7,629.7
)
 
$
(7,277.0
)
Net Property, Plant and Equipment
$
16,912.2

 
$
15,542.5


(1)NIPSCO’s common utility plant and associated accumulated depreciation and amortization are allocated between Gas Distribution Utility and Electric Utility Property, Plant and Equipment.
The weighted average depreciation provisions for utility plant, as a percentage of the original cost, for the periods ended December 31, 2019, 2018 and 2017 were as follows:
 
2019
 
2018
 
2017
Electric Operations(1)
2.8
%
 
2.9
%
 
3.4
%
Gas Distribution Operations
2.5
%
 
2.2
%
 
2.1
%

(1)Lower depreciation rate beginning in 2018 due to reduced EERM-related depreciation expense and higher depreciable base from transmission assets being placed into service in 2018.
We recognized depreciation expense of $612.2 million, $503.4 million and $501.5 million for the years ended 2019, 2018 and 2017, respectively.
Amortization of Software Costs. We amortized $55.5 million, $54.1 million and $44.0 million in 2019, 2018 and 2017, respectively, related to software costs. Our unamortized software balance was $169.6 million and $159.5 million at December 31, 2019 and 2018, respectively.
Amortization of Cloud Computing Costs. We amortized $1.6 million and $0.1 million in 2019 and 2018, respectively, related to cloud computing costs. Our unamortized cloud computing balance was $14.2 million and $4.9 million at December 31, 2019 and 2018, respectively.
v3.19.3.a.u2
Goodwill and Other Intangible Assets
 12 Months Ended
Dec. 31, 2019
Goodwill and Intangible Assets Disclosure [Abstract]  
Goodwill And Other Intangible Assets Goodwill and Other Intangible Assets
Intangible and Other Long-Lived Assets Impairment. Our intangible assets, apart from goodwill, consist of franchise rights. Franchise rights were identified as part of the purchase price allocations associated with the acquisition in February 1999 of Columbia of Massachusetts. We review our definite-lived intangible assets, along with other long-lived assets (utility plant), for impairment when events or changes in circumstances indicate the assets' fair value might be below their carrying amount.
During the fourth quarter of 2019, in connection with the preparation of the year-end financial statements, we assessed the changes in circumstances that occurred during the quarter to determine if it was more likely than not that the fair value of our long-lived assets (including franchise rights) were below their carrying amount. While there was no single determinative event or factor, the consideration in totality of several factors that developed during the fourth quarter of 2019 led us to conclude that it was more likely than not that the fair value of the Columbia of Massachusetts reporting unit and the value of its long-lived assets was below
its carrying value. These factors included: (i) increased Massachusetts DPU regulatory enforcement activity related to Columbia of Massachusetts during the fourth quarter, including (a) an order imposing work restrictions on Columbia of Massachusetts, impacting Columbia of Massachusetts' infrastructure replacement program, (b) two orders opening public investigations into Columbia of Massachusetts related to the Greater Lawrence Incident and restoration efforts following the incident, and (c) an order defining the scope of the Massachusetts DPU's investigation into the preparation and response of Columbia of Massachusetts related to the incident; (ii) increased uncertainty as to the ability of Columbia of Massachusetts to execute its growth strategy, including utility infrastructure investments, and to obtain timely regulatory outcomes with reasonable rates of return; (iii) further damage to Columbia of Massachusetts' reputation as a result of concerns related to service lines abandoned during the restoration work following the Greater Lawrence Incident and the gas release event in Lawrence, Massachusetts on September 27, 2019; and (iv) the potential sale of the Massachusetts Business. See Note 19, "Other Commitments and Contingencies - C. Legal Proceedings" for more information regarding Massachusetts DPU regulatory enforcement activity. See Note 26, "Subsequent Event" for more information on the potential sale of the Massachusetts Business.
As a result, we performed a year-end impairment test of the held and used long-lived assets in which we compared the book value of the Columbia of Massachusetts asset group to its undiscounted future cash flow and determined the carrying value of the asset group was not recoverable. We estimated the fair value of the Columbia of Massachusetts asset group using a weighting of income and market approaches and determined that the fair value was less than the carrying value. This resulting impairment was allocated to reduce the entire franchise rights book value to its fair value of zero, which resulted in an impairment charge totaling $209.7 million recorded in the Gas Distribution Operations segment.
We also considered if any regulatory assets or ROU assets were probable of disallowance and determined no disallowances were probable. All of Columbia of Massachusetts' regulatory assets represent incurred costs probable of recovery.
As of December 31, 2019 and 2018, the carrying amount of the franchise rights was $0.0 million and $220.7 million (net of accumulated amortization of $221.5 million), respectively. We recorded amortization expense of $11.0 million in 2019, 2018 and 2017 related to our franchise rights intangible asset.
Goodwill. Substantially all of our goodwill relates to the excess of cost over the fair value of the net assets acquired in the Columbia acquisition on November 1, 2000. The following presents our goodwill balance allocated by segment as of December 31, 2019 and 2018:
(in millions)
2019
 
2018
Gas Distribution Operations
$
1,485.9

 
$
1,690.7

Electric Operations
—

 
—

Corporate and Other
—

 
—

Total
$
1,485.9

 
$
1,690.7


For our annual goodwill impairment analysis performed as of May 1, 2019, we completed a qualitative "step 0" analysis for all reporting units other than our Columbia of Massachusetts reporting unit. In the step 0 analysis, we assessed various assumptions, events and circumstances that would have affected the estimated fair value of the applicable reporting units as compared to their baseline May 1, 2016 "step 1" fair value measurement. The results of this assessment indicated that it was not more likely than not that the fair values of these reporting units were less than their respective carrying values, accordingly, no "step 1" analysis was required.
The results of our Columbia of Massachusetts reporting unit were negatively impacted by the Greater Lawrence Incident (see Note 19-C, "Legal Proceedings"). As a result, we completed a quantitative "step 1" analysis for the May 1, 2019 goodwill analysis for this reporting unit. This analysis considered the progress Columbia of Massachusetts had made with its restoration efforts related to the Greater Lawrence Incident, including the replacement of previously repaired equipment and the settlement agreement with the three impacted municipalities, as well as the ability for Columbia of Massachusetts to sustain its infrastructure replacement growth strategy through GSEP and timely rate cases with reasonable rates of return. Consistent with our historical impairment testing of goodwill, fair value of the Columbia of Massachusetts reporting unit was determined based on a weighting of income and market approaches. These approaches require significant judgments, including appropriate long-term growth rates and discount rates for the income approach and appropriate multiples of earnings for peer companies and control premiums for the market approach. These approaches also incorporate the latest available cash flow projections reflecting the estimated ongoing impacts of the Greater Lawrence Incident on Columbia of Massachusetts’ operations. The discount rates were derived using peer company
data compiled with the assistance of a third party valuation services firm. The discount rates used are subject to change based on changes in tax rates at both the state and federal level, debt and equity ratios at each reporting unit and general economic conditions. The long-term growth rate was derived by evaluating historic growth rates, new business and investment opportunities beyond the near term horizon. The long-term growth rate is subject to change depending on inflationary impacts to the U.S. economy and the individual business environments in which each reporting unit operates. The step 1 analysis performed indicated that the fair value of the Columbia of Massachusetts reporting unit exceeds its carrying value. As a result, no impairment charge was recorded as of the May 1, 2019 test date.
Although our annual impairment test is performed during the second quarter, we continue to monitor changes in circumstances that may indicate that it is more likely than not that the fair value of our reporting units is less than the reporting unit carrying value. During the fourth quarter of 2019, in connection with the preparation of the year-end financial statements, we assessed the matters related to Columbia of Massachusetts. These factors were the same fourth quarter circumstances outlined in the intangible and other long-lived assets impairment above.
As a result, a new impairment analysis was required for our Columbia of Massachusetts reporting unit. Consistent with the May 1, 2019 test, fair value of this reporting unit was determined based on a weighting of income and market approaches. The income approach calculated discounted cash flows using updated cash flow projections, discount rates and return on equity assumptions. The market approach applied a combination of comparable company multiples and comparable transactions and used updated cash flow projections. While certain assumptions, such as market multiples, remained unchanged in the year-end test, our cash flow projections, return on equity and rate case assumptions were all unfavorably updated at year-end compared to the May 1, 2019 test. The effects of these unfavorable developments were greater than the favorable change in weighted average cost of capital between the two tests. The year-end impairment analysis indicated that the fair value of the Columbia of Massachusetts reporting unit was below its carrying value. As a result, we reduced the Columbia of Massachusetts reporting unit goodwill balance to zero and recognized a goodwill impairment charge totaling $204.8 million, which is non-deductible for tax purposes.
v3.19.3.a.u2
Asset Retirement Obligations
 12 Months Ended
Dec. 31, 2019
Asset Retirement Obligation [Abstract]  
Asset Retirement Obligations Asset Retirement Obligations
We have recognized asset retirement obligations associated with various legal obligations including costs to remove and dispose of certain construction materials located within many of our facilities, certain costs to retire pipeline, removal costs for certain underground storage tanks, removal of certain pipelines known to contain PCB contamination, closure costs for certain sites including ash ponds, solid waste management units and a landfill, as well as some other nominal asset retirement obligations. We also have a significant obligation associated with the decommissioning of our two hydro facilities located in Indiana. These hydro facilities have an indeterminate life, and as such, no asset retirement obligation has been recorded.
Changes in our liability for asset retirement obligations for the years 2019 and 2018 are presented in the table below:
(in millions)
2019
 
2018
 
Beginning Balance
$
352.0

 
$
268.7

 
Accretion recorded as a regulatory asset/liability
15.7

 
11.1

 
Additions
—

 
63.3

(2) 
Settlements
(5.4
)
 
(5.9
)
 
Change in estimated cash flows 
54.6

(1) 
14.8

(2) 
Ending Balance
$
416.9

 
$
352.0

 

(1)The change in estimated cash flows for 2019 is primarily attributed to changes in estimated costs and settlement timing for electric generating stations and the changes in estimated costs for retirement of gas mains.
(2)In 2018, $59.8 million of additions and $17.7 million of the change in estimated cash flows are attributed to costs associated with refining the CCR compliance plan. See Note 19-D, "Environmental Matters," for additional information on CCRs.
Certain non-legal costs of removal that have been, and continue to be, included in depreciation rates and collected in the customer rates of the rate-regulated subsidiaries are classified as "Regulatory liabilities" on the Consolidated Balance Sheets.
v3.19.3.a.u2
Regulatory Matters
 12 Months Ended
Dec. 31, 2019
Regulatory Assets and Liabilities Disclosure [Abstract]  
Regulatory Matters Regulatory Matters
Regulatory Assets and Liabilities
We follow the accounting and reporting requirements of ASC Topic 980, which provides that regulated entities account for and report assets and liabilities consistent with the economic effect of regulatory rate-making procedures if the rates established are
designed to recover the costs of providing the regulated service and it is probable that such rates can be charged and collected from customers. Certain expenses and credits subject to utility regulation or rate determination normally reflected in income or expense are deferred on the balance sheet and are recognized in the income statement as the related amounts are included in customer rates and recovered from or refunded to customers.
Regulatory assets were comprised of the following items: 
At December 31, (in millions)
2019
 
2018
Regulatory Assets
 
 
 
Unrecognized pension and other postretirement benefit costs (see Note 11)
$
739.1

 
$
798.3

Deferred pension and other postretirement benefit costs (see Note 11)
91.3

 
74.1

Environmental costs (see Note 19-D)
73.4

 
61.5

Regulatory effects of accounting for income taxes (see Note 1-N and Note 10)
234.0

 
233.1

Under-recovered gas and fuel costs (see Note 1-J)
3.9

 
34.7

Depreciation
210.7

 
209.6

Post-in-service carrying charges
219.8

 
206.6

Safety activity costs
118.6

 
91.7

DSM programs
50.1

 
45.5

Bailly Generating Station
221.8

 
244.3

Other
276.9

 
238.1

Total Regulatory Assets
$
2,239.6

 
$
2,237.5


Regulatory liabilities were comprised of the following items: 
At December 31, (in millions)
2019
 
2018
Regulatory Liabilities
 
 
 
Over-recovered gas and fuel costs (see Note 1-J)
$
42.6

 
$
32.0

Cost of removal (see Note 7)
1,047.5

 
1,076.0

Regulatory effects of accounting for income taxes (see Note 1-N and Note 10)
1,307.0

 
1,428.3

Deferred pension and other postretirement benefit costs (see Note 11)
64.7

 
62.7

Other
50.4

 
61.0

Total Regulatory Liabilities
$
2,512.2

 
$
2,660.0


Regulatory assets, including under-recovered gas and fuel cost, of approximately $1,524.3 million as of December 31, 2019 are not earning a return on investment. These costs are recovered over a remaining life of up to 41 years. Regulatory assets of approximately $1,932.4 million include expenses that are recovered as components of the cost of service and are covered by regulatory orders. Regulatory assets of approximately $307.2 million at December 31, 2019, require specific rate action.
Assets:
Unrecognized pension and other postretirement benefit costs. In 2007, we adopted certain updates of ASC 715 which required, among other things, the recognition in other comprehensive income or loss of the actuarial gains or losses and the prior service costs or credits that arise during the period but that are not immediately recognized as components of net periodic benefit costs. Certain subsidiaries defer these gains or losses as a regulatory asset in accordance with regulatory orders or as a result of regulatory precedent, to be recovered through base rates.
Deferred pension and other postretirement benefit costs. Primarily relates to the difference between postretirement expense recorded by certain subsidiaries due to regulatory orders and the postretirement expense recorded in accordance with GAAP. These costs are expected to be collected through future base rates, revenue riders or tracking mechanisms.
Environmental costs. Includes certain recoverable costs of investigating, testing, remediating and other costs related to gas plant sites, disposal sites or other sites onto which material may have migrated. Certain of our companies defer the costs as a regulatory asset in accordance with regulatory orders, to be recovered in future base rates, billing riders or tracking mechanisms.
Regulatory effects of accounting for income taxes. Represents the deferral and under collection of deferred taxes in the rate making process. In prior years, we have lowered customer rates in certain jurisdictions for the benefits of accelerated tax deductions. Amounts are expensed for financial reporting purposes as we recover deferred taxes in the rate making process.
Under-recovered gas and fuel costs. Represents the difference between the costs of gas and fuel and the recovery of such costs in revenue and is used to adjust future billings for such deferrals on a basis consistent with applicable state-approved tariff provisions. Recovery of these costs is achieved through tracking mechanisms.
Depreciation. Represents differences between depreciation expense incurred on a GAAP basis and that prescribed through regulatory order. Significant components of this balance include:
•
Columbia of Ohio depreciation rates. Prior to 2005, the PUCO-approved depreciation rates for rate-making had been lower than those which would have been utilized if Columbia of Ohio were not subject to regulation resulting in the creation of a regulatory asset. In 2005, the PUCO authorized Columbia of Ohio to revise its depreciation accrual rates for the period beginning January 1, 2005. The revised depreciation rates are higher than those which would have been utilized if Columbia of Ohio were not subject to regulation allowing for amortization of the previously created regulatory asset. The amount of depreciation that would have been recorded from 2005 through 2019 had Columbia of Ohio not been subject to rate regulation is a cumulative $923.5 million, $103.8 million less than that reflected in rates. The resulting regulatory asset balance was $27.9 million and $39.5 million as of December 31, 2019 and 2018, respectively.
•
Columbia of Ohio IRP and CEP. Columbia of Ohio also has PUCO approval to defer depreciation and debt-based post-in-service carrying charges (see "Post-in-service carrying charges" below) associated with its IRP and CEP. As of December 31, 2019, depreciation of $31.9 million and $77.2 million was deferred for the respective programs. Depreciation deferral balances for the respective programs as of December 31, 2018 were $29.1 million and $76.0 million. Recovery of the depreciation is approved annually through the IRP and CEP riders. The equivalent of annual depreciation expense, based on the average life of the related assets, is included in the calculation of the IRP and CEP riders approved by the PUCO and billed to customers. Deferred depreciation expense is recognized as the IRP and CEP riders are billed to customers.
•
NIPSCO ECRM. NIPSCO obtained approval from the IURC to recover certain environmental related costs including operation and maintenance and depreciation expense once the environmental facilities become operational. The ECRM deferred charges represent expenses that will be recovered from customers through an annual ECRM Cost Tracker (ECT) which authorizes the collection of deferred balances over a six month period. Depreciation of $15.2 million and $14.4 million was deferred to a regulatory asset as of December 31, 2019 and 2018, respectively. This regulatory asset was included in electric base rates, which was approved by the IURC on December 4, 2019.
•
NIPSCO TDSIC. NIPSCO obtained approval from the IURC to recover costs for certain system modernization projects outside of a base rate proceeding. Eighty percent of the related costs, including depreciation, property taxes, and debt and equity based carrying charges (see "Post-in-service carrying charges" below) are recovered through a semi-annual recovery mechanism. Recovery of these costs will continue through the TDSIC tracker until such assets are included in rate base through a gas or electric base rate case, respectively. The remaining twenty percent of the costs are deferred until the next base rate case. As of December 31, 2019 and 2018, depreciation of $22.0 million and $16.5 million, respectively, was deferred as a regulatory asset.
Post-in-service carrying charges. Represents deferred debt-based carrying charges incurred on certain assets placed into service but not yet included in customer rates. This balance includes:
•
Columbia of Ohio IRP and CEP. See description of IRP and CEP programs above under the heading "Depreciation." As of December 31, 2019 and 2018, Columbia of Ohio had deferred PISCC of $206.4 million and $197.1 million, respectively.
•
NIPSCO TDSIC. See description of TDSIC program above under the heading "Depreciation." Deferral of equity-based carrying charges for the TDSIC program is allowed; however, such amounts are not reflected in regulatory asset balances for financial reporting as equity-based returns do not meet the definition of incurred costs under ASC 980. As of December 31, 2019 and 2018, NIPSCO had deferred PISCC of $13.4 million and $9.5 million, respectively.
Safety activity costs. Represents the difference between costs incurred in eligible safety programs in excess of those being recovered in rates. The eligible cost deferrals represent necessary business expenses incurred in compliance with PHMSA regulations and are targeted to enhance the safety of the pipeline systems. Certain subsidiaries defer the excess costs as a regulatory asset in accordance with regulatory orders and recovery of these costs will be addressed in future base rate proceedings.
DSM programs. Represents costs associated with Gas Distribution Operations and Electric Operations segments' energy efficiency and conservation programs. Costs are recovered through tracking mechanisms.
Bailly Generating Station. Represents the net book value of Units 7 and 8 of Bailly Generating Station that was retired during 2018. These amounts are currently being amortized at a rate consistent with their inclusion in customer rates.
 Liabilities:
Over-recovered gas and fuel costs. Represents the difference between the cost of gas and fuel and the recovery of such costs in revenues and is the basis to adjust future billings for such refunds on a basis consistent with applicable state-approved tariff provisions. Refunding of these revenues is achieved through tracking mechanisms.
Cost of removal. Represents anticipated costs of removal that have been, and continue to be, included in depreciation rates and collected in customer rates of the rate-regulated subsidiaries for future costs to be incurred.
Regulatory effects of accounting for income taxes. Represents amounts owed to customers for deferred taxes collected at a higher rate than the current statutory rates and liabilities associated with accelerated tax deductions owed to customers that are established during the rate making process. Balance includes excess deferred taxes recorded upon implementation of the TCJA in December 2017, net of amounts amortized through 2019.
Deferred pension and other postretirement benefit costs. Primarily represents cash contributions in excess of postretirement benefit expense that is deferred as a regulatory liability by certain subsidiaries in accordance with regulatory orders.
Cost Recovery and Trackers
Comparability of our line item operating results is impacted by regulatory trackers that allow for the recovery in rates of certain costs such as those described below. Increases in the expenses that are the subject of trackers generally result in a corresponding increase in operating revenues and, therefore, have essentially no impact on total operating income results.
Certain costs of our operating companies are significant, recurring in nature and generally outside the control of the operating companies. Some states allow the recovery of such costs through cost tracking mechanisms. Such tracking mechanisms allow for abbreviated regulatory proceedings in order for the operating companies to implement charges and recover appropriate costs. Tracking mechanisms allow for more timely recovery of such costs as compared with more traditional cost recovery mechanisms. Examples of such mechanisms include GCR adjustment mechanisms, tax riders, bad debt recovery mechanisms, electric energy efficiency programs, MISO non-fuel costs and revenues, resource capacity charges, federally mandated costs and environmental-related costs.
A portion of the Gas Distribution revenue is related to the recovery of gas costs, the review and recovery of which occurs through standard regulatory proceedings. All states in our operating area require periodic review of actual gas procurement activity to determine prudence and to permit the recovery of prudently incurred costs related to the supply of gas for customers. Our distribution companies have historically been found prudent in the procurement of gas supplies to serve customers.
A portion of the Electric Operations revenue is related to the recovery of fuel costs to generate power and the fuel costs related to purchased power. These costs are recovered through a FAC, a quarterly regulatory proceeding in Indiana.
Infrastructure Replacement and Federally-Mandated Compliance Programs
All of our operating utility companies have completed rate proceedings involving infrastructure replacement or enhancement, and have embarked upon initiatives to replace significant portions of their operating systems that are nearing the end of their useful lives. Each company's approach to cost recovery is unique, given the different laws, regulations and precedent that exist in each jurisdiction.
Columbia of Ohio, IRP - On December 3, 2008, the PUCO issued an order which established Columbia of Ohio’s IRP. Pursuant to that order, the IRP provides for recovery of costs resulting from: (1) the maintenance, repair and replacement of customer-owned service lines that have been determined by Columbia of Ohio to present an existing or probable hazard to persons and property;
(2) Columbia of Ohio’s replacement of cast iron, wrought iron, unprotected coated steel and bare steel pipe and associated company and customer-owned metallic service lines; (3) the replacement of customer-owned natural gas risers identified by the PUCO as prone to failure; and (4) the installation of AMR devices on all residential and commercial meters served by Columbia of Ohio. Recoverable costs include a return on investment, depreciation and property taxes, offset by specified cost savings. Columbia of Ohio’s five-year IRP plan renewal was last approved on January 31, 2018 for the years 2018-2022.
Columbia of Ohio, CEP - On October 3, 2011, Columbia of Ohio filed an application for approval to establish the CEP that would provide for the deferral of PISCC on those assets placed into service, but not reflected in rates as plant in service, and the deferral of depreciation expense and property taxes directly attributable to the CEP assets for the period October 1, 2011 through December 31, 2012. Capital expenditures covered under this program included those placed into service that were not part of Columbia of Ohio's IRP. CEP was approved by the PUCO on August 29, 2012. Under this program, the PUCO’s approval provided for the deferral of related PISCC, depreciation and property taxes up to the point where the deferred amount, if included in rates, would exceed $1.50 per month impact on the Small General Service class of customers, subject to the PUCO’s determination of the prudence and reasonableness of investments covered under this program in a future regulatory proceeding. Subsequently, on October 3, 2013, the PUCO modified and approved Columbia of Ohio’s application to continue its CEP deferrals in 2013 and succeeding years, subject to the determination of the prudence, reasonableness and magnitude of the deferrals and capital expenditures in a future cost recovery proceeding. On December 1, 2017, Columbia of Ohio filed an application in which it requested authority to implement a rider to begin recovering plant and associated deferrals related to its CEP. On October 25, 2018, a joint stipulation and recommendation was filed to recover CEP investments and deferrals through December 31, 2017, with annual adjustments for capital investments made in subsequent years. Additionally, the signatory parties to the stipulation agreed to a reduction in rates to adjust for the impacts of the Tax Cut Jobs Act and for a base rate case filing to be made by Columbia of Ohio no later than June 30, 2021. On November 28, 2018 the PUCO issued an order unanimously approving the settlement, without modification.
NIPSCO Gas and Electric, TDSIC - On April 30, 2013, the Indiana Governor signed Senate Enrolled Act 560, known as the TDSIC statute, into law. Among other provisions, the TDSIC statute 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, known as the TDSIC mechanism. Recoverable costs include a return on the investment, including AFUDC, PISCC, depreciation and property taxes. The remaining twenty percent of recoverable costs are deferred for future recovery in NIPSCO's next general rate case. This rate adjustment mechanism is typically filed semi-annually and has a cap at an annual increase of two percent of total retail revenues. During the 2019 Legislative session, the Indiana General Assembly amended the TDSIC statute in House Enrolled Act 1470 that was signed into law by the Governor on April 24, 2019. The revisions that became effective on July 1, 2019 permit flexibility in TDSIC Plans between five and seven years in length, permits the IURC to authorize multi-unit projects that do not include specific locations or an exact number of inspections, repairs, or replacements and projects involving advanced technology investments to support the modernization of transmission, distribution, or storage systems. The amendments also authorize termination of TDSIC Plans prior to their expiration and provide that the projects associated with the terminated plan will continue to receive TDSIC treatment until an Order is issued in the utility’s next general rate case, and provide for the ability to seek approval of a new TDSIC Plan. The amended statute also provides that the two percent revenue cap applies to the aggregate of approved TDSIC Plans and requires that the utility file a base rate case at some point during the term of each TDSIC plan. On December 31, 2019, NIPSCO Gas filed a new 6-year TDSIC for the periods 2020 through 2025.
NIPSCO Electric, ECRM - NIPSCO has approval from the IURC to recover certain environmental related costs through an ECT (environmental cost tracker). Under the ECT, NIPSCO is permitted to recover (1) AFUDC and a return on the capital investment expended by NIPSCO to implement environmental compliance plan projects and (2) related operation and maintenance and depreciation expenses once the environmental facilities become operational. All deferred costs associated with ECRM were included in electric rate base and approved by the IURC on December 4, 2019.
NIPSCO Gas and Electric, FMCA - The FMCA statute provides for cost recovery outside of a base rate proceeding for projected federally mandated costs. Once the plan is approved by the IURC, eighty percent of eligible costs can be recovered using a periodic rate adjustment mechanism, known as the FMCA mechanism. Recoverable costs include a return on the investment, including AFUDC, PISCC, mandated operation and maintenance expenses, depreciation and property taxes. The remaining twenty percent of recoverable costs are deferred for future recovery in NIPSCO's next general rate case. Actual costs that exceed the projected
federally mandated costs of the approved compliance project by more than twenty-five percent shall require specific justification by NIPSCO and specific approval by the IURC before being authorized in the next general rate case.
Columbia of Massachusetts, GSEP - 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”). Adopted into the Massachusetts Utility Provisions, G.L. c. 164, § 145, the Act authorizes natural gas distribution companies to file a GSEP for capital investments made on or after January 1, 2015, that are not included in the company’s current rate base as determined in the most recent base rate case, with the Massachusetts DPU to (1) address the replacement or improvement of existing aging natural gas pipeline infrastructure to improve public safety or infrastructure reliability, and (2) reduce the lost and unaccounted for natural gas through a reduction in natural gas system leaks. In addition, the Act provides that the Massachusetts DPU may, after review of the plan, allow the proposed estimated costs of the plan into rates as of May 1 of the subsequent year. Recoverable costs include a return on investment, depreciation and property taxes, offset by identified operations and maintenance cost savings. Beginning with the 2019 GSEP, rates are subject to a capped annual revenue increase of three percent of total annual firm delivery revenues, plus imputed gas revenues for sales and transportation customers, calculated as the product of (1) the historical average cost of gas per therm, and (2) the average weather normalized sales, for the period beginning with 2013 and ending with the most recent year that actual data is available at the time of the October GSEP Plan filing, per the Massachusetts DPU order in Columbia of Massachusetts' 2019 GSEP. Prior to the 2019 GSEP, the annual revenue increase was capped at one and a half percent. At the end of each 12-month period, in May of the subsequent year, Columbia of Massachusetts must file a reconciliation of the amount collected and actual costs. Any over-collection or under-collection balance is passed back to, or recovered from, customers through the surcharge over a 12-month period beginning in November. On October 31, 2019, the Massachusetts DPU issued an order on Columbia of Massachusetts' GSEP reconciliation proceeding finding that, due to pending investigations of the Greater Lawrence Incident and other operational matters, the Massachusetts DPU could not, at this time, make a finding of prudence with respect to the Columbia of Massachusetts' 2018 GSEP investments and deferred the decision on the prudency of the 2018 GSEP investments in the annual GSEP and GSEP reconciliation filings until the investigations by the DPU are complete. The DPU added that its inability to make a finding of prudence did not constitute a finding of imprudence. Once new base rates are established under a base rate proceeding, the GSEP factor is re-set to remove the capital investment and associated revenue reflected in the base rates. Columbia of Massachusetts' current five year GSEP plan for the periods 2019-2023 was approved April 30, 2019.
Columbia of Pennsylvania, DSIC - On February 14, 2012, the Governor of Pennsylvania signed into law Act 11 of 2012, which provided a DSIC mechanism for certain utilities to recover costs related to repair, replacement or improvement of eligible distribution property that has not previously been reflected in rates or rate base. Through a DSIC, a utility may recover the fixed costs of eligible infrastructure incurred during the three months ended one month prior to the effective date of the charge, thereby reducing the historical regulatory lag associated with cost recovery through the traditional rate-making process. On March 14, 2013, the Pennsylvania PUC approved Columbia of Pennsylvania’s petition to implement a DSIC as of April 1, 2013. Accordingly, Columbia of Pennsylvania is authorized to recover the cost of eligible plant associated with repair, replacement or improvement that was not previously reflected in rate base and has been placed in service during the applicable three-month period. After the initial charge is established, the DSIC is updated quarterly to recover the cost of further plant additions and cannot exceed five percent of distribution revenues. Recoverable costs include a return on investment, exclusive of accumulated deferred income taxes from the calculation of rate base, and depreciation. Once new base rates are established under a base rate proceeding, the DSIC is set to zero. Additionally, the DSIC rate is also reset to zero if, in any quarter, the data reflected in the Columbia of Pennsylvania's most recent quarterly financial earnings report show that the utility will earn an overall rate of return that would exceed the allowable rate of return used to calculate its fixed costs under the DSIC mechanism. A utility is exempt from filing a quarterly financial earnings report when a base rate proceeding is pending before the Pennsylvania PUC.
Columbia of Virginia, SAVE - On March 11, 2010, the Virginia Governor signed legislation into law that allows natural gas utilities to implement programs to replace qualifying infrastructure on an expedited basis and provides for timely cost recovery. Known as the SAVE Act, the law allows natural gas utilities to file programs with the VSCC providing a timeline and estimated costs for replacing eligible infrastructure. Eligible infrastructure replacement projects are those that (1) enhance safety or reliability by reducing system integrity risks associated with customer outages, corrosion, equipment failures, material failures, or natural forces; (2) do not increase revenues by directly connecting the infrastructure replacement to new customers; (3) reduce or have the potential to reduce greenhouse gas emissions; (4) are not included in the natural gas utility’s rate base in its most recent rate case; and (5) are commenced on or after January 1, 2010. The SAVE Act provides for recovery of costs associated with the eligible infrastructure through a rate rider. Recoverable costs include a return on investment, depreciation and property taxes. Columbia of Virginia’s current five year SAVE plan was approved by the VSCC in 2016 and amended in 2017 for the years 2016 through 2020 and amended in 2019 for calendar year 2020.
Columbia of Kentucky, SMRP (formerly AMRP) - On October 26, 2009, the Kentucky PSC approved a mechanism for recovering the costs of Columbia of Kentucky’s AMRP not previously reflected in rate base through an annual fixed monthly rate rider filed in October. In its 2013 rate case, Columbia of Kentucky was allowed to base the AMRP rider on the expected annual cost of service. Recoverable costs include a return on investment, depreciation and property taxes, offset by specific cost savings. At the end of each 12-month period, Columbia of Kentucky must file a reconciliation of the amount collected and actual costs. Any over-collection or under-collection balance is passed back to, or recovered from, customers through the surcharge over a 12-month period beginning in June of the subsequent year. Once new base rates are established under a base rate proceeding, the AMRP rider is set to zero. On July 29, 2019, CKY filed its SMRP to clarify approval of low pressure project spend and expand its AMRP to include for recovery of system safety investments, including low pressure project spend. On November 7, 2019, the Commission approved Columbia of Kentucky's request to amend and expand its annual AMRP to become the SMRP.
Columbia of Maryland, STRIDE - On May 2, 2013, the Governor of Maryland signed Senate Bill 8 into law, authorizing gas companies to accelerate recovery of eligible infrastructure replacement, effective June 1, 2013. The STRIDE statute provides recovery for gas pipeline upgrades outside of the context of a base rate proceeding through an annual surcharge, IRIS, as approved by the Maryland PSC. The STRIDE statute directs gas utilities to file a plan to invest in eligible infrastructure replacement projects and to list the specific projects and elements in any such STRIDE plan with the Maryland PSC. The calendar year projected capital projects to be placed into plant in service and included in Columbia of Maryland's surcharge recovery request must satisfy a number of criteria per the statute, including a requirement that they be designed to improve public safety or infrastructure reliability. Columbia of Maryland’s five-year STRIDE Plan renewal for years 2019 through 2023, as with the preceding five years, is focused on replacing (1) existing cast iron and bare steel mains, (2) associated services and meters, and (3) identified prone-to-failure vintage plastic piping. Columbia of Maryland’s IRIS mechanism recovers a return on investment, depreciation and property taxes of the STRIDE-eligible capital infrastructure statutorily capped at $2 per month for residential customers, and proportionally capped for commercial and industrial customer classes, and is reconciled to actual costs on an annual basis. Any over-collection or under-collection balance is passed back to, or recovered from, customers through the surcharge effective in May of the subsequent year, subject to the cap. STRIDE investments, and recovery thereof, are subject to prudency review by the Maryland PSC in the context of quarterly STRIDE update filings and in subsequent rate proceedings where STRIDE assets are rolled into rate base for recovery in base rates.
The following table describes the most recent vintage of our regulatory programs to recover infrastructure replacement and other federally-mandated compliance investments currently in rates and those pending commission approval:
(in millions)
 
 
 
 
 
Company
Program
Incremental Revenue
Incremental Capital Investment
Investment Period
Filed
Status
Rates
Effective
Columbia of Ohio
IRP - 2019(1)
$
18.2

$
199.6

1/18-12/18
February 28, 2019
Approved
April 24, 2019
May 2019
Columbia of Ohio
CEP - 2018
$
74.5

$
659.9

1/11-12/17
December 1, 2017
Approved
November 28, 2018
December 2018
Columbia of Ohio
CEP - 2019
$
15.0

$
121.7

1/18-12/18
February 28, 2019
Approved
August 28, 2019
September 2019
NIPSCO - Gas
TDSIC 9(1)(2)
$
(10.6
)
$
54.4

1/18-6/18
August 28, 2018
Approved
December 27, 2018
January 2019
NIPSCO - Gas
TDSIC 10(3)
$
1.6

$
12.4

7/18-4/19
June 25, 2019
Approved
October 16, 2019
November 2019
NIPSCO - Gas
TDSIC 11(4)
$
(1.7
)
$
38.7

5/19-12/19
February 25, 2020
Order Expected June 2020
July 2020
NIPSCO - Gas
FMCA 1(5)
$
9.9

$
1.5

11/17-9/18
November 30, 2018
Approved
March 27, 2019
April 2019
NIPSCO - Gas
FMCA 2(5)
$
(3.5
)
$
1.8

10/18-3/19
May 29, 2019
Approved September 25, 2019
October 2019
NIPSCO - Gas
FMCA 3(5)
$
0.3

$
43.0

4/19-9/19
November 26, 2019
Order Expected March 2020
April 2020
Columbia of Massachusetts
GSEP - 2019(6)
$
9.6

$
36.0

1/19-12/19
October 31, 2018
Approved
April 30, 2019
May 2019
Columbia of Massachusetts
GSEP - 2020(6)(7)
$
2.4

$
75.0

1/20-12/20
October 31, 2019
Order Expected April 2020
May 2020
Columbia of Virginia
SAVE - 2019
$
2.4

$
36.0

1/19-12/19
August 17, 2018
Approved
October 26, 2018
January 2019
Columbia of Virginia
SAVE - 2020
$
3.8

$
50.0

1/20-12/20
August 15, 2019
Approved December 6, 2019
January 2020
Columbia of Kentucky
AMRP - 2019
$
3.6

$
30.1

1/19-12/19
October 15, 2018
Approved
December 5, 2018
January 2019
Columbia of Kentucky
SMRP - 2020
$
4.2

$
40.4

1/20-12/20
October 15, 2019
Approved December 20, 2019
January 2020
Columbia of Maryland
STRIDE - 2019
$
1.2

$
19.7

1/19-12/19
November 1, 2018
Approved
December 12, 2018
January 2019
Columbia of Maryland
STRIDE - 2020
$
1.3

$
15.0

1/20-12/20
January 29, 2020
Approved
February 19, 2020
February 2020
NIPSCO - Electric
TDSIC - 5(1)
$
15.9

$
58.8

6/18-11/18
January 29, 2019
Approved
June 12, 2019
June 2019
NIPSCO - Electric
TDSIC - 6
$
28.1

$
131.1

12/18-6/19
August 21, 2019
Approved December 18, 2019
January 2020
NIPSCO - Electric
FMCA - 11(5)
$
0.9

$
22.4

9/18-2/19
April 17, 2019
Approved
July 29, 2019
August 2019
NIPSCO - Electric
FMCA - 12(5)
$
1.6

$
4.7

3/19-8/19
October 18, 2019
Approved
January 29, 2020
February 2020
(1)Incremental revenue is net of amounts due back to customers as a result of the TCJA.
(2)Incremental revenue is net of $5.2 million of adjustments in the TDSIC-9 settlement.
(3)Incremental capital and revenue are net of amounts included in the step 2 rates.
(4)Incremental revenue is net of amounts included in the step 2 rates and reflects a more typical filing period.
(5)Incremental revenue is inclusive of tracker eligible operations and maintenance expense.
(6)Due to an order from the Massachusetts DPU on October 3, 2019 imposing work restrictions on Columbia of Massachusetts, Columbia of Massachusetts did not meet the approved projected 2019 GSEP spend of $64 million and associated incremental revenue of $10.7 million. In the 2020 GSEP, Columbia of Massachusetts reduced the projected capital spend for calendar year 2019 to $36 million and the associated incremental revenue in 2019 GSEP to $9.6 million.
(7)Incremental capital investment is anticipated to be lower than $75 million in 2020 due to the Massachusetts DPU imposed work restrictions.
Rate Case Actions
The following table describes current rate case actions as applicable in each of our jurisdictions net of tracker impacts:
(in millions)
 
 
 
 
Company
Requested Incremental Revenue
Approved Incremental Revenue
Filed
Status
Rates
Effective
NIPSCO - Gas(1)
$
138.1

$
105.6

September 27, 2017
Approved
September 19, 2018
October 2018
Columbia of Virginia(2)
$
14.2

$
1.3

August 28, 2018
Approved
June 12, 2019
February 2019
NIPSCO - Electric(3)
$
21.4

$
(53.5
)
October 31, 2018
Approved
December 4, 2019
January 2020
Columbia of Maryland
$
2.5

$
(0.1
)
May 22, 2019
Approved
December 18, 2019
December 2019
(1)Rates were implemented in three steps, with implementation of step 1 rates effective October 1, 2018. Step 2 rates were effective on March 1, 2019, and step 3 rates were effective on January 1, 2020. The step 3 increase was approved based on actual information and revised from $107.3 million to $105.6 million. The IURC’s order also dismissed NIPSCO from phase 2 of the IURC’s TCJA investigation.
(2)Rates, as originally filed, were implemented in February 2019 on an interim basis, subject to refund. The final approved rates, which replaced interim rates, were implemented in July 2019.
(3)An order was received on December 4, 2019, which included the resolution of outstanding TCJA impacts to rates. Incremental revenues decreased due to a reduction in fuel costs associated with the new industrial service structure. Rates will be implemented in two steps, with implementation of step 1 rates effective January 2, 2020 and step 2 rates effective March 2, 2020.
Additional Regulatory Matters
NIPSCO Electric. On March 29, 2018, WCE, which is currently owned by BP p.l.c ("BP") and BP Products North America, which operates the BP Refinery, filed a petition at the IURC asking that the combined operations of WCE and BP be treated as a single premise, and the WCE generation be dedicated primarily to BP Refinery operations beginning in May 2019 as WCE has self-certified as a qualifying facility at FERC. BP Refinery planned to continue to purchase electric service from NIPSCO at a reduced demand level beginning in May 2019; however, a settlement agreement was filed on November 2, 2018 agreeing that BP and WCE would not move forward with construction of a private transmission line to serve BP until conclusion of NIPSCO’s pending electric rate case. The IURC approved the settlement agreement as filed on February 20, 2019. On December 4, 2019, the IURC issued an order in the electric rate case approving the implementation of a new industrial service structure. This resolved the issues included in BP’s original petition.
The December 4, 2019 electric rate case order approved the revenue requirement settlement filed in the case, with the exception of a change in the agreed to return on equity; the approved return on equity is 9.75%. The order included approval of the depreciation rates as requested, as well as authorization to create a regulatory asset upon the retirement of R.M. Schahfer Generating Units 14, 15, 17 and 18 and Michigan City Generating Station Unit 12. The order allows for the recovery of and on the net book value of the units by the end of 2032.
v3.19.3.a.u2
Risk Management Activities
 12 Months Ended
Dec. 31, 2019
Risk Management Activities [Abstract]  
Risk Management Activities Risk Management Activities
We are exposed to certain risks relating to 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 interest rate exposure and limit volatility in the price of natural gas.
Risk management assets and liabilities on our derivatives are presented on the Consolidated Balance Sheets as shown below:
December 31, (in millions)
2019
 
2018
Risk Management Assets - Current(1)
 
 
 
Interest rate risk programs
$
—

 
$
—

Commodity price risk programs
0.6

 
1.1

Total
$
0.6

 
$
1.1

Risk Management Assets - Noncurrent(2)
 
 
 
Interest rate risk programs
$
—

 
$
18.5

Commodity price risk programs
3.8

 
4.4

Total
$
3.8

 
$
22.9

Risk Management Liabilities - Current(3)
 
 
 
Interest rate risk programs
$
—

 
$
—

Commodity price risk programs
12.6

 
5.0

Total
$
12.6

 
$
5.0

Risk Management Liabilities - Noncurrent
 
 
 
Interest rate risk programs
$
76.2

 
$
9.5

Commodity price risk programs
57.8

 
37.2

Total
$
134.0

 
$
46.7

(1)Presented in "Prepayments and other" on the Consolidated Balance Sheets.
(2)Presented in "Deferred charges and other" on the Consolidated Balance Sheets.
(3)Presented in "Other accruals" on the Consolidated Balance Sheets.
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 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 December 31, 2019, we have forward-starting interest rate swaps with an aggregate notional value totaling $500.0 million to hedge the variability in cash flows attributable to changes in the benchmark interest rate during the periods from the effective dates of the swaps to the anticipated dates of forecasted debt issuances, which are expected to take place by the end of 2024. These interest rate swaps are designated as cash flow hedges. The effective portions of the gains and losses related to these swaps are recorded to AOCI and are recognized in "Interest expense, net" concurrently with the recognition of interest expense on the associated debt, once issued. If it becomes probable that a hedged forecasted transaction will no longer occur, the accumulated gains or losses on the derivative will be recognized currently in "Other, net" in the Statements of Consolidated Income (Loss).
The passage of the TCJA and Greater Lawrence Incident led to significant changes to our long-term financing plan. As a result, during 2018, we settled forward-starting interest rate swaps with a notional value of $750.0 million. These derivative contracts were accounted for as cash flow hedges. As part of the transactions, the associated net unrealized gain of $46.2 million was recognized immediately in "Other, net" on the Statements of Consolidated Income (Loss) due to the probability associated with the forecasted borrowing transactions no longer occurring.
There were no amounts excluded from effectiveness testing for derivatives in cash flow hedging relationships at December 31, 2019, 2018 and 2017.
Our derivative instruments measured at fair value as of December 31, 2019 and 2018 do not contain any credit-risk-related contingent features.
v3.19.3.a.u2
Income Taxes
 12 Months Ended
Dec. 31, 2019
Income Tax Disclosure [Abstract]  
Income Taxes Income Taxes
Income Tax Expense
The components of income tax expense (benefit) were as follows: 
Year Ended December 31, (in millions)
2019
 
2018
 
2017
Income Taxes
 
 
 
 
 
Current
 
 
 
 
 
Federal
$
—

 
$
—

 
$
—

State
5.2

 
8.2

 
7.8

Total Current
5.2

 
8.2

 
7.8

Deferred
 
 
 
 
 
Federal
110.7

 
(209.4
)
 
302.7

State
9.0

 
22.2

 
5.0

Total Deferred
119.7

 
(187.2
)
 
307.7

Deferred Investment Credits
(1.4
)
 
(1.0
)
 
(1.0
)
Income Taxes
$
123.5

 
$
(180.0
)
 
$
314.5


Statutory Rate Reconciliation
The following table represents a reconciliation of income tax expense at the statutory federal income tax rate to the actual income tax expense from continuing operations:
Year Ended December 31, (in millions)
2019
 
2018
 
2017
Book income (loss) before income taxes
$
506.6

 
 
 
$
(230.6
)
 
 
 
$
443.0

 
 
Tax expense (benefit) at statutory federal income tax rate
106.5

 
21.0
 %
 
(48.4
)
 
21.0
 %
 
155.0

 
35.0
 %
Increases (reductions) in taxes resulting from:
 
 
 
 
 
 
 
 
 
 
 
State income taxes, net of federal income tax benefit
10.1

 
2.0

 
24.7

 
(10.7
)
 
6.9

 
1.5

Amortization of regulatory liabilities
(29.4
)
 
(5.8
)
 
(29.3
)
 
12.7

 
(2.4
)
 
(0.5
)
Goodwill impairment
43.0

 
8.5

 
—

 
—

 
—

 
—

Fines and penalties
11.5

 
2.3

 
0.2

 
(0.1
)
 
2.8

 
0.6

Charitable contribution carryover
(2.5
)
 
(0.5
)
 
—

 
—

 
(1.2
)
 
(0.3
)
State regulatory proceedings
(9.5
)
 
(1.9
)
 
(127.8
)
 
55.4

 
—

 
—

Remeasurement due to TCJA
—

 
—

 
—

 
—

 
161.1

 
36.4

Employee stock ownership plan dividends and other compensation
(2.0
)
 
(0.4
)
 
(2.2
)
 
1.0

 
(6.5
)
 
(1.5
)
Other adjustments
(4.2
)
 
(0.8
)
 
2.8

 
(1.2
)
 
(1.2
)
 
(0.2
)
Income Taxes
$
123.5

 
24.4
 %
 
$
(180.0
)
 
78.1
 %
 
$
314.5

 
71.0
 %

The effective income tax rates were 24.4%, 78.1% and 71.0% in 2019, 2018 and 2017, respectively. The 53.7% decrease in effective tax rate in 2019 versus 2018 was primarily the result of not having significant income tax decreases resulting from state regulatory proceedings as in 2018. Additionally, there was an increase in the effective tax rate related to the non-cash impairment of goodwill in 2019 related to Columbia of Massachusetts (see Note 6, "Goodwill and Other Intangible Assets" for additional information)
and non-deductible fines and penalties related to the Greater Lawrence Incident (see Note 19, "Legal Proceedings" for additional information). The rate is also impacted by the relative impact of permanent differences on higher pre-tax income.
The 7.1% increase in the overall effective tax rate in 2018 versus 2017 was primarily the result of state regulatory proceedings which resulted in a $127.8 million decrease in federal income taxes offset by a related increase in state income taxes of $7.1 million. Additionally, the increase was driven by a $26.9 million decrease in income taxes related to amortization of the regulatory liability primarily associated with excess deferred taxes.
Net Deferred Income Tax Liability Components
Deferred income taxes result from temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities. The principal components of our net deferred tax liability were as follows: 
At December 31, (in millions)
2019
 
2018
Deferred tax liabilities
 
 
 
Accelerated depreciation and other property differences
$
2,516.9

 
$
2,458.0

Other regulatory assets
381.5

 
375.4

Total Deferred Tax Liabilities
2,898.4

 
2,833.4

Deferred tax assets
 
 
 
Other regulatory liabilities and deferred investment tax credits (including TCJA)
336.1

 
365.5

Pension and other postretirement/postemployment benefits
152.1

 
157.5

Net operating loss carryforward and AMT credit carryforward
765.9

 
849.8

Environmental liabilities
25.4

 
24.4

Other accrued liabilities
35.3

 
37.5

Other, net
98.3

 
68.2

Total Deferred Tax Assets
1,413.1

 
1,502.9

Net Deferred Tax Liabilities
$
1,485.3

 
$
1,330.5


At December 31, 2019, we had $657.1 million of federal net operating loss carryforwards. The federal net operating loss carryforwards are available to offset taxable income and will begin to expire in 2028. We also have $1.6 million of federal alternative minimum tax credit carryforwards which do not expire. In addition, we have $1.4 million in charitable contribution carryforwards to offset future taxable income, which begin to expire in 2023. We also have $107.2 million (net) of state net operating loss carryforwards. Depending on the jurisdiction in which the state net operating loss was generated, the carryforwards will begin to expire in 2028. We believe it is more likely than not that we will realize the benefit from the state net operating loss carryforwards.
Unrecognized Tax Benefits
A reconciliation of the beginning and ending amounts of unrecognized tax benefits is as follows:
Reconciliation of Unrecognized Tax Benefits (in millions)
2019
 
2018
 
2017
Unrecognized Tax Benefits - Opening Balance
$
1.2

 
$
1.4

 
$
2.6

Gross decreases - tax positions in prior period
(0.6
)
 
(0.4
)
 
(1.4
)
Gross increases - current period tax positions
22.6

 
0.2

 
0.2

Unrecognized Tax Benefits - Ending Balance
$
23.2

 
$
1.2

 
$
1.4

Offset for net operating loss carryforwards
(22.6
)
 
—

 
—

Balance - Less Net Operating Loss Carryforwards
$
0.6

 
$
1.2

 
$
1.4


In 2019, we resolved prior unrecognized tax benefits of $0.6 million and established new unrecognized tax benefits related to state matters of $22.6 million. We present accrued interest on unrecognized tax benefits, accrued interest on other income tax liabilities and tax penalties in "Income Taxes" on our Statements of Consolidated Income (Loss). Interest expense recorded on unrecognized tax benefits and other income tax liabilities was immaterial for all periods presented. There were no accruals for penalties recorded in the Statements of Consolidated Income (Loss) for the years ended December 31, 2019, 2018 and 2017, and there were no balances for accrued penalties recorded on the Consolidated Balance Sheets as of December 31, 2019 and 2018.
We are subject to income taxation in the United States and various state jurisdictions, primarily Indiana, Pennsylvania, Kentucky, Massachusetts, Maryland and Virginia.
We participate in the IRS CAP which provides the opportunity to resolve tax matters with the IRS before filing each year's consolidated federal income tax return. As of December 31, 2019, tax years through 2018 have been audited and are effectively closed to further assessment. The audit of tax year 2019 under the CAP program is expected to be completed in 2020.
The statute of limitations in each of the state jurisdictions in which we operate remains open until the years are settled for federal income tax purposes, at which time amended state income tax returns reflecting all federal income tax adjustments are filed. As of December 31, 2019, there were no state income tax audits in progress that would have a material impact on the consolidated financial statements.
In December 22, 2017, the TCJA was signed into law. As a result of the implementation of the TCJA, we remeasured deferred taxes and recognized $161.1 million of income tax expense in our Consolidated Statements of Income (Loss) for the year ended December 31, 2017. The result of this remeasurement was a reduction in the net deferred tax liability of approximately $1.3 billion, including approximately $0.4 billion of regulatory "gross up" to account for over collection of past taxes from customers. Offsetting the reduction in net deferred tax liabilities was an increase in regulatory liabilities of approximately $1.5 billion as of December 31, 2017. In 2018, we received regulatory orders on the treatment of excess deferred taxes from the jurisdictions in which we operate. As a result of these orders, we reduced our regulatory liability related to excess deferred income taxes by $120.7 million (net of tax). This adjustment is reflected in "Income Taxes" on our Consolidated Statements of Income (Loss) for the year ended December 31, 2018.
As of December 31, 2019, we received approval from regulators to return excess deferred taxes in all of our jurisdictions in accordance with regulatory proceedings.
On December 22, 2017, the SEC issued Staff Accounting Bulletin 118 ("SAB 118"), which provides guidance on accounting for tax effects of the TCJA. SAB 118 provides a measurement period that should not extend beyond one year from the TCJA enactment date for companies to complete the accounting under ASC 740. There were no adjustments recorded in the SAB 118 remeasurement period in 2018.
v3.19.3.a.u2
Pension and Other Postretirement Benefits
 12 Months Ended
Dec. 31, 2019
Pension and Other Postretirement Benefits Cost (Reversal of Cost) [Abstract]  
Pension and Other Postretirement Benefits Pension and Other Postretirement Benefits
We provide defined contribution plans and noncontributory defined benefit retirement plans that cover certain of our employees. Benefits under the defined benefit retirement plans reflect the employees’ compensation, years of service and age at retirement. Additionally, we provide health care and life insurance benefits for certain retired employees. The majority of employees may become eligible for these benefits if they reach retirement age while working for us. The expected cost of such benefits is accrued during the employees’ years of service. Current rates of rate-regulated companies include postretirement benefit costs, including amortization of the regulatory assets that arose prior to inclusion of these costs in rates. For most plans, cash contributions are remitted to grantor trusts.
Our Pension and Other Postretirement Benefit Plans’ Asset Management. We employ a liability-driven investing strategy for the pension plan, as noted below. A mix of equities and fixed income investments are used to maximize the long-term return of plan assets and hedge the liabilities at a prudent level of risk. We utilize a total return investment approach for the other postretirement benefit plans. Risk tolerance is established through careful consideration of plan liabilities, plan funded status, and asset class volatility. The investment portfolio contains a diversified blend of equity and fixed income investments. Furthermore, equity investments are diversified across U.S. and non-U.S. stocks, as well as growth, value, small and large capitalizations. Other assets such as private equity funds are used judiciously to enhance long-term returns while improving portfolio diversification. Derivatives may be used to gain market exposure in an efficient and timely manner; however, derivatives may not be used to leverage the portfolio beyond the market value of the underlying assets. Investment risk is measured and monitored on an ongoing basis through quarterly investment portfolio reviews, annual liability measurements, and periodic asset/liability studies.
We utilize a building block approach with proper consideration of diversification and rebalancing in determining the long-term rate of return for plan assets. Historical markets are studied and long-term historical relationships between equities and fixed income are analyzed to ensure that they are consistent with the widely accepted capital market principle that assets with higher volatility generate greater return over the long run. Current market factors, such as inflation and interest rates, are evaluated before long-term capital market assumptions are determined. Peer data and historical returns are reviewed to check for reasonability and appropriateness.
The most important component of an investment strategy is the portfolio asset mix, or the allocation between the various classes of securities available to the pension and other postretirement benefit plans for investment purposes. The asset mix and acceptable minimum and maximum ranges established for our plan assets represents a long-term view and are listed in the table below.
In 2012, a dynamic asset allocation policy for the pension fund was approved. This policy calls for a gradual reduction in the allocation of return-seeking assets (equities, real estate and private equity) and a corresponding increase in the allocation of liability-hedging assets (fixed income) as the funded status of the plans increase above 90% (as measured by the market value of qualified pension plan assets divided by the projected benefit obligations of the qualified pension plans). A new asset-liability study was completed in 2018 resulting in a more conservative glide path and an increase in the allocation to liability-hedging assets held in the portfolio.
As of December 31, 2019, the asset mix and acceptable minimum and maximum ranges established by the policy for the pension and other postretirement benefit plans are as follows:
Asset Mix Policy of Funds:
 
Defined Benefit Pension Plan
 
Postretirement Benefit Plan
Asset Category
Minimum
 
Maximum
 
Minimum
 
Maximum
Domestic Equities
12%
 
32%
 
0%
 
55%
International Equities
6%
 
16%
 
0%
 
25%
Fixed Income
59%
 
71%
 
20%
 
100%
Real Estate
0%
 
7%
 
0%
 
0%
Short-Term Investments/Other
0%
 
15%
 
0%
 
10%

As of December 31, 2018, the asset mix and acceptable minimum and maximum ranges established by the policy for the pension and other postretirement benefit plans were as follows:
Asset Mix Policy of Funds:
 
Defined Benefit Pension Plan
 
Postretirement Benefit Plan
Asset Category
Minimum
 
Maximum
 
Minimum
 
Maximum
Domestic Equities
12%
 
32%
 
0%
 
55%
International Equities
6%
 
16%
 
0%
 
25%
Fixed Income
59%
 
71%
 
20%
 
100%
Real Estate
0%
 
7%
 
0%
 
0%
Short-Term Investments/Other
0%
 
15%
 
0%
 
10%
Pension Plan and Postretirement Plan Asset Mix at December 31, 2019 and December 31, 2018:
 
Defined Benefit
Pension Assets
 
December 31,
2019
 
Postretirement
Benefit Plan Assets
 
December 31,
2019
Asset Class (in millions)
Asset Value
 
% of Total Assets
 
Asset Value
 
% of Total Assets
Domestic Equities
$
446.4

 
21.5
%
 
$
93.8

 
35.9
%
International Equities
205.0

 
9.9
%
 
40.7

 
15.6
%
Fixed Income
1,337.2

 
64.2
%
 
119.5

 
45.7
%
Real Estate
53.9

 
2.6
%
 
—

 
—

Cash/Other
38.4

 
1.8
%
 
7.4

 
2.8
%
Total
$
2,080.9

 
100.0
%
 
$
261.4

 
100.0
%
 
 
 
 
 
 
 
 
 
Defined Benefit Pension Assets
 
December 31,
2018
 
Postretirement Benefit Plan Assets
 
December 31,
2018
Asset Class (in millions)
Asset Value
 
% of Total Assets
 
Asset Value
 
% of Total Assets
Domestic Equities
$
355.5

 
19.0
%
 
$
78.8

 
36.4
%
International Equities
165.5

 
8.9
%
 
17.5

 
8.1
%
Fixed Income
1,241.9

 
66.5
%
 
115.1

 
53.2
%
Real Estate
52.7

 
2.8
%
 
—

 
—

Cash/Other
52.1

 
2.8
%
 
4.9

 
2.3
%
Total
$
1,867.7

 
100.0
%
 
$
216.3

 
100.0
%

The categorization of investments into the asset classes in the table above are based on definitions established by our Benefits Committee.
Fair Value Measurements. The following table sets forth, by level within the fair value hierarchy, the Master Trust and other postretirement benefits investment assets at fair value as of December 31, 2019 and 2018. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Total Master Trust and other postretirement benefits investment assets at fair value classified within Level 3 were $0 million and $86.1 million as of December 31, 2019 and December 31, 2018, respectively. Such amounts were approximately 0% and 4% of the Master Trust and other postretirement benefits’ total investments as reported on the statement of net assets available for benefits at fair value as of December 31, 2019 and 2018, respectively.
Valuation Techniques Used to Determine Fair Value:
Level 1 Measurements
Most common and preferred stocks are traded in active markets on national and international securities exchanges and are valued at closing prices on the last business day of each period presented. Cash is stated at cost which approximates fair value, with the exception of cash held in foreign currencies which fluctuates with changes in the exchange rates. Short-term bills and notes are priced based on quoted market values.
Level 2 Measurements
Most U.S. Government Agency obligations, mortgage/asset-backed securities, and corporate fixed income securities are generally valued by benchmarking model-derived prices to quoted market prices and trade data for identical or comparable securities. To the extent that quoted prices are not available, fair value is determined based on a valuation model that includes inputs such as interest rate yield curves and credit spreads. Securities traded in markets that are not considered active are valued based on quoted market prices, broker or dealer quotations, or alternative pricing sources with reasonable levels of price transparency. Other fixed income includes futures and options which are priced on bid valuation or settlement pricing.
Level 3 Measurements
Investments with unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets and liabilities are classified as level 3 investments.
Not Classified
Commingled funds, private equity limited partnerships and real estate partnerships hold underlying investments that have prices derived from quoted prices in active markets and are not classified within the fair value hierarchy. Instead, these assets are measured at estimated fair value using the net asset value per share of the investments. Commingled funds' underlying assets are principally marketable equity and fixed income securities. Units held in commingled funds are valued at the unit value as reported by the investment managers. Private equity and real estate funds invest in natural resources, commercial real estate and distressed real estate. The fair value of these investments is determined by reference to the funds’ underlying assets.
For the year ended December 31, 2019, there were no significant changes to valuation techniques to determine the fair value of our pension and other postretirement benefits' assets.
Fair Value Measurements at December 31, 2019: 
(in millions)
December 31,
2019
 
Quoted Prices in  Active Markets for
 Identical Assets
(Level 1)
 
Significant Other
Observable Inputs (Level 2)
 
Significant
Unobservable Inputs
 (Level 3)
Pension plan assets:
 
 
 
 
 
 
 
Cash
$
6.7

 
$
6.7

 
$
—

 
$
—

Fixed income securities
 
 
 
 
 
 
 
Government
319.6

 
—

 
319.6

 
—

Corporate
651.8

 
—

 
651.8

 
—

Mutual Funds
 
 
 
 
 
 
 
U.S. multi-strategy
140.5

 
140.5

 
—

 
—

International equities
56.9

 
56.9

 
—

 
—

Private equity limited partnerships(3)
 
 
 
 
 
 
 
U.S. multi-strategy(1)
14.0

 
—

 
—

 
—

International multi-strategy(2)
8.5

 
—

 
—

 
—

Distressed opportunities
0.5

 
—

 
—

 
—

Real estate
53.9

 
—

 
—

 
—

Commingled funds(3)
 
 
 
 
 
 
 
Short-term money markets
14.8

 
—

 
—

 
—

U.S. equities
305.9

 
—

 
—

 
—

International equities
148.1

 
—

 
—

 
—

Fixed income
351.8

 
—

 
—

 
—

Pension plan assets subtotal
2,073.0

 
204.1

 
971.4

 
—

Other postretirement benefit plan assets:
 
 
 
 
 
 
 
Mutual funds
 
 
 
 
 
 
 
U.S. multi-strategy
81.7

 
81.7

 
—

 
—

International equities
20.6

 
20.6

 
—

 
—

Fixed income
119.2

 
119.2

 
—

 
—

Commingled funds(3)
 
 
 
 
 
 
 
Short-term money markets
7.7

 
—

 
—

 
—

U.S. equities
12.1

 
—

 
—

 
—

International equities
20.1

 
—

 
—

 
—

Other postretirement benefit plan assets subtotal
261.4

 
221.5

 
—

 
—

Due to brokers, net(4)
(2.8
)
 
—

 
(2.8
)
 
—

Accrued income/dividends
10.7

 
10.7

 
—

 
—

Total pension and other postretirement benefit plan assets
$
2,342.3

 
$
436.3

 
$
968.6

 
$
—


(1) This class includes limited partnerships/fund of funds that invest in a diverse portfolio of private equity strategies, including buy-outs, venture capital, growth capital, special situations and secondary markets, primarily inside the United States. 
(2) This class includes limited partnerships/fund of funds that invest in diverse portfolio of private equity strategies, including buy-outs, venture capital, growth capital, special situations and secondary markets, primarily outside the United States.
(3) This class of investments is measured at fair value using the net asset value per share and has not been classified in the fair value hierarchy.
(4) This class represents pending trades with brokers.
The table below sets forth a summary of changes in the fair value of the Plan’s Level 3 assets for the year ended December 31, 2019:
 
Balance at
January 1, 
2019
 
Transfers out
(Level 3)(1) 
 
Balance at
December 31,  2019
Private equity limited partnerships
 
 
 
 
 
U.S. multi-strategy
18.5

 
(18.5
)
 
—

International multi-strategy
12.5

 
(12.5
)
 
—

Distressed opportunities
2.4

 
(2.4
)
 
—

Real estate
52.7

 
(52.7
)
 
—

Total
$
86.1

 
$
(86.1
)
 
$
—


(1) Level 3 assets from the prior year were reclassified in the current year presentation and included within the fair value hierarchy table as of December 31, 2019 as “Not Classified" investments for which fair value is measured using net asset value per share, consistent with the definitions described above.
The table below sets forth a summary of unfunded commitments, redemption frequency and redemption notice periods for certain investments that are measured at fair value using the net asset value per share for the year ended December 31, 2019:
(in millions)
Fair Value
 
Redemption Frequency
 
Redemption Notice Period
Commingled Funds
 
 
 
 
 
Short-term money markets
$
22.5

 
Daily
 
1 day
U.S. equities
318.0

 
Monthly
 
1 day
International equities
168.2

 
Monthly
 
10-30 days
Fixed income
351.8

 
Daily
 
3 days
Total
$
860.5

 
 
 
 

Fair Value Measurements at December 31, 2018: 
(in millions)
December 31,
2018
 
Quoted Prices in Active Markets for Identical Assets (Level 1)
 
Significant Other
Observable Inputs (Level 2)
 
Significant
Unobservable Inputs 
(Level 3)
Pension plan assets:
 
 
 
 
 
 
 
Cash
$
9.2

 
$
8.8

 
$
0.4

 
$
—

Equity securities
 
 
 
 
 
 
 
U.S. equities
0.2

 
0.2

 
—

 
—

Fixed income securities
 
 
 
 
 
 
 
Government
250.2

 
—

 
250.2

 
—

Corporate
442.8

 
—

 
442.8

 
—

Mutual Funds
 
 
 
 
 
 
 
U.S. multi-strategy
110.3

 
110.3

 
—

 
—

International equities
43.2

 
43.2

 
—

 
—

Fixed income
166.8

 
166.8

 
—

 
—

Private equity limited partnerships
 
 
 
 
 
 
 
U.S. multi-strategy(1)
18.5

 
—

 
—

 
18.5

International multi-strategy(2)
12.5

 
—

 
—

 
12.5

Distressed opportunities
2.4

 
—

 
—

 
2.4

Real Estate
52.7

 
—

 
—

 
52.7

Commingled funds(3)
 
 
 
 
 
 
 
Short-term money markets
18.3

 
—

 
—

 
—

U.S. equities
245.2

 
—

 
—

 
—

International equities
122.3

 
—

 
—

 
—

Fixed income
365.7

 
—

 
—

 
—

Pension plan assets subtotal
1,860.3

 
329.3

 
693.4

 
86.1

Other postretirement benefit plan assets:
 
 
 
 
 
 
 
Mutual funds
 
 
 
 
 
 
 
U.S. equities
68.4

 
68.4

 
—

 
—

International equities
17.5

 
17.5

 
—

 
—

Fixed income
114.8

 
114.8

 
—

 
—

Commingled funds(3)
 
 
 
 
 
 
 
Short-term money markets
5.2

 
—

 
—

 
—

U.S. equities
10.4

 
—

 
—

 
—

Other postretirement benefit plan assets subtotal
216.3

 
200.7

 
—

 
—

Due to brokers, net(4)
(1.1
)
 
—

 
(1.1
)
 
—

Accrued investment income/dividends
8.6

 
8.6

 
—

 
—

Total pension and other postretirement benefit plan assets
$
2,084.1

 
$
538.6

 
$
692.3

 
$
86.1

(1) This class includes limited partnerships/fund of funds that invest in a diverse portfolio of private equity strategies, including buy-outs, venture capital, growth capital, special situations and secondary markets, primarily inside the United States.
(2) This class includes limited partnerships/fund of funds that invest in a diverse portfolio of private equity strategies, including buy-outs, venture capital, growth capital, special situations and secondary markets, primarily outside the United States.
(3) This class of investments is measured at fair value using the net asset value per share and has not been classified in the fair value hierarchy.
(4) This class represents pending trades with brokers.
The table below sets forth a summary of changes in the fair value of the Plan’s Level 3 assets for the year ended December 31, 2018:
 
Balance at
January 1, 
2018
 
Total gains or
losses (unrealized
/ realized)
 
Purchases
 
(Sales)
 
Balance at
December 31, 
2018
Private equity limited partnerships
 
 
 
 
 
 
 
 
 
U.S. multi-strategy
26.7

 
2.4

 
0.7

 
(11.3
)
 
18.5

International multi-strategy
19.1

 
(0.6
)
 
—

 
(6.0
)
 
12.5

Distress opportunities
3.2

 
(0.8
)
 
—

 
—

 
2.4

Real estate
49.9

 
1.7

 
1.8

 
(0.7
)
 
52.7

Total
$
98.9

 
$
2.7

 
$
2.5

 
$
(18.0
)
 
$
86.1


The table below sets forth a summary of unfunded commitments, redemption frequency and redemption notice periods for certain investments that are measured at fair value using the net asset value per share for the year ended December 31, 2018:
(in millions)
Fair Value
 
Redemption Frequency
 
Redemption Notice Period
Commingled Funds
 
 
 
 
 
Short-term money markets
$
23.5

 
Daily
 
1 day
U.S. equities
255.6

 
Monthly
 
3 days
International equities
122.3

 
Monthly
 
10-30 days
Fixed income
365.7

 
Monthly
 
3 days
Total
$
767.1

 
 
 
 
 
Our Pension and Other Postretirement Benefit Plans’ Funded Status and Related Disclosure. The following table provides a reconciliation of the plans’ funded status and amounts reflected in our Consolidated Balance Sheets at December 31 based on a December 31 measurement date:
 
Pension Benefits
 
Other Postretirement Benefits
(in millions)
2019
 
2018
 
2019
 
2018
Change in projected benefit obligation(1)
 
 
 
 
 
 
 
Benefit obligation at beginning of year
$
1,981.3

 
$
2,192.6

 
$
492.5

 
$
556.3

Service cost
29.2

 
31.3

 
5.1

 
5.0

Interest cost
72.3

 
67.1

 
19.2

 
17.6

Plan participants’ contributions
—

 
—

 
4.8

 
5.7

Plan amendments
—

 
0.2

 
5.1

 
0.1

Actuarial (gain) loss
204.3

 
(103.9
)
 
88.8

 
(51.7
)
Settlement loss
—

 
0.8

 
—

 
—

Benefits paid
(156.6
)
 
(206.8
)
 
(39.5
)
 
(41.1
)
Estimated benefits paid by incurred subsidy
—

 
—

 
0.5

 
0.6

Projected benefit obligation at end of year
$
2,130.5

 
$
1,981.3

 
$
576.5

 
$
492.5

Change in plan assets
 
 
 
 
 
 
 
Fair value of plan assets at beginning of year
$
1,867.7

 
$
2,160.0

 
$
216.3

 
$
262.5

Actual (loss) return on plan assets
366.8

 
(88.4
)
 
56.9

 
(31.8
)
Employer contributions
2.9

 
2.9

 
23.0

 
21.0

Plan participants’ contributions
—

 
—

 
4.7

 
5.7

Benefits paid
(156.5
)
 
(206.8
)
 
(39.5
)
 
(41.1
)
Fair value of plan assets at end of year
$
2,080.9

 
$
1,867.7

 
$
261.4

 
$
216.3

Funded Status at end of year
$
(49.6
)
 
$
(113.6
)
 
$
(315.1
)

$
(276.2
)
Amounts recognized in the statement of financial position consist of:
 
 
 
 
 
 
 
Noncurrent assets
8.2

 
—

 
—

 
—

Current liabilities
(3.0
)
 
(3.0
)
 
(0.8
)
 
(0.8
)
Noncurrent liabilities
(54.8
)
 
(110.6
)
 
(314.3
)
 
(275.4
)
Net amount recognized at end of year(2)
$
(49.6
)
 
$
(113.6
)
 
$
(315.1
)
 
$
(276.2
)
Amounts recognized in accumulated other comprehensive income or regulatory asset/liability(3)
 
 
 
 
 
 
 
Unrecognized prior service credit
$
3.0

 
$
3.2

 
$
(10.7
)
 
$
(19.0
)
Unrecognized actuarial loss
652.8

 
761.2

 
118.4

 
75.3

 Net amount recognized at end of year
$
655.8

 
$
764.4

 
$
107.7

 
$
56.3


(1) The change in benefit obligation for Pension Benefits represents the change in Projected Benefit Obligation while the change in benefit obligation for Other Postretirement Benefits represents the change in accumulated postretirement benefit obligation.
(2) We recognize our Consolidated Balance Sheets underfunded and overfunded status of our various defined benefit postretirement plans, measured as the difference between the fair value of the plan assets and the benefit obligation.
(3) We determined that for certain rate-regulated subsidiaries the future recovery of pension and other postretirement benefits costs is probable. These rate-regulated subsidiaries recorded regulatory assets and liabilities of $739.1 million and $0.1 million, respectively, as of December 31, 2019, and $798.3 million and $0.1 million, respectively, as of December 31, 2018 that would otherwise have been recorded to accumulated other comprehensive loss.
Our accumulated benefit obligation for our pension plans was $2,111.5 million and $1,965.6 million as of December 31, 2019 and 2018, respectively. The accumulated benefit obligation as of a date is the actuarial present value of benefits attributed by the pension benefit formula to employee service rendered prior to that date and based on current and past compensation levels. The accumulated benefit obligation differs from the projected benefit obligation disclosed in the table above in that it includes no assumptions about future compensation levels. 
We are required to reflect the funded status of the pension and postretirement benefit plans on the Consolidated Balance Sheet. The funded status of the plans is measured as the difference between the plan assets' fair value and the projected benefit obligation. We present the noncurrent aggregate of all underfunded plans within "Accrued liability for postretirement and postemployment benefits." The portion of the amount by which the actuarial present value of benefits included in the projected benefit obligation
exceeds the fair value of plan assets, payable in the next 12 months, is reflected in "Accrued compensation and other benefits." We present the aggregate of all overfunded plans within "Deferred charges and other."
Information for pension plans with a projected benefit obligation in excess of plan assets:
 
December 31,
 
2019
 
2018
Accumulated Benefit Obligation
$
1,473.9

 
$
1,965.6

Funded Status
 
 
 
Projected Benefit Obligation
1,492.9

 
1,981.3

Fair Value of Plan Assets
1,435.1

 
1,867.7

Funded Status of Underfunded Pension Plans at End of Year
$
(57.8
)
 
$
(113.6
)
Information for pension plans with plan assets in excess of the projected benefit obligation:
 
December 31,
 
2019
 
2018
Accumulated Benefit Obligation
$
637.6

 
$
—

Funded Status
 
 
 
Projected Benefit Obligation
637.6

 
—

Fair Value of Plan Assets
645.8

 
—

Funded Status of Overfunded Pension Plans at End of Year
$
8.2

 
$
—


Our pension plans were underfunded, in aggregate, by $49.6 million at December 31, 2019 compared to being underfunded by $113.6 million at December 31, 2018. The improvement in the funded status was due primarily to favorable asset returns offset by a decrease in discount rates. We contributed $2.9 million to our pension plans in both 2019 and 2018.
Our other postretirement benefit plans were underfunded by $315.1 million at December 31, 2019 compared to being underfunded by $276.2 million at December 31, 2018. The decline in funded status was primarily due to a decrease in discount rates offset by favorable asset returns. We contributed $23.0 million and $21.0 million to our other postretirement benefit plans in 2019 and 2018, respectively.
No amounts of our pension or other postretirement benefit plans’ assets are expected to be returned to us or any of our subsidiaries in 2019.
In 2019 and 2018, some of our qualified pension plans paid lump sum payouts in excess of the respective plan's service cost plus interest cost, thereby meeting the requirement for settlement accounting. We recorded settlement charges of $9.5 million and $18.5 million in 2019 and 2018, respectively. Net periodic pension benefit cost for 2019 was decreased by $0.7 million as a result of the interim remeasurement.
The following table provides the key assumptions that were used to calculate the pension and other postretirement benefits obligations for our various plans as of December 31:
 
Pension Benefits
 
Other Postretirement  Benefits
  
2019
 
2018
 
2019
 
2018
Weighted-average assumptions to Determine Benefit Obligation
 
 
 
 
 
 
 
Discount Rate
3.12
%
 
4.26
%
 
3.21
%
 
4.31
%
Rate of Compensation Increases
4.00
%
 
4.00
%
 
—

 
—

Health Care Trend Rates
 
 
 
 
 
 
 
Trend for Next Year
—

 
—

 
6.68
%
 
8.48
%
Ultimate Trend
—

 
—

 
4.50
%
 
4.50
%
Year Ultimate Trend Reached
—

 
—

 
2028

 
2026


Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects:
(in millions)
1% point increase
 
1% point decrease
Effect on service and interest components of net periodic cost
$
1.2

 
$
(1.1
)
Effect on accumulated postretirement benefit obligation
30.1

 
(26.3
)

We expect to make contributions of approximately $3.0 million to our pension plans and approximately $24.0 million to our postretirement medical and life plans in 2020.
The following table provides benefits expected to be paid in each of the next five fiscal years, and in the aggregate for the five fiscal years thereafter. The expected benefits are estimated based on the same assumptions used to measure our benefit obligation at the end of the year and include benefits attributable to the estimated future service of employees:
(in millions)
Pension Benefits
 
Other
Postretirement Benefits
 
Federal
Subsidy Receipts
Year(s)
 
 
 
 
 
2020
$
178.8

 
$
38.1

 
$
0.5

2021
177.8

 
38.6

 
0.4

2022
175.8

 
38.4

 
0.4

2023
168.5

 
38.1

 
0.4

2024
164.4

 
37.9

 
0.4

2025-2029
723.7

 
181.0

 
1.5


The following table provides the components of the plans’ actuarially determined net periodic benefits cost for each of the three years ended December 31, 2019, 2018 and 2017:
 
Pension Benefits
 
Other Postretirement
Benefits
(in millions)
2019
 
2018
 
2017
 
2019
 
2018
 
2017
Components of Net Periodic Benefit Cost(1)
 
 
 
 
 
 
 
 
 
 
 
Service cost
$
29.2

 
$
31.3

 
$
30.0

 
$
5.1

 
$
5.0

 
$
4.8

Interest cost
72.3

 
67.1

 
68.3

 
19.2

 
17.6

 
17.8

Expected return on assets
(108.8
)
 
(142.3
)
 
(123.1
)
 
(13.1
)
 
(14.9
)
 
(15.9
)
Amortization of prior service cost (credit)
0.2

 
(0.4
)
 
(0.7
)
 
(3.2
)
 
(4.0
)
 
(4.4
)
Recognized actuarial loss
45.2

 
40.6

 
52.9

 
2.0

 
3.8

 
3.0

Settlement loss
9.5

 
18.5

 
13.7

 
—

 
—

 
—

Total Net Periodic Benefits Cost
$
47.6

 
$
14.8

 
$
41.1

 
$
10.0

 
$
7.5

 
$
5.3


(1)Service cost is presented in "Operation and maintenance" on the Statements of Consolidated Income (Loss). Non-service cost components are presented within "Other, net."
The following table provides the key assumptions that were used to calculate the net periodic benefits cost for our various plans:
 
Pension Benefits
 
 Other Postretirement
Benefits
  
2019
 
2018
 
2017
 
2019
 
2018
 
2017
Weighted-average Assumptions to Determine Net Periodic Benefit Cost
 
 
 
 
 
 
 
 
 
 
 
Discount rate - service cost(1)
4.48
%
 
3.79
%
 
4.40
%
 
4.59
%
 
3.89
%
 
4.58
%
Discount rate - interest cost(1)
3.84
%
 
3.15
%
 
3.31
%
 
3.94
%
 
3.27
%
 
3.48
%
Expected Long-Term Rate of Return on Plan Assets
6.10
%
 
7.00
%
 
7.25
%
 
5.83
%
 
5.80
%
 
6.99
%
Rate of Compensation Increases
4.00
%
 
4.00
%
 
4.00
%
 
—

 
—

 
—

(1)  In January 2017, we changed the method used to estimate the service and interest components of net periodic benefit cost for pension and other postretirement benefits. This change, compared to the previous method, resulted in a decrease in the actuarially-determined service and interest cost components. Historically, we estimated service and interest cost utilizing a single weighted-average discount rate derived from the yield curve used to measure the benefit obligation at the beginning of the period. For fiscal 2017 and beyond, we now utilize a full yield curve approach to estimate these components by applying the specific spot rates along the yield curve used in the determination of the benefit obligation to the relevant projected cash flows.
We believe it is appropriate to assume a 6.10% and 5.83% rate of return on pension and other postretirement plan assets, respectively, for our calculation of 2019 pension benefits cost. These rates are primarily based on asset mix and historical rates of return and were adjusted in the current year due to anticipated changes in asset allocation and projected market returns.
The following table provides other changes in plan assets and projected benefit obligations recognized in other comprehensive income or regulatory asset or liability:
  
Pension Benefits
 
Other Postretirement
Benefits
(in millions)
2019
 
2018
 
2019
 
2018
Other Changes in Plan Assets and Projected Benefit Obligations Recognized in Other Comprehensive Income or Regulatory Asset or Liability
 
 
 
 
 
 
 
Net prior service cost
$
—

 
$
0.2

 
$
5.1

 
$
0.1

Net actuarial loss (gain)
(53.8
)
 
127.5

 
45.1

 
(5.0
)
Settlements
(9.5
)
 
(18.5
)
 
—

 
—

Less: amortization of prior service cost
(0.2
)
 
0.4

 
3.2

 
4.0

Less: amortization of net actuarial loss
(45.2
)
 
(40.6
)
 
(2.0
)
 
(3.8
)
Total Recognized in Other Comprehensive Income or Regulatory Asset or  Liability
$
(108.7
)
 
$
69.0

 
$
51.4

 
$
(4.7
)
Amount Recognized in Net Periodic Benefits Cost and Other Comprehensive Income or Regulatory Asset or Liability
$
(61.1
)
 
$
83.8

 
$
61.4

 
$
2.8


Based on a December 31 measurement date, the estimated net unrecognized actuarial loss, unrecognized prior service cost, and unrecognized transition obligation that will be amortized into net periodic benefit cost during 2020 for the pension plans are $34.7 million, $0.8 million and zero, respectively, and for other postretirement benefit plans are $4.9 million, $(1.8) million and zero, respectively.
v3.19.3.a.u2
Equity
 12 Months Ended
Dec. 31, 2019
Equity [Abstract]  
Equity Equity
We raise equity financing through a variety of programs including traditional common equity issuances and preferred stock issuances. As of December 31, 2019, we had 600,000,000 shares of common stock and 20,000,000 shares of preferred stock authorized for issuance, of which 382,135,680 shares of common stock and 440,000 shares of preferred stock are currently outstanding.
Holders of shares of our common stock are entitled to receive dividends when, as and if declared by the Board out of funds legally available. The policy of the Board has been to declare cash dividends on a quarterly basis payable on or about the 20th day of February, May, August and November. We have paid quarterly common dividends totaling $0.80, $0.78, and $0.70 per share for the years ended December 31, 2019, 2018 and 2017, respectively. Our Board declared a quarterly common dividend of $0.21 per share, payable on February 20, 2020 to holders of record on February 11, 2020. We have certain debt covenants which could potentially limit the amount of dividends the Company could pay in order to maintain compliance with these covenants. Refer to Note 14, "Long-Term Debt," for more information. As of December 31, 2019, these covenants did not restrict the amount of dividends that were available to be paid.
Dividends paid to preferred shareholders vary based on the series of preferred stock owned. Additional information is provided below. Holders of our shares of common stock are subject to the prior dividend rights of holders of our preferred stock or the depositary shares representing such preferred stock outstanding, and if full dividends have not been declared and paid on all outstanding shares of preferred stock in any dividend period, no dividend may be declared or paid or set aside for payment on our common stock.
Common and preferred stock activity for 2019, 2018 and 2017 is described further below:
ATM Program and Forward Sale Agreements. On May 3, 2017, we entered into four separate equity distribution agreements, pursuant to which we were able to sell up to an aggregate of $500.0 million of our common stock.
On November 13, 2017, under the ATM program, we executed a forward agreement, which allowed us to issue a fixed number of shares at a price to be settled in the future. On November 6, 2018, the forward agreement was settled for $26.43 per share, resulting in $167.7 million of net proceeds. The equity distribution agreements entered into on May 3, 2017 expired December 31, 2018.
On November 1, 2018, we entered into five separate equity distribution agreements pursuant to which we were able to sell up to an aggregate of $500.0 million of our common stock. Four of these agreements were then amended on August 1, 2019 and one was terminated, pursuant to which we may sell, from time to time, up to an aggregate of $434.4 million of our common stock.
On December 6, 2018, under the ATM program, we executed a forward agreement, which allowed us to issue a fixed number of shares at a price to be settled in the future. From December 6, 2018 to December 10, 2018, 4,708,098 shares were borrowed from third parties and sold by the dealer at a weighted average price of $26.55 per share. On November 21, 2019, the forward agreement was settled for $26.01 per share, resulting in $122.5 million of net proceeds.
On August 12, 2019, under the ATM program, we executed a separate forward agreement, which allowed us to issue a fixed number of shares at a price to be settled in the future. From August 12, 2019 to September 13, 2019, 3,714,400 shares were borrowed from third parties and sold by the dealer at a weighted average price of $29.26 per share. On December 11, 2019, the forward agreement was settled for $28.83 per share, resulting in $107.1 million of net proceeds.
As of December 31, 2019, the ATM program had approximately $200.7 million of equity available for issuance. The program expires on December 31, 2020.
The following table summarizes our activity under the ATM program:
Year Ending December 31,
2019
 
2018
 
2017
Number of shares issued
8,422,498

 
8,883,014

 
11,931,376

Average price per share
$
27.75

 
$
26.85

 
$
26.58

Proceeds, net of fees (in millions)
$
229.1

 
$
232.5

 
$
314.7


Private Placement of Common Stock. On May 4, 2018, we completed the sale of 24,964,163 shares of $0.01 par value common stock at a price of $24.28 per share in a private placement to selected institutional and accredited investors. The private placement resulted in $606.0 million of gross proceeds or $599.6 million of net proceeds, after deducting commissions and sale expenses. The common stock issued in connection with the private placement was registered on Form S-1, filed with the SEC on May 11, 2018.
Preferred Stock. On June 11, 2018, we completed the sale of 400,000 shares of 5.650% Series A Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Stock (the "Series A Preferred Stock") at a price of $1,000 per share. The transaction resulted in $400.0 million of gross proceeds or $393.9 million of net proceeds, after deducting commissions and sale expenses. The Series A Preferred Stock was issued in a private placement pursuant to SEC Rule 144A. On December 13, 2018, we filed a registration statement with the SEC enabling holders to exchange their unregistered shares of Series A Preferred Stock for publicly registered shares with substantially identical terms.
Proceeds from the issuance of the Series A Preferred Stock were used to pay a portion of the notes tendered in June 2018 and the redemption of the remaining notes in July 2018. See Note 14, “Long-term Debt” for additional information regarding the tender offer and redemption.
Dividends on the Series A Preferred Stock accrue and are cumulative from the date the shares of Series A Preferred Stock were originally issued to, but not including, June 15, 2023 at a rate of 5.650% per annum of the $1,000 liquidation preference per share. On and after June 15, 2023, dividends on the Series A Preferred Stock will accumulate for each five year period at a percentage of the $1,000 liquidation preference equal to the five-year U.S. Treasury Rate plus (i) in respect of each five year period commencing on or after June 15, 2023 but before June 15, 2043, a spread of 2.843% (the “Initial Margin”), and (ii) in respect of each five year period commencing on or after June 15, 2043, the Initial Margin plus 1.000%. The Series A Preferred Stock may be redeemed by us at our option on June 15, 2023, or on each date falling on the fifth anniversary thereafter, or in connection with a ratings event (as defined in the Certificate of Designation of the Series A Preferred Stock).
As of December 31, 2019 and 2018, Series A Preferred Stock had $1.0 million of cumulative preferred dividends in arrears, or $2.51 per share.
Holders of Series A Preferred Stock generally have no voting rights, except for limited voting rights with respect to (i) potential amendments to our certificate of incorporation that would have a material adverse effect on the existing preferences, rights, powers or duties of the Series A Preferred Stock, (ii) the creation or issuance of any security ranking on a parity with the Series A Preferred Stock if the cumulative dividends payable on then outstanding Series A Preferred Stock are in arrears, or (iii) the creation or issuance of any security ranking senior to the Series A Preferred Stock. The Series A Preferred Stock does not have a stated maturity and is not subject to mandatory redemption or any sinking fund. The Series A Preferred Stock will remain outstanding indefinitely unless repurchased or redeemed by us. Any such redemption would be effected only out of funds legally available for such purposes and will be subject to compliance with the provisions of our outstanding indebtedness.
On December 5, 2018, we completed the sale of 20,000,000 depositary shares with an aggregate liquidation preference of $500,000,000 under the Company’s registration statement on Form S-3. Each depositary share represents 1/1,000th ownership interest in a share of our 6.500% Series B Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Stock, liquidation preference $25,000 per share (equivalent to $25 per depositary share) (the “Series B Preferred Stock"). The transaction resulted in $500.0 million of gross proceeds or $486.1 million of net proceeds, after deducting commissions and sale expenses.
Dividends on the Series B Preferred Stock accrue and are cumulative from the date the shares of Series B Preferred Stock were originally issued to, but not including, March 15, 2024 at a rate of 6.500% per annum of the $25,000 liquidation preference per share. On and after March 15, 2024, dividends on the Series B Preferred Stock will accumulate for each five year period at a percentage of the $25,000 liquidation preference equal to the five-year U.S. Treasury Rate plus (i) in respect of each five year period commencing on or after March 15, 2024 but before March 15, 2044, a spread of 3.632% (the “Initial Margin”), and (ii) in respect of each five year period commencing on or after March 15, 2044, the Initial Margin plus 1.000%. The Series B Preferred Stock may be redeemed by us at our option on March 15, 2024, or on each date falling on the fifth anniversary thereafter, or in connection with a ratings event (as defined in the Certificate of Designation of the Series B Preferred Stock).
As of December 31, 2019 and 2018, Series B Preferred Stock had $1.4 million and $2.4 million, respectively, of cumulative preferred dividends in arrears, or $72.23 and $121.88 per share, respectively.
In addition, we issued 20,000 shares of “Series B-1 Preferred Stock”, par value $0.01 per share, (“Series B-1 Preferred Stock”), as a distribution with respect to the Series B Preferred Stock. As a result, each of the depositary shares issued on December 5, 2018 now represents a 1/1,000th ownership interest in a share of Series B Preferred Stock and a 1/1,000th ownership interest in a share of Series B-1 Preferred Stock. We issued the Series B-1 Preferred Stock to enhance the voting rights of the Series B Preferred Stock to comply with the minimum voting rights policy of the New York Stock Exchange. The Series B-1 Preferred Stock is paired with the Series B Preferred Stock and may not be transferred, redeemed or repurchased except in connection with the simultaneous transfer, redemption or repurchase of a like number of shares of the underlying Series B Preferred Stock.
Holders of Series B Preferred Stock generally have no voting rights, except for limited voting rights with respect to (i) potential amendments to our certificate of incorporation that would have a material adverse effect on the existing preferences, rights, powers or duties of the Series B Preferred Stock, (ii) the creation or issuance of any security ranking on a parity with the Series B Preferred Stock if the cumulative dividends payable on then outstanding Series B Preferred Stock are in arrears, or (iii) the creation or issuance of any security ranking senior to the Series B Preferred Stock. In addition, if and whenever dividends on any shares of Series B Preferred Stock shall not have been declared and paid for at least six dividend periods, whether or not consecutive, the number of directors then constituting our Board of Directors shall automatically be increased by two until all accumulated and unpaid dividends on the Series B Preferred Stock shall have been paid in full, and the holders of Series B-1 Preferred Stock, voting as a class together with the holders of any outstanding securities ranking on a parity with the Series B-1 Preferred Stock and having like voting rights that are exercisable at the time and entitled to vote thereon, shall be entitled to elect the two additional directors. The Series B Preferred Stock does not have a stated maturity and is not subject to mandatory redemption or any sinking fund. The Series B Preferred Stock will remain outstanding indefinitely unless repurchased or redeemed by us. Any such redemption would be effected only out of funds legally available for such purposes and will be subject to compliance with the provisions of our outstanding indebtedness.
The following table summarizes preferred stock by outstanding series of shares:
 
 
 
Year ended December 31,
December 31,
 
December 31,
 
 
 
2019
2018
2017
2019
 
2018
(in millions except shares and per share amounts)
Liquidation Preference Per Share
Shares
Dividends Declared Per Share
Outstanding
5.650% Series A
$
1,000.00

400,000

$
56.50

$
28.88

$
—

$
393.9

 
$
393.9

6.500% Series B
$
25,000.00

20,000

$
1,674.65

$
—

$
—

$
486.1

 
$
486.1
v3.19.3.a.u2
Share-Based Compensation
 12 Months Ended
Dec. 31, 2019
Share-based Payment Arrangement, Noncash Expense [Abstract]  
Share-Based Compensation Share-Based Compensation
Our stockholders most recently approved the NiSource Inc. 2010 Omnibus Incentive Plan (“Omnibus Plan”) at the Annual Meeting of Stockholders held on May 12, 2015. The Omnibus Plan provides for awards to employees and non-employee directors of incentive and nonqualified stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance units, cash-based awards and other stock-based awards and supersedes the long-term incentive plan approved by stockholders on April 13, 1994 (“1994 Plan”) and the Director Stock Incentive Plan (“Director Plan”). The Omnibus Plan provides that the number of shares of common stock of NiSource available for awards is 8,000,000 plus the number of shares subject to outstanding awards that expire or terminate for any reason that were granted under either the 1994 Plan or the Director Plan, plus the number of shares that were awarded as a result of the Separation-related adjustments. At December 31, 2019, there were 3,313,183 shares reserved for future awards under the Omnibus Plan.
We recognized stock-based employee compensation expense of $16.3 million, $15.2 million and $15.3 million, during 2019, 2018 and 2017, respectively, as well as related tax benefits of $4.0 million, $3.7 million and $5.9 million, respectively. We recognized related excess tax benefits from the distribution of vested share-based employee compensation of $0.8 million, $1.0 million and $4.4 million in 2019, 2018 and 2017, respectively.
As of December 31, 2019, the total remaining unrecognized compensation cost related to non-vested awards amounted to $19.5 million, which will be amortized over the weighted-average remaining requisite service period of 1.8 years.
Restricted Stock Units and Restricted Stock. In 2019, we granted 166,031 restricted stock units and shares of restricted stock to employees, subject to service conditions. The total grant date fair value of the restricted stock units and shares of restricted stock was $4.1 million, based on the average market price of our common stock at the date of each grant less the present value of any dividends not received during the vesting period, which will be expensed over the vesting period which is generally three years. As of December 31, 2019, 157,786 non-vested restricted stock units and shares of restricted stock granted in 2019 were outstanding as of December 31, 2019.
In 2018, we granted 158,689 restricted stock units and shares of restricted stock to employees, subject to service conditions. The total grant date fair value of the restricted stock units and shares of restricted stock was $3.5 million, based on the average market price of our common stock at the date of each grant less the present value of any dividends not received during the vesting period, which will be expensed over the vesting period which is generally three years. As of December 31, 2019, 136,820 non-vested restricted stock units and shares of restricted stock granted in 2018 were outstanding as of December 31, 2019.
Restricted stock units and shares of restricted stock granted to employees in 2017 were immaterial.
If an employee terminates employment before the service conditions lapse under the 2017, 2018 or 2019 awards due to (1) retirement or disability (as defined in the award agreement), or (2) death, the service conditions will lapse on the date of such termination with respect to a pro rata portion of the restricted stock units and shares of restricted stock based upon the percentage of the service period satisfied between the grant date and the date of the termination of employment. In the event of a change in control (as defined in the award agreement), all unvested shares of restricted stock and restricted stock units awarded will immediately vest upon termination of employment occurring in connection with a change in control. Termination due to any other reason will result in all unvested shares of restricted stock and restricted stock units awarded being forfeited effective on the employee’s date of termination.
(shares)
Restricted Stock
Units
 
Weighted Average
Award Date Fair 
Value Per Unit ($)
Non-vested at December 31, 2018
178,678

 
21.82

Granted
166,031

 
24.93

Forfeited
(21,547
)
 
22.99

Vested
(20,556
)
 
21.08

Non-vested at December 31, 2019
302,606

 
23.49



Performance Shares. In 2019, we granted 552,389 performance shares subject to service, performance and market conditions. The service conditions for these awards lapse on February 28, 2022. The performance period for the awards is the period beginning January 1, 2019 and ending December 31, 2021. The performance conditions are based on the achievement of one non-GAAP financial measure and additional operational measures as outlined below.
The financial measure is cumulative net operating earnings per share ("NOEPS"), which we define as income from continuing operations adjusted for certain unusual or non-recurring items. The number of cumulative NOEPS shares determined using this measure shall be increased or decreased based on our relative total shareholder return, a market condition which we define as the annualized growth in dividends and share price of a share of our common stock (calculated using a 20 trading day average of our closing price beginning on December 31, 2018 and ending on December 31, 2021) compared to the total shareholder return of a predetermined peer group of companies. A relative shareholder return result within the first quartile will result in an increase to the NOEPS shares of 25%, while a relative shareholder return result within the fourth quartile will result in a decrease of 25%. A Monte Carlo analysis was used to value the portion of these awards dependent on market conditions. The grant date fair value of the awards was $11.7 million, based on the average market price of our common stock at the date of each grant less the present value of dividends not received during the vesting period which will be expensed over the requisite service period of three years. As of December 31, 2019, 422,825 of these non-vested performance shares granted in 2019 remained outstanding.
If a threshold level of cumulative NOEPS financial performance is achieved, additional operational measures which we refer to as the customer value index, which consists of five equally weighted areas of focus including safety, customer satisfaction, financial, culture and environmental apply. Each area of focus represents 20% of the customer value index shares, and the targets for all areas must be met for these awards to be eligible for 100% payout of these awards. The grant date fair value of the awards was $2.5 million, based on the average market price of our common stock on the grant date of each award less the present value of dividends not received during the vesting period which will be expensed over the requisite service period of three years. As of December 31, 2019, 97,574 of these awards that were issued in 2019 remained outstanding.
In 2018, we awarded 514,338 performance shares subject to service, performance and market conditions. The service conditions for these awards lapse on February 26, 2021. The performance period for the awards is the period beginning January 1, 2018 and ending December 31, 2020. The performance conditions are based on the achievement of one non-GAAP financial measure and additional operational measures as outlined below.
The financial measure is cumulative net operating earnings per share ("NOEPS"), which we define as income from continuing operations adjusted for certain unusual or non-recurring items. The number of cumulative NOEPS shares determined using this measure shall be increased or decreased based on our relative total shareholder return, a market condition which we define as the annualized growth in dividends and share price of a share of our common stock (calculated using a 20 trading day average of our closing price beginning on December 31, 2017 and ending on December 31, 2020) compared to the total shareholder return of a predetermined peer group of companies. A relative shareholder return result within the first quartile will result in an increase to the NOEPS shares of 25% while a relative shareholder return result within the fourth quartile will result in a decrease of 25%. A Monte Carlo analysis was used to value the portion of these awards dependent on market conditions. The grant date fair value of the awards was $9.2 million, based on the average market price of our common stock at the date of each grant less the present value of dividends not received during the vesting period which will be expensed over the requisite service period of three years. As of December 31, 2019, 368,811 of these non-vested performance shares granted in 2018 remained outstanding.
If a threshold level of cumulative NOEPS financial performance is achieved, additional operational measures which we refer to as the customer value index, which consists of five equally weighted areas of focus including safety, customer satisfaction, financial, culture and environmental apply. Each area of focus represents 20% of the customer value index shares and the targets for all areas must be met for these awards to be eligible for 100% payout of these awards. Individual payout percentages for these shares may
range from 0%-200% as determined by the compensation committee in its sole discretion. Due to this discretion, these shares are not considered to be granted under ASC 718. The service inception date fair value of the awards was $2.4 million, based on the closing market price of our common stock on the service inception date of each award. This value will be reassessed at each reporting period to be based on our closing market price of our common stock at the reporting period date with adjustments to expense recorded as appropriate. As of December 31, 2019, 85,111 of these awards that were issued in 2018 remained outstanding. The service conditions for these awards lapse on February 26, 2021.
In 2017, we granted 660,750 performance shares subject to service, performance and market conditions. The grant date fair value of the awards was $12.9 million, based on the average market price of our common stock at the date of each grant less the present value of dividends not received during the vesting period which will be expensed over the requisite service period of three years. The performance conditions are based on achievement of non-GAAP financial measures similar to those discussed above: cumulative net operating earnings per share for the three-year period ending December 31, 2019 and relative total shareholder return (calculated using a 20 trading day average of our closing price beginning on December 31, 2016 and ending on December 31, 2019). As of December 31, 2019, 528,928 non-vested performance shares granted in 2017 remained outstanding. The service conditions for these awards lapse on February 28, 2020.
(shares)
Performance
Awards
 
Weighted Average
Grant Date Fair 
Value Per Unit ($)(1)
Non-vested at December 31, 2018
1,634,718

 
20.45

Granted
552,389

 
25.77

Forfeited
(156,700
)
 
26.72

Vested
(527,156
)
 
28.11

Non-vested at December 31, 2019
1,503,251

 
22.74


(1)2018 performance shares awarded based on the customer value index are included at reporting date fair value as these awards have not been granted under ASC 718 as discussed above.
Non-employee Director Awards. As of May 11, 2010, awards to non-employee directors may be made only under the Omnibus Plan. Currently, restricted stock units are granted annually to non-employee directors, subject to a non-employee director’s election to defer receipt of such restricted stock unit award. The non-employee director’s annual award of restricted stock units vest on the first anniversary of the grant date subject to special pro-rata vesting rules in the event of retirement or disability (as defined in the award agreement), or death. The vested restricted stock units are payable as soon as practicable following vesting except as otherwise provided pursuant to the non-employee director’s election to defer. Certain restricted stock units remain outstanding from the Director Plan. All such awards are fully vested and shall be distributed to the directors upon their separation from the Board.
As of December 31, 2019, 165,768 restricted stock units are outstanding to non-employee directors under either the Omnibus Plan or the Director Plan. Of this amount, 49,926 restricted stock units are unvested and expected to vest.
401(k) Match, Profit Sharing and Company Contribution. We have a voluntary 401(k) savings plan covering eligible employees that allows for periodic discretionary matches as a percentage of each participant’s contributions payable in cash for nonunion employees and generally payable in shares of NiSource common stock for union employees, subject to collective bargaining. We also have a retirement savings plan that provides for discretionary profit sharing contributions similarly payable in cash or shares of NiSource common stock to eligible employees based on earnings results, and eligible employees hired after January 1, 2010 receive a non-elective company contribution of 3% of eligible pay similarly payable in cash or shares of NiSource common stock. For the years ended December 31, 2019, 2018 and 2017, we recognized 401(k) match, profit sharing and non-elective contribution expense of $37.5 million, $37.6 million and $37.6 million, respectively.
v3.19.3.a.u2
Long-Term Debt
 12 Months Ended
Dec. 31, 2019
Long-term Debt, Current and Noncurrent [Abstract]  
Long-Term Debt Long-Term Debt
Our long-term debt as of December 31, 2019 and 2018 is as follows:
Long-term debt type
Maturity as of December 31,
2019
Weighted average interest rate (%)
 
Outstanding balance as of December 31, (in millions)
 
2019
 
2018
Senior notes:
 
 
 
 
 
 
NiSource
December 2021
4.45
%
 
63.6

 
63.6

NiSource
November 2022
2.65
%
 
500.0

 
500.0

NiSource
February 2023
3.85
%
 
250.0

 
250.0

NiSource
June 2023
3.65
%
 
350.0

 
350.0

NiSource
November 2025
5.89
%
 
265.0

 
265.0

NiSource
May 2027
3.49
%
 
1,000.0

 
1,000.0

NiSource
December 2027
6.78
%
 
3.0

 
3.0

NiSource
September 2029
2.95
%
 
750.0

 
—

NiSource
December 2040
6.25
%
 
250.0

 
250.0

NiSource
June 2041
5.95
%
 
400.0

 
400.0

NiSource
February 2042
5.80
%
 
250.0

 
250.0

NiSource
February 2043
5.25
%
 
500.0

 
500.0

NiSource
February 2044
4.80
%
 
750.0

 
750.0

NiSource
February 2045
5.65
%
 
500.0

 
500.0

NiSource
May 2047
4.38
%
 
1,000.0

 
1,000.0

NiSource
March 2048
3.95
%
 
750.0

 
750.0

Total senior notes
 
 
 
$
7,581.6

 
$
6,831.6

Medium term notes:
 
 
 
 
 
 
NiSource
April 2022 to May 2027
7.99
%
 
$
49.0

 
$
49.0

NIPSCO
August 2022 to August 2027
7.61
%
 
68.0

 
68.0

Columbia of Massachusetts
December 2025 to February 2028
6.30
%
 
40.0

 
40.0

Total medium term notes
 
 
 
$
157.0

 
$
157.0

Finance leases:
 
 
 
 
 
 
NiSource Corporate Services
January 2020 to November 2023
3.47
%
 
22.3

 
11.6

Columbia of Ohio
October 2021 to March 2044
6.16
%
 
94.8

 
91.5

Columbia of Virginia
July 2029 to November 2039
6.31
%
 
19.1

 
15.2

Columbia of Kentucky
May 2027
3.79
%
 
0.3

 
0.3

Columbia of Pennsylvania
August 2027 to May 2035
5.67
%
 
20.7

 
30.0

Columbia of Massachusetts
December 2033 to November 2043
5.49
%
 
44.3

 
45.7

Total finance leases
 
 
 
201.5

 
194.3

Pollution control bonds - NIPSCO
April 2019
5.85
%
 
—

 
41.0

Unamortized issuance costs and discounts
 
 
 
(70.5
)
 
$
(68.5
)
Total Long-Term Debt
 
 
 
$
7,869.6

 
$
7,155.4


Details of our 2019 long-term debt related activity are summarized below:
•
On April 1, 2019, NIPSCO repaid $41.0 million of 5.85% pollution control bonds at maturity.
•
On August 12, 2019, we closed our placement of $750.0 million of 2.95% senior unsecured notes maturing in 2029 which resulted in approximately $742.4 million of net proceeds after deducting commissions and expenses.
Details of our 2018 long-term debt related activity are summarized below:
•
On March 15, 2018, we redeemed $275.1 million of 6.40% senior unsecured notes at maturity.
•
In June 2018, we executed a tender offer for $209.0 million of outstanding notes consisting of a combination of our 6.80% notes due 2019, 5.45% notes due 2020, and 6.125% notes due 2022. In conjunction with the debt retired, we recorded a $12.5 million loss on early extinguishment of long-term debt, primarily attributable to early redemption premiums.
•
On June 11, 2018, we closed our private placement of $350.0 million of 3.65% senior unsecured notes maturing in 2023 which resulted in approximately $346.6 million of net proceeds after deducting commissions and expenses. We used the net proceeds from this private placement to pay a portion of the redemption price for the notes subject to the tender offer described above.
•
In July 2018, we redeemed $551.1 million of outstanding notes representing the remainder of our 6.80% notes due 2019, 5.45% notes due 2020 and 6.125% notes due 2022. During the third quarter of 2018, we recorded a $33.0 million loss on early extinguishment of long-term debt, primarily attributable to early redemption premiums.
See Note 19-A, "Contractual Obligations," for the outstanding long-term debt maturities at December 31, 2019.
Unamortized debt expense, premium and discount on long-term debt applicable to outstanding bonds are being amortized over the life of such bonds.
We are subject to a financial covenant under our revolving credit facility and term loan agreement which requires us to maintain a debt to capitalization ratio that does not exceed 70%. A similar covenant in a 2005 private placement note purchase agreement requires us to maintain a debt to capitalization ratio that does not exceed 75%. As of December 31, 2019, the ratio was 61.7%.
We are also subject to certain other non-financial covenants under the revolving credit facility. Such covenants include a limitation on the creation or existence of new liens on our assets, generally exempting liens on utility assets, purchase money security interests, preexisting security interests and an additional subset of assets equal to $150 million. An asset sale covenant generally restricts the sale, conveyance, lease, transfer or other disposition of our assets to those dispositions that are for a price not materially less than fair market of such assets, that would not materially impair our ability to perform obligations under the revolving credit facility, and that together with all other such dispositions, would not have a material adverse effect. The covenant also restricts dispositions to no more than 10% of our consolidated total assets on December 31, 2015. The revolving credit facility also includes a cross-default provision, which triggers an event of default under the credit facility in the event of an uncured payment default relating to any indebtedness of us or any of our subsidiaries in a principal amount of $50.0 million or more.
Our indentures generally do not contain any financial maintenance covenants. However, our indentures are generally subject to cross-default provisions ranging from uncured payment defaults of $5 million to $50 million, and limitations on the incurrence of liens on our assets, generally exempting liens on utility assets, purchase money security interests, preexisting security interests and an additional subset of assets capped at 10% of our consolidated net tangible assets.
v3.19.3.a.u2
Short-Term Borrowings
 12 Months Ended
Dec. 31, 2019
Short-term Debt [Abstract]  
Short-Term Borrowings Short-Term Borrowings
We generate short-term borrowings from our revolving credit facility, commercial paper program, accounts receivable transfer programs and term loan borrowings. Each of these borrowing sources is described further below.
We maintain a revolving credit facility to fund ongoing working capital requirements, including the provision of liquidity support for our commercial paper program, provide for issuance of letters of credit and also for general corporate purposes. Our revolving credit facility has a program limit of $1.85 billion and is comprised of a syndicate of banks led by Barclays. On February 20, 2019, we extended the termination date of our revolving credit facility to February 20, 2024. At December 31, 2019 and 2018, we had no outstanding borrowings under this facility.
Our commercial paper program has a program limit of up to $1.5 billion with a dealer group comprised of Barclays, Citigroup, Credit Suisse and Wells Fargo. We had $570.0 million and $978.0 million of commercial paper outstanding as of December 31, 2019 and 2018, respectively.
Transfers of accounts receivable are accounted for as secured borrowings resulting in the recognition of short-term borrowings on the Consolidated Balance Sheets. We had $353.2 million and $399.2 million in transfers as of December 31, 2019 and 2018, respectively. Refer to Note 18, "Transfers of Financial Assets," for additional information.
On April 17, 2019, we amended our existing term loan agreement with a syndicate of banks, with MUFG Bank Ltd. as the Administrative Agent, Sole Lead Arranger and Sole Bookrunner. The amendment increased the amount of our term loan from $600.0 million to $850.0 million and extended the maturity date to April 16, 2020. Interest charged on borrowings depends on the variable rate structure we elect at the time of each borrowing. The available variable rate structures from which we may choose are defined in the term loan agreement. Under the agreement, we borrowed $850.0 million on April 17, 2019 with an interest rate of LIBOR plus 60 basis points.
Short-term borrowings were as follows: 
At December 31, (in millions)
2019
 
2018
Commercial Paper weighted-average interest rate of 2.03% and 2.96% at December 31, 2019 and 2018, respectively
$
570.0

 
$
978.0

Accounts receivable securitization facility borrowings
353.2

 
399.2

Term loan weighted-average interest rate of 2.40% and 3.07% at December 31, 2019 and 2018, respectively
850.0

 
$
600.0

Total Short-Term Borrowings
$
1,773.2

 
$
1,977.2


Other than for the term loan and certain commercial paper borrowings, cash flows related to the borrowings and repayments of the items listed above are presented net in the Statements of Consolidated Cash Flows as their maturities are less than 90 days.
v3.19.3.a.u2
Leases
 12 Months Ended
Dec. 31, 2019
Leases [Abstract]  
Leases Leases
ASC 842 Adoption. In February 2016, the FASB issued ASU 2016-02, Leases (ASC 842). ASU 2016-02 introduces a lessee model that brings most leases onto the balance sheet. The standard requires that lessees recognize the following for all leases (with the exception of short-term leases, as that term is defined in the standard) at the lease commencement date: (1) a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and (2) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. In 2018, the FASB issued ASU 2018-01, Leases (ASC 842): Land Easement Practical Expedient for Transition to ASC 842, which allows us to not evaluate existing land easements under ASC 842, and ASU 2018-11, Leases (ASC 842): Targeted Improvements, which allows calendar year entities to initially apply ASC 842 prospectively from January 1, 2019.
We adopted the provisions of ASC 842 beginning on January 1, 2019, using the transition method provided in ASU 2018-11, which was applied to all existing leases at that date. As such, results for reporting periods beginning after January 1, 2019 will be presented under ASC 842, while prior period amounts will continue to be reported in accordance with ASC 840. We elected a number of practical expedients, including the "practical expedient package" described in ASC 842-10-65-1 and the provisions of ASU 2018-01, which allows us to not evaluate existing land easements under ASC 842. Further, ASC 842 provides lessees the option of electing an accounting policy, by class of underlying asset, in which the lessee may choose not to separate nonlease components from lease components. We elected this practical expedient for our leases of fleet vehicles, IT assets and railcars. We elected to use a practical expedient that allows the use of hindsight in determining lease terms when evaluating leases that existed at the implementation date. We also elected the short-term lease recognition exemption, allowing us to not recognize ROU assets or lease liabilities for all leases that qualify.
Adoption of the new standard resulted in the recording of additional lease liabilities and corresponding ROU assets of $57.0 million on our Consolidated Balance Sheets as of January 1, 2019. The standard had no material impact on our Statements of Consolidated Income (Loss) or our Statements of Consolidated Cash Flows.
Lease Descriptions. We are the lessee for substantially all of our leasing activity, which includes operating and finance leases for corporate and field offices, railcars, fleet vehicles and certain IT assets. Our corporate and field office leases have remaining lease terms between 1 and 24 years with options to renew the leases for up to 25 years. We lease railcars to transport coal to and from our electric generation facilities in Indiana. Our railcars are specifically identified in the lease agreements and have lease terms between 1 and 3 years with options to renew for 1 year. Our fleet vehicles include trucks, trailers and equipment that have been customized specifically for use in the utility industry. We lease fleet vehicles on 1 year terms, after which we have the option to extend on a month-to-month basis or terminate with written notice. ROU assets and liabilities on our Consolidated Balance Sheets do not include obligations for possible fleet vehicle lease renewals beyond the initial lease term. While we have the ability to renew these leases beyond the initial term, we are not reasonably certain (as that term is defined in ASC 842) to do so. We lease the majority of our IT assets under 4 year lease terms. Ownership of leased IT assets is transferred to us at the end of the lease term.
We have not provided material residual value guarantees for our leases, nor do our leases contain material restrictions or covenants. Lease contracts containing renewal and termination options are mostly exercisable at our sole discretion. Certain of our real estate and railcar leases include renewal periods in the measurement of the lease obligation if we have deemed the renewals reasonably certain to be exercised.
With respect to service contracts involving the use of assets, if we have the right to direct the use of the asset and obtain substantially all economic benefits from the use of an asset, we account for the service contract as a lease. Unless specifically provided to us by the lessor, we utilize NiSource's collateralized incremental borrowing rate commensurate to the lease term as the discount rate for all of our leases.
Lease costs for the year ended December 31, 2019 are presented in the table below. These costs include both amounts recognized in expense and amounts capitalized as part of the cost of another asset. Income statement presentation for these costs (when ultimately recognized on the income statement) is also included:
Year Ended December 31, (in millions)
Income Statement Classification
2019
Finance lease cost
 
 
Amortization of right-of-use assets
Depreciation and amortization
$
15.5

Interest on lease liabilities
Interest expense, net
11.3

Total finance lease cost
 
26.8

Operating lease cost
Operation and maintenance
17.9

Short-term lease cost
Operation and maintenance
1.0

Total lease cost
 
$
45.7


Our right-of-use assets and liabilities are presented in the following lines on the Consolidated Balance Sheets:
(in millions)
Balance Sheet Classification
December 31, 2019
Assets
 
 
Finance leases
Net Property, Plant and Equipment
$
179.5

Operating leases
Deferred charges and other
64.2

Total leased assets
 
243.7

Liabilities
 
 
Current
 
 
Finance leases
Current portion of long-term debt
13.4

Operating leases
Other accruals
13.2

Noncurrent
 
 
Finance leases
Long-term debt, excluding amounts due within one year
188.1

Operating leases
Other noncurrent liabilities
51.6

Total lease liabilities
 
$
266.3


Other pertinent information related to leases was as follows:
Year Ended December 31, (in millions)
2019
Cash paid for amounts included in the measurement of lease liabilities
 
Operating cash flows used for finance leases
$
11.3

Operating cash flows used for operating leases
17.9

Financing cash flows used for finance leases
10.6

Right-of-use assets obtained in exchange for lease obligations
 
Finance leases
26.4

Operating leases
$
13.4

 
December 31, 2019
Weighted-average remaining lease term (years)
 
Finance leases
14.8

Operating leases
9.2

Weighted-average discount rate
 
Finance leases
5.9
%
Operating leases
4.3
%

Maturities of our lease liabilities presented on a rolling 12-month basis were as follows:
As of December 31, 2019, (in millions)
Total
Finance Leases
Operating Leases
Year 1
$
42.8

$
27.2

$
15.6

Year 2
36.7

27.3

9.4

Year 3
35.0

26.8

8.2

Year 4
30.7

23.1

7.6

Year 5
26.5

19.9

6.6

Thereafter
233.3

201.6

31.7

Total lease payments(1)
405.0

325.9

79.1

Less: Imputed interest
(116.6
)
(102.3
)
(14.3
)
Less: Leases not yet commenced
(22.1
)
(22.1
)
—

Total
266.3

201.5

64.8

Reported as of December 31, 2019
 
 
 
Short-term lease liabilities
26.6

13.4

13.2

Long-term lease liabilities
239.7

188.1

51.6

Total lease liabilities
$
266.3

$
201.5

$
64.8

(1) Expected payments include obligations for leases not yet commenced of approximately $22.1 million for IT assets and interconnection facilities. These leases have terms between 4 years and 20 years, with estimated commencements in the first quarter of 2020 and in the third quarter of 2020.
Disclosures Related to Periods Prior to Adoption of ASC 842.We lease assets in several areas of our operations including fleet vehicles and equipment, rail cars for coal delivery and certain operations centers. Payments made in connection with operating leases were $49.1 million in 2018 and $49.5 million in 2017, and are primarily charged to operation and maintenance expense as incurred.
As of December 31, 2018, total contractual obligations for capital and operating leases were as follows:
As of December 31, 2018, (in millions)
Total
Capital Leases(1)
Operating Leases(2)
2019
$
34.0

$
23.0

$
11.0

2020
29.8

22.5

7.3

2021
28.7

22.6

6.1

2022
26.3

22.1

4.2

2023
22.6

19.8

2.8

Thereafter
226.9

212.4

14.5

Total lease payments
$
368.3

$
322.4

$
45.9

(1)Capital lease payments shown above are inclusive of interest totaling $114.6 million.
(2)Operating lease balances do not include obligations for possible fleet vehicle lease renewals beyond the initial lease term. While we have the ability to renew these leases beyond the initial term, we are not reasonably certain to do so. Expected payments are $26.7 million in 2019, $22.4 million in 2020, $16.6 million in 2021, $12.3 million in 2022, $9.3 million in 2023 and $8.8 million thereafter.
v3.19.3.a.u2
Fair Value
 12 Months Ended
Dec. 31, 2019
Fair Value Disclosures [Abstract]  
Fair Value Fair Value
A.Fair Value Measurements
Recurring Fair Value Measurements. The following tables present financial assets and liabilities measured and recorded at fair value on our Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of December 31, 2019 and December 31, 2018:
 
Recurring Fair Value Measurements
December 31, 2019 (in millions)
Quoted Prices
in Active Markets
for Identical Assets
(Level 1)
 
Significant Other
Observable Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
 
Balance as of
December 31, 2019
Assets
 
 
 
 
 
 
 
Risk management assets
$
—

 
$
4.4

 
$
—

 
$
4.4

Available-for-sale securities
—

 
154.2

 
—

 
154.2

Total
$
—

 
$
158.6

 
$
—

 
$
158.6

Liabilities
 
 
 
 
 
 
 
Risk management liabilities
$
—

 
$
146.6

 
$
—

 
$
146.6

Total
$
—

 
$
146.6

 
$
—

 
$
146.6

 
Recurring Fair Value Measurements
December 31, 2018 (in millions)
Quoted Prices
in Active Markets
for Identical Assets
(Level 1)
 
Significant Other
Observable Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
 
Balance as of
December 31, 2018
Assets
 
 
 
 
 
 
 
Risk management assets
$
—

 
$
24.0

 
$
—

 
$
24.0

Available-for-sale securities
—

 
138.3

 
—

 
138.3

Total
$
—

 
$
162.3

 
$
—

 
$
162.3

Liabilities
 
 
 
 
 
 
 
Risk management liabilities
$
—

 
$
51.7

 
$
—

 
$
51.7

Total
$
—

 
$
51.7

 
$
—

 
$
51.7

Risk management assets and liabilities include interest rate swaps, exchange-traded NYMEX futures and NYMEX options and non-exchange-based forward purchase contracts. When utilized, exchange-traded derivative contracts are based on unadjusted quoted prices in active markets and are classified within Level 1. These financial assets and liabilities are secured with cash on deposit with the exchange; therefore, nonperformance risk has not been incorporated into these valuations. Certain non-exchange-traded derivatives are valued using broker or over-the-counter, on-line exchanges. In such cases, these non-exchange-traded derivatives are classified within Level 2. Non-exchange-based derivative instruments include swaps, forwards, and options. In certain instances, these instruments may utilize models to measure fair value. We use a similar model to value similar instruments. Valuation models utilize various inputs that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, other observable inputs for the asset or liability and market-corroborated inputs, (i.e., inputs derived principally from or corroborated by observable market data by correlation or other means). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized within Level 2. Certain derivatives trade in less active markets with a lower availability of pricing information and models may be utilized in the valuation. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized within Level 3. Credit risk is considered in the fair value calculation of derivative instruments that are not exchange-traded. Credit exposures are adjusted to reflect collateral agreements which reduce exposures. As of December 31, 2019 and 2018, there were no material transfers between fair value hierarchies. Additionally, there were no changes in the method or significant assumptions used to estimate the fair value of our financial instruments.
We have entered into forward-starting interest rate swaps to hedge the interest rate risk on coupon payments of forecasted issuances of long-term debt. These derivatives are designated as cash flow hedges. Credit risk is considered in the fair value calculation of each agreement. As they are based on observable data and valuations of similar instruments, the hedges are categorized within Level 2 of the fair value hierarchy. There was no exchange of premium at the initial date of the swaps and we can settle the contracts at any time. For additional information, see Note 9, "Risk Management Activities."
NIPSCO has entered into long-term forward natural gas purchase instruments that range from five to ten years to lock in a fixed price for its natural gas customers. We value these contracts using a pricing model that incorporates market-based information when available, as these instruments trade less frequently and are classified within Level 2 of the fair value hierarchy. For additional information see Note 9, “Risk Management Activities.”
Available-for-sale securities are investments pledged as collateral for trust accounts related to our wholly-owned insurance company. Available-for-sale securities are included within “Other investments” in the Consolidated Balance Sheets. 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 December 31, 2019 and 2018 were: 
December 31, 2019 (in millions)
Amortized
Cost
 
Gross
Unrealized
Gains
 
Gross
Unrealized
Losses
 
Fair Value
Available-for-sale securities
 
 
 
 
 
 
 
U.S. Treasury debt securities
$
31.4

 
$
0.1

 
$
(0.1
)
 
$
31.4

Corporate/Other debt securities
118.7

 
4.2

 
(0.1
)
 
122.8

Total
$
150.1

 
$
4.3

 
$
(0.2
)
 
$
154.2

 
 
 
 
 
 
 
 
December 31, 2018 (in millions)
Amortized
Cost
 
Gross
Unrealized
Gains
 
Gross
Unrealized
Losses
 
Fair Value
Available-for-sale securities
 
 
 
 
 
 
 
U.S. Treasury debt securities
$
23.6

 
$
0.1

 
$
(0.1
)
 
$
23.6

Corporate/Other debt securities
117.7

 
0.4

 
(3.4
)
 
114.7

Total
$
141.3

 
$
0.5

 
$
(3.5
)
 
$
138.3

 
Realized gains and losses on available-for-sale securities were immaterial for the year-ended December 31, 2019 and 2018.
The cost of maturities sold is based upon specific identification. At December 31, 2019, approximately $7.7 million of U.S. Treasury debt securities and approximately $6.0 million of Corporate/Other debt securities have maturities of less than a year.
There are no material items in the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis for the years ended December 31, 2019 and 2018.
Non-recurring Fair Value Measurements. We measure the fair value of certain assets on a non-recurring basis, typically annually or when events or changes in circumstances indicate that the carrying amount of the assets may not be recoverable. These assets include goodwill and other intangible assets.
At December 31, 2019, we recorded an impairment charge of $204.8 million for goodwill and an impairment charge of $209.7 million for franchise rights, in each case related to Columbia of Massachusetts. For additional information, see Note 6, “Goodwill and Other Intangible Assets.”
B.         Other Fair Value Disclosures for Financial Instruments. The carrying amount of cash and cash equivalents, restricted cash, notes receivable, 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 years ended December 31, 2019 and 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: 
At December 31, (in millions)
Carrying
Amount
2019
 
Estimated
Fair Value
2019
 
Carrying
Amount
2018
 
Estimated
Fair Value
2018
Long-term debt (including current portion)
$
7,869.6

 
$
8,764.4

 
$
7,155.4

 
$
7,228.3
v3.19.3.a.u2
Transfers Of Financial Assets
 12 Months Ended
Dec. 31, 2019
Transfers and Servicing [Abstract]  
Transfers Of Financial Assets Transfers of Financial Assets

Columbia of Ohio, NIPSCO and Columbia of Pennsylvania each maintain a receivables agreement whereby they transfer their customer accounts receivables to third party financial institutions through wholly-owned and consolidated special purpose entities. The three agreements expire between May 2020 and October 2020 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 Consolidated Balance Sheets. As of December 31, 2019, the maximum amount of debt that could be recognized related to our accounts receivable programs is $465.0 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 December 31, 2019 and 2018:
At December 31, (in millions)
2019
 
2018
Gross receivables
$
569.1

 
$
694.4

Less: receivables not transferred
215.9

 
295.2

Net receivables transferred
$
353.2

 
$
399.2

Short-term debt due to asset securitization
$
353.2

 
$
399.2


During 2019, $46.0 million was recorded as cash flows used for financing activities related to the change in short-term borrowings due to securitization transactions. During 2018, $62.5 million was recorded as cash flows from financing activities related to the change in short-term borrowings due to securitization transactions. Fees associated with the securitization transactions were $2.6 million, $2.6 million and $2.5 million for the years ended December 31, 2019, 2018 and 2017, respectively. Columbia of Ohio, NIPSCO and Columbia of Pennsylvania remain responsible for collecting on the receivables securitized, and the receivables cannot be transferred to another party.
v3.19.3.a.u2
Other Commitments And Contingencies
 12 Months Ended
Dec. 31, 2019
Commitments and Contingencies Disclosure [Abstract]  
Other Commitments And Contingencies Other Commitments and Contingencies
A.    Contractual Obligations. We have certain contractual obligations requiring payments at specified periods. The obligations include long-term debt, lease obligations, energy commodity contracts and obligations for various services including pipeline capacity and outsourcing of IT services. The total contractual obligations in existence at December 31, 2019 and their maturities were:
(in millions)
Total
 
2020
 
2021
 
2022
 
2023
 
2024
 
After
Long-term debt (1)
$
7,738.6

 
$
—

 
$
63.6

 
$
530.0

 
$
600.0

 
$
—

 
$
6,545.0

Interest payments on long-term debt
6,214.2

 
342.0

 
340.7

 
337.1

 
311.1

 
299.9

 
4,583.4

Finance leases(2)
325.9

 
27.2

 
27.3

 
26.8

 
23.1

 
19.9

 
201.6

Operating leases(3)
79.1

 
15.6

 
9.4

 
8.2

 
7.6

 
6.6

 
31.7

Energy commodity contracts(4)
95.9

 
65.5

 
30.4

 
—

 
—

 
—

 
—

Service obligations:


 
 
 
 
 
 
 
 
 
 
 
 
Pipeline service obligations
3,450.7

 
605.0

 
590.1

 
546.8

 
357.2

 
237.5

 
1,114.1

IT service obligations
153.2

 
63.6

 
49.4

 
38.0

 
1.1

 
1.1

 
—

Other service obligations(5)
59.8

 
45.8

 
14.0

 
—

 
—

 
—

 
—

Other liabilities
27.3

 
27.3

 
—

 
—

 
—

 
—

 
—

Total contractual obligations
$
18,144.7

 
$
1,192.0

 
$
1,124.9

 
$
1,486.9

 
$
1,300.1

 
$
565.0

 
$
12,475.8

(1) Long-term debt balance excludes unamortized issuance costs and discounts of $70.5 million.
(2) Finance lease payments shown above are inclusive of interest totaling $108.3 million.
(3) Operating lease payments shown above are inclusive of interest totaling $14.3 million. Operating lease balances do not include obligations for possible fleet vehicle lease renewals beyond the initial lease term. While we have the ability to renew these leases beyond the initial term, we are not reasonably certain (as that term is defined in ASC 842) to do so. If we were to continue the fleet vehicle leases outstanding at December 31, 2019, payments would be $34.5 million in 2020, $28.3 million in 2021, $23.4 million in 2022, $19.9 million in 2023, $15.2 million in 2024 and $15.2 million thereafter.  
(4)In January 2020, NIPSCO signed new coal contract commitments of $14.4 million for 2020. These contracts are not included above.  
(5)In February 2020, NIPSCO signed a new railcar coal transportation contract commitment of $12.0 million for 2020. This contract is not included above.
Operating and Finance Lease Commitments. We lease assets in several areas of our operations including corporate and field offices, railcars, fleet vehicles and certain IT assets. Payments made in connection with operating and month-to-month leases were $52.5 million in 2019, $49.1 million in 2018 and $49.5 million in 2017, and are primarily charged to operation and maintenance expense as incurred. See Note 16, "Leases" for additional details.
Purchase and Service Obligations. We have entered into various purchase and service agreements whereby we are contractually obligated to make certain minimum payments in future periods. Our purchase obligations are for the purchase of physical quantities of natural gas, electricity and coal. Our service agreements encompass a broad range of business support and maintenance functions which are generally described below.
Our subsidiaries have entered into various energy commodity contracts to purchase physical quantities of natural gas, electricity and coal. These amounts represent minimum quantities of these commodities we are obligated to purchase at both fixed and variable prices. To the extent contractual purchase prices are variable, obligations disclosed in the table above are valued at market prices as of December 31, 2019.
In July 2008, the IURC issued an order approving NIPSCO’s purchase power agreements with subsidiaries of Iberdrola Renewables, Buffalo Ridge I LLC and Barton Windpower LLC. These agreements provide NIPSCO the opportunity and obligation to purchase up to 100 MW of wind power generated commencing in early 2009. The contracts extend 15 and 20 years, representing 50 MW of wind power each. No minimum quantities are specified within these agreements due to the variability of electricity generation from wind, so no amounts related to these contracts are included in the table above. Upon any termination of the agreements by NIPSCO for any reason (other than material breach by Buffalo Ridge I LLC or Barton Windpower LLC), NIPSCO may be required to pay a termination charge that could be material depending on the events giving rise to termination and the timing of the termination. NIPSCO began purchasing wind power in April 2009.
We have pipeline service agreements that provide for pipeline capacity, transportation and storage services. These agreements, which have expiration dates ranging from 2020 to 2045, require us to pay fixed monthly charges.
NIPSCO has contracts with three major rail operators providing for coal transportation services for which there are certain minimum payments. These service contracts extend for various periods through 2021.
We have executed agreements with multiple IT service providers. The agreements extend for various periods through 2024.
B.        Guarantees and Indemnities. We and certain subsidiaries enter into various agreements providing financial or performance assurance to third parties on behalf of certain subsidiaries as 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. At December 31, 2019 and 2018, we had issued stand-by letters of credit of $10.2 million for the benefit of third parties.
C.         Legal Proceedings.
On September 13, 2018, a series of fires and explosions occurred in Lawrence, Andover and North Andover, Massachusetts related to the delivery of natural gas by Columbia of Massachusetts (the "Greater Lawrence Incident"). The Greater Lawrence Incident resulted in one fatality and a number of injuries, damaged multiple homes and businesses, and caused the temporary evacuation of significant portions of each municipality. The Massachusetts Governor’s Office declared a state of emergency, authorizing the Massachusetts DPU to order another utility company to coordinate the restoration of utility services in Lawrence, Andover and North Andover. The incident resulted in the interruption of gas for approximately 7,500 gas meters, the majority of which served residences and approximately 700 of which served businesses, and the interruption of other utility service more broadly in the area. Columbia of Massachusetts has replaced the cast iron and bare steel gas pipeline system in the affected area and restored service to nearly all of the gas meters. See “ - E. Other Matters - Greater Lawrence Pipeline Replacement” below for more information.
We are subject to inquiries and investigations by government authorities and regulatory agencies regarding the Greater Lawrence Incident, including the Massachusetts DPU and the Massachusetts Attorney General's Office, as described below. We are cooperating with all inquiries and investigations. In addition, on February 26, 2020, the Company and Columbia of Massachusetts entered into agreements with the U.S. Attorney’s Office to resolve the U.S. Attorney’s Office’s investigation relating to the Greater Lawrence Incident, as described below.
NTSB Investigation. As previously disclosed, the NTSB concluded its investigation into the Greater Lawrence Incident, and we are implementing the one remaining safety recommendation resulting from the investigation.
Massachusetts Investigations. Under Massachusetts law, the DPU is authorized to investigate potential violations of pipeline safety regulations and to assess a civil penalty of up to $218,647 for a violation of federal pipeline safety regulations. A separate violation occurs for each day of violation up to $2.2 million for a related series of violations. The Massachusetts DPU also is authorized to investigate potential violations of the Columbia of Massachusetts emergency response plan and to assess penalties of up to $250,000 per violation per day, or up to $20 million per related series of violations. Further, as a result of the declaration of emergency by the Governor, the DPU is authorized to investigate potential violations of the DPU's operational directives during the restoration efforts and assess penalties of up to $1 million per violation. Pursuant to these authorities, the DPU is investigating Columbia of Massachusetts as described below. Columbia of Massachusetts will likely be subject to potential compliance actions related to the Greater Lawrence Incident and the restoration work following the incident, the timing and outcomes of which are uncertain at this time.
After the Greater Lawrence Incident, the Massachusetts DPU retained an independent evaluator to conduct a statewide examination of the safety of the natural gas distribution system and the operational and maintenance functions of natural gas companies in the Commonwealth of Massachusetts. Through authority granted by the Massachusetts Governor under the state of emergency, the Chair of the Massachusetts DPU has directed all natural gas distribution companies operating in the Commonwealth to fund the statewide examination. The statewide examination is complete. The Phase I report, which was issued in May 2019, included a program level assessment and evaluation of natural gas distribution companies. The Phase I report's conclusions were statewide and contained no specific conclusions about Columbia of Massachusetts. Phase II, which was focused on field assessments of each Massachusetts gas company, concluded in December 2019. The Phase II report made several observations about and recommendations to Massachusetts gas companies, including Columbia of Massachusetts, with regard to safety culture and assets. The final report was issued in late January 2020, and the DPU directed each natural gas distribution company operating in Massachusetts to submit a plan in response to the report no later than February 28, 2020.
On September 11, 2019, the Massachusetts DPU issued an order directing Columbia of Massachusetts to take several specific actions to address concerns related to service lines abandoned during the restoration work following the Greater Lawrence Incident and to furnish certain information and periodic reports to the DPU.
On October 1, 2019, the Massachusetts DPU issued four orders to Columbia of Massachusetts in connection with the service lines abandoned during the Greater Lawrence Incident restoration, which require: (1) the submission of a detailed work plan to the DPU, (2) the completion of quality control work on certain abandoned services, (3) the payment for a third-party independent audit, to be contracted through the DPU, of all gas pipeline work completed as part of the incident restoration effort, and (4) prompt and full response to any requests for information by the third-party auditor. The Massachusetts DPU retained an independent evaluator to conduct this audit, and that third party is currently evaluating compliance with Massachusetts and federal law, as well as any other operational or safety risks that may be posed by the pipeline work. The audit scope also includes Columbia of Massachusetts' operations in the Lawrence Division and other service territories as appropriate.
Also in October 2019, the Massachusetts DPU issued three additional orders requiring: (1) daily leak surveillance and reporting in areas where abandoned services are located, (2) completion by November 15, 2019 of the work plan previously submitted describing how Columbia of Massachusetts would address the estimated 2,200 locations at which an inside meter set was moved outside the property as part of the abandoned service work completed during the Greater Lawrence Incident restoration, and (3) submission of a report by December 2, 2019 showing any patterns, trends or correlations among the non-compliant work related to the abandonment of service lines, gate boxes and curb boxes during the incident restoration.
On October 3, 2019, the Massachusetts DPU notified Columbia of Massachusetts that, absent DPU approval, it is currently allowed to perform only emergency work on its gas distribution system throughout its service territories in Massachusetts. The restrictions do not apply to Columbia of Massachusetts’ work to address the previously identified issues with abandoned service lines and valve boxes in the Greater Lawrence, Massachusetts area. Columbia of Massachusetts is subject to daily monitoring by the DPU on any work that Columbia of Massachusetts conducts in Massachusetts. Such restrictions on work remain in place until modified by the DPU.
On October 25, 2019, the Massachusetts DPU issued two orders opening public investigations into Columbia of Massachusetts with respect to the Greater Lawrence Incident. The Massachusetts DPU opened the first investigation under its authority to determine compliance with federal and state pipeline safety laws and regulations, and to investigate Columbia of Massachusetts’ responsibility for and response to the Greater Lawrence Incident and its restoration efforts following the incident. The Massachusetts DPU opened the second investigation under its authority to determine whether a gas distribution company has violated established standards regarding acceptable performance for emergency preparedness and restoration of service to investigate efforts by Columbia of Massachusetts to prepare for and restore service following the Greater Lawrence Incident. Separate penalties are applicable under each exercise of authority.
On December 23, 2019, the Massachusetts DPU issued an order defining the scope of its investigation into the response of Columbia of Massachusetts related to the Greater Lawrence Incident. The DPU identified three distinct time frames in which Columbia of Massachusetts handled emergency response and restoration directly: (1) September 13-14, 2018, (2) September 21 through December 16, 2018 (the Phase I restoration), and (3) September 27, 2019 through completion of restoration of outages resulting from the gas release event in Lawrence, Massachusetts that occurred on September 27, 2019. The DPU determined that it is appropriate to investigate separately, for each time period described above, the areas of response, recovery and restoration for which Columbia of Massachusetts was responsible. The DPU noted that it also may investigate the continued restoration and related repair work that took place after December 16, 2018 and, depending on the outcome of that investigation, may deem it appropriate to consider that period of restoration as an additional separate time period.
The DPU also noted that its investigation into all of the above described time periods is ongoing and that if the DPU determines, based on its investigation, that it is appropriate to treat the separate time frames as separate emergency events, it may impose up to the maximum statutory penalty for each event, pursuant to Mass. G.L. c. 164 Section 1J. This provision authorizes the DPU to investigate potential violations of the Columbia of Massachusetts emergency response plan and to assess penalties of up to $250,000 per violation per day, or up to $20 million per related series of violations. The DPU noted that at this preliminary stage of the investigation, it does not have the factual basis to make those determinations.
In connection with its investigation related to the Greater Lawrence Incident, on February 4, 2020, the Massachusetts Attorney General's Office issued a request for documents primarily focused on the restoration work following the incident.
Columbia of Massachusetts is cooperating with the investigations set forth above as well as other inquiries resulting from an increased amount of enforcement activity, for all of which the outcomes are uncertain at this time.
Massachusetts Legislative Matters. On November 12, 2019, the Joint Committee on Telecommunications, Utilities and Energy held a hearing that focused on gas safety, but the Committee has not taken action on any bills. Increased scrutiny related to gas system safety and regulatory oversight in Massachusetts, including additional legislative oversight hearings and new legislative proposals, is expected to continue during the current two-year legislative session that ends in December 2020.
U.S. Department of Justice Investigation. As previously disclosed, the Company and Columbia of Massachusetts are subject to a criminal investigation related to the Greater Lawrence Incident that is being conducted under the supervision of the U.S. Attorney's Office. The initial grand jury subpoenas were served on the Company and Columbia of Massachusetts on September 24, 2018.
On February 26, 2020, the Company and Columbia of Massachusetts entered into agreements with the U.S. Attorney’s Office to resolve the U.S. Attorney’s Office’s investigation relating to the Greater Lawrence Incident. Columbia of Massachusetts agreed to plead guilty in the United States District Court for the District of Massachusetts (the “Court”) to violating the Natural Gas Pipeline Safety Act (the “Plea Agreement”), and the Company entered into a DPA.
Under the Plea Agreement, which must be approved by the Court, Columbia of Massachusetts will be subject to the following terms, among others: (i) a criminal fine in the amount of $53,030,116 paid within 30 days of sentencing; (ii) a three year probationary period that will early terminate upon a sale of Columbia of Massachusetts or a sale of its gas distribution business to a qualified third-party buyer consistent with certain requirements; (iii) compliance with each of the NTSB recommendations stemming from the Greater Lawrence Incident; and (iv) employment of an in-house monitor during the term of the probationary period.
Under the DPA, the U.S. Attorney’s Office agreed to defer prosecution of the Company in connection with the Greater Lawrence Incident for a three-year period (which three-year period may be extended for twelve (12) months upon the U.S. Attorney’s Office’s determination of a breach of the DPA) subject to certain obligations of the Company, including, but not limited to, the following: (i) the Company will use reasonable best efforts to sell Columbia of Massachusetts or Columbia of Massachusetts’ gas distribution business to a qualified third-party buyer consistent with certain requirements, and, upon the completion of any such sale, the Company will cease and desist any and all gas pipeline and distribution activities in the District of Massachusetts; (ii) the Company will forfeit and pay, within 30 days of the later of the sale becoming final or the date on which post-closing adjustments to the purchase price are finally determined in accordance with the agreement to sell Columbia Gas of Massachusetts or its gas distribution business, a fine equal to the total amount of any profit or gain from any sale of Columbia of Massachusetts or its gas distribution business, with the amount of profit or gain determined as provided in the DPA; and (iii) the Company agrees as to each of the Company’s subsidiaries involved in the distribution of gas through pipeline facilities in Massachusetts, Indiana, Ohio, Pennsylvania, Maryland, Kentucky and Virginia to implement and adhere to each of the recommendations from the NTSB stemming from the Greater Lawrence Incident. Pursuant to the DPA, if the Company complies with all of its obligations under the DPA, including, but not limited to those identified above, the U.S. Attorney’s Office will not file any criminal charges against the Company related to the Greater Lawrence Incident. If Columbia of Massachusetts’ guilty plea is not accepted by the Court or is withdrawn for any reason, or if Columbia of Massachusetts should fail to perform an obligation under the Plea Agreement prior to the sale of Columbia of Massachusetts or its gas distribution business, the U.S. Attorney's Office may, at its sole option, render the DPA null and void.
U.S. Congressional Activity. On September 30, 2019, the U.S. Pipeline Safety Act expired. There is no effect on PHMSA's authority. Action on past re-authorization bills has extended past the expiration date and action on this re-authorization is expected to continue well into 2020. Pipeline safety jurisdiction resides with the U.S. Senate Commerce Committee, and is divided between two committees in the U.S. House of Representatives (Energy and Commerce, and Transportation and Infrastructure). Legislative proposals are currently in various stages of committee development and the timing of further action is uncertain. Certain legislative proposals, if enacted into law, may increase costs for natural gas industry companies, including the Company and Columbia of Massachusetts.
SEC Investigation. On November 27, 2019, the SEC staff notified the Company that it concluded its investigation related to disclosures made by the Company prior to the Greater Lawrence Incident and, based on the information provided as of such date, it does not intend to recommend an enforcement action against the Company.
Private Actions. Various lawsuits, including several purported class action lawsuits, have been filed by various affected residents or businesses in Massachusetts state courts against the Company and/or Columbia of Massachusetts in connection with the Greater Lawrence Incident. A special judge has been appointed to hear all pending and future cases and the class actions have been consolidated into one class action. On January 14, 2019, the special judge granted the parties’ joint motion to stay all cases until
April 30, 2019 to allow mediation, and the parties subsequently agreed to extend the stay until July 25, 2019. The class action lawsuits allege varying causes of action, including those for strict liability for ultra-hazardous activity, negligence, private nuisance, public nuisance, premises liability, trespass, breach of warranty, breach of contract, failure to warn, unjust enrichment, consumer protection act claims, negligent, reckless and intentional infliction of emotional distress and gross negligence, and seek actual compensatory damages, plus treble damages, and punitive damages.
On July 26, 2019, the Company, Columbia of Massachusetts and NiSource Corporate Services Company, a subsidiary of the Company, entered into a term sheet with the class action plaintiffs under which they agreed to settle the class action claims in connection with the Greater Lawrence Incident. Columbia of Massachusetts agreed to pay $143 million into a settlement fund to compensate the settlement class and the settlement class agreed to release Columbia of Massachusetts and affiliates from all claims arising out of or related to the Greater Lawrence Incident. The following claims are not covered under the proposed settlement because they are not part of the consolidated class action: (1) physical bodily injury and wrongful death; (2) insurance subrogation, whether equitable, contractual or otherwise; and (3) claims arising out of appliances that are subject to the Massachusetts DPU orders. Emotional distress and similar claims are covered under the proposed settlement unless they are secondary to a physical bodily injury. The settlement class is defined under the term sheet as all persons and businesses in the three municipalities of Lawrence, Andover and North Andover, Massachusetts, subject to certain limited exceptions. The motion for preliminary approval and the settlement documents were filed on September 25, 2019. The preliminary approval court hearing was held on October 7, 2019 and the court issued an order granting preliminary approval of the settlement on October 11, 2019. The proposed settlement is subject to final court approval, and a hearing occurred on February 27, 2020. The court took the matter under advisement.
Many residents and business owners have submitted individual damage claims to Columbia of Massachusetts. Most of the wrongful death and bodily injury claims that have been asserted have been settled, and we continue to discuss potential settlements with plaintiffs asserting such claims. In addition, the Commonwealth of Massachusetts is seeking reimbursement from Columbia of Massachusetts for its expenses incurred in connection with the Greater Lawrence Incident. The outcomes and impacts of such private actions are uncertain at this time.
Financial Impact. Since the Greater Lawrence Incident, we have recorded expenses of approximately $1,041 million for third-party claims and fines, penalties and settlements associated with government investigations. We estimate that total costs related to third-party claims and fines, penalties and settlements associated with government investigations resulting from the incident will range from $1,041 million to $1,065 million, depending on the number, nature, final outcome and value of third-party claims and the final outcome of government investigations. With regard to third-party claims, these costs include, but are not limited to, personal injury and property damage claims, damage to infrastructure, business interruption claims, and mutual aid payments to other utilities assisting with the restoration effort. These costs do not include costs of certain third-party claims and fines, penalties or settlements associated with government investigations that we are not able to estimate, nor do they include non-claims related and government investigation-related legal expenses resulting from the incident and the capital cost of the pipeline replacement, which are set forth in " - E. Other Matters - Greater Lawrence Incident Restoration" and "- Greater Lawrence Incident Pipeline Replacement," respectively, below.
The process for estimating costs associated with third-party claims and fines, penalties, and settlements associated with government investigations relating to the Greater Lawrence Incident requires management to exercise significant judgment based on a number of assumptions and subjective factors. As more information becomes known, including additional information regarding ongoing investigations, management’s estimates and assumptions regarding the financial impact of the Greater Lawrence Incident may change.
The aggregate amount of third-party liability insurance coverage available for losses arising from the Greater Lawrence Incident is $800 million. We have collected the entire $800 million as of December 31, 2019. Total expenses related to the incident have exceeded the total amount of insurance coverage available under our policies. Refer to "- E. Other Matters - Greater Lawrence Incident Restoration," below for a summary of third-party claims-related expense activity and associated insurance recoveries recorded since the Greater Lawrence Incident.
We are also party to certain other claims, regulatory and legal proceedings arising in the ordinary course of business in each state in which we have operations, 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, proceeding or investigation related to the Greater Lawrence Incident or otherwise would not have a material adverse effect on our results of
operations, financial position or liquidity. Certain matters in connection with the Greater Lawrence Incident have had or may have a material impact as described above. If one or more of such additional or other 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.
D.        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, improvement and remediation costs to be recoverable through rates for certain of our companies.
As of December 31, 2019 and 2018, we had recorded a liability of $104.4 million and $101.2 million, respectively, to cover environmental remediation at various sites. The current portion of this liability is included in "Legal and environmental" in the Consolidated Balance Sheets. The noncurrent portion is included in "Other noncurrent liabilities." We recognize costs associated with environmental remediation obligations when the incurrence of such costs is probable and the amounts can be reasonably estimated. The original estimates for remediation activities may differ materially from the amount ultimately expended. The actual future expenditures depend on many factors, including currently enacted laws and regulations, the nature and extent of impact and the method of remediation. These expenditures are not currently estimable at some sites. We periodically adjust our liability as information is collected and estimates become more refined.
Electric Operations' compliance estimates disclosed below are reflective of NIPSCO's Integrated Resource Plan submitted to the IURC on October 31, 2018. See section " - E. Other Matters - NIPSCO 2018 Integrated Resource Plan," below for additional information.
Air
Future legislative and regulatory programs could significantly limit allowed GHG emissions or impose a cost or tax on GHG emissions. Additionally, rules that require further GHG reductions or impose additional requirements for natural gas facilities could impose additional costs. NiSource will carefully monitor all GHG reduction proposals and regulations.
ACE Rule. On July 8, 2019, the EPA published the final ACE rule, which establishes emission guidelines for states to use when developing plans to limit carbon dioxide at coal-fired electric generating units based on heat rate improvement measures. The coal-fired units at NIPSCO’s R.M. Schahfer Generating Station and Michigan City Generating Station are potentially affected sources, and compliance requirements for these units which NIPSCO plans to retire by 2023 and 2028, respectively, will be determined by future Indiana rulemaking. The ACE rule notes that states have “broad flexibility in setting standards of performance for designated facilities” and that a state may set a “business as usual” standard for sources that have a remaining useful life “so short that imposing any costs on the electric generating unit is unreasonable.” State plans are due by 2022, and the EPA will have six months to determine completeness and then one additional year to determine whether to approve the submitted plan. States have the discretion to determine the compliance period for each source. As a result, NIPSCO will continue to monitor this matter and cannot estimate its impact at this time.
Waste
CERCLA. Our subsidiaries are potentially responsible parties at waste disposal sites under the CERCLA (commonly known as Superfund) and similar state laws. Under CERCLA, each potentially responsible party can be held jointly, severally and strictly liable for the remediation costs as the EPA, or state, can allow the parties to pay for remedial action or perform remedial action themselves and request reimbursement from the potentially responsible parties. Our affiliates have retained CERCLA environmental liabilities, including remediation liabilities, associated with certain current and former operations. These liabilities are not material to the Consolidated Financial Statements.
MGP. A program has been instituted to identify and investigate former MGP sites where Gas Distribution Operations subsidiaries or predecessors may have liability. The program has identified 63 such sites where liability is probable. Remedial actions at many of these sites are being overseen by state or federal environmental agencies through consent agreements or voluntary remediation agreements.
We utilize a probabilistic model to estimate our future remediation costs related to MGP sites. The model was prepared with the assistance of a third party and incorporates our experience and general industry experience with remediating MGP sites. We
complete an annual refresh of the model in the second quarter of each fiscal year. No material changes to the estimated future remediation costs were noted as a result of the refresh completed as of June 30, 2019. Our total estimated liability related to the facilities subject to remediation was $102.2 million and $97.5 million at December 31, 2019 and 2018, respectively. The liability represents our best estimate of the probable cost to remediate the facilities. We believe that it is reasonably possible that remediation costs could vary by as much as $20 million in addition to the costs noted above. Remediation costs are estimated based on the best available information, applicable remediation standards at the balance sheet date, and experience with similar facilities.
CCRs. On April 17, 2015, the EPA issued a final rule for regulation of CCRs. The rule regulates CCRs under the RCRA Subtitle D, which determines them to be nonhazardous. The rule is implemented in phases and requires increased groundwater monitoring, reporting, recordkeeping and posting of related information to the Internet. The rule also establishes requirements related to CCR management and disposal. The rule will allow NIPSCO to continue its byproduct beneficial use program.
To comply with the rule, NIPSCO completed capital expenditures to modify its infrastructure and manage CCRs during 2019. The CCR rule also 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 requirements that will be established by environmental authorities, compliance strategies that will be used and the preliminary nature of available data used to estimate costs. As allowed by the rule, 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 has filed initial CCR closure plans for R.M. Schahfer Generating Station and Michigan City Generating Station with the Indiana Department of Environmental Management.
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. Based upon a study performed in 2016 of the final rule, capital compliance costs were expected to be approximately $170.0 million. The EPA has proposed revisions to the final rule, and public comments were due on January 21, 2020. NIPSCO does not anticipate material ELG compliance costs based on the preferred option announced as part of NIPSCO's 2018 Integrated Resource Plan (discussed below).
E.         Other Matters.
NIPSCO 2018 Integrated Resource Plan. Multiple factors, but primarily economic ones, including low natural gas prices, advancing cost effective renewable technology and increasing capital and operating costs associated with existing coal plants, have led NIPSCO to conclude in its October 2018 Integrated Resource Plan submission that NIPSCO’s current fleet of coal generation facilities will be retired earlier than previous Integrated Resource Plans had indicated.
The Integrated Resource Plan evaluated demand-side and supply-side resource alternatives to reliably and cost effectively meet NIPSCO customers' future energy requirements over the ensuing 20 years. The preferred option within the Integrated Resource Plan retires R.M. Schahfer Generating Station (Units 14, 15, 17, and 18) by 2023 and Michigan City Generating Station (Unit 12) by 2028. These units represent 2,080 MW of generating capacity, equal to 72% of NIPSCO’s remaining generating capacity (and 100% of NIPSCO's remaining coal-fired generating capacity) after the retirement of Bailly Units 7 and 8 on May 31, 2018.
The current replacement plan includes renewable sources of energy, including wind, solar, and battery storage to be obtained through a combination of NIPSCO ownership and PPAs.
In January 2019, NIPSCO executed two 20 year PPAs to purchase 100% of the output from renewable generation facilities at a fixed price per MWh. NIPSCO submitted the PPAs to the IURC for approval in February 2019 and the IURC approved the PPAs on June 5, 2019. Payments under the PPAs will not begin until the associated generation facilities are constructed by the owner / seller which is currently scheduled to be complete by the end of 2020 for one facility. NIPSCO has filed a notice with the IURC of its intention not to move forward with one of its approved PPAs due to the failure to meet a condition precedent in the agreement as a result of local zoning restrictions.
Also in January 2019, NIPSCO executed a BTA with a developer to construct a renewable generation facility with a nameplate capacity of approximately 100 MW. Once complete, ownership of the facility would be transferred to a joint venture owned by NIPSCO, the developer and an unrelated tax equity partner. The aforementioned joint venture is expected to be fully owned by NIPSCO after the PTC are monetized from the project (approximately 10 years after the facility goes into service). NIPSCO's purchase requirement under the BTA is dependent on satisfactory approval of the BTA by the IURC, successful execution of an agreement with a tax equity partner, and timely completion of construction. NIPSCO submitted the BTA to the IURC for approval
in February 2019 and the IURC approved the BTA on August 7, 2019. Required FERC filings occurred after receiving the IURC order and the related approvals were received. Construction of the facility is expected to be completed by the end of 2020.
On October 1, 2019, NIPSCO announced the opening of its next round of RFP to consider potential resources to meet the future electric needs of its customers. The RFP closed on November 20, 2019, and NIPSCO continues to evaluate the results. NIPSCO is considering all sources in the RFP process.
In October 2019, NIPSCO executed a BTA with a developer to construct an additional renewable generation facility with a nameplate capacity of approximately 300 MW. Once complete, ownership of the facility would be transferred to a joint venture owned by NIPSCO, the developer and an unrelated tax equity partner. The aforementioned joint venture is expected to be fully owned by NIPSCO after the PTC are monetized from the project (approximately 10 years after the facility goes into service). NIPSCO's purchase requirement under the BTA is dependent on satisfactory approval of the BTA by the IURC, successful execution of an agreement with a tax equity partner, and timely completion of construction. NIPSCO submitted the BTA to the IURC for approval on October 22, 2019, and the IURC approved the BTA on February 19, 2020. Required FERC filings are expected to be filed by the end of June 2020. Construction of the facility is expected to be completed by the end of 2021.
Greater Lawrence Incident Restoration. In addition to the amounts estimated for third-party claims and fines, penalties and settlements associated with government investigations described above, since the Greater Lawrence Incident, we have recorded expenses of approximately $420 million for other incident-related costs. We estimate that total other incident-related costs will range from $450 million to $460 million, depending on the incurrence of costs associated with resolving outstanding inquiries and investigations discuss above in " - C. Legal Proceedings." Such costs include certain consulting costs, legal costs, vendor costs, claims center costs, labor and related expenses incurred in connection with the incident, and insurance-related loss surcharges. The amounts set forth above do not include the capital cost of the pipeline replacement, which is set forth below, or any estimates for fines and penalties, which are discussed above in " - C. Legal Proceedings."
As discussed in "- C. Legal Proceedings," the aggregate amount of third-party liability insurance coverage available for losses arising from the Greater Lawrence Incident is $800 million. We have collected the entire $800 million as of December 31, 2019. Expenses related to the incident have exceeded the total amount of insurance coverage available under our policies.
The following table summarizes expenses incurred and insurance recoveries recorded since the Greater Lawrence Incident. This activity is presented within "Operation and maintenance" and "Other, net" in our Statements of Consolidated Income (Loss).
 
Year Ended
 
Year Ended
 
(in millions)
December 31, 2018
 
December 31, 2019
Incident to Date
Third-party claims and government fines, penalties and settlements
$
757

 
$
284

$
1,041

Other incident-related costs
266

 
154

420

Total
1,023

 
438

1,461

Insurance recoveries recorded
(135
)
 
(665
)
(800
)
Loss (benefit) to income before income taxes
$
888

 
$
(227
)
$
661


The following table presents activity related to our Greater Lawrence Incident insurance recovery, which we have recovered in full as of December 31, 2019.
(in millions)
Insurance receivable(1)
Balance, December 31, 2018
$
130

Insurance recoveries recorded in first quarter of 2019
100

Cash collected from insurance recoveries in the first quarter of 2019
(108
)
Balance, March 31, 2019
122

Insurance recoveries recorded in the second quarter of 2019
435

Cash collected from insurance recoveries in the second quarter of 2019
(297
)
Balance, June 30, 2019
$
260

Insurance recoveries recorded in third quarter of 2019
—

Cash collected from insurance recoveries in the third quarter of 2019
(260
)
Balance, September 30, 2019
$
—

Insurance recoveries recorded in the fourth quarter of 2019
130

Cash collected from insurance recoveries in the fourth quarter of 2019
(130
)
Balance, December 31, 2019
$
—

(1)$5 million of insurance recoveries were collected during 2018.
Greater Lawrence Pipeline Replacement. In connection with the Greater Lawrence Incident, Columbia of Massachusetts, in cooperation with the Massachusetts Governor’s office, replaced the entire affected 45-mile cast iron and bare steel pipeline system that delivers gas to approximately 7,500 gas meters, the majority of which serve residences and approximately 700 of which serve businesses impacted in the Greater Lawrence Incident. This system was replaced with plastic distribution mains and service lines, as well as enhanced safety features such as pressure regulation and excess flow valves at each premise.
Since the Greater Lawrence Incident and through December 31, 2019, we have invested approximately $258 million of capital spend for the pipeline replacement; this work was completed in 2019. We maintain property insurance for gas pipelines and other applicable property. Columbia of Massachusetts has filed a proof of loss with its property insurer for the full cost of the pipeline replacement. In January 2020, we filed a lawsuit against the property insurer, seeking payment of our property claim. We are currently unable to predict the timing or amount of any insurance recovery under the property policy. The recovery of any capital investment not reimbursed through insurance will be addressed in a future regulatory proceeding; a future regulatory proceeding is dependent on the outcome of the sale of the Massachusetts Business. The outcome of such a proceeding (if any) is uncertain. In accordance with ASC 980-360, if it becomes probable that a portion of the pipeline replacement cost will not be recoverable through customer rates and an amount can be reasonably estimated, we will reduce our regulated plant balance for the amount of the probable disallowance and record an associated charge to earnings. This could result in a material adverse effect to our financial condition, results of operations and cash flows. Additionally, if a rate order is received allowing recovery of the investment with no or reduced return on investment, a loss on disallowance may be required.
State Income Taxes Related to Greater Lawrence Incident Expenses. As of December 31, 2018, expenses related to the Greater Lawrence Incident were $1,023 million. In the fourth quarter of 2019, we filed an application for Alternative Apportionment with the MA DOR to request an allocable approach to these expenses for purposes of Massachusetts state income taxes, which, if approved, would result in a state deferred tax asset of approximately $50 million, net. The MA DOR is expected to review the application within nine months from the date of filing, and we believe it is reasonably possible that the application will be accepted, or an alternative method proposed.
v3.19.3.a.u2
Accumulated Other Comprehensive Loss
 12 Months Ended
Dec. 31, 2019
Components of Accumulated Other Comprehensive Income (Loss) [Abstract]  
Accumulated Other Comprehensive Loss Accumulated Other Comprehensive Loss
The following table displays the activity of Accumulated Other Comprehensive Loss, net of tax:
(in millions)
Gains and Losses on Securities(1)
 
Gains and Losses on Cash Flow Hedges(1)
 
Pension and OPEB Items(1)
 
Accumulated
Other
Comprehensive
Loss(1)
Balance as of January 1, 2017
$
(0.6
)
 
$
(6.9
)
 
$
(17.6
)
 
$
(25.1
)
Other comprehensive income (loss) before reclassifications
0.6

 
(24.2
)
 
1.9

 
(21.7
)
Amounts reclassified from accumulated other comprehensive loss
0.2

 
1.7

 
1.5

 
3.4

Net current-period other comprehensive income (loss)
0.8

 
(22.5
)
 
3.4

 
(18.3
)
Balance as of December 31, 2017
$
0.2

 
$
(29.4
)
 
$
(14.2
)
 
$
(43.4
)
Other comprehensive income (loss) before reclassifications
(3.0
)
 
55.8

 
(4.4
)
 
48.4

Amounts reclassified from accumulated other comprehensive loss
0.4

 
(33.1
)
 
—

 
(32.7
)
Net current-period other comprehensive income (loss)
(2.6
)
 
22.7

 
(4.4
)
 
15.7

Reclassification due to adoption of ASU 2018-02
—

 
(6.3
)
 
(3.2
)
 
(9.5
)
Balance as of December 31, 2018
$
(2.4
)
 
$
(13.0
)
 
$
(21.8
)
 
$
(37.2
)
Other comprehensive income (loss) before reclassifications
6.1

 
(64.3
)
 
2.3

 
(55.9
)
Amounts reclassified from accumulated other comprehensive loss
(0.4
)
 
0.1

 
0.8

 
0.5

Net current-period other comprehensive income (loss)
5.7

 
(64.2
)
 
3.1

 
(55.4
)
Balance as of December 31, 2019
$
3.3

 
$
(77.2
)
 
$
(18.7
)
 
$
(92.6
)
 
 (1)All amounts are net of tax. Amounts in parentheses indicate debits.
v3.19.3.a.u2
Other, Net
 12 Months Ended
Dec. 31, 2019
Other Nonoperating Income (Expense) [Abstract]  
Other, Net Other, Net
Year Ended December 31, (in millions)
2019
 
2018
 
2017
Interest income
$
7.7

 
$
6.6

 
$
4.6

AFUDC equity
8.0

 
14.2

 
12.6

Charitable contributions(1)
(5.1
)
 
(45.3
)
 
(19.9
)
Pension and other postretirement non-service cost(2)
(16.5
)
 
18.0

 
(10.6
)
Interest rate swap settlement gain(3)
—

 
46.2

 
—

Miscellaneous
0.7

 
3.8

 
(0.2
)
Total Other, net
$
(5.2
)
 
$
43.5

 
$
(13.5
)

(1) 2018 charitable contributions include $20.7 million related to the Greater Lawrence Incident and $20.0 million of discretionary contributions made to the Nisource Charitable Foundation. See Note 19, "Other Commitments and Contingencies" for additional information on the Greater Lawrence Incident.
(2) See Note 11, "Pension and Other Postretirement Benefits" for additional information.
(3) See Note 9, "Risk Management Activities" for additional information.
v3.19.3.a.u2
Interest Expense, Net
 12 Months Ended
Dec. 31, 2019
Interest Expense [Abstract]  
Interest Expense, Net Interest Expense, Net
Year Ended December 31, (in millions)
2019
 
2018
 
2017
Interest on long-term debt
$
327.7

 
$
342.2

 
$
354.8

Interest on short-term borrowings
50.8

 
31.8

 
14.9

Debt discount/cost amortization
8.3

 
7.7

 
7.2

Accounts receivable securitization fees
2.6

 
2.6

 
2.5

Allowance for borrowed funds used and interest capitalized during construction
(7.5
)
 
(9.1
)
 
(6.2
)
Debt-based post-in-service carrying charges
(18.7
)
 
(35.0
)
 
(36.4
)
Other
15.7

 
13.1

 
16.4

Total Interest Expense, net
$
378.9

 
$
353.3

 
$
353.2
v3.19.3.a.u2
Segments Of Business
 12 Months Ended
Dec. 31, 2019
Segment Reporting [Abstract]  
Segments Of Business Segments of Business
At December 31, 2019, our operations are divided into two primary reportable segments. The Gas Distribution Operations segment provides natural gas service and transportation for residential, commercial and industrial customers in Ohio, Pennsylvania, Virginia, Kentucky, Maryland, Indiana and Massachusetts. The Electric Operations segment provides electric service in 20 counties in the northern part of Indiana.
The following table provides information about our reportable 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.
Year Ended December 31, (in millions)
2019
 
2018
 
2017
Operating Revenues
 
 
 
 
 
Gas Distribution Operations
 
 
 
 
 
Unaffiliated
$
3,509.7

 
$
3,406.4

 
$
3,087.9

Intersegment
13.1

 
13.1

 
14.2

Total
3,522.8

 
3,419.5

 
3,102.1

Electric Operations
 
 
 
 
 
Unaffiliated
1,698.4

 
1,707.4

 
1,785.7

Intersegment
0.8

 
0.8

 
0.8

Total
1,699.2

 
1,708.2

 
1,786.5

Corporate and Other
 
 
 
 
 
Unaffiliated
0.8

 
0.7

 
1.0

Intersegment
468.1

 
517.6

 
510.8

Total
468.9

 
518.3

 
511.8

Eliminations
(482.0
)
 
(531.5
)
 
(525.8
)
Consolidated Operating Revenues
$
5,208.9

 
$
5,114.5

 
$
4,874.6


Year Ended December 31, (in millions)
2019
 
2018
 
2017
Operating Income (Loss)
 
 
 
 
 
Gas Distribution Operations
$
675.4

 
$
(254.1
)
 
$
550.1

Electric Operations
406.8

 
386.1

 
367.4

Corporate and Other(2)
(191.5
)
 
(7.3
)
 
3.7

Consolidated Operating Income
$
890.7

 
$
124.7

 
$
921.2

Depreciation and Amortization
 
 
 
 
 
Gas Distribution Operations
$
403.2

 
$
301.0

 
$
269.3

Electric Operations
277.3

 
262.9

 
277.8

Corporate and Other
36.9

 
35.7

 
23.2

Consolidated Depreciation and Amortization
$
717.4

 
$
599.6

 
$
570.3

Assets
 
 
 
 
 
Gas Distribution Operations
$
14,224.5

 
$
13,527.0

 
$
12,048.8

Electric Operations
6,027.6

 
5,735.2

 
5,478.6

Corporate and Other
2,407.7

 
2,541.8

 
2,434.3

Consolidated Assets
$
22,659.8

 
$
21,804.0

 
$
19,961.7

Capital Expenditures(1)
 
 
 
 
 
Gas Distribution Operations
$
1,380.3

 
$
1,315.3

 
$
1,125.6

Electric Operations
468.9

 
499.3

 
592.4

Corporate and Other
18.6

 
—

 
35.8

Consolidated Capital Expenditures
$
1,867.8


$
1,814.6

 
$
1,753.8


(1)Amounts differ from those presented on the Statements of Consolidated Cash Flows primarily due to the inclusion of capital expenditures included in current liabilities and AFUDC Equity.
(2) In 2019, Corporate and Other reflects an impairment charge of $204.8 million for goodwill related to Columbia of Massachusetts. For additional information, see Note 6, "Goodwill and Other Intangible Assets."
v3.19.3.a.u2
Quarterly Financial Data
 12 Months Ended
Dec. 31, 2019
Quarterly Financial Data [Abstract]  
Quarterly Financial Data (Unaudited) Quarterly Financial Data (Unaudited)
Quarterly financial data does not always reveal the trend of our business operations due to nonrecurring items and seasonal weather patterns, which affect earnings and related components of revenue and operating income.
(in millions, except per share data)
First
Quarter(1)
 
Second
Quarter(2)
 
Third
   Quarter(3)
 
Fourth
Quarter(4)
2019
 
 
 
 
 
 
 
Operating Revenues
$
1,869.8

 
$
1,010.4

 
$
931.5

 
$
1,397.2

Operating Income (Loss)
374.2

 
463.5

 
91.0

 
(38.0
)
Net Income (Loss)
218.9

 
296.9

 
6.6

 
(139.3
)
Preferred Dividends
(13.8
)
 
(13.8
)
 
(13.8
)
 
(13.7
)
Net Income (Loss) Available to Common Shareholders
205.1

 
283.1

 
(7.2
)
 
(153.0
)
Earnings (Loss) Per Share
 
 
 
 
 
 
 
Basic Earnings (Loss) Per Share
$
0.55

 
$
0.76

 
$
(0.02
)
 
$
(0.41
)
Diluted Earnings (Loss) Per Share
$
0.55

 
$
0.75

 
$
(0.02
)
 
$
(0.41
)
2018
 
 
 
 
 
 
 
Operating Revenues
$
1,750.8

 
$
1,007.0

 
$
895.0

 
$
1,461.7

Operating Income (Loss)
400.6

 
118.4

 
(315.9
)
 
(78.4
)
Net Income (Loss)
276.1

 
24.5

 
(339.5
)
 
(11.7
)
Preferred Dividends
—

 
(1.3
)
 
(5.6
)
 
(8.1
)
Net Income (Loss) Available to Common Shareholders
276.1

 
23.2

 
(345.1
)
 
(19.8
)
Earnings (Loss) Per Share
 
 
 
 
 
 
 
Basic Earnings (Loss) Per Share
$
0.82

 
$
0.07

 
$
(0.95
)
 
$
(0.05
)
Diluted Earnings (Loss) Per Share
$
0.81

 
$
0.07

 
$
(0.95
)
 
$
(0.05
)

(1) Net income for the first quarter of 2019 was impacted by $108.0 million in insurance recoveries (pretax) related to the Greater Lawrence Incident. See Note 19-E, "Other Matters" for additional information.
(2) Net income for the second quarter of 2019 was impacted by $297.0 million in insurance recoveries (pretax) related to the Greater Lawrence Incident. See Note 19-E, "Other Matters" for additional information.
(3) Net loss for the third quarter of 2018 was impacted by approximately $462 million in expenses (pretax) related to the Greater Lawrence Incident restoration and a $33.0 million loss (pretax) on an early extinguishment of long-term debt. See Note 19-E, "Other Matters" and Note 14, "Long-Term Debt" for additional information.
(4) Net loss for the fourth quarter of 2019 was impacted by an impairment charge of $204.8 million for goodwill and an impairment charge of $209.7 million for franchise rights, in each case related to Columbia of Massachusetts. For additional information, see Note 6, "Goodwill and Other Intangible Assets."
v3.19.3.a.u2
Supplemental Cash Flow Information
 12 Months Ended
Dec. 31, 2019
Supplemental Cash Flow Information [Abstract]  
Supplemental Cash Flow Information Supplemental Cash Flow Information
The following table provides additional information regarding our Consolidated Statements of Cash Flows for the years ended December 31, 2019, 2018 and 2017:
Year Ended December 31, (in millions)
2019
 
2018
 
2017
Supplemental Disclosures of Cash Flow Information
 
 
 
 
 
Non-cash transactions:
 
 
 
 
 
Capital expenditures included in current liabilities
$
223.6

 
$
152.0

 
$
173.0

Assets acquired under a finance lease
26.4

 
54.6

 
11.5

Assets acquired under an operating lease
13.4

 
—

 
—

Reclassification of other property to regulatory assets(1)
—

 
245.3

 
—

Assets recorded for asset retirement obligations(2)
54.6

 
78.1

 
11.4

Schedule of interest and income taxes paid:
 
 
 
 
 
Cash paid for interest, net of interest capitalized amounts
$
349.7

 
$
354.2

 
$
339.9

Cash paid for income taxes, net of refunds
10.8

 
3.3

 
5.5


(1)See Note 8 "Regulatory Matters" for additional information.
(2)See Note 7 "Asset Retirement Obligations" for additional information.
v3.19.3.a.u2
Subsequent Event
 12 Months Ended
Dec. 31, 2019
Subsequent Event [Abstract]  
Subsequent Event Subsequent Event
On February 26, 2020, NiSource and Columbia of Massachusetts entered into the Asset Purchase Agreement with Eversource. Upon the terms and subject to the conditions set forth in the Asset Purchase Agreement, NiSource and Columbia of Massachusetts agreed to sell to Eversource, with certain additions and exceptions: (1) substantially all of the assets of Columbia of Massachusetts and (2) all of the assets held by any of Columbia of Massachusetts’ affiliates that primarily relate to the Massachusetts Business, and Eversource agreed to assume certain liabilities of Columbia of Massachusetts and its affiliates. The liabilities assumed by Eversource under the Asset Purchase Agreement do not include, among others, any liabilities arising out of the Greater Lawrence Incident or liabilities of Columbia of Massachusetts or its affiliates pursuant to civil claims for injury of persons or damage to property to the extent such injury or damage occurs prior to the closing in connection with the Massachusetts Business. The Asset Purchase Agreement provides for a purchase price of $1,100 million in cash, subject to adjustment based on Columbia of Massachusetts’ net working capital as of the closing. The closing of the transactions contemplated by the Asset Purchase Agreement is subject to Hart-Scott Rodino Antitrust Improvements Act of 1976 and regulatory approvals, resolution of certain proceedings before governmental bodies and other conditions. The Massachusetts Business did not meet the requirements under GAAP to be classified as held-for-sale as of December 31, 2019. When the Massachusetts Business meets the requirements to be classified as held-for-sale, in each period leading up to the closing date of the transaction, the assets and liabilities of the Massachusetts Business will be measured at fair value, less costs to sell. The final pre-tax gain or loss on the transaction will be determined as of the closing date. Assuming the Massachusetts Business is classified as held-for-sale at March 31, 2020, we estimate that the total pre-tax loss to be measured in the quarter ended March 31, 2020 will be approximately $360 million, based on December 31, 2019 asset and liability balances and estimated transaction costs. This estimated pre-tax loss is subject to change based on estimated transaction costs, working capital adjustments and asset and liability balances at each measurement date leading up to the closing date. The sale is expected to close by September 30, 2020, subject to closing conditions.
v3.19.3.a.u2
Nature of Operations And Summary of Significant Accounting Policies (Policy)
 12 Months Ended
Dec. 31, 2019
Organization, Consolidation and Presentation of Financial Statements [Abstract]  
Company Structure And Principles Of Consolidation Company Structure and Principles of Consolidation.  We are an energy holding company incorporated in Delaware and headquartered in Merrillville, Indiana. Our subsidiaries are fully regulated natural gas and electric utility companies serving approximately 4.0 million customers in seven states. We generate substantially all of our operating income through these rate-regulated businesses. The consolidated financial statements include the accounts of us and our majority-owned subsidiaries after the elimination of all intercompany accounts and transactions.
Use Of Estimates Use of Estimates.    The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Cash, Cash Equivalents, And Restricted Cash Cash, Cash Equivalents and Restricted Cash.    We consider all highly liquid investments with original maturities of three months or less to be cash equivalents. We report amounts deposited in brokerage accounts for margin requirements as restricted cash. In addition, we have amounts deposited in trust to satisfy requirements for the provision of various property, liability, workers compensation, and long-term disability insurance, which is classified as restricted cash on the Consolidated Balance Sheets and disclosed with cash and cash equivalents on the Statements of Consolidated Cash Flows.
Accounts Receivable And Unbilled Revenue Accounts Receivable and Unbilled Revenue.    Accounts receivable on the Consolidated Balance Sheets includes both billed and unbilled amounts. Unbilled amounts of accounts receivable relate to a portion of a customer’s consumption of gas or electricity from 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. Accounts receivable fluctuates from year to year depending in large part on weather impacts and price volatility. Our accounts receivable on the Consolidated Balance Sheets include unbilled revenue, less reserves, in the amounts of $350.5 million and $324.2 million as of December 31, 2019 and 2018, respectively. The reserve for uncollectible receivables is our best estimate of the amount of probable credit losses in the existing accounts receivable. We determined the reserve based on historical experience and in consideration of current market conditions. Account balances are charged against the allowance when it is anticipated the receivable will not be recovered. Refer to Note 3, "Revenue Recognition," for additional information on customer-related accounts receivable.
Investments In Debt And Equity Securities Investments in Debt Securities.    Our investments in debt securities are carried at fair value and are designated as available-for-sale. These investments are included within “Other investments” on the Consolidated Balance Sheets. Unrealized gains and losses, net of deferred income taxes, are recorded to accumulated other comprehensive income or loss. These investments are monitored for other than temporary declines in market value. Realized gains and losses and permanent impairments are reflected in the Statements of Consolidated Income (Loss). No material impairment charges were recorded for the years ended December 31, 2019, 2018 or 2017. Refer to Note 17, "Fair Value," for additional information.
Basis Of Accounting For Rate-Regulated Subsidiaries Basis of Accounting for Rate-Regulated Subsidiaries.    Rate-regulated subsidiaries account for and report assets and liabilities consistent with the economic effect of the way in which regulators establish rates, if the rates established are designed to recover the costs of providing the regulated service and it is probable that such rates can be charged and collected. Certain expenses and credits subject to utility regulation or rate determination normally reflected in income are deferred on the Consolidated Balance Sheets and are later recognized in income as the related amounts are included in customer rates and recovered from or refunded to customers.
In the event that regulation significantly changes the opportunity for us to recover our costs in the future, all or a portion of our regulated operations may no longer meet the criteria for regulatory accounting. In such an event, a write-down of all or a portion of our existing regulatory assets and liabilities could result. If transition cost recovery was approved by the appropriate regulatory bodies that would meet the requirements under GAAP for continued accounting as regulatory assets and liabilities during such recovery period, the regulatory assets and liabilities would be reported at the recoverable amounts. If unable to continue to apply
the provisions of regulatory accounting, we would be required to apply the provisions of ASC 980-20, Discontinuation of Rate-Regulated Accounting. In management’s opinion, our regulated subsidiaries will be subject to regulatory accounting for the foreseeable future. Refer to Note 8, "Regulatory Matters," for additional information.
Utility Plant And Other Property And Related Depreciation And Maintenance Plant and Other Property and Related Depreciation and Maintenance.    Property, plant and equipment (principally utility plant) is stated at cost. The rate-regulated subsidiaries record depreciation using composite rates on a straight-line basis over the remaining service lives of the electric, gas and common properties as approved by the appropriate regulators.
Non-utility property is generally depreciated on a straight-line basis over the life of the associated asset. Refer to Note 5, "Property, Plant and Equipment," for additional information related to depreciation expense.
For rate-regulated companies, AFUDC is capitalized on all classes of property except organization costs, land, autos, office equipment, tools and other general property purchases. The allowance is applied to construction costs for that period of time between the date of the expenditure and the date on which such project is placed in service. Our pre-tax rate for AFUDC was 3.0% in 2019, 3.5% in 2018 and 4.0% in 2017.
Generally, our subsidiaries follow the practice of charging maintenance and repairs, including the cost of removal of minor items of property, to expense as incurred. When our subsidiaries retire regulated property, plant and equipment, original cost plus the cost of retirement, less salvage value, is charged to accumulated depreciation. However, when it becomes probable a regulated asset will be retired substantially in advance of its original expected useful life or is abandoned, the cost of the asset and the corresponding accumulated depreciation is recognized as a separate asset. If the asset is still in operation, the net amount is classified as "Other property, at cost, less accumulated depreciation" on the Consolidated Balance Sheets. If the asset is no longer operating, the net amount is classified in "Regulatory assets" on the Consolidated Balance Sheets. If we are able to recover a full return of and on investment, the carrying value of the asset is based on historical cost. If we are not able to recover a full return on investment, a loss on impairment is recognized to the extent the net book value of the asset exceeds the present value of future revenues discounted at the incremental borrowing rate.
When our subsidiaries sell entire regulated operating units, or retire or sell nonregulated properties, the original cost and accumulated depreciation and amortization balances are removed from "Property, Plant and Equipment" on the Consolidated Balance Sheets. Any gain or loss is recorded in earnings, unless otherwise required by the applicable regulatory body. Refer to Note 5, "Property, Plant and Equipment," for further information.
External and internal costs associated with computer software developed for internal use are capitalized. Capitalization of such costs commences upon the completion of the preliminary stage of each project. Once the installed software is ready for its intended use, such capitalized costs are amortized on a straight-line basis generally over a period of five years, except for certain significant enterprise-wide technology investments which are amortized over a ten-year period.
External and internal up-front implementation costs associated with cloud computing arrangements that are service contracts are deferred on the Consolidated Balance Sheets. Once the installed software is ready for its intended use, such deferred costs are amortized on a straight-line basis to "Operation and maintenance," over the minimum term of the contract plus contractually-provided renewal periods that are reasonable expected to be exercised -- generally up to a maximum of five years.
Goodwill And Other Intangible Assets Goodwill and Other Intangible Assets.    Substantially all of our goodwill relates to the excess of cost over the fair value of the net assets acquired in the Columbia acquisition on November 1, 2000. We test our goodwill for impairment annually as of May 1, or more frequently if events and circumstances indicate that goodwill might be impaired. Fair value of our reporting units is determined using a combination of income and market approaches.
We had other intangible assets consisting primarily of franchise rights apart from goodwill that were identified as part of the purchase price allocations associated with the acquisition of Columbia of Massachusetts, which were being amortized on a straight-line basis over forty years from the date of acquisition.
During the fourth quarter of 2019, we impaired goodwill and intangible assets related to Columbia of Massachusetts. See Note 6, "Goodwill and Other Intangible Assets," for additional information.
Accounts Receivable Transfer Program Accounts Receivable Transfer Program.    Certain of our subsidiaries have agreements with third parties to transfer certain accounts receivable without recourse. These transfers of accounts receivable are accounted for as secured borrowings. The entire gross receivables balance remains on the December 31, 2019 and 2018 Consolidated Balance Sheets and short-term debt is recorded
in the amount of proceeds received from the transferees involved in the transactions. Refer to Note 18, "Transfers of Financial Assets," for further information.
Fuel Adjustment Clause Gas Cost and Fuel Adjustment Clause.    Our regulated subsidiaries defer most differences between gas and fuel purchase costs and the recovery of such costs in revenues, and adjust future billings for such deferrals on a basis consistent with applicable state-approved tariff provisions. These deferred balances are recorded as "Regulatory assets" or "Regulatory liabilities," as appropriate, on the Consolidated Balance Sheets. Refer to Note 8, "Regulatory Matters," for additional information.
Gas Inventory Inventory.    Both the LIFO inventory methodology and the weighted average cost methodology are used to value natural gas in storage, as approved by regulators for all of our regulated subsidiaries. Inventory valued using LIFO was $47.2 million and $47.5 million at December 31, 2019 and 2018, respectively. Based on the average cost of gas using the LIFO method, the estimated replacement cost of gas in storage was less than the stated LIFO cost by $25.5 million and $12.2 million at December 31, 2019 and 2018, respectively. Gas inventory valued using the weighted average cost methodology was $203.7 million at December 31, 2019 and $239.3 million at December 31, 2018.
Electric production fuel is valued using the weighted average cost inventory methodology, as approved by NIPSCO's regulator.
Materials and supplies are valued using the weighted average cost inventory methodology.
Accounting For Exchange And Balancing Arrangements Of Natural Gas Accounting for Exchange and Balancing Arrangements of Natural Gas.    Our Gas Distribution Operations segment enters into balancing and exchange arrangements of natural gas as part of its operations and off-system sales programs. We record a receivable or payable for any of our respective cumulative gas imbalances, as well as for any gas inventory borrowed or lent under a Gas Distribution Operations exchange agreement. Exchange gas is valued based on individual regulatory jurisdiction requirements (for example, historical spot rate, spot at the beginning of the month). These receivables and payables are recorded as “Exchange gas receivable” or “Exchange gas payable” on our Consolidated Balance Sheets, as appropriate.
Accounting For Risk Management Activities Accounting for Risk Management Activities.    We account for our derivatives and hedging activities in accordance with ASC 815. We recognize all derivatives as either assets or liabilities on the Consolidated Balance Sheets at fair value, unless such contracts are exempted as a normal purchase normal sale under the provisions of the standard. The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and resulting designation.
We have elected not to net fair value amounts for any of our derivative instruments or the fair value amounts recognized for the right to receive cash collateral or obligation to pay cash collateral arising from those derivative instruments recognized at fair value, which are executed with the same counterparty under a master netting arrangement. See Note 9, "Risk Management Activities," for additional information.
Income Taxes And Investment Tax Credits Income Taxes and Investment Tax Credits.    We record income taxes to recognize full interperiod tax allocations. Under the asset and liability method, deferred income taxes are provided for the tax consequences of temporary differences by applying enacted statutory tax rates applicable to future years to differences between the financial statement carrying amount and the tax basis of existing assets and liabilities. Investment tax credits associated with regulated operations are deferred and amortized as a reduction to income tax expense over the estimated useful lives of the related properties.
To the extent certain deferred income taxes of the regulated companies are recoverable or payable through future rates, regulatory assets and liabilities have been established. Regulatory assets for income taxes are primarily attributable to property-related tax timing differences for which deferred taxes had not been provided in the past, when regulators did not recognize such taxes as costs in the rate-making process. Regulatory liabilities for income taxes are primarily attributable to the regulated companies’ obligation to refund to ratepayers deferred income taxes provided at rates higher than the current Federal income tax rate. Such property-related amounts are credited to ratepayers using either the average rate assumption method or the reverse South Georgia method. Non property-related amounts are credited to ratepayers consistent with state utility commission direction.
Pursuant to the Internal Revenue Code and relevant state taxing authorities, we and our subsidiaries file consolidated income tax returns for federal and certain state jurisdictions. We and our subsidiaries are parties to a tax sharing agreement. Income taxes recorded by each party represent amounts that would be owed had the party been separately subject to tax.
Environmental Expenditures Environmental Expenditures.    We accrue for costs associated with environmental remediation obligations when the incurrence of such costs is probable and the amounts can be reasonably estimated, regardless of when the expenditures are actually made. The undiscounted estimated future expenditures are based on currently enacted laws and regulations, existing technology and estimated site-specific costs where assumptions may be made about the nature and extent of site contamination, the extent of
cleanup efforts, costs of alternative cleanup methods and other variables. The liability is adjusted as further information is discovered or circumstances change. The accruals for estimated environmental expenditures are recorded on the Consolidated Balance Sheets in “Legal and environmental” for short-term portions of these liabilities and “Other noncurrent liabilities” for the respective long-term portions of these liabilities. Rate-regulated subsidiaries applying regulatory accounting establish regulatory assets on the Consolidated Balance Sheets to the extent that future recovery of environmental remediation costs is probable through the regulatory process. Refer to Note 19, "Other Commitments and Contingencies," for further information.
Excise Taxes Excise Taxes. As an agent for some state and local governments, we invoice and collect certain excise taxes levied by state and local governments on customers and record these amounts as liabilities payable to the applicable taxing jurisdiction. Such balances are presented within "Other accruals" on the Consolidated Balance Sheets. These types of taxes collected from customers, comprised largely of sales taxes, are presented on a net basis affecting neither revenues nor cost of sales. We account for excise taxes for which we are liable by recording a liability for the expected tax with a corresponding charge to “Other taxes” expense on the Statements of Consolidated Income (Loss).
Accrued Insurance Liabilities Accrued Insurance Liabilities. We accrue for insurance costs related to workers compensation, automobile, property, general and employment practices liabilities based on the most probable value of each claim. In general, claim values are determined by professional, licensed loss adjusters who consider the facts of the claim, anticipated indemnification and legal expenses, and respective state rules. Claims are reviewed by us at least quarterly and an adjustment is made to the accrual based on the most current information. Refer to Note 19-E "Other Matters" for further information on accrued insurance liabilities related to the Greater Lawrence Incident.
v3.19.3.a.u2
Recent Accounting Pronouncements (Tables)
 12 Months Ended
Dec. 31, 2019
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]  
Description of New Accounting Pronouncements Not yet Adopted [Text Block]
Recently Issued Accounting Pronouncements
We are currently evaluating the impact of certain ASUs on our Consolidated Financial Statements or Notes to Consolidated Financial Statements, which are described below:
Standard
Description
Effective Date
Effect on the financial statements or other significant matters
ASU 2018-14, Compensation—Retirement Benefits—Defined Benefit Plans—General (Subtopic 715-20): Disclosure Framework—Changes to the Disclosure Requirements for Defined Benefit Plans
The pronouncement modifies the disclosure requirements for defined benefit pension or other postretirement benefit plans. The guidance removes disclosures that are no longer considered cost beneficial, clarifies the specific requirements of disclosures and adds disclosure requirements identified as relevant. The modifications affect annual period disclosures and must be applied on a retrospective basis to all periods presented.
Annual periods ending after December 15, 2020. Early adoption is permitted.
We are currently evaluating the effects of this pronouncement on our Notes to Consolidated Financial Statements. We expect to adopt this ASU on its effective date.

ASU 2019-12,
Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes
This pronouncement simplifies the accounting for income taxes by eliminating certain exceptions to the general principles in ASC 740, income taxes. It also improves consistency of application for other areas of the guidance by clarifying and amending existing guidance.
 
Annual periods beginning after December 15, 2020. Early adoption is permitted.
We are currently evaluating the effects of this pronouncement on our Consolidated Financial Statements and Notes to Consolidated Financial Statements. We tentatively expect to adopt this ASU on its effective date.
Schedule of New Accounting Pronouncements and Changes in Accounting Principles [Table Text Block]
Recently Adopted Accounting Pronouncements
Standard
Adoption
ASU 2019-01, Leases (Topic 842): Codification Improvements
See Note 16, "Leases," for our discussion of the effects of implementing these standards.
ASU 2018-11, Leases (Topic 842): Targeted Improvements
ASU 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842
ASU 2016-02, Leases (Topic 842)
ASU 2019-04, Codification Improvements to Topic 326, Financial Instruments-Credit Losses, Topic 815, Derivatives and Hedging, and Topic 825, Financial Instruments
In June 2016, the FASB issued ASU 2016-13 that revised the guidance on the impairment of most financial assets and certain other instruments that are not measured at fair value through net income. This ASU replaces the current "incurred loss" model with an "expected loss" model for instruments measured at amortized cost. It also requires entities to record allowances for available-for-sale securities rather than impair the carrying amount of the securities. Subsequent improvements to the estimated credit losses of available-for-sale securities will be recognized immediately in earnings instead of over time as they are under historic guidance.

We adopted this ASU effective January 1, 2020, using a modified retrospective method. Adoption of this standard did not have a material impact on our Consolidated Financial Statements. No material adjustments were made to January 1, 2020 opening balances as a result of adoption. For our investments that are classified as available for sale debt securities, we will recognize impairment using an allowance approach instead of an 'other than temporary' impairment (OTTI) model. Since we do not have amounts previously recognized in other comprehensive income related to previous OTTI charges, provisions of this ASU are adopted prospectively. In regards to our recorded balances of trade receivables that fall within the scope of this ASU, the ASU did not result in any significant modifications to our policies related to recognizing an allowance on our trade receivables. Based on shared risk characteristics, we segregate our trade receivables into separate pools. We will apply separate models to calculate reserves for uncollectible receivables, as well as consider factors other than time to determine whether a credit loss exists. ASC 326 also prescribes additional presentation and disclosure requirements. For reporting periods beginning after January 1, 2020, we will include additional disclosures in our Notes to Consolidated Financial Statements based on qualitative and quantitative assessment of materiality.
ASU 2016-13,  Financial Instruments-Credit Losses (Topic 326)
v3.19.3.a.u2
Revenue Recognition (Tables)
 12 Months Ended
Dec. 31, 2019
Revenue from Contract with Customer [Abstract]  
Revenue Recognition Under Previous Guidance
The table below provides results for the years ended December 31, 2019 and 2018 as if it had been prepared under historic accounting guidance. We included operating revenue information for the year ended December 31, 2017 for comparability.
Year Ended December 31, (in millions)
 
2019
 
2018
 
2017
Operating Revenues
 
 
 
 
 
 
Gas Distribution
 
$
2,336.1

 
$
2,348.4

 
$
2,063.2

Gas Transportation
 
1,171.3

 
1,055.2

 
1,021.5

Electric
 
1,698.5

 
1,707.4

 
1,785.5

Other
 
3.0

 
3.5

 
4.4

Total Operating Revenues
 
$
5,208.9

 
$
5,114.5

 
$
4,874.6
Disaggregation of Revenue
The table below reconciles revenue disaggregation by customer class to segment revenue as well as to revenues reflected on the Statements of Consolidated Income (Loss):
Year Ended December 31, 2019 (in millions)
Gas Distribution Operations
 
Electric Operations
 
Corporate and Other
 
Total
Customer Revenues(1)
 
 
 
 
 
 
 
Residential
$
2,309.0

 
$
481.6

 
$
—

 
$
2,790.6

Commercial
771.3

 
486.6

 
—

 
1,257.9

Industrial
245.2

 
607.7

 
—

 
852.9

Off-system
77.7

 
—

 
—

 
77.7

Miscellaneous
52.0

 
21.5

 
0.8

 
74.3

Total Customer Revenues
$
3,455.2

 
$
1,597.4

 
$
0.8

 
$
5,053.4

Other Revenues
54.5

 
101.0

 
—

 
155.5

Total Operating Revenues
$
3,509.7

 
$
1,698.4

 
$
0.8

 
$
5,208.9

(1) Customer revenue amounts exclude intersegment revenues. See Note 23, "Segments of Business," for discussion of intersegment revenues.
Year Ended December 31, 2018 (in millions)
Gas Distribution Operations
 
Electric Operations
 
Corporate and Other
 
Total
Customer Revenues(1)
 
 
 
 
 
 
 
Residential
$
2,250.0

 
$
494.7

 
$
—

 
$
2,744.7

Commercial
751.9

 
492.7

 
—

 
1,244.6

Industrial
228.0

 
613.6

 
—

 
841.6

Off-system
92.4

 
—

 
—

 
92.4

Miscellaneous
49.7

 
17.4

 
0.7

 
67.8

Total Customer Revenues
$
3,372.0

 
$
1,618.4

 
$
0.7

 
$
4,991.1

Other Revenues
34.4

 
89.0

 
—

 
123.4

Total Operating Revenues
$
3,406.4

 
$
1,707.4

 
$
0.7

 
$
5,114.5

(1) Customer revenue amounts exclude intersegment revenues. See Note 23, "Segments of Business," for discussion of intersegment revenues.
Customer Accounts Receivable The opening and closing balances of customer receivables for the years ended December 31, 2019 and 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)
Balance as of December 31, 2018
$
540.5

 
$
349.1

Balance as of December 31, 2019
466.6

 
346.6

Decrease
$
(73.9
)
 
$
(2.5
)
(1) Customer billed receivables decreased due to decreased natural gas costs and warmer weather in 2019 compared to 2018.
v3.19.3.a.u2
Earnings Per Share (Tables)
 12 Months Ended
Dec. 31, 2019
Earnings Per Share [Abstract]  
Schedule of Weighted Average Number of Shares The computation of diluted average common shares is as follows:
Year Ended December 31, (in thousands)
2019
 
2018
 
2017
Denominator
 
 
 
 
 
Basic average common shares outstanding
374,650

 
356,491

 
329,388

Dilutive potential common shares:
 
 
 
 
 
Shares contingently issuable under employee stock plans
929

 
—

 
547

Shares restricted under stock plans
154

 
—

 
821

Forward agreements
253

 
—

 
—

Diluted Average Common Shares
375,986

 
356,491

 
330,756
v3.19.3.a.u2
Property, Plant And Equipment (Tables)
 12 Months Ended
Dec. 31, 2019
Property, Plant and Equipment [Abstract]  
Schedule Of Property, Plant And Equipment property, plant and equipment on the Consolidated Balance Sheets are classified as follows: 
At December 31, (in millions)
2019
 
2018
Property, Plant and Equipment
 
 
 
Gas Distribution Utility(1)
$
14,989.7

 
$
13,776.0

Electric Utility(1)
8,902.3

 
8,374.2

Corporate
153.3

 
155.8

Construction Work in Process
457.3

 
474.8

Non-Utility and Other
39.3

 
38.7

Total Property, Plant and Equipment
$
24,541.9

 
$
22,819.5

Accumulated Depreciation and Amortization
 
 
 
Gas Distribution Utility(1)
$
(3,556.0
)
 
$
(3,373.8
)
Electric Utility(1)
(3,973.8
)
 
(3,809.5
)
Corporate
(79.5
)
 
(74.6
)
Non-Utility and Other
(20.4
)
 
(19.1
)
Total Accumulated Depreciation and Amortization
$
(7,629.7
)
 
$
(7,277.0
)
Net Property, Plant and Equipment
$
16,912.2

 
$
15,542.5


(1)NIPSCO’s common utility plant and associated accumulated depreciation and amortization are allocated between Gas Distribution Utility and Electric Utility Property, Plant and Equipment.
Schedule Of Depreciation Provisions For Utility Plant As A Percentage Of The Original Cost
The weighted average depreciation provisions for utility plant, as a percentage of the original cost, for the periods ended December 31, 2019, 2018 and 2017 were as follows:
 
2019
 
2018
 
2017
Electric Operations(1)
2.8
%
 
2.9
%
 
3.4
%
Gas Distribution Operations
2.5
%
 
2.2
%
 
2.1
%
v3.19.3.a.u2
Goodwill and Other Intangible Assets (Tables)
 12 Months Ended
Dec. 31, 2019
Goodwill and Intangible Assets Disclosure [Abstract]  
Schedule of Goodwill The following presents our goodwill balance allocated by segment as of December 31, 2019 and 2018:
(in millions)
2019
 
2018
Gas Distribution Operations
$
1,485.9

 
$
1,690.7

Electric Operations
—

 
—

Corporate and Other
—

 
—

Total
$
1,485.9

 
$
1,690.7
v3.19.3.a.u2
Asset Retirement Obligations (Tables)
 12 Months Ended
Dec. 31, 2019
Asset Retirement Obligation [Abstract]  
Changes In Liability For Asset Retirement Obligations
Changes in our liability for asset retirement obligations for the years 2019 and 2018 are presented in the table below:
(in millions)
2019
 
2018
 
Beginning Balance
$
352.0

 
$
268.7

 
Accretion recorded as a regulatory asset/liability
15.7

 
11.1

 
Additions
—

 
63.3

(2) 
Settlements
(5.4
)
 
(5.9
)
 
Change in estimated cash flows 
54.6

(1) 
14.8

(2) 
Ending Balance
$
416.9

 
$
352.0

 

(1)The change in estimated cash flows for 2019 is primarily attributed to changes in estimated costs and settlement timing for electric generating stations and the changes in estimated costs for retirement of gas mains.
(2)In 2018, $59.8 million of additions and $17.7 million of the change in estimated cash flows are attributed to costs associated with refining the CCR compliance plan. See Note 19-D, "Environmental Matters," for additional information on CCRs.
v3.19.3.a.u2
Regulatory Matters (Tables)
 12 Months Ended
Dec. 31, 2019
Regulatory Assets and Liabilities Disclosure [Abstract]  
Regulatory Assets
Regulatory assets were comprised of the following items: 
At December 31, (in millions)
2019
 
2018
Regulatory Assets
 
 
 
Unrecognized pension and other postretirement benefit costs (see Note 11)
$
739.1

 
$
798.3

Deferred pension and other postretirement benefit costs (see Note 11)
91.3

 
74.1

Environmental costs (see Note 19-D)
73.4

 
61.5

Regulatory effects of accounting for income taxes (see Note 1-N and Note 10)
234.0

 
233.1

Under-recovered gas and fuel costs (see Note 1-J)
3.9

 
34.7

Depreciation
210.7

 
209.6

Post-in-service carrying charges
219.8

 
206.6

Safety activity costs
118.6

 
91.7

DSM programs
50.1

 
45.5

Bailly Generating Station
221.8

 
244.3

Other
276.9

 
238.1

Total Regulatory Assets
$
2,239.6

 
$
2,237.5
Regulatory Liabilities
Regulatory liabilities were comprised of the following items: 
At December 31, (in millions)
2019
 
2018
Regulatory Liabilities
 
 
 
Over-recovered gas and fuel costs (see Note 1-J)
$
42.6

 
$
32.0

Cost of removal (see Note 7)
1,047.5

 
1,076.0

Regulatory effects of accounting for income taxes (see Note 1-N and Note 10)
1,307.0

 
1,428.3

Deferred pension and other postretirement benefit costs (see Note 11)
64.7

 
62.7

Other
50.4

 
61.0

Total Regulatory Liabilities
$
2,512.2

 
$
2,660.0
Schedule of Regulatory Programs
The following table describes the most recent vintage of our regulatory programs to recover infrastructure replacement and other federally-mandated compliance investments currently in rates and those pending commission approval:
(in millions)
 
 
 
 
 
Company
Program
Incremental Revenue
Incremental Capital Investment
Investment Period
Filed
Status
Rates
Effective
Columbia of Ohio
IRP - 2019(1)
$
18.2

$
199.6

1/18-12/18
February 28, 2019
Approved
April 24, 2019
May 2019
Columbia of Ohio
CEP - 2018
$
74.5

$
659.9

1/11-12/17
December 1, 2017
Approved
November 28, 2018
December 2018
Columbia of Ohio
CEP - 2019
$
15.0

$
121.7

1/18-12/18
February 28, 2019
Approved
August 28, 2019
September 2019
NIPSCO - Gas
TDSIC 9(1)(2)
$
(10.6
)
$
54.4

1/18-6/18
August 28, 2018
Approved
December 27, 2018
January 2019
NIPSCO - Gas
TDSIC 10(3)
$
1.6

$
12.4

7/18-4/19
June 25, 2019
Approved
October 16, 2019
November 2019
NIPSCO - Gas
TDSIC 11(4)
$
(1.7
)
$
38.7

5/19-12/19
February 25, 2020
Order Expected June 2020
July 2020
NIPSCO - Gas
FMCA 1(5)
$
9.9

$
1.5

11/17-9/18
November 30, 2018
Approved
March 27, 2019
April 2019
NIPSCO - Gas
FMCA 2(5)
$
(3.5
)
$
1.8

10/18-3/19
May 29, 2019
Approved September 25, 2019
October 2019
NIPSCO - Gas
FMCA 3(5)
$
0.3

$
43.0

4/19-9/19
November 26, 2019
Order Expected March 2020
April 2020
Columbia of Massachusetts
GSEP - 2019(6)
$
9.6

$
36.0

1/19-12/19
October 31, 2018
Approved
April 30, 2019
May 2019
Columbia of Massachusetts
GSEP - 2020(6)(7)
$
2.4

$
75.0

1/20-12/20
October 31, 2019
Order Expected April 2020
May 2020
Columbia of Virginia
SAVE - 2019
$
2.4

$
36.0

1/19-12/19
August 17, 2018
Approved
October 26, 2018
January 2019
Columbia of Virginia
SAVE - 2020
$
3.8

$
50.0

1/20-12/20
August 15, 2019
Approved December 6, 2019
January 2020
Columbia of Kentucky
AMRP - 2019
$
3.6

$
30.1

1/19-12/19
October 15, 2018
Approved
December 5, 2018
January 2019
Columbia of Kentucky
SMRP - 2020
$
4.2

$
40.4

1/20-12/20
October 15, 2019
Approved December 20, 2019
January 2020
Columbia of Maryland
STRIDE - 2019
$
1.2

$
19.7

1/19-12/19
November 1, 2018
Approved
December 12, 2018
January 2019
Columbia of Maryland
STRIDE - 2020
$
1.3

$
15.0

1/20-12/20
January 29, 2020
Approved
February 19, 2020
February 2020
NIPSCO - Electric
TDSIC - 5(1)
$
15.9

$
58.8

6/18-11/18
January 29, 2019
Approved
June 12, 2019
June 2019
NIPSCO - Electric
TDSIC - 6
$
28.1

$
131.1

12/18-6/19
August 21, 2019
Approved December 18, 2019
January 2020
NIPSCO - Electric
FMCA - 11(5)
$
0.9

$
22.4

9/18-2/19
April 17, 2019
Approved
July 29, 2019
August 2019
NIPSCO - Electric
FMCA - 12(5)
$
1.6

$
4.7

3/19-8/19
October 18, 2019
Approved
January 29, 2020
February 2020
(1)Incremental revenue is net of amounts due back to customers as a result of the TCJA.
(2)Incremental revenue is net of $5.2 million of adjustments in the TDSIC-9 settlement.
(3)Incremental capital and revenue are net of amounts included in the step 2 rates.
(4)Incremental revenue is net of amounts included in the step 2 rates and reflects a more typical filing period.
(5)Incremental revenue is inclusive of tracker eligible operations and maintenance expense.
(6)Due to an order from the Massachusetts DPU on October 3, 2019 imposing work restrictions on Columbia of Massachusetts, Columbia of Massachusetts did not meet the approved projected 2019 GSEP spend of $64 million and associated incremental revenue of $10.7 million. In the 2020 GSEP, Columbia of Massachusetts reduced the projected capital spend for calendar year 2019 to $36 million and the associated incremental revenue in 2019 GSEP to $9.6 million.
(7)Incremental capital investment is anticipated to be lower than $75 million in 2020 due to the Massachusetts DPU imposed work restrictions.
Rate Case Action
The following table describes current rate case actions as applicable in each of our jurisdictions net of tracker impacts:
(in millions)
 
 
 
 
Company
Requested Incremental Revenue
Approved Incremental Revenue
Filed
Status
Rates
Effective
NIPSCO - Gas(1)
$
138.1

$
105.6

September 27, 2017
Approved
September 19, 2018
October 2018
Columbia of Virginia(2)
$
14.2

$
1.3

August 28, 2018
Approved
June 12, 2019
February 2019
NIPSCO - Electric(3)
$
21.4

$
(53.5
)
October 31, 2018
Approved
December 4, 2019
January 2020
Columbia of Maryland
$
2.5

$
(0.1
)
May 22, 2019
Approved
December 18, 2019
December 2019
(1)Rates were implemented in three steps, with implementation of step 1 rates effective October 1, 2018. Step 2 rates were effective on March 1, 2019, and step 3 rates were effective on January 1, 2020. The step 3 increase was approved based on actual information and revised from $107.3 million to $105.6 million. The IURC’s order also dismissed NIPSCO from phase 2 of the IURC’s TCJA investigation.
(2)Rates, as originally filed, were implemented in February 2019 on an interim basis, subject to refund. The final approved rates, which replaced interim rates, were implemented in July 2019.
(3)An order was received on December 4, 2019, which included the resolution of outstanding TCJA impacts to rates. Incremental revenues decreased due to a reduction in fuel costs associated with the new industrial service structure. Rates will be implemented in two steps, with implementation of step 1 rates effective January 2, 2020 and step 2 rates effective March 2, 2020.
v3.19.3.a.u2
Risk Management Activities (Tables)
 12 Months Ended
Dec. 31, 2019
Risk Management Activities [Abstract]  
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value
Risk management assets and liabilities on our derivatives are presented on the Consolidated Balance Sheets as shown below:
December 31, (in millions)
2019
 
2018
Risk Management Assets - Current(1)
 
 
 
Interest rate risk programs
$
—

 
$
—

Commodity price risk programs
0.6

 
1.1

Total
$
0.6

 
$
1.1

Risk Management Assets - Noncurrent(2)
 
 
 
Interest rate risk programs
$
—

 
$
18.5

Commodity price risk programs
3.8

 
4.4

Total
$
3.8

 
$
22.9

Risk Management Liabilities - Current(3)
 
 
 
Interest rate risk programs
$
—

 
$
—

Commodity price risk programs
12.6

 
5.0

Total
$
12.6

 
$
5.0

Risk Management Liabilities - Noncurrent
 
 
 
Interest rate risk programs
$
76.2

 
$
9.5

Commodity price risk programs
57.8

 
37.2

Total
$
134.0

 
$
46.7

(1)Presented in "Prepayments and other" on the Consolidated Balance Sheets.
(2)Presented in "Deferred charges and other" on the Consolidated Balance Sheets.
(3)Presented in "Other accruals" on the Consolidated Balance Sheets.
v3.19.3.a.u2
Income Taxes (Tables)
 12 Months Ended
Dec. 31, 2019
Income Tax Disclosure [Abstract]  
Schedule Of Components Of Income Tax Expense
The components of income tax expense (benefit) were as follows: 
Year Ended December 31, (in millions)
2019
 
2018
 
2017
Income Taxes
 
 
 
 
 
Current
 
 
 
 
 
Federal
$
—

 
$
—

 
$
—

State
5.2

 
8.2

 
7.8

Total Current
5.2

 
8.2

 
7.8

Deferred
 
 
 
 
 
Federal
110.7

 
(209.4
)
 
302.7

State
9.0

 
22.2

 
5.0

Total Deferred
119.7

 
(187.2
)
 
307.7

Deferred Investment Credits
(1.4
)
 
(1.0
)
 
(1.0
)
Income Taxes
$
123.5

 
$
(180.0
)
 
$
314.5
Schedule Of Reasons Behind Differences In Computation Of Total Income Taxes
The following table represents a reconciliation of income tax expense at the statutory federal income tax rate to the actual income tax expense from continuing operations:
Year Ended December 31, (in millions)
2019
 
2018
 
2017
Book income (loss) before income taxes
$
506.6

 
 
 
$
(230.6
)
 
 
 
$
443.0

 
 
Tax expense (benefit) at statutory federal income tax rate
106.5

 
21.0
 %
 
(48.4
)
 
21.0
 %
 
155.0

 
35.0
 %
Increases (reductions) in taxes resulting from:
 
 
 
 
 
 
 
 
 
 
 
State income taxes, net of federal income tax benefit
10.1

 
2.0

 
24.7

 
(10.7
)
 
6.9

 
1.5

Amortization of regulatory liabilities
(29.4
)
 
(5.8
)
 
(29.3
)
 
12.7

 
(2.4
)
 
(0.5
)
Goodwill impairment
43.0

 
8.5

 
—

 
—

 
—

 
—

Fines and penalties
11.5

 
2.3

 
0.2

 
(0.1
)
 
2.8

 
0.6

Charitable contribution carryover
(2.5
)
 
(0.5
)
 
—

 
—

 
(1.2
)
 
(0.3
)
State regulatory proceedings
(9.5
)
 
(1.9
)
 
(127.8
)
 
55.4

 
—

 
—

Remeasurement due to TCJA
—

 
—

 
—

 
—

 
161.1

 
36.4

Employee stock ownership plan dividends and other compensation
(2.0
)
 
(0.4
)
 
(2.2
)
 
1.0

 
(6.5
)
 
(1.5
)
Other adjustments
(4.2
)
 
(0.8
)
 
2.8

 
(1.2
)
 
(1.2
)
 
(0.2
)
Income Taxes
$
123.5

 
24.4
 %
 
$
(180.0
)
 
78.1
 %
 
$
314.5

 
71.0
 %
Schedule Of Principal Components Of Net Deferred Tax Liability
Deferred income taxes result from temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities. The principal components of our net deferred tax liability were as follows: 
At December 31, (in millions)
2019
 
2018
Deferred tax liabilities
 
 
 
Accelerated depreciation and other property differences
$
2,516.9

 
$
2,458.0

Other regulatory assets
381.5

 
375.4

Total Deferred Tax Liabilities
2,898.4

 
2,833.4

Deferred tax assets
 
 
 
Other regulatory liabilities and deferred investment tax credits (including TCJA)
336.1

 
365.5

Pension and other postretirement/postemployment benefits
152.1

 
157.5

Net operating loss carryforward and AMT credit carryforward
765.9

 
849.8

Environmental liabilities
25.4

 
24.4

Other accrued liabilities
35.3

 
37.5

Other, net
98.3

 
68.2

Total Deferred Tax Assets
1,413.1

 
1,502.9

Net Deferred Tax Liabilities
$
1,485.3

 
$
1,330.5
Schedule of Unrecognized Tax Benefits Roll Forward
A reconciliation of the beginning and ending amounts of unrecognized tax benefits is as follows:
Reconciliation of Unrecognized Tax Benefits (in millions)
2019
 
2018
 
2017
Unrecognized Tax Benefits - Opening Balance
$
1.2

 
$
1.4

 
$
2.6

Gross decreases - tax positions in prior period
(0.6
)
 
(0.4
)
 
(1.4
)
Gross increases - current period tax positions
22.6

 
0.2

 
0.2

Unrecognized Tax Benefits - Ending Balance
$
23.2

 
$
1.2

 
$
1.4

Offset for net operating loss carryforwards
(22.6
)
 
—

 
—

Balance - Less Net Operating Loss Carryforwards
$
0.6

 
$
1.2

 
$
1.4
v3.19.3.a.u2
Pension and Other Postretirement Benefits (Tables)
 12 Months Ended
Dec. 31, 2019
Defined Benefit Plan Disclosure [Line Items]  
Schedule Of Allocation of Plan Assets
Asset Mix Policy of Funds:
 
Defined Benefit Pension Plan
 
Postretirement Benefit Plan
Asset Category
Minimum
 
Maximum
 
Minimum
 
Maximum
Domestic Equities
12%
 
32%
 
0%
 
55%
International Equities
6%
 
16%
 
0%
 
25%
Fixed Income
59%
 
71%
 
20%
 
100%
Real Estate
0%
 
7%
 
0%
 
0%
Short-Term Investments/Other
0%
 
15%
 
0%
 
10%

As of December 31, 2018, the asset mix and acceptable minimum and maximum ranges established by the policy for the pension and other postretirement benefit plans were as follows:
Asset Mix Policy of Funds:
 
Defined Benefit Pension Plan
 
Postretirement Benefit Plan
Asset Category
Minimum
 
Maximum
 
Minimum
 
Maximum
Domestic Equities
12%
 
32%
 
0%
 
55%
International Equities
6%
 
16%
 
0%
 
25%
Fixed Income
59%
 
71%
 
20%
 
100%
Real Estate
0%
 
7%
 
0%
 
0%
Short-Term Investments/Other
0%
 
15%
 
0%
 
10%
Pension Plan and Postretirement Plan Asset Mix at December 31, 2019 and December 31, 2018:
 
Defined Benefit
Pension Assets
 
December 31,
2019
 
Postretirement
Benefit Plan Assets
 
December 31,
2019
Asset Class (in millions)
Asset Value
 
% of Total Assets
 
Asset Value
 
% of Total Assets
Domestic Equities
$
446.4

 
21.5
%
 
$
93.8

 
35.9
%
International Equities
205.0

 
9.9
%
 
40.7

 
15.6
%
Fixed Income
1,337.2

 
64.2
%
 
119.5

 
45.7
%
Real Estate
53.9

 
2.6
%
 
—

 
—

Cash/Other
38.4

 
1.8
%
 
7.4

 
2.8
%
Total
$
2,080.9

 
100.0
%
 
$
261.4

 
100.0
%
 
 
 
 
 
 
 
 
 
Defined Benefit Pension Assets
 
December 31,
2018
 
Postretirement Benefit Plan Assets
 
December 31,
2018
Asset Class (in millions)
Asset Value
 
% of Total Assets
 
Asset Value
 
% of Total Assets
Domestic Equities
$
355.5

 
19.0
%
 
$
78.8

 
36.4
%
International Equities
165.5

 
8.9
%
 
17.5

 
8.1
%
Fixed Income
1,241.9

 
66.5
%
 
115.1

 
53.2
%
Real Estate
52.7

 
2.8
%
 
—

 
—

Cash/Other
52.1

 
2.8
%
 
4.9

 
2.3
%
Total
$
1,867.7

 
100.0
%
 
$
216.3

 
100.0
%
Schedule Of Fair Value and Changes In The Fair Value Of The Plan Assets
Fair Value Measurements at December 31, 2019: 
(in millions)
December 31,
2019
 
Quoted Prices in  Active Markets for
 Identical Assets
(Level 1)
 
Significant Other
Observable Inputs (Level 2)
 
Significant
Unobservable Inputs
 (Level 3)
Pension plan assets:
 
 
 
 
 
 
 
Cash
$
6.7

 
$
6.7

 
$
—

 
$
—

Fixed income securities
 
 
 
 
 
 
 
Government
319.6

 
—

 
319.6

 
—

Corporate
651.8

 
—

 
651.8

 
—

Mutual Funds
 
 
 
 
 
 
 
U.S. multi-strategy
140.5

 
140.5

 
—

 
—

International equities
56.9

 
56.9

 
—

 
—

Private equity limited partnerships(3)
 
 
 
 
 
 
 
U.S. multi-strategy(1)
14.0

 
—

 
—

 
—

International multi-strategy(2)
8.5

 
—

 
—

 
—

Distressed opportunities
0.5

 
—

 
—

 
—

Real estate
53.9

 
—

 
—

 
—

Commingled funds(3)
 
 
 
 
 
 
 
Short-term money markets
14.8

 
—

 
—

 
—

U.S. equities
305.9

 
—

 
—

 
—

International equities
148.1

 
—

 
—

 
—

Fixed income
351.8

 
—

 
—

 
—

Pension plan assets subtotal
2,073.0

 
204.1

 
971.4

 
—

Other postretirement benefit plan assets:
 
 
 
 
 
 
 
Mutual funds
 
 
 
 
 
 
 
U.S. multi-strategy
81.7

 
81.7

 
—

 
—

International equities
20.6

 
20.6

 
—

 
—

Fixed income
119.2

 
119.2

 
—

 
—

Commingled funds(3)
 
 
 
 
 
 
 
Short-term money markets
7.7

 
—

 
—

 
—

U.S. equities
12.1

 
—

 
—

 
—

International equities
20.1

 
—

 
—

 
—

Other postretirement benefit plan assets subtotal
261.4

 
221.5

 
—

 
—

Due to brokers, net(4)
(2.8
)
 
—

 
(2.8
)
 
—

Accrued income/dividends
10.7

 
10.7

 
—

 
—

Total pension and other postretirement benefit plan assets
$
2,342.3

 
$
436.3

 
$
968.6

 
$
—


(1) This class includes limited partnerships/fund of funds that invest in a diverse portfolio of private equity strategies, including buy-outs, venture capital, growth capital, special situations and secondary markets, primarily inside the United States. 
(2) This class includes limited partnerships/fund of funds that invest in diverse portfolio of private equity strategies, including buy-outs, venture capital, growth capital, special situations and secondary markets, primarily outside the United States.
(3) This class of investments is measured at fair value using the net asset value per share and has not been classified in the fair value hierarchy.
(4) This class represents pending trades with brokers.
The table below sets forth a summary of changes in the fair value of the Plan’s Level 3 assets for the year ended December 31, 2019:
 
Balance at
January 1, 
2019
 
Transfers out
(Level 3)(1) 
 
Balance at
December 31,  2019
Private equity limited partnerships
 
 
 
 
 
U.S. multi-strategy
18.5

 
(18.5
)
 
—

International multi-strategy
12.5

 
(12.5
)
 
—

Distressed opportunities
2.4

 
(2.4
)
 
—

Real estate
52.7

 
(52.7
)
 
—

Total
$
86.1

 
$
(86.1
)
 
$
—


(1) Level 3 assets from the prior year were reclassified in the current year presentation and included within the fair value hierarchy table as of December 31, 2019 as “Not Classified" investments for which fair value is measured using net asset value per share, consistent with the definitions described above.
The table below sets forth a summary of unfunded commitments, redemption frequency and redemption notice periods for certain investments that are measured at fair value using the net asset value per share for the year ended December 31, 2019:
(in millions)
Fair Value
 
Redemption Frequency
 
Redemption Notice Period
Commingled Funds
 
 
 
 
 
Short-term money markets
$
22.5

 
Daily
 
1 day
U.S. equities
318.0

 
Monthly
 
1 day
International equities
168.2

 
Monthly
 
10-30 days
Fixed income
351.8

 
Daily
 
3 days
Total
$
860.5

 
 
 
 

Fair Value Measurements at December 31, 2018: 
(in millions)
December 31,
2018
 
Quoted Prices in Active Markets for Identical Assets (Level 1)
 
Significant Other
Observable Inputs (Level 2)
 
Significant
Unobservable Inputs 
(Level 3)
Pension plan assets:
 
 
 
 
 
 
 
Cash
$
9.2

 
$
8.8

 
$
0.4

 
$
—

Equity securities
 
 
 
 
 
 
 
U.S. equities
0.2

 
0.2

 
—

 
—

Fixed income securities
 
 
 
 
 
 
 
Government
250.2

 
—

 
250.2

 
—

Corporate
442.8

 
—

 
442.8

 
—

Mutual Funds
 
 
 
 
 
 
 
U.S. multi-strategy
110.3

 
110.3

 
—

 
—

International equities
43.2

 
43.2

 
—

 
—

Fixed income
166.8

 
166.8

 
—

 
—

Private equity limited partnerships
 
 
 
 
 
 
 
U.S. multi-strategy(1)
18.5

 
—

 
—

 
18.5

International multi-strategy(2)
12.5

 
—

 
—

 
12.5

Distressed opportunities
2.4

 
—

 
—

 
2.4

Real Estate
52.7

 
—

 
—

 
52.7

Commingled funds(3)
 
 
 
 
 
 
 
Short-term money markets
18.3

 
—

 
—

 
—

U.S. equities
245.2

 
—

 
—

 
—

International equities
122.3

 
—

 
—

 
—

Fixed income
365.7

 
—

 
—

 
—

Pension plan assets subtotal
1,860.3

 
329.3

 
693.4

 
86.1

Other postretirement benefit plan assets:
 
 
 
 
 
 
 
Mutual funds
 
 
 
 
 
 
 
U.S. equities
68.4

 
68.4

 
—

 
—

International equities
17.5

 
17.5

 
—

 
—

Fixed income
114.8

 
114.8

 
—

 
—

Commingled funds(3)
 
 
 
 
 
 
 
Short-term money markets
5.2

 
—

 
—

 
—

U.S. equities
10.4

 
—

 
—

 
—

Other postretirement benefit plan assets subtotal
216.3

 
200.7

 
—

 
—

Due to brokers, net(4)
(1.1
)
 
—

 
(1.1
)
 
—

Accrued investment income/dividends
8.6

 
8.6

 
—

 
—

Total pension and other postretirement benefit plan assets
$
2,084.1

 
$
538.6

 
$
692.3

 
$
86.1

(1) This class includes limited partnerships/fund of funds that invest in a diverse portfolio of private equity strategies, including buy-outs, venture capital, growth capital, special situations and secondary markets, primarily inside the United States.
(2) This class includes limited partnerships/fund of funds that invest in a diverse portfolio of private equity strategies, including buy-outs, venture capital, growth capital, special situations and secondary markets, primarily outside the United States.
(3) This class of investments is measured at fair value using the net asset value per share and has not been classified in the fair value hierarchy.
(4) This class represents pending trades with brokers.
The table below sets forth a summary of changes in the fair value of the Plan’s Level 3 assets for the year ended December 31, 2018:
 
Balance at
January 1, 
2018
 
Total gains or
losses (unrealized
/ realized)
 
Purchases
 
(Sales)
 
Balance at
December 31, 
2018
Private equity limited partnerships
 
 
 
 
 
 
 
 
 
U.S. multi-strategy
26.7

 
2.4

 
0.7

 
(11.3
)
 
18.5

International multi-strategy
19.1

 
(0.6
)
 
—

 
(6.0
)
 
12.5

Distress opportunities
3.2

 
(0.8
)
 
—

 
—

 
2.4

Real estate
49.9

 
1.7

 
1.8

 
(0.7
)
 
52.7

Total
$
98.9

 
$
2.7

 
$
2.5

 
$
(18.0
)
 
$
86.1


The table below sets forth a summary of unfunded commitments, redemption frequency and redemption notice periods for certain investments that are measured at fair value using the net asset value per share for the year ended December 31, 2018:
(in millions)
Fair Value
 
Redemption Frequency
 
Redemption Notice Period
Commingled Funds
 
 
 
 
 
Short-term money markets
$
23.5

 
Daily
 
1 day
U.S. equities
255.6

 
Monthly
 
3 days
International equities
122.3

 
Monthly
 
10-30 days
Fixed income
365.7

 
Monthly
 
3 days
Total
$
767.1

 
 
 
 
 
Schedule Of Reconciliation Of The Plan Funded Status The following table provides a reconciliation of the plans’ funded status and amounts reflected in our Consolidated Balance Sheets at December 31 based on a December 31 measurement date:
 
Pension Benefits
 
Other Postretirement Benefits
(in millions)
2019
 
2018
 
2019
 
2018
Change in projected benefit obligation(1)
 
 
 
 
 
 
 
Benefit obligation at beginning of year
$
1,981.3

 
$
2,192.6

 
$
492.5

 
$
556.3

Service cost
29.2

 
31.3

 
5.1

 
5.0

Interest cost
72.3

 
67.1

 
19.2

 
17.6

Plan participants’ contributions
—

 
—

 
4.8

 
5.7

Plan amendments
—

 
0.2

 
5.1

 
0.1

Actuarial (gain) loss
204.3

 
(103.9
)
 
88.8

 
(51.7
)
Settlement loss
—

 
0.8

 
—

 
—

Benefits paid
(156.6
)
 
(206.8
)
 
(39.5
)
 
(41.1
)
Estimated benefits paid by incurred subsidy
—

 
—

 
0.5

 
0.6

Projected benefit obligation at end of year
$
2,130.5

 
$
1,981.3

 
$
576.5

 
$
492.5

Change in plan assets
 
 
 
 
 
 
 
Fair value of plan assets at beginning of year
$
1,867.7

 
$
2,160.0

 
$
216.3

 
$
262.5

Actual (loss) return on plan assets
366.8

 
(88.4
)
 
56.9

 
(31.8
)
Employer contributions
2.9

 
2.9

 
23.0

 
21.0

Plan participants’ contributions
—

 
—

 
4.7

 
5.7

Benefits paid
(156.5
)
 
(206.8
)
 
(39.5
)
 
(41.1
)
Fair value of plan assets at end of year
$
2,080.9

 
$
1,867.7

 
$
261.4

 
$
216.3

Funded Status at end of year
$
(49.6
)
 
$
(113.6
)
 
$
(315.1
)

$
(276.2
)
Amounts recognized in the statement of financial position consist of:
 
 
 
 
 
 
 
Noncurrent assets
8.2

 
—

 
—

 
—

Current liabilities
(3.0
)
 
(3.0
)
 
(0.8
)
 
(0.8
)
Noncurrent liabilities
(54.8
)
 
(110.6
)
 
(314.3
)
 
(275.4
)
Net amount recognized at end of year(2)
$
(49.6
)
 
$
(113.6
)
 
$
(315.1
)
 
$
(276.2
)
Amounts recognized in accumulated other comprehensive income or regulatory asset/liability(3)
 
 
 
 
 
 
 
Unrecognized prior service credit
$
3.0

 
$
3.2

 
$
(10.7
)
 
$
(19.0
)
Unrecognized actuarial loss
652.8

 
761.2

 
118.4

 
75.3

 Net amount recognized at end of year
$
655.8

 
$
764.4

 
$
107.7

 
$
56.3


(1) The change in benefit obligation for Pension Benefits represents the change in Projected Benefit Obligation while the change in benefit obligation for Other Postretirement Benefits represents the change in accumulated postretirement benefit obligation.
(2) We recognize our Consolidated Balance Sheets underfunded and overfunded status of our various defined benefit postretirement plans, measured as the difference between the fair value of the plan assets and the benefit obligation.
(3) We determined that for certain rate-regulated subsidiaries the future recovery of pension and other postretirement benefits costs is probable. These rate-regulated subsidiaries recorded regulatory assets and liabilities of $739.1 million and $0.1 million, respectively, as of December 31, 2019, and $798.3 million and $0.1 million, respectively, as of December 31, 2018 that would otherwise have been recorded to accumulated other comprehensive loss.
Schedule of Benefit Obligations in Excess of Fair Value of Plan Assets
Information for pension plans with a projected benefit obligation in excess of plan assets:
 
December 31,
 
2019
 
2018
Accumulated Benefit Obligation
$
1,473.9

 
$
1,965.6

Funded Status
 
 
 
Projected Benefit Obligation
1,492.9

 
1,981.3

Fair Value of Plan Assets
1,435.1

 
1,867.7

Funded Status of Underfunded Pension Plans at End of Year
$
(57.8
)
 
$
(113.6
)
Information for pension plans with plan assets in excess of the projected benefit obligation:
 
December 31,
 
2019
 
2018
Accumulated Benefit Obligation
$
637.6

 
$
—

Funded Status
 
 
 
Projected Benefit Obligation
637.6

 
—

Fair Value of Plan Assets
645.8

 
—

Funded Status of Overfunded Pension Plans at End of Year
$
8.2

 
$
—
Schedule Of Significant Actuarial Assumptions In Determining Funded Status Plan
The following table provides the key assumptions that were used to calculate the pension and other postretirement benefits obligations for our various plans as of December 31:
 
Pension Benefits
 
Other Postretirement  Benefits
  
2019
 
2018
 
2019
 
2018
Weighted-average assumptions to Determine Benefit Obligation
 
 
 
 
 
 
 
Discount Rate
3.12
%
 
4.26
%
 
3.21
%
 
4.31
%
Rate of Compensation Increases
4.00
%
 
4.00
%
 
—

 
—

Health Care Trend Rates
 
 
 
 
 
 
 
Trend for Next Year
—

 
—

 
6.68
%
 
8.48
%
Ultimate Trend
—

 
—

 
4.50
%
 
4.50
%
Year Ultimate Trend Reached
—

 
—

 
2028

 
2026


The following table provides the key assumptions that were used to calculate the net periodic benefits cost for our various plans:
 
Pension Benefits
 
 Other Postretirement
Benefits
  
2019
 
2018
 
2017
 
2019
 
2018
 
2017
Weighted-average Assumptions to Determine Net Periodic Benefit Cost
 
 
 
 
 
 
 
 
 
 
 
Discount rate - service cost(1)
4.48
%
 
3.79
%
 
4.40
%
 
4.59
%
 
3.89
%
 
4.58
%
Discount rate - interest cost(1)
3.84
%
 
3.15
%
 
3.31
%
 
3.94
%
 
3.27
%
 
3.48
%
Expected Long-Term Rate of Return on Plan Assets
6.10
%
 
7.00
%
 
7.25
%
 
5.83
%
 
5.80
%
 
6.99
%
Rate of Compensation Increases
4.00
%
 
4.00
%
 
4.00
%
 
—

 
—

 
—
Schedule Of One-Percentage-Point Change In Assumed Health Care Cost Trend Rates
Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects:
(in millions)
1% point increase
 
1% point decrease
Effect on service and interest components of net periodic cost
$
1.2

 
$
(1.1
)
Effect on accumulated postretirement benefit obligation
30.1

 
(26.3
)
Schedule Of Expected Payments To Participants In Pension Plan The expected benefits are estimated based on the same assumptions used to measure our benefit obligation at the end of the year and include benefits attributable to the estimated future service of employees:
(in millions)
Pension Benefits
 
Other
Postretirement Benefits
 
Federal
Subsidy Receipts
Year(s)
 
 
 
 
 
2020
$
178.8

 
$
38.1

 
$
0.5

2021
177.8

 
38.6

 
0.4

2022
175.8

 
38.4

 
0.4

2023
168.5

 
38.1

 
0.4

2024
164.4

 
37.9

 
0.4

2025-2029
723.7

 
181.0

 
1.5
Components Of The Plans' Net Periodic Benefits Cost
The following table provides the components of the plans’ actuarially determined net periodic benefits cost for each of the three years ended December 31, 2019, 2018 and 2017:
 
Pension Benefits
 
Other Postretirement
Benefits
(in millions)
2019
 
2018
 
2017
 
2019
 
2018
 
2017
Components of Net Periodic Benefit Cost(1)
 
 
 
 
 
 
 
 
 
 
 
Service cost
$
29.2

 
$
31.3

 
$
30.0

 
$
5.1

 
$
5.0

 
$
4.8

Interest cost
72.3

 
67.1

 
68.3

 
19.2

 
17.6

 
17.8

Expected return on assets
(108.8
)
 
(142.3
)
 
(123.1
)
 
(13.1
)
 
(14.9
)
 
(15.9
)
Amortization of prior service cost (credit)
0.2

 
(0.4
)
 
(0.7
)
 
(3.2
)
 
(4.0
)
 
(4.4
)
Recognized actuarial loss
45.2

 
40.6

 
52.9

 
2.0

 
3.8

 
3.0

Settlement loss
9.5

 
18.5

 
13.7

 
—

 
—

 
—

Total Net Periodic Benefits Cost
$
47.6

 
$
14.8

 
$
41.1

 
$
10.0

 
$
7.5

 
$
5.3


(1)Service cost is presented in "Operation and maintenance" on the Statements of Consolidated Income (Loss). Non-service cost components are presented within "Other, net."
Schedule Of Changes In Plan Assets And Projected Benefit Obligations Recognized In Other Comprehensive Income
The following table provides other changes in plan assets and projected benefit obligations recognized in other comprehensive income or regulatory asset or liability:
  
Pension Benefits
 
Other Postretirement
Benefits
(in millions)
2019
 
2018
 
2019
 
2018
Other Changes in Plan Assets and Projected Benefit Obligations Recognized in Other Comprehensive Income or Regulatory Asset or Liability
 
 
 
 
 
 
 
Net prior service cost
$
—

 
$
0.2

 
$
5.1

 
$
0.1

Net actuarial loss (gain)
(53.8
)
 
127.5

 
45.1

 
(5.0
)
Settlements
(9.5
)
 
(18.5
)
 
—

 
—

Less: amortization of prior service cost
(0.2
)
 
0.4

 
3.2

 
4.0

Less: amortization of net actuarial loss
(45.2
)
 
(40.6
)
 
(2.0
)
 
(3.8
)
Total Recognized in Other Comprehensive Income or Regulatory Asset or  Liability
$
(108.7
)
 
$
69.0

 
$
51.4

 
$
(4.7
)
Amount Recognized in Net Periodic Benefits Cost and Other Comprehensive Income or Regulatory Asset or Liability
$
(61.1
)
 
$
83.8

 
$
61.4

 
$
2.8
v3.19.3.a.u2
Equity (Tables)
 12 Months Ended
Dec. 31, 2019
Equity [Abstract]  
Schedule Of Stock Offering Program
The following table summarizes our activity under the ATM program:
Year Ending December 31,
2019
 
2018
 
2017
Number of shares issued
8,422,498

 
8,883,014

 
11,931,376

Average price per share
$
27.75

 
$
26.85

 
$
26.58

Proceeds, net of fees (in millions)
$
229.1

 
$
232.5

 
$
314.7
Schedule of Stock by Class - Preferred
The following table summarizes preferred stock by outstanding series of shares:
 
 
 
Year ended December 31,
December 31,
 
December 31,
 
 
 
2019
2018
2017
2019
 
2018
(in millions except shares and per share amounts)
Liquidation Preference Per Share
Shares
Dividends Declared Per Share
Outstanding
5.650% Series A
$
1,000.00

400,000

$
56.50

$
28.88

$
—

$
393.9

 
$
393.9

6.500% Series B
$
25,000.00

20,000

$
1,674.65

$
—

$
—

$
486.1

 
$
486.1
v3.19.3.a.u2
Share-Based Compensation (Tables)
 12 Months Ended
Dec. 31, 2019
Restricted Stock Units (RSUs)  
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]  
Schedule Of Transactions Of Share Based Compensation Other Than Stock Options
(shares)
Restricted Stock
Units
 
Weighted Average
Award Date Fair 
Value Per Unit ($)
Non-vested at December 31, 2018
178,678

 
21.82

Granted
166,031

 
24.93

Forfeited
(21,547
)
 
22.99

Vested
(20,556
)
 
21.08

Non-vested at December 31, 2019
302,606

 
23.49
Performance Shares  
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]  
Schedule Of Transactions Of Share Based Compensation Other Than Stock Options
(shares)
Performance
Awards
 
Weighted Average
Grant Date Fair 
Value Per Unit ($)(1)
Non-vested at December 31, 2018
1,634,718

 
20.45

Granted
552,389

 
25.77

Forfeited
(156,700
)
 
26.72

Vested
(527,156
)
 
28.11

Non-vested at December 31, 2019
1,503,251

 
22.74
v3.19.3.a.u2
Long-Term Debt (Tables)
 12 Months Ended
Dec. 31, 2019
Long-term Debt, Current and Noncurrent [Abstract]  
Schedule of Long-Term Debt
Our long-term debt as of December 31, 2019 and 2018 is as follows:
Long-term debt type
Maturity as of December 31,
2019
Weighted average interest rate (%)
 
Outstanding balance as of December 31, (in millions)
 
2019
 
2018
Senior notes:
 
 
 
 
 
 
NiSource
December 2021
4.45
%
 
63.6

 
63.6

NiSource
November 2022
2.65
%
 
500.0

 
500.0

NiSource
February 2023
3.85
%
 
250.0

 
250.0

NiSource
June 2023
3.65
%
 
350.0

 
350.0

NiSource
November 2025
5.89
%
 
265.0

 
265.0

NiSource
May 2027
3.49
%
 
1,000.0

 
1,000.0

NiSource
December 2027
6.78
%
 
3.0

 
3.0

NiSource
September 2029
2.95
%
 
750.0

 
—

NiSource
December 2040
6.25
%
 
250.0

 
250.0

NiSource
June 2041
5.95
%
 
400.0

 
400.0

NiSource
February 2042
5.80
%
 
250.0

 
250.0

NiSource
February 2043
5.25
%
 
500.0

 
500.0

NiSource
February 2044
4.80
%
 
750.0

 
750.0

NiSource
February 2045
5.65
%
 
500.0

 
500.0

NiSource
May 2047
4.38
%
 
1,000.0

 
1,000.0

NiSource
March 2048
3.95
%
 
750.0

 
750.0

Total senior notes
 
 
 
$
7,581.6

 
$
6,831.6

Medium term notes:
 
 
 
 
 
 
NiSource
April 2022 to May 2027
7.99
%
 
$
49.0

 
$
49.0

NIPSCO
August 2022 to August 2027
7.61
%
 
68.0

 
68.0

Columbia of Massachusetts
December 2025 to February 2028
6.30
%
 
40.0

 
40.0

Total medium term notes
 
 
 
$
157.0

 
$
157.0

Finance leases:
 
 
 
 
 
 
NiSource Corporate Services
January 2020 to November 2023
3.47
%
 
22.3

 
11.6

Columbia of Ohio
October 2021 to March 2044
6.16
%
 
94.8

 
91.5

Columbia of Virginia
July 2029 to November 2039
6.31
%
 
19.1

 
15.2

Columbia of Kentucky
May 2027
3.79
%
 
0.3

 
0.3

Columbia of Pennsylvania
August 2027 to May 2035
5.67
%
 
20.7

 
30.0

Columbia of Massachusetts
December 2033 to November 2043
5.49
%
 
44.3

 
45.7

Total finance leases
 
 
 
201.5

 
194.3

Pollution control bonds - NIPSCO
April 2019
5.85
%
 
—

 
41.0

Unamortized issuance costs and discounts
 
 
 
(70.5
)
 
$
(68.5
)
Total Long-Term Debt
 
 
 
$
7,869.6

 
$
7,155.4
v3.19.3.a.u2
Short-Term Borrowings (Tables)
 12 Months Ended
Dec. 31, 2019
Short-term Debt [Abstract]  
Schedule Of Short-Term Borrowings
Short-term borrowings were as follows: 
At December 31, (in millions)
2019
 
2018
Commercial Paper weighted-average interest rate of 2.03% and 2.96% at December 31, 2019 and 2018, respectively
$
570.0

 
$
978.0

Accounts receivable securitization facility borrowings
353.2

 
399.2

Term loan weighted-average interest rate of 2.40% and 3.07% at December 31, 2019 and 2018, respectively
850.0

 
$
600.0

Total Short-Term Borrowings
$
1,773.2

 
$
1,977.2
v3.19.3.a.u2
Leases (Tables)
 12 Months Ended
Dec. 31, 2019
Leases [Abstract]  
Lease Cost Income statement presentation for these costs (when ultimately recognized on the income statement) is also included:
Year Ended December 31, (in millions)
Income Statement Classification
2019
Finance lease cost
 
 
Amortization of right-of-use assets
Depreciation and amortization
$
15.5

Interest on lease liabilities
Interest expense, net
11.3

Total finance lease cost
 
26.8

Operating lease cost
Operation and maintenance
17.9

Short-term lease cost
Operation and maintenance
1.0

Total lease cost
 
$
45.7
Right-of-Use Assets and Liabilities
Our right-of-use assets and liabilities are presented in the following lines on the Consolidated Balance Sheets:
(in millions)
Balance Sheet Classification
December 31, 2019
Assets
 
 
Finance leases
Net Property, Plant and Equipment
$
179.5

Operating leases
Deferred charges and other
64.2

Total leased assets
 
243.7

Liabilities
 
 
Current
 
 
Finance leases
Current portion of long-term debt
13.4

Operating leases
Other accruals
13.2

Noncurrent
 
 
Finance leases
Long-term debt, excluding amounts due within one year
188.1

Operating leases
Other noncurrent liabilities
51.6

Total lease liabilities
 
$
266.3
Lease Information
Other pertinent information related to leases was as follows:
Year Ended December 31, (in millions)
2019
Cash paid for amounts included in the measurement of lease liabilities
 
Operating cash flows used for finance leases
$
11.3

Operating cash flows used for operating leases
17.9

Financing cash flows used for finance leases
10.6

Right-of-use assets obtained in exchange for lease obligations
 
Finance leases
26.4

Operating leases
$
13.4

 
December 31, 2019
Weighted-average remaining lease term (years)
 
Finance leases
14.8

Operating leases
9.2

Weighted-average discount rate
 
Finance leases
5.9
%
Operating leases
4.3
%
Lease Maturity
Maturities of our lease liabilities presented on a rolling 12-month basis were as follows:
As of December 31, 2019, (in millions)
Total
Finance Leases
Operating Leases
Year 1
$
42.8

$
27.2

$
15.6

Year 2
36.7

27.3

9.4

Year 3
35.0

26.8

8.2

Year 4
30.7

23.1

7.6

Year 5
26.5

19.9

6.6

Thereafter
233.3

201.6

31.7

Total lease payments(1)
405.0

325.9

79.1

Less: Imputed interest
(116.6
)
(102.3
)
(14.3
)
Less: Leases not yet commenced
(22.1
)
(22.1
)
—

Total
266.3

201.5

64.8

Reported as of December 31, 2019
 
 
 
Short-term lease liabilities
26.6

13.4

13.2

Long-term lease liabilities
239.7

188.1

51.6

Total lease liabilities
$
266.3

$
201.5

$
64.8

(1) Expected payments include obligations for leases not yet commenced of approximately $22.1 million for IT assets and interconnection facilities. These leases have terms between 4 years and 20 years, with estimated commencements in the first quarter of 2020 and in the third quarter of 2020.
Lease Maturity under 840 As of December 31, 2018, total contractual obligations for capital and operating leases were as follows:
As of December 31, 2018, (in millions)
Total
Capital Leases(1)
Operating Leases(2)
2019
$
34.0

$
23.0

$
11.0

2020
29.8

22.5

7.3

2021
28.7

22.6

6.1

2022
26.3

22.1

4.2

2023
22.6

19.8

2.8

Thereafter
226.9

212.4

14.5

Total lease payments
$
368.3

$
322.4

$
45.9

(1)Capital lease payments shown above are inclusive of interest totaling $114.6 million.
(2)Operating lease balances do not include obligations for possible fleet vehicle lease renewals beyond the initial lease term. While we have the ability to renew these leases beyond the initial term, we are not reasonably certain to do so. Expected payments are $26.7 million in 2019, $22.4 million in 2020, $16.6 million in 2021, $12.3 million in 2022, $9.3 million in 2023 and $8.8 million thereafter.
v3.19.3.a.u2
Fair Value (Tables)
 12 Months Ended
Dec. 31, 2019
Fair Value Disclosures [Abstract]  
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis The following tables present financial assets and liabilities measured and recorded at fair value on our Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of December 31, 2019 and December 31, 2018:
 
Recurring Fair Value Measurements
December 31, 2019 (in millions)
Quoted Prices
in Active Markets
for Identical Assets
(Level 1)
 
Significant Other
Observable Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
 
Balance as of
December 31, 2019
Assets
 
 
 
 
 
 
 
Risk management assets
$
—

 
$
4.4

 
$
—

 
$
4.4

Available-for-sale securities
—

 
154.2

 
—

 
154.2

Total
$
—

 
$
158.6

 
$
—

 
$
158.6

Liabilities
 
 
 
 
 
 
 
Risk management liabilities
$
—

 
$
146.6

 
$
—

 
$
146.6

Total
$
—

 
$
146.6

 
$
—

 
$
146.6

 
Recurring Fair Value Measurements
December 31, 2018 (in millions)
Quoted Prices
in Active Markets
for Identical Assets
(Level 1)
 
Significant Other
Observable Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
 
Balance as of
December 31, 2018
Assets
 
 
 
 
 
 
 
Risk management assets
$
—

 
$
24.0

 
$
—

 
$
24.0

Available-for-sale securities
—

 
138.3

 
—

 
138.3

Total
$
—

 
$
162.3

 
$
—

 
$
162.3

Liabilities
 
 
 
 
 
 
 
Risk management liabilities
$
—

 
$
51.7

 
$
—

 
$
51.7

Total
$
—

 
$
51.7

 
$
—

 
$
51.7
Available-For-Sale Debt Securities The amortized cost, gross unrealized gains and losses and fair value of available-for-sale securities at December 31, 2019 and 2018 were: 
December 31, 2019 (in millions)
Amortized
Cost
 
Gross
Unrealized
Gains
 
Gross
Unrealized
Losses
 
Fair Value
Available-for-sale securities
 
 
 
 
 
 
 
U.S. Treasury debt securities
$
31.4

 
$
0.1

 
$
(0.1
)
 
$
31.4

Corporate/Other debt securities
118.7

 
4.2

 
(0.1
)
 
122.8

Total
$
150.1

 
$
4.3

 
$
(0.2
)
 
$
154.2

 
 
 
 
 
 
 
 
December 31, 2018 (in millions)
Amortized
Cost
 
Gross
Unrealized
Gains
 
Gross
Unrealized
Losses
 
Fair Value
Available-for-sale securities
 
 
 
 
 
 
 
U.S. Treasury debt securities
$
23.6

 
$
0.1

 
$
(0.1
)
 
$
23.6

Corporate/Other debt securities
117.7

 
0.4

 
(3.4
)
 
114.7

Total
$
141.3

 
$
0.5

 
$
(3.5
)
 
$
138.3
Carrying Amount And Estimated Fair Values Of Financial Instruments
The carrying amount and estimated fair values of these financial instruments were as follows: 
At December 31, (in millions)
Carrying
Amount
2019
 
Estimated
Fair Value
2019
 
Carrying
Amount
2018
 
Estimated
Fair Value
2018
Long-term debt (including current portion)
$
7,869.6

 
$
8,764.4

 
$
7,155.4

 
$
7,228.3
v3.19.3.a.u2
Transfers Of Financial Assets (Tables)
 12 Months Ended
Dec. 31, 2019
Transfers and Servicing [Abstract]  
Schedule of Assets and Associated Liabilities Accounted for as Secured Borrowings
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 December 31, 2019 and 2018:
At December 31, (in millions)
2019
 
2018
Gross receivables
$
569.1

 
$
694.4

Less: receivables not transferred
215.9

 
295.2

Net receivables transferred
$
353.2

 
$
399.2

Short-term debt due to asset securitization
$
353.2

 
$
399.2
v3.19.3.a.u2
Other Commitments And Contingencies (Tables)
 12 Months Ended
Dec. 31, 2019
Commitments and Contingencies Disclosure [Abstract]  
Contractual Obligation, Fiscal Year Maturity Contractual Obligations. We have certain contractual obligations requiring payments at specified periods. The obligations include long-term debt, lease obligations, energy commodity contracts and obligations for various services including pipeline capacity and outsourcing of IT services. The total contractual obligations in existence at December 31, 2019 and their maturities were:
(in millions)
Total
 
2020
 
2021
 
2022
 
2023
 
2024
 
After
Long-term debt (1)
$
7,738.6

 
$
—

 
$
63.6

 
$
530.0

 
$
600.0

 
$
—

 
$
6,545.0

Interest payments on long-term debt
6,214.2

 
342.0

 
340.7

 
337.1

 
311.1

 
299.9

 
4,583.4

Finance leases(2)
325.9

 
27.2

 
27.3

 
26.8

 
23.1

 
19.9

 
201.6

Operating leases(3)
79.1

 
15.6

 
9.4

 
8.2

 
7.6

 
6.6

 
31.7

Energy commodity contracts(4)
95.9

 
65.5

 
30.4

 
—

 
—

 
—

 
—

Service obligations:


 
 
 
 
 
 
 
 
 
 
 
 
Pipeline service obligations
3,450.7

 
605.0

 
590.1

 
546.8

 
357.2

 
237.5

 
1,114.1

IT service obligations
153.2

 
63.6

 
49.4

 
38.0

 
1.1

 
1.1

 
—

Other service obligations(5)
59.8

 
45.8

 
14.0

 
—

 
—

 
—

 
—

Other liabilities
27.3

 
27.3

 
—

 
—

 
—

 
—

 
—

Total contractual obligations
$
18,144.7

 
$
1,192.0

 
$
1,124.9

 
$
1,486.9

 
$
1,300.1

 
$
565.0

 
$
12,475.8

(1) Long-term debt balance excludes unamortized issuance costs and discounts of $70.5 million.
(2) Finance lease payments shown above are inclusive of interest totaling $108.3 million.
(3) Operating lease payments shown above are inclusive of interest totaling $14.3 million. Operating lease balances do not include obligations for possible fleet vehicle lease renewals beyond the initial lease term. While we have the ability to renew these leases beyond the initial term, we are not reasonably certain (as that term is defined in ASC 842) to do so. If we were to continue the fleet vehicle leases outstanding at December 31, 2019, payments would be $34.5 million in 2020, $28.3 million in 2021, $23.4 million in 2022, $19.9 million in 2023, $15.2 million in 2024 and $15.2 million thereafter.  
(4)In January 2020, NIPSCO signed new coal contract commitments of $14.4 million for 2020. These contracts are not included above.  
(5)In February 2020, NIPSCO signed a new railcar coal transportation contract commitment of $12.0 million for 2020. This contract is not included above.
Expenses Incurred and Insurance Recoveries
The following table summarizes expenses incurred and insurance recoveries recorded since the Greater Lawrence Incident. This activity is presented within "Operation and maintenance" and "Other, net" in our Statements of Consolidated Income (Loss).
 
Year Ended
 
Year Ended
 
(in millions)
December 31, 2018
 
December 31, 2019
Incident to Date
Third-party claims and government fines, penalties and settlements
$
757

 
$
284

$
1,041

Other incident-related costs
266

 
154

420

Total
1,023

 
438

1,461

Insurance recoveries recorded
(135
)
 
(665
)
(800
)
Loss (benefit) to income before income taxes
$
888

 
$
(227
)
$
661
Insurance Recoveries and Cash Collected
The following table presents activity related to our Greater Lawrence Incident insurance recovery, which we have recovered in full as of December 31, 2019.
(in millions)
Insurance receivable(1)
Balance, December 31, 2018
$
130

Insurance recoveries recorded in first quarter of 2019
100

Cash collected from insurance recoveries in the first quarter of 2019
(108
)
Balance, March 31, 2019
122

Insurance recoveries recorded in the second quarter of 2019
435

Cash collected from insurance recoveries in the second quarter of 2019
(297
)
Balance, June 30, 2019
$
260

Insurance recoveries recorded in third quarter of 2019
—

Cash collected from insurance recoveries in the third quarter of 2019
(260
)
Balance, September 30, 2019
$
—

Insurance recoveries recorded in the fourth quarter of 2019
130

Cash collected from insurance recoveries in the fourth quarter of 2019
(130
)
Balance, December 31, 2019
$
—

(1)$5 million of insurance recoveries were collected during 2018.
v3.19.3.a.u2
Accumulated Other Comprehensive Loss (Tables)
 12 Months Ended
Dec. 31, 2019
Components of Accumulated Other Comprehensive Income (Loss) [Abstract]  
Schedule of Accumulated Other Comprehensive Income (Loss)
The following table displays the activity of Accumulated Other Comprehensive Loss, net of tax:
(in millions)
Gains and Losses on Securities(1)
 
Gains and Losses on Cash Flow Hedges(1)
 
Pension and OPEB Items(1)
 
Accumulated
Other
Comprehensive
Loss(1)
Balance as of January 1, 2017
$
(0.6
)
 
$
(6.9
)
 
$
(17.6
)
 
$
(25.1
)
Other comprehensive income (loss) before reclassifications
0.6

 
(24.2
)
 
1.9

 
(21.7
)
Amounts reclassified from accumulated other comprehensive loss
0.2

 
1.7

 
1.5

 
3.4

Net current-period other comprehensive income (loss)
0.8

 
(22.5
)
 
3.4

 
(18.3
)
Balance as of December 31, 2017
$
0.2

 
$
(29.4
)
 
$
(14.2
)
 
$
(43.4
)
Other comprehensive income (loss) before reclassifications
(3.0
)
 
55.8

 
(4.4
)
 
48.4

Amounts reclassified from accumulated other comprehensive loss
0.4

 
(33.1
)
 
—

 
(32.7
)
Net current-period other comprehensive income (loss)
(2.6
)
 
22.7

 
(4.4
)
 
15.7

Reclassification due to adoption of ASU 2018-02
—

 
(6.3
)
 
(3.2
)
 
(9.5
)
Balance as of December 31, 2018
$
(2.4
)
 
$
(13.0
)
 
$
(21.8
)
 
$
(37.2
)
Other comprehensive income (loss) before reclassifications
6.1

 
(64.3
)
 
2.3

 
(55.9
)
Amounts reclassified from accumulated other comprehensive loss
(0.4
)
 
0.1

 
0.8

 
0.5

Net current-period other comprehensive income (loss)
5.7

 
(64.2
)
 
3.1

 
(55.4
)
Balance as of December 31, 2019
$
3.3

 
$
(77.2
)
 
$
(18.7
)
 
$
(92.6
)
 
 (1)All amounts are net of tax. Amounts in parentheses indicate debits.
v3.19.3.a.u2
Other, Net (Tables)
 12 Months Ended
Dec. 31, 2019
Other Nonoperating Income (Expense) [Abstract]  
Schedule Of Other, Net
Year Ended December 31, (in millions)
2019
 
2018
 
2017
Interest income
$
7.7

 
$
6.6

 
$
4.6

AFUDC equity
8.0

 
14.2

 
12.6

Charitable contributions(1)
(5.1
)
 
(45.3
)
 
(19.9
)
Pension and other postretirement non-service cost(2)
(16.5
)
 
18.0

 
(10.6
)
Interest rate swap settlement gain(3)
—

 
46.2

 
—

Miscellaneous
0.7

 
3.8

 
(0.2
)
Total Other, net
$
(5.2
)
 
$
43.5

 
$
(13.5
)

(1) 2018 charitable contributions include $20.7 million related to the Greater Lawrence Incident and $20.0 million of discretionary contributions made to the Nisource Charitable Foundation. See Note 19, "Other Commitments and Contingencies" for additional information on the Greater Lawrence Incident.
(2) See Note 11, "Pension and Other Postretirement Benefits" for additional information.
(3) See Note 9, "Risk Management Activities" for additional information.
v3.19.3.a.u2
Interest Expense, Net (Tables)
 12 Months Ended
Dec. 31, 2019
Interest Expense [Abstract]  
Schedule Of Interest Expense, Net
Year Ended December 31, (in millions)
2019
 
2018
 
2017
Interest on long-term debt
$
327.7

 
$
342.2

 
$
354.8

Interest on short-term borrowings
50.8

 
31.8

 
14.9

Debt discount/cost amortization
8.3

 
7.7

 
7.2

Accounts receivable securitization fees
2.6

 
2.6

 
2.5

Allowance for borrowed funds used and interest capitalized during construction
(7.5
)
 
(9.1
)
 
(6.2
)
Debt-based post-in-service carrying charges
(18.7
)
 
(35.0
)
 
(36.4
)
Other
15.7

 
13.1

 
16.4

Total Interest Expense, net
$
378.9

 
$
353.3

 
$
353.2
v3.19.3.a.u2
Segments Of Business (Tables)
 12 Months Ended
Dec. 31, 2019
Segment Reporting [Abstract]  
Schedule Of Operating Income Derived From Revenues And Expenses By Segment
Year Ended December 31, (in millions)
2019
 
2018
 
2017
Operating Revenues
 
 
 
 
 
Gas Distribution Operations
 
 
 
 
 
Unaffiliated
$
3,509.7

 
$
3,406.4

 
$
3,087.9

Intersegment
13.1

 
13.1

 
14.2

Total
3,522.8

 
3,419.5

 
3,102.1

Electric Operations
 
 
 
 
 
Unaffiliated
1,698.4

 
1,707.4

 
1,785.7

Intersegment
0.8

 
0.8

 
0.8

Total
1,699.2

 
1,708.2

 
1,786.5

Corporate and Other
 
 
 
 
 
Unaffiliated
0.8

 
0.7

 
1.0

Intersegment
468.1

 
517.6

 
510.8

Total
468.9

 
518.3

 
511.8

Eliminations
(482.0
)
 
(531.5
)
 
(525.8
)
Consolidated Operating Revenues
$
5,208.9

 
$
5,114.5

 
$
4,874.6


Year Ended December 31, (in millions)
2019
 
2018
 
2017
Operating Income (Loss)
 
 
 
 
 
Gas Distribution Operations
$
675.4

 
$
(254.1
)
 
$
550.1

Electric Operations
406.8

 
386.1

 
367.4

Corporate and Other(2)
(191.5
)
 
(7.3
)
 
3.7

Consolidated Operating Income
$
890.7

 
$
124.7

 
$
921.2

Depreciation and Amortization
 
 
 
 
 
Gas Distribution Operations
$
403.2

 
$
301.0

 
$
269.3

Electric Operations
277.3

 
262.9

 
277.8

Corporate and Other
36.9

 
35.7

 
23.2

Consolidated Depreciation and Amortization
$
717.4

 
$
599.6

 
$
570.3

Assets
 
 
 
 
 
Gas Distribution Operations
$
14,224.5

 
$
13,527.0

 
$
12,048.8

Electric Operations
6,027.6

 
5,735.2

 
5,478.6

Corporate and Other
2,407.7

 
2,541.8

 
2,434.3

Consolidated Assets
$
22,659.8

 
$
21,804.0

 
$
19,961.7

Capital Expenditures(1)
 
 
 
 
 
Gas Distribution Operations
$
1,380.3

 
$
1,315.3

 
$
1,125.6

Electric Operations
468.9

 
499.3

 
592.4

Corporate and Other
18.6

 
—

 
35.8

Consolidated Capital Expenditures
$
1,867.8


$
1,814.6

 
$
1,753.8


(1)Amounts differ from those presented on the Statements of Consolidated Cash Flows primarily due to the inclusion of capital expenditures included in current liabilities and AFUDC Equity.
(2) In 2019, Corporate and Other reflects an impairment charge of $204.8 million for goodwill related to Columbia of Massachusetts. For additional information, see Note 6, "Goodwill and Other Intangible Assets."
v3.19.3.a.u2
Quarterly Financial Data (Tables)
 12 Months Ended
Dec. 31, 2019
Quarterly Financial Data [Abstract]  
Schedule Of Quarterly Financial Data
(in millions, except per share data)
First
Quarter(1)
 
Second
Quarter(2)
 
Third
   Quarter(3)
 
Fourth
Quarter(4)
2019
 
 
 
 
 
 
 
Operating Revenues
$
1,869.8

 
$
1,010.4

 
$
931.5

 
$
1,397.2

Operating Income (Loss)
374.2

 
463.5

 
91.0

 
(38.0
)
Net Income (Loss)
218.9

 
296.9

 
6.6

 
(139.3
)
Preferred Dividends
(13.8
)
 
(13.8
)
 
(13.8
)
 
(13.7
)
Net Income (Loss) Available to Common Shareholders
205.1

 
283.1

 
(7.2
)
 
(153.0
)
Earnings (Loss) Per Share
 
 
 
 
 
 
 
Basic Earnings (Loss) Per Share
$
0.55

 
$
0.76

 
$
(0.02
)
 
$
(0.41
)
Diluted Earnings (Loss) Per Share
$
0.55

 
$
0.75

 
$
(0.02
)
 
$
(0.41
)
2018
 
 
 
 
 
 
 
Operating Revenues
$
1,750.8

 
$
1,007.0

 
$
895.0

 
$
1,461.7

Operating Income (Loss)
400.6

 
118.4

 
(315.9
)
 
(78.4
)
Net Income (Loss)
276.1

 
24.5

 
(339.5
)
 
(11.7
)
Preferred Dividends
—

 
(1.3
)
 
(5.6
)
 
(8.1
)
Net Income (Loss) Available to Common Shareholders
276.1

 
23.2

 
(345.1
)
 
(19.8
)
Earnings (Loss) Per Share
 
 
 
 
 
 
 
Basic Earnings (Loss) Per Share
$
0.82

 
$
0.07

 
$
(0.95
)
 
$
(0.05
)
Diluted Earnings (Loss) Per Share
$
0.81

 
$
0.07

 
$
(0.95
)
 
$
(0.05
)

(1) Net income for the first quarter of 2019 was impacted by $108.0 million in insurance recoveries (pretax) related to the Greater Lawrence Incident. See Note 19-E, "Other Matters" for additional information.
(2) Net income for the second quarter of 2019 was impacted by $297.0 million in insurance recoveries (pretax) related to the Greater Lawrence Incident. See Note 19-E, "Other Matters" for additional information.
(3) Net loss for the third quarter of 2018 was impacted by approximately $462 million in expenses (pretax) related to the Greater Lawrence Incident restoration and a $33.0 million loss (pretax) on an early extinguishment of long-term debt. See Note 19-E, "Other Matters" and Note 14, "Long-Term Debt" for additional information.
(4) Net loss for the fourth quarter of 2019 was impacted by an impairment charge of $204.8 million for goodwill and an impairment charge of $209.7 million for franchise rights, in each case related to Columbia of Massachusetts. For additional information, see Note 6, "Goodwill and Other Intangible Assets."
v3.19.3.a.u2
Supplemental Cash Flow Information (Tables)
 12 Months Ended
Dec. 31, 2019
Supplemental Cash Flow Information [Abstract]  
Schedule of Cash Flow, Supplemental Disclosures
The following table provides additional information regarding our Consolidated Statements of Cash Flows for the years ended December 31, 2019, 2018 and 2017:
Year Ended December 31, (in millions)
2019
 
2018
 
2017
Supplemental Disclosures of Cash Flow Information
 
 
 
 
 
Non-cash transactions:
 
 
 
 
 
Capital expenditures included in current liabilities
$
223.6

 
$
152.0

 
$
173.0

Assets acquired under a finance lease
26.4

 
54.6

 
11.5

Assets acquired under an operating lease
13.4

 
—

 
—

Reclassification of other property to regulatory assets(1)
—

 
245.3

 
—

Assets recorded for asset retirement obligations(2)
54.6

 
78.1

 
11.4

Schedule of interest and income taxes paid:
 
 
 
 
 
Cash paid for interest, net of interest capitalized amounts
$
349.7

 
$
354.2

 
$
339.9

Cash paid for income taxes, net of refunds
10.8

 
3.3

 
5.5


(1)See Note 8 "Regulatory Matters" for additional information.
(2)See Note 7 "Asset Retirement Obligations" for additional information.
v3.19.3.a.u2
Valuation and Qualifying Accounts (Tables)
 12 Months Ended
Dec. 31, 2019
SEC Schedule, 12-09, Valuation and Qualifying Accounts [Abstract]  
Schedule of Valuation and Qualifying Accounts Disclosure
NISOURCE INC.
SCHEDULE II – VALUATION AND QUALIFYING ACCOUNTS
Twelve months ended December 31, 2019
  
 
 
Additions
 
 
 
 
 
($ in millions)
Balance Jan. 1, 2019
 
Charged to Costs and Expenses
 
Charged to Other Account (1)
 
 
Deductions for Purposes for which Reserves were Created
 
Balance Dec. 31, 2019
Reserves Deducted in Consolidated Balance Sheet from Assets to Which They Apply:
 
 
 
 
 
 
 
 
 
 
Reserve for accounts receivable
$
21.1

 
$
21.6

 
$
41.3

 
 
$
64.8

 
$
19.2

Reserve for other investments
3.0

 
—

 
—

 
 
—

 
3.0

 
 
 
 
 
 
 
 
 
 
 
Twelve months ended December 31, 2018
 
 
 
Additions
 
 
 
 
 
($ in millions)
Balance
Jan. 1, 2018
 
Charged to Costs and Expenses
 
Charged to Other Account (1)
 
 
Deductions for Purposes for which Reserves were Created
 
Balance
Dec. 31, 2018
Reserves Deducted in Consolidated Balance Sheet from Assets to Which They Apply:
 
 
 
 
 
 
 
 
 
 
Reserve for accounts receivable
$
18.3

 
$
20.2

 
$
43.7

 
 
$
61.1

 
$
21.1

Reserve for other investments
3.0

 
—

 
—

 
 
—

 
3.0

 
 
 
 
 
 
 
 
 
 
 
Twelve months ended December 31, 2017
 
 
 
Additions
 
 
 
 
 
($ in millions)
Balance
Jan. 1, 2017
 
Charged to Costs and Expenses
 
Charged to Other Account (1)
 
 
Deductions for Purposes for which Reserves were Created
 
Balance
Dec. 31, 2017
Reserves Deducted in Consolidated Balance Sheet from Assets to Which They Apply:
 
 
 
 
 
 
 
 
 
 
Reserve for accounts receivable
$
23.3

 
$
14.8

 
$
39.1

 
 
$
58.9

 
$
18.3

Reserve for other investments
3.0

 
—

 
—

 
 
—

 
3.0

(1) Charged to Other Accounts reflects the deferral of bad debt expense to a regulatory asset.
v3.19.3.a.u2
Nature of Operations And Summary of Significant Accounting Policies (Narrative) (Details)
$ in Millions
 12 Months Ended
Dec. 31, 2019
USD ($)
Dec. 31, 2018
USD ($)
Dec. 31, 2017
Basis Of Accounting Presentation [Line Items]      
Number of customers 4,000,000    
Unbilled revenue, less reserves $ 350.5 $ 324.2  
Other than Temporary Impairment Losses, Investments $ 0.0 $ 0.0  
Pre-tax rate for allowance for funds used during construction 3.00% 3.50% 4.00%
Inventory valued using LIFO $ 47.2 $ 47.5  
Excess of replacement over LIFO value (25.5) (12.2)  
Inventory valued using the weighted average cost methodology $ 203.7 $ 239.3  
v3.19.3.a.u2
Revenue Recognition (Narrative) (Details)
 12 Months Ended
Dec. 31, 2019
Revenue from Contract with Customer [Abstract]  
Service Area By County 20
v3.19.3.a.u2
Revenue Recognition (Revenue Recognition Under Previous Guidance) (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2019
Dec. 31, 2018
Dec. 31, 2017
Revenue Recognition Under Previous Guidance [Line Items]      
Total Operating Revenues $ 5,208.9 $ 5,114.5 $ 4,874.6
Previous Accounting Guidance | Gas Distribution [Member]      
Revenue Recognition Under Previous Guidance [Line Items]      
Total Operating Revenues 2,336.1 2,348.4 2,063.2
Previous Accounting Guidance | Gas Transportation [Member]      
Revenue Recognition Under Previous Guidance [Line Items]      
Total Operating Revenues 1,171.3 1,055.2 1,021.5
Previous Accounting Guidance | Electric [Member]      
Revenue Recognition Under Previous Guidance [Line Items]      
Total Operating Revenues 1,698.5 1,707.4 1,785.5
Previous Accounting Guidance | Other [Member]      
Revenue Recognition Under Previous Guidance [Line Items]      
Total Operating Revenues $ 3.0 $ 3.5 $ 4.4
v3.19.3.a.u2
Revenue Recognition (Disaggregation of Revenue) (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2019
Dec. 31, 2018
Dec. 31, 2017
Disaggregation of Revenue [Line Items]      
Customer revenues $ 5,053.4 [1] $ 4,991.1 [1] $ 4,730.2
Other revenues 155.5 123.4 144.4
Total Operating Revenues 5,208.9 5,114.5 $ 4,874.6
Gas Distribution Operations      
Disaggregation of Revenue [Line Items]      
Customer revenues [1] 3,455.2 3,372.0  
Other revenues 54.5 34.4  
Total Operating Revenues 3,509.7 3,406.4  
Electric Operations      
Disaggregation of Revenue [Line Items]      
Customer revenues [1] 1,597.4 1,618.4  
Other revenues 101.0 89.0  
Total Operating Revenues 1,698.4 1,707.4  
Corporate and Other      
Disaggregation of Revenue [Line Items]      
Customer revenues [1] 0.8 0.7  
Other revenues 0.0 0.0  
Total Operating Revenues 0.8 0.7  
Residential      
Disaggregation of Revenue [Line Items]      
Customer revenues [1] 2,790.6 2,744.7  
Residential | Gas Distribution Operations      
Disaggregation of Revenue [Line Items]      
Customer revenues [1] 2,309.0 2,250.0  
Residential | Electric Operations      
Disaggregation of Revenue [Line Items]      
Customer revenues [1] 481.6 494.7  
Residential | Corporate and Other      
Disaggregation of Revenue [Line Items]      
Customer revenues [1] 0.0 0.0  
Commercial      
Disaggregation of Revenue [Line Items]      
Customer revenues [1] 1,257.9 1,244.6  
Commercial | Gas Distribution Operations      
Disaggregation of Revenue [Line Items]      
Customer revenues [1] 771.3 751.9  
Commercial | Electric Operations      
Disaggregation of Revenue [Line Items]      
Customer revenues [1] 486.6 492.7  
Commercial | Corporate and Other      
Disaggregation of Revenue [Line Items]      
Customer revenues [1] 0.0 0.0  
Industrial      
Disaggregation of Revenue [Line Items]      
Customer revenues [1] 852.9 841.6  
Industrial | Gas Distribution Operations      
Disaggregation of Revenue [Line Items]      
Customer revenues [1] 245.2 228.0  
Industrial | Electric Operations      
Disaggregation of Revenue [Line Items]      
Customer revenues [1] 607.7 613.6  
Industrial | Corporate and Other      
Disaggregation of Revenue [Line Items]      
Customer revenues [1] 0.0 0.0  
Off-system      
Disaggregation of Revenue [Line Items]      
Customer revenues [1] 77.7 92.4  
Off-system | Gas Distribution Operations      
Disaggregation of Revenue [Line Items]      
Customer revenues [1] 77.7 92.4  
Off-system | Electric Operations      
Disaggregation of Revenue [Line Items]      
Customer revenues [1] 0.0 0.0  
Off-system | Corporate and Other      
Disaggregation of Revenue [Line Items]      
Customer revenues [1] 0.0 0.0  
Miscellaneous      
Disaggregation of Revenue [Line Items]      
Customer revenues [1] 74.3 67.8  
Miscellaneous | Gas Distribution Operations      
Disaggregation of Revenue [Line Items]      
Customer revenues [1] 52.0 49.7  
Miscellaneous | Electric Operations      
Disaggregation of Revenue [Line Items]      
Customer revenues [1] 21.5 17.4  
Miscellaneous | Corporate and Other      
Disaggregation of Revenue [Line Items]      
Customer revenues [1] $ 0.8 $ 0.7  
[1] Customer revenue amounts exclude intersegment revenues. See Note 23, "Segments of Business," for discussion of intersegment revenues.
v3.19.3.a.u2
Revenue Recognition (Customer Accounts Receivable) (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2019
Dec. 31, 2018
Revenue Recognition [Abstract]    
Customer Accounts Receivable, Billed (Less Reserve) [1] $ 466.6 $ 540.5
Customer Accounts Receivable, Unbilled (Less Reserve) 346.6 $ 349.1
Increase (Decrease) in Customer Accounts Receivable, Billed (Less Reserve) [1] (73.9)  
Increase (Decrease) in Customer Accounts Receivable, Unbilled (Less Reserve) $ (2.5)  
[1] Customer billed receivables decreased due to decreased natural gas costs and warmer weather in 2019 compared to 2018
v3.19.3.a.u2
Earnings Per Share (Details) - shares
shares in Thousands
 12 Months Ended
Dec. 31, 2019
Dec. 31, 2018
Dec. 31, 2017
Earnings Per Share [Abstract]      
Basic Average Common Shares Outstanding 374,650 356,491 329,388
Shares contingently issuable under employee stock plans 929 0 547
Shares restricted under stock plans 154 0 821
Forward agreements 253 0 0
Diluted Average Common Shares 375,986 356,491 330,756
v3.19.3.a.u2
Property, Plant and Equipment (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2019
Dec. 31, 2018
Dec. 31, 2017
Property, Plant and Equipment [Line Items]      
Depreciation $ 612.2 $ 503.4 $ 501.5
Capitalized Computer Software, Amortization 55.5 54.1 $ 44.0
Capitalized Computer Software, Gross 169.6 159.5  
Capitalized Cloud Computing, Amortization 1.6 0.1  
Capitalized Cloud Computing, Gross $ 14.2 $ 4.9  
v3.19.3.a.u2
Property, Plant And Equipment (Schedule Of Property, Plant And Equipment) (Details) - USD ($)
$ in Millions
Dec. 31, 2019
Dec. 31, 2018
Property, Plant and Equipment [Line Items]    
Property Plant and Equipment $ 24,541.9 $ 22,819.5
Accumulated Depreciation and Amortization (7,629.7) (7,277.0)
Net Property, Plant and Equipment 16,912.2 15,542.5
Gas Distribution Utility    
Property, Plant and Equipment [Line Items]    
Property Plant and Equipment [1] 14,989.7 13,776.0
Accumulated Depreciation and Amortization [1] (3,556.0) (3,373.8)
Electric Utility    
Property, Plant and Equipment [Line Items]    
Property Plant and Equipment [1] 8,902.3 8,374.2
Accumulated Depreciation and Amortization [1] (3,973.8) (3,809.5)
Common Utility    
Property, Plant and Equipment [Line Items]    
Property Plant and Equipment 153.3 155.8
Accumulated Depreciation and Amortization (79.5) (74.6)
Construction Work In Process    
Property, Plant and Equipment [Line Items]    
Property Plant and Equipment 457.3 474.8
Non-Utility And Other    
Property, Plant and Equipment [Line Items]    
Property Plant and Equipment 39.3 38.7
Accumulated Depreciation and Amortization $ (20.4) $ (19.1)
[1] NIPSCO’s common utility plant and associated accumulated depreciation and amortization are allocated between Gas Distribution Utility and Electric Utility Property, Plant and Equipment.
v3.19.3.a.u2
Property, Plant And Equipment Property, Plant and Equipment (Schedule of Depreciation Provisions For Utility Plant as a Percentage of the Original Cost) (Details)
 12 Months Ended
Dec. 31, 2019
Dec. 31, 2018
Dec. 31, 2017
Electric Operations      
Property, Plant and Equipment [Line Items]      
Depreciation Provisions For Utility Plant Percentage 2.80% [1] 2.90% [1] 3.40%
Gas Distribution Operations      
Property, Plant and Equipment [Line Items]      
Depreciation Provisions For Utility Plant Percentage 2.50% 2.20% 2.10%
[1] Lower depreciation rate beginning in 2018 due to reduced EERM-related depreciation expense and higher depreciable base from transmission assets being placed into service in 2018.
v3.19.3.a.u2
Goodwill and Other Intangible Assets (Details) - USD ($)
$ in Millions
 3 Months Ended 12 Months Ended
Dec. 31, 2019
Dec. 31, 2019
Dec. 31, 2018
Dec. 31, 2017
Goodwill And Other Intangible Assets [Line Items]        
Goodwill $ 1,485.9 $ 1,485.9 $ 1,690.7  
Intangible Assets, Net (Excluding Goodwill) 0.0 0.0 220.7  
Amortization     221.5  
Amortization of Intangible Assets   $ 11.0 11.0 $ 11.0
Finite-Lived Intangible Asset, Useful Life   40 years    
Finite-Lived Intangible Assets, Amortization End Date   2039    
Gas Distribution Operations        
Goodwill And Other Intangible Assets [Line Items]        
Goodwill 1,485.9 $ 1,485.9 1,690.7  
Electric Operations        
Goodwill And Other Intangible Assets [Line Items]        
Goodwill 0.0 0.0 0.0  
Corporate and Other        
Goodwill And Other Intangible Assets [Line Items]        
Goodwill 0.0 $ 0.0 $ 0.0  
Columbia Of Massachusetts        
Goodwill And Other Intangible Assets [Line Items]        
Impairment of Intangible Assets, Finite-lived 209.7      
Goodwill, Impairment Loss $ 204.8      
v3.19.3.a.u2
Asset Retirement Obligations (Changes In Company's Liability For Asset Retirement Obligations) (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2019
Dec. 31, 2018
Beginning Balance $ 352.0 $ 268.7
Accretion recorded as a regulatory asset 15.7 11.1
Additions 0.0 63.3 [1]
Settlements (5.4) (5.9)
Change in estimated cash flows 54.6 [2] 14.8 [1]
Ending Balance 416.9 $ 352.0
CCR    
Additions 59.8  
Change in estimated cash flows $ 17.7  
[1] In 2018, $59.8 million of additions and $17.7 million of the change in estimated cash flows are attributed to costs associated with refining the CCR compliance plan. See Note 19-D, "Environmental Matters," for additional information on CCRs.
[2] The change in estimated cash flows for 2019 is primarily attributed to changes in estimated costs and settlement timing for electric generating stations and the changes in estimated costs for retirement of gas mains.
v3.19.3.a.u2
Regulatory Matters (Narrative) (Details) - USD ($)
$ in Millions
 12 Months Ended 156 Months Ended
May 29, 2019
May 22, 2019
Aug. 28, 2018
Dec. 27, 2016
Dec. 31, 2019
Dec. 31, 2017
Dec. 31, 2018
Regulatory Matters [Line Items]              
Public Utilities, Requested Rate Increase (Decrease), Adjustment     $ 5.2        
Remaining Recovery Period of Regulatory Assets for which No Return on Investment During Recovery Period is Provided         41 years    
Regulatory asset not earning return on investment         $ 1,524.3    
Expenses recovered as components of cost of service and regulatory orders         1,932.4    
Regulatory assets Requiring Specific Rate Action         307.2    
Columbia Of Ohio              
Regulatory Matters [Line Items]              
Depreciation Before Rate Regulation           $ 923.5  
Decrease In Depreciation And Amortization Over That Reflected In Rates           $ 103.8  
Depreciation Regulatory Asset         27.9   $ 39.5
Requested IRP Extension       5 years      
Columbia Of Virginia              
Regulatory Matters [Line Items]              
Public Utilities, Requested Rate Increase (Decrease), Amount     14.2        
Public Utilities, Approved Rate Increase (Decrease), Amount     $ 1.3        
Columbia Of Maryland              
Regulatory Matters [Line Items]              
Public Utilities, Requested Rate Increase (Decrease), Amount   $ 2.5          
Public Utilities, Approved Rate Increase (Decrease), Amount $ (0.1)            
IRP | Columbia Of Ohio              
Regulatory Matters [Line Items]              
Deferred Depreciation         31.9   76.0
Capital Expenditure Program | Columbia Of Ohio              
Regulatory Matters [Line Items]              
Deferred Depreciation         77.2   29.1
EERM [Domain] | NIPSCO              
Regulatory Matters [Line Items]              
Deferred Depreciation         15.2   14.4
TDSIC [Domain] | NIPSCO              
Regulatory Matters [Line Items]              
Deferred Depreciation         22.0   16.5
Deferred Post-in-Service Carrying Charges         13.4   9.5
IRP and CEP [Domain] | Columbia Of Ohio              
Regulatory Matters [Line Items]              
Deferred Post-in-Service Carrying Charges         $ 206.4   $ 197.1
v3.19.3.a.u2
Regulatory Matters (Regulatory Assets) (Details) - USD ($)
$ in Millions
Dec. 31, 2019
Dec. 31, 2018
Regulatory Assets [Line Items]    
Total Assets $ 2,239.6 $ 2,237.5
Unrecognized Pension Benefit And Other Postretirement Benefit Costs    
Regulatory Assets [Line Items]    
Total Assets 739.1 798.3
Other Postretirement Costs    
Regulatory Assets [Line Items]    
Total Assets 91.3 74.1
Environmental Costs    
Regulatory Assets [Line Items]    
Total Assets 73.4 61.5
Regulatory Effects Of Accounting For Income Taxes    
Regulatory Assets [Line Items]    
Total Assets 234.0 233.1
Underrecovered Gas And Fuel Costs    
Regulatory Assets [Line Items]    
Total Assets 3.9 34.7
Depreciation    
Regulatory Assets [Line Items]    
Total Assets 210.7 209.6
Post-In Service Carrying Charges    
Regulatory Assets [Line Items]    
Total Assets 219.8 206.6
Safety Activity Costs    
Regulatory Assets [Line Items]    
Total Assets 118.6 91.7
DSM Program    
Regulatory Assets [Line Items]    
Total Assets 50.1 45.5
Bailly Generating Station [Member]    
Regulatory Assets [Line Items]    
Total Assets 221.8 244.3
Other Assets    
Regulatory Assets [Line Items]    
Total Assets $ 276.9 $ 238.1
v3.19.3.a.u2
Regulatory Matters (Regulatory Liabilities) (Details) - USD ($)
$ in Millions
Dec. 31, 2019
Dec. 31, 2018
Regulatory Liabilities [Line Items]    
Regulatory Liabilities $ 2,512.2 $ 2,660.0
Overrecovered Gas And Fuel Costs    
Regulatory Liabilities [Line Items]    
Regulatory Liabilities 42.6 32.0
Cost Of Removal    
Regulatory Liabilities [Line Items]    
Regulatory Liabilities 1,047.5 1,076.0
Regulatory Effects Of Accounting For Income Taxes    
Regulatory Liabilities [Line Items]    
Regulatory Liabilities 1,307.0 1,428.3
Other Postretirement Costs    
Regulatory Liabilities [Line Items]    
Regulatory Liabilities 64.7 62.7
Other Liabilities    
Regulatory Liabilities [Line Items]    
Regulatory Liabilities $ 50.4 $ 61.0
v3.19.3.a.u2
Regulatory Matters (Schedule of Regulatory Programs) (Details) - USD ($)
$ in Millions
Feb. 25, 2020
Jan. 29, 2020
Nov. 26, 2019
Oct. 31, 2019
Oct. 18, 2019
Oct. 15, 2019
Aug. 21, 2019
Aug. 15, 2019
Jun. 25, 2019
May 29, 2019
May 22, 2019
Apr. 17, 2019
Feb. 28, 2019
Jan. 29, 2019
Nov. 30, 2018
Nov. 01, 2018
Oct. 31, 2018
Oct. 15, 2018
Aug. 28, 2018
Aug. 17, 2018
Dec. 01, 2017
Sep. 27, 2017
Regulatory Matters [Line Items]                                            
Public Utilities, Requested Rate Increase (Decrease), Adjustment                                     $ 5.2      
NIPSCO - Gas                                            
Regulatory Matters [Line Items]                                            
Public Utilities, Approved Rate Increase (Decrease), Amount                                           $ 105.6
Public Utilities, Requested Rate Increase (Decrease), Amount                                           $ 138.1
Columbia Of Virginia                                            
Regulatory Matters [Line Items]                                            
Public Utilities, Approved Rate Increase (Decrease), Amount                                     1.3      
Public Utilities, Requested Rate Increase (Decrease), Amount                                     14.2      
Columbia Of Maryland                                            
Regulatory Matters [Line Items]                                            
Public Utilities, Approved Rate Increase (Decrease), Amount                   $ (0.1)                        
Public Utilities, Requested Rate Increase (Decrease), Amount                     $ 2.5                      
NIPSCO - Electric                                            
Regulatory Matters [Line Items]                                            
Public Utilities, Approved Rate Increase (Decrease), Amount                                 $ (53.5)          
Public Utilities, Requested Rate Increase (Decrease), Amount                                 21.4          
2019 IRP | Columbia Of Ohio                                            
Regulatory Matters [Line Items]                                            
Public Utilities, Approved Rate Increase (Decrease), Amount [1]                         $ 18.2                  
Regulatory Net Capital Expenditures Included In Filing [1]                         199.6                  
2018 CEP | Columbia Of Ohio                                            
Regulatory Matters [Line Items]                                            
Public Utilities, Approved Rate Increase (Decrease), Amount                                         $ 74.5  
Regulatory Net Capital Expenditures Included In Filing                                         $ 659.9  
2019 CEP | Columbia Of Ohio                                            
Regulatory Matters [Line Items]                                            
Public Utilities, Approved Rate Increase (Decrease), Amount                         15.0                  
Regulatory Net Capital Expenditures Included In Filing                         $ 121.7                  
TDSIC 9 | NIPSCO - Gas                                            
Regulatory Matters [Line Items]                                            
Public Utilities, Approved Rate Increase (Decrease), Amount [1],[2]                                     (10.6)      
Regulatory Net Capital Expenditures Included In Filing [1],[2]                                     $ 54.4      
TDSIC 10 | NIPSCO - Gas                                            
Regulatory Matters [Line Items]                                            
Public Utilities, Approved Rate Increase (Decrease), Amount [3]                 $ 1.6                          
Regulatory Net Capital Expenditures Included In Filing [3]                 $ 12.4                          
FMCA 1 | NIPSCO - Gas                                            
Regulatory Matters [Line Items]                                            
Public Utilities, Approved Rate Increase (Decrease), Amount [4]                             $ 9.9              
Regulatory Net Capital Expenditures Included In Filing [4]                             $ 1.5              
FMCA 2 | NIPSCO - Gas                                            
Regulatory Matters [Line Items]                                            
Public Utilities, Approved Rate Increase (Decrease), Amount [4]                   (3.5)                        
Regulatory Net Capital Expenditures Included In Filing [4]                   $ 1.8                        
FMCA 3 | NIPSCO - Gas                                            
Regulatory Matters [Line Items]                                            
Public Utilities, Approved Rate Increase (Decrease), Amount [4]     $ 0.3                                      
Regulatory Net Capital Expenditures Included In Filing [4]     $ 43.0                                      
2019 GSEP | Columbia Of Massachusetts                                            
Regulatory Matters [Line Items]                                            
Public Utilities, Approved Rate Increase (Decrease), Amount [5]                                 9.6          
Regulatory Net Capital Expenditures Included In Filing [5]                                 $ 36.0          
2020 GSEP | Columbia Of Massachusetts                                            
Regulatory Matters [Line Items]                                            
Public Utilities, Approved Rate Increase (Decrease), Amount [5],[6]       $ 2.4                                    
Regulatory Net Capital Expenditures Included In Filing [5],[6]       $ 75.0                                    
2019 SAVE | Columbia Of Virginia                                            
Regulatory Matters [Line Items]                                            
Public Utilities, Approved Rate Increase (Decrease), Amount                                       $ 2.4    
Regulatory Net Capital Expenditures Included In Filing                                       $ 36.0    
2020 SAVE | Columbia Of Virginia                                            
Regulatory Matters [Line Items]                                            
Public Utilities, Requested Rate Increase (Decrease), Amount               $ 3.8                            
Regulatory Net Capital Expenditures Included In Filing               $ 50.0                            
2019 AMRP | Columbia Of Kentucky                                            
Regulatory Matters [Line Items]                                            
Public Utilities, Approved Rate Increase (Decrease), Amount                                   $ 3.6        
Regulatory Net Capital Expenditures Included In Filing                                   $ 30.1        
2020 SMRP | Columbia Of Kentucky                                            
Regulatory Matters [Line Items]                                            
Public Utilities, Approved Rate Increase (Decrease), Amount           $ 4.2                                
Regulatory Net Capital Expenditures Included In Filing           $ 40.4                                
2019 STRIDE | Columbia Of Maryland                                            
Regulatory Matters [Line Items]                                            
Public Utilities, Approved Rate Increase (Decrease), Amount                               $ 1.2            
Regulatory Net Capital Expenditures Included In Filing                               $ 19.7            
TDSIC 5 | NIPSCO - Electric                                            
Regulatory Matters [Line Items]                                            
Public Utilities, Approved Rate Increase (Decrease), Amount [1]                           $ 15.9                
Regulatory Net Capital Expenditures Included In Filing [1]                           $ 58.8                
TDSIC 6 | NIPSCO - Electric                                            
Regulatory Matters [Line Items]                                            
Public Utilities, Requested Rate Increase (Decrease), Amount             $ 28.1                              
Regulatory Net Capital Expenditures Included In Filing             $ 131.1                              
FMCA 11 | NIPSCO - Electric                                            
Regulatory Matters [Line Items]                                            
Public Utilities, Approved Rate Increase (Decrease), Amount [4]                       $ 0.9                    
Regulatory Net Capital Expenditures Included In Filing [4]                       $ 22.4                    
FMCA 12 | NIPSCO - Electric                                            
Regulatory Matters [Line Items]                                            
Public Utilities, Approved Rate Increase (Decrease), Amount [4]         $ 1.6                                  
Regulatory Net Capital Expenditures Included In Filing [4]         $ 4.7                                  
Subsequent Event | TDSIC 11 | NIPSCO - Gas                                            
Regulatory Matters [Line Items]                                            
Public Utilities, Approved Rate Increase (Decrease), Amount [7] $ (1.7)                                          
Regulatory Net Capital Expenditures Included In Filing [7] $ 38.7                                          
Subsequent Event | 2020 STRIDE | Columbia Of Maryland                                            
Regulatory Matters [Line Items]                                            
Public Utilities, Approved Rate Increase (Decrease), Amount   $ 1.3                                        
Regulatory Net Capital Expenditures Included In Filing   $ 15.0                                        
[1] Incremental revenue is net of amounts due back to customers as a result of the TCJA.
[2] Incremental revenue is net of $5.2 million of adjustments in the TDSIC-9 settlement.
[3]
(3)Incremental capital and revenue are net of amounts included in the step 2 rates.
[4]
(5)Incremental revenue is inclusive of tracker eligible operations and maintenance expense.
[5]
(6)Due to an order from the Massachusetts DPU on October 3, 2019 imposing work restrictions on Columbia of Massachusetts, Columbia of Massachusetts did not meet the approved projected 2019 GSEP spend of $64 million and associated incremental revenue of $10.7 million. In the 2020 GSEP, Columbia of Massachusetts reduced the projected capital spend for calendar year 2019 to $36 million and the associated incremental revenue in 2019 GSEP to $9.6 million.
[6]
(7)Incremental capital investment is anticipated to be lower than $75 million in 2020 due to the Massachusetts DPU imposed work restrictions.
[7]
(4)Incremental revenue is net of amounts included in the step 2 rates and reflects a more typical filing period.
v3.19.3.a.u2
Regulatory Matters (Rate Case Action) (Details) - USD ($)
$ in Millions
May 29, 2019
May 22, 2019
Oct. 31, 2018
Aug. 28, 2018
Sep. 27, 2017
NIPSCO - Gas          
Regulatory Matters [Line Items]          
Public Utilities, Requested Rate Increase (Decrease), Amount         $ 138.1
Public Utilities, Approved Rate Increase (Decrease), Amount         $ 105.6
Columbia Of Virginia          
Regulatory Matters [Line Items]          
Public Utilities, Requested Rate Increase (Decrease), Amount       $ 14.2  
Public Utilities, Approved Rate Increase (Decrease), Amount       $ 1.3  
Columbia Of Maryland          
Regulatory Matters [Line Items]          
Public Utilities, Requested Rate Increase (Decrease), Amount   $ 2.5      
Public Utilities, Approved Rate Increase (Decrease), Amount $ (0.1)        
NIPSCO - Electric          
Regulatory Matters [Line Items]          
Public Utilities, Requested Rate Increase (Decrease), Amount     $ 21.4    
Public Utilities, Approved Rate Increase (Decrease), Amount     $ (53.5)    
v3.19.3.a.u2
Risk Management Activities (Narrative) (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2019
Dec. 31, 2018
Dec. 31, 2017
Derivative [Line Items]      
Limit of GCA Volumes 2000.00%    
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net $ 0.0 $ 0.0 $ 0.0
Interest Rate Swap      
Derivative [Line Items]      
Derivative, Notional Amount 500.0    
Interest Rate Swap Settled      
Derivative [Line Items]      
Derivative, Notional Amount   750.0  
Derivative, Gain (Loss) on Derivative, Net $ 0.0 [1] $ 46.2  
[1]
(3) See Note 9, "Risk Management Activities" for additional information.
v3.19.3.a.u2
Risk Management Activities (Schedule of Derivative Instruments in Statement of Financial Position, Fair Value) (Details) - USD ($)
$ in Millions
Dec. 31, 2019
Dec. 31, 2018
Derivatives, Fair Value [Line Items]    
Derivative Asset $ 4.4 $ 24.0
Derivative Liability 146.6 51.7
Risk Management Assets Current    
Derivatives, Fair Value [Line Items]    
Derivative Asset [1] 0.6 1.1
Risk Management Assets Noncurrent    
Derivatives, Fair Value [Line Items]    
Derivative Asset [2] 3.8 22.9
Risk Management Liabilities Current    
Derivatives, Fair Value [Line Items]    
Derivative Liability [3] 12.6 5.0
Risk Management Liabilities Noncurrent    
Derivatives, Fair Value [Line Items]    
Derivative Liability 134.0 46.7
Interest rate risk programs | Risk Management Assets Current    
Derivatives, Fair Value [Line Items]    
Derivative Asset 0.0 0.0
Interest rate risk programs | Risk Management Assets Noncurrent    
Derivatives, Fair Value [Line Items]    
Derivative Asset 0.0 18.5
Interest rate risk programs | Risk Management Liabilities Current    
Derivatives, Fair Value [Line Items]    
Derivative Liability 0.0 0.0
Interest rate risk programs | Risk Management Liabilities Noncurrent    
Derivatives, Fair Value [Line Items]    
Derivative Liability 76.2 9.5
Commodity price risk programs | Risk Management Assets Current    
Derivatives, Fair Value [Line Items]    
Derivative Asset 0.6 1.1
Commodity price risk programs | Risk Management Assets Noncurrent    
Derivatives, Fair Value [Line Items]    
Derivative Asset 3.8 4.4
Commodity price risk programs | Risk Management Liabilities Current    
Derivatives, Fair Value [Line Items]    
Derivative Liability 12.6 5.0
Commodity price risk programs | Risk Management Liabilities Noncurrent    
Derivatives, Fair Value [Line Items]    
Derivative Liability $ 57.8 $ 37.2
[1] Presented in "Prepayments and other" on the Consolidated Balance Sheets.
[2] Presented in "Other accruals" on the Consolidated Balance Sheets.
[3]
(3)Presented in "Other accruals" on the Consolidated Balance Sheets.
v3.19.3.a.u2
Income Taxes (Narrative) (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2019
Dec. 31, 2019
Dec. 31, 2019
Dec. 31, 2018
Dec. 31, 2018
Dec. 31, 2018
Dec. 31, 2017
Dec. 31, 2017
Dec. 31, 2017
Income Taxes [Line Items]                  
Effective income tax rate 24.40%   24.40% 78.10%   78.10% 71.00%   71.00%
Increase (Decrease) in Effective Tax Rate (53.70%)     7.10%          
State regulatory proceedings, value   $ 9.5     $ 127.8     $ 0.0  
Increase in State Income Taxes         7.1        
Tax Benefit From Excess Deferred Tax Amortization Related To Regulatory LIabilities         26.9        
Deferred Tax Assets, Operating Loss Carryforwards $ 765.9 765.9 $ 765.9 $ 849.8 849.8 $ 849.8      
Deferred Tax Assets, Tax Credit Carryforwards, Alternative Minimum Tax 1.6 1.6 1.6            
Deferred Tax Assets, Charitable Contribution Carryforwards 1.4 1.4 1.4            
Unrecognized Tax Benefits, Decrease Resulting from Prior Period Tax Positions   0.6     0.4     1.4  
Unrecognized Tax Benefits, Increase Resulting from Current Period Tax Positions   22.6     0.2     0.2  
Unrecognized Tax Benefits, Income Tax Penalties Expense   0.0              
Unrecognized Tax Benefits, Income Tax Penalties Accrued 0.0 0.0 0.0 $ 0.0 0.0 $ 0.0 $ 0.0 0.0 $ 0.0
Remeasurement due to TCJA, value   0.0     0.0     161.1  
Reduction in Deferred Tax Liability Due To Tax Law Change               1,300.0  
Reduction in Regulatory Deferred tax Liabilities               400.0  
Increase in Regulatory Liability Due to Tax Law Change               $ 1,500.0  
Change in tax expense         $ 120.7        
Internal Revenue Service (IRS)                  
Income Taxes [Line Items]                  
Deferred Tax Assets, Operating Loss Carryforwards 657.1 657.1 657.1            
State and Local Jurisdiction                  
Income Taxes [Line Items]                  
Deferred Tax Assets, Operating Loss Carryforwards $ 107.2 $ 107.2 $ 107.2            
v3.19.3.a.u2
Income Taxes (Schedule Of Components Of Income Tax Expense) (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2019
Dec. 31, 2018
Dec. 31, 2017
Current      
Federal $ 0.0 $ 0.0 $ 0.0
State 5.2 8.2 7.8
Total Current 5.2 8.2 7.8
Deferred      
Federal 110.7 (209.4) 302.7
State 9.0 22.2 5.0
Total Deferred 119.7 (187.2) 307.7
Deferred Investment Credits (1.4) (1.0) (1.0)
Income Taxes $ 123.5 $ (180.0) $ 314.5
v3.19.3.a.u2
Income Taxes (Schedule Of Reasons Behind Differences In Computation Of Total Income Taxes) (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2019
Dec. 31, 2019
Dec. 31, 2019
Dec. 31, 2018
Dec. 31, 2018
Dec. 31, 2018
Dec. 31, 2017
Dec. 31, 2017
Dec. 31, 2017
Schedule of Reasons Behind Differences in Computation of Total Income Taxes [Line Items]                  
Book income (loss) before income taxes   $ 506.6     $ (230.6)     $ 443.0  
Tax expense (benefit) at statutory federal income tax rate, value   106.5     (48.4)     155.0  
Tax expense (benefit) at statutory federal income tax rate, rate 21.00%     21.00%     35.00%    
Increases (reductions) in taxes resulting from:                  
State income taxes, net of federal income tax benefit, value   10.1     24.7     6.9  
State income taxes, net of federal income tax benefit, rate 2.00%     (10.70%)     1.50%    
Amortization of regulatory liabilities, value   (29.4)     (29.3)     (2.4)  
Amortization of regulatory liabilities, rate (5.80%)     12.70%     (0.50%)    
Goodwill impairment, value   43.0     0.0     0.0  
Goodwill impairment, rate 8.50%     0.00%     0.00%    
Fines and penalties, value   11.5     0.2     2.8  
Fines and penalties, rate 2.30%     (0.10%)     0.60%    
Charitable contribution carryover, value   (2.5)     0.0     (1.2)  
Charitable contribution carryover, rate (0.50%)     0.00%     (0.30%)    
State regulatory proceedings, value   (9.5)     (127.8)     0.0  
State regulatory proceedings, rate (1.90%)     55.40%     0.00%    
Remeasurement due to TCJA, value   0.0     0.0     161.1  
Remeasurement due to TCJA, rate 0.00%     0.00%     36.40%    
Employee stock ownership plan dividends and other compensation, value   (2.0)     (2.2)     (6.5)  
Employee stock ownership plan dividends and other compensation, rate (0.40%)     1.00%     (1.50%)    
Other adjustments, value   (4.2)     2.8     (1.2)  
Other adjustments, rate (0.80%)     (1.20%)     (0.20%)    
Income Taxes   $ 123.5     $ (180.0)     $ 314.5  
Income Taxes, rate 24.40%   24.40% 78.10%   78.10% 71.00%   71.00%
v3.19.3.a.u2
Income Taxes (Schedule Of Principal Components Of Net Deferred Tax Liability) (Details) - USD ($)
$ in Millions
Dec. 31, 2019
Dec. 31, 2018
Deferred Tax Liabilities    
Accelerated depreciation and other property differences $ 2,516.9 $ 2,458.0
Other regulatory assets 381.5 375.4
Total Deferred Tax Liabilities 2,898.4 2,833.4
Deferred Tax Assets    
Other regulatory liabilities and deferred investment tax credits (including TCJA) 336.1 365.5
Pension and other postretirement/postemployment benefits 152.1 157.5
Net operating loss carryforward and AMT credit carryforward 765.9 849.8
Environmental liabilities 25.4 24.4
Other accrued liabilities 35.3 37.5
Other, net 98.3 68.2
Total Deferred Tax Assets 1,413.1 1,502.9
Net Deferred Tax Liabilities $ 1,485.3 $ 1,330.5
v3.19.3.a.u2
Income Taxes (Schedule of Unrecognized Tax Benefits Roll Forward) (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2019
Dec. 31, 2018
Dec. 31, 2017
Income Tax Disclosure [Abstract]      
Unrecognized Tax Benefits - Opening Balance $ 1.2 $ 1.4 $ 2.6
Gross decreases - tax positions in prior period (0.6) (0.4) (1.4)
Gross increases - current period tax positions 22.6 0.2 0.2
Unrecognized Tax Benefits - Ending Balance 23.2 1.2 1.4
Offset for net operating loss carryforwards (22.6) 0.0 0.0
Balance - Less Net Operating Loss Carryforwards $ 0.6 $ 1.2 $ 1.4
v3.19.3.a.u2
Pension and Other Postretirement Benefits (Narrative) (Details) - USD ($)
$ in Millions
 3 Months Ended 12 Months Ended
Dec. 31, 2019
Dec. 31, 2018
Dec. 31, 2020
Dec. 31, 2019
Dec. 31, 2018
Dec. 31, 2017
Defined Benefit Plan Disclosure [Line Items]            
Defined Benefit Plan, Plan Assets, Amount $ 2,342.3 $ 2,084.1   $ 2,342.3 $ 2,084.1  
Regulatory assets 2,239.6 2,237.5   2,239.6 2,237.5  
Regulatory Liabilities 2,512.2 2,660.0   $ 2,512.2 2,660.0  
Expected return on plan assets       6.10%    
Pension Plan            
Defined Benefit Plan Disclosure [Line Items]            
Defined Benefit Plan, Plan Assets, Amount 2,080.9 1,867.7   $ 2,080.9 1,867.7 $ 2,160.0
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)       53.8 (127.5)  
Defined Benefit Plan, Amortization of Prior Service Cost (Credit) 0.2 (0.4)   0.2 (0.4) (0.7)
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)       47.6 14.8 $ 41.1
Employer contributions       2.9 2.9  
Expected contribution 3.0     3.0    
Defined Benefit Plan, Accumulated Benefit Obligation 2,111.5 1,965.6   2,111.5 1,965.6  
Funded status of plan 49.6 113.6   49.6 113.6  
Liability, Defined Benefit Plan [1] 49.6 113.6   $ 49.6 $ 113.6  
Expected return on plan assets       6.10% 7.00% 7.25%
Settlement loss 9.5 18.5   $ 9.5 $ 18.5 $ 13.7
Defined Benefit Plan, Benefit Obligation, (Increase) Decrease for Remeasurement due to Settlement       0.7    
Other Postretirement Benefits            
Defined Benefit Plan Disclosure [Line Items]            
Defined Benefit Plan, Plan Assets, Amount 261.4 216.3   261.4 216.3 262.5
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)       (45.1) 5.0  
Defined Benefit Plan, Amortization of Prior Service Cost (Credit) (3.2) (4.0)   (3.2) (4.0) (4.4)
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)       10.0 7.5 $ 5.3
Employer contributions       23.0 21.0  
Expected contribution 24.0     24.0    
Funded status of plan 315.1 276.2   315.1 276.2  
Liability, Defined Benefit Plan [1] 315.1 276.2   $ 315.1 $ 276.2  
Expected return on plan assets       5.83% 5.80% 6.99%
Settlement loss 0.0 0.0   $ 0.0 $ 0.0 $ 0.0
Significant Unobservable Inputs (Level 3) [Member]            
Defined Benefit Plan Disclosure [Line Items]            
Defined Benefit Plan, Plan Assets, Amount $ 0.0 $ 86.1   $ 0.0 $ 86.1 $ 98.9
Percentage of investments 0.00% 4.00%   0.00% 4.00%  
Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits            
Defined Benefit Plan Disclosure [Line Items]            
Defined Benefit Plan, Plan Assets, Amount   $ 0.0     $ 0.0  
Scenario, Forecast | Pension Plan            
Defined Benefit Plan Disclosure [Line Items]            
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)     $ 34.7      
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)     (0.8)      
Amortization of transition obligation     0.0      
Scenario, Forecast | Other Postretirement Benefits            
Defined Benefit Plan Disclosure [Line Items]            
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)     4.9      
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)     1.8      
Amortization of transition obligation     $ 0.0      
Unrecognized Pension Benefit And Other Postretirement Benefit Costs            
Defined Benefit Plan Disclosure [Line Items]            
Regulatory assets $ 739.1 798.3   $ 739.1 798.3  
Regulatory Liabilities 0.1 0.1   0.1 0.1  
International Equities | Pension Plan            
Defined Benefit Plan Disclosure [Line Items]            
Defined Benefit Plan, Plan Assets, Amount 205.0 165.5   205.0 165.5  
International Equities | Other Postretirement Benefits            
Defined Benefit Plan Disclosure [Line Items]            
Defined Benefit Plan, Plan Assets, Amount 40.7 17.5   40.7 17.5  
Commingled Funds | Short-Term Money Markets | Pension Plan            
Defined Benefit Plan Disclosure [Line Items]            
Defined Benefit Plan, Plan Assets, Amount 14.8 [2] 18.3 [3]   14.8 [2] 18.3 [3]  
Commingled Funds | Short-Term Money Markets | Other Postretirement Benefits            
Defined Benefit Plan Disclosure [Line Items]            
Defined Benefit Plan, Plan Assets, Amount 7.7 [2] 5.2 [3]   7.7 [2] 5.2 [3]  
Commingled Funds | United States Equities | Pension Plan            
Defined Benefit Plan Disclosure [Line Items]            
Defined Benefit Plan, Plan Assets, Amount 305.9 [2] 245.2 [3]   305.9 [2] 245.2 [3]  
Commingled Funds | United States Equities | Other Postretirement Benefits            
Defined Benefit Plan Disclosure [Line Items]            
Defined Benefit Plan, Plan Assets, Amount 12.1 [2] 10.4 [3]   12.1 [2] 10.4 [3]  
Commingled Funds | International Equities | Pension Plan            
Defined Benefit Plan Disclosure [Line Items]            
Defined Benefit Plan, Plan Assets, Amount 148.1 [2] $ 122.3 [3]   148.1 [2] $ 122.3 [3]  
Commingled Funds | International Equities | Other Postretirement Benefits            
Defined Benefit Plan Disclosure [Line Items]            
Defined Benefit Plan, Plan Assets, Amount [2] $ 20.1     $ 20.1    
[1] recognize our Consolidated Balance Sheets underfunded and overfunded status of our various defined benefit postretirement plans, measured as the difference between the fair value of the plan assets and the benefit obligation.
[2] This class of investments is measured at fair value using the net asset value per share and has not been classified in the fair value hierarchy.
[3] This class of investments is measured at fair value using the net asset value per share and has not been classified in the fair value hierarchy.
v3.19.3.a.u2
Pension and Other Postretirement Benefits (Schedule Of Portfolio Asset Mix) (Details)
Dec. 31, 2019
Dec. 31, 2018
Minimum | Domestic Equities | Pension Plan    
Defined Benefit Plan Disclosure [Line Items]    
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage 12.00% 12.00%
Minimum | Domestic Equities | Other Postretirement Benefits    
Defined Benefit Plan Disclosure [Line Items]    
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage 0.00% 0.00%
Minimum | International Equities | Pension Plan    
Defined Benefit Plan Disclosure [Line Items]    
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage 6.00% 6.00%
Minimum | International Equities | Other Postretirement Benefits    
Defined Benefit Plan Disclosure [Line Items]    
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage 0.00% 0.00%
Minimum | Fixed Income | Pension Plan    
Defined Benefit Plan Disclosure [Line Items]    
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage 59.00%  
Minimum | Fixed Income | Other Postretirement Benefits    
Defined Benefit Plan Disclosure [Line Items]    
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage 20.00%  
Minimum | Real Estate [Member] | Pension Plan    
Defined Benefit Plan Disclosure [Line Items]    
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage 0.00%  
Minimum | Real Estate [Member] | Other Postretirement Benefits    
Defined Benefit Plan Disclosure [Line Items]    
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage 0.00%  
Minimum | Real Estate | Pension Plan    
Defined Benefit Plan Disclosure [Line Items]    
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage   0.00%
Minimum | Real Estate | Other Postretirement Benefits    
Defined Benefit Plan Disclosure [Line Items]    
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage   0.00%
Minimum | Short-Term Investments/Other | Pension Plan    
Defined Benefit Plan Disclosure [Line Items]    
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage 0.00% 0.00%
Minimum | Short-Term Investments/Other | Other Postretirement Benefits    
Defined Benefit Plan Disclosure [Line Items]    
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage 0.00% 0.00%
Maximum | Domestic Equities | Pension Plan    
Defined Benefit Plan Disclosure [Line Items]    
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage 32.00% 32.00%
Maximum | Domestic Equities | Other Postretirement Benefits    
Defined Benefit Plan Disclosure [Line Items]    
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage 55.00% 55.00%
Maximum | International Equities | Pension Plan    
Defined Benefit Plan Disclosure [Line Items]    
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage 16.00% 16.00%
Maximum | International Equities | Other Postretirement Benefits    
Defined Benefit Plan Disclosure [Line Items]    
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage 25.00% 25.00%
Maximum | Fixed Income | Pension Plan    
Defined Benefit Plan Disclosure [Line Items]    
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage 71.00%  
Maximum | Fixed Income | Other Postretirement Benefits    
Defined Benefit Plan Disclosure [Line Items]    
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage 100.00%  
Maximum | Real Estate [Member] | Pension Plan    
Defined Benefit Plan Disclosure [Line Items]    
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage 7.00%  
Maximum | Real Estate [Member] | Other Postretirement Benefits    
Defined Benefit Plan Disclosure [Line Items]    
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage 0.00%  
Maximum | Real Estate | Pension Plan    
Defined Benefit Plan Disclosure [Line Items]    
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage   7.00%
Maximum | Real Estate | Other Postretirement Benefits    
Defined Benefit Plan Disclosure [Line Items]    
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage   0.00%
Maximum | Short-Term Investments/Other | Pension Plan    
Defined Benefit Plan Disclosure [Line Items]    
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage 15.00% 15.00%
Maximum | Short-Term Investments/Other | Other Postretirement Benefits    
Defined Benefit Plan Disclosure [Line Items]    
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage 10.00% 10.00%
v3.19.3.a.u2
Pension and Other Postretirement Benefits (Schedule of Plan Asset Mix Prior Year) (Details)
Dec. 31, 2019
Dec. 31, 2018
Pension Plan | Domestic Equities | Minimum    
Defined Benefit Plan Disclosure [Line Items]    
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage 12.00% 12.00%
Pension Plan | Domestic Equities | Maximum    
Defined Benefit Plan Disclosure [Line Items]    
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage 32.00% 32.00%
Pension Plan | International Equities | Minimum    
Defined Benefit Plan Disclosure [Line Items]    
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage 6.00% 6.00%
Pension Plan | International Equities | Maximum    
Defined Benefit Plan Disclosure [Line Items]    
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage 16.00% 16.00%
Pension Plan | Fixed Income | Minimum    
Defined Benefit Plan Disclosure [Line Items]    
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage   59.00%
Pension Plan | Fixed Income | Maximum    
Defined Benefit Plan Disclosure [Line Items]    
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage   71.00%
Pension Plan | Real Estate | Minimum    
Defined Benefit Plan Disclosure [Line Items]    
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage   0.00%
Pension Plan | Real Estate | Maximum    
Defined Benefit Plan Disclosure [Line Items]    
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage   7.00%
Pension Plan | Short-Term Investments/Other | Minimum    
Defined Benefit Plan Disclosure [Line Items]    
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage 0.00% 0.00%
Pension Plan | Short-Term Investments/Other | Maximum    
Defined Benefit Plan Disclosure [Line Items]    
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage 15.00% 15.00%
Other Postretirement Benefits | Domestic Equities | Minimum    
Defined Benefit Plan Disclosure [Line Items]    
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage 0.00% 0.00%
Other Postretirement Benefits | Domestic Equities | Maximum    
Defined Benefit Plan Disclosure [Line Items]    
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage 55.00% 55.00%
Other Postretirement Benefits | International Equities | Minimum    
Defined Benefit Plan Disclosure [Line Items]    
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage 0.00% 0.00%
Other Postretirement Benefits | International Equities | Maximum    
Defined Benefit Plan Disclosure [Line Items]    
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage 25.00% 25.00%
Other Postretirement Benefits | Fixed Income | Minimum    
Defined Benefit Plan Disclosure [Line Items]    
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage   20.00%
Other Postretirement Benefits | Fixed Income | Maximum    
Defined Benefit Plan Disclosure [Line Items]    
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage   100.00%
Other Postretirement Benefits | Real Estate | Minimum    
Defined Benefit Plan Disclosure [Line Items]    
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage   0.00%
Other Postretirement Benefits | Real Estate | Maximum    
Defined Benefit Plan Disclosure [Line Items]    
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage   0.00%
Other Postretirement Benefits | Short-Term Investments/Other | Minimum    
Defined Benefit Plan Disclosure [Line Items]    
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage 0.00% 0.00%
Other Postretirement Benefits | Short-Term Investments/Other | Maximum    
Defined Benefit Plan Disclosure [Line Items]    
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage 10.00% 10.00%
v3.19.3.a.u2
Pension and Other Postretirement Benefits (Schedule Of Pension Plan And Postretirement Plan Asset Mix) (Details) - USD ($)
$ in Millions
Dec. 31, 2019
Dec. 31, 2018
Dec. 31, 2017
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount $ 2,342.3 $ 2,084.1  
Pension Plan      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount $ 2,080.9 $ 1,867.7 $ 2,160.0
Percentage of total asset 100.00% 100.00%  
Other Postretirement Benefits      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount $ 261.4 $ 216.3 $ 262.5
Percentage of total asset 100.00% 100.00%  
Domestic Equities | Pension Plan      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount $ 446.4 $ 355.5  
Percentage of total asset 21.50% 19.00%  
Domestic Equities | Other Postretirement Benefits      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount $ 93.8 $ 78.8  
Percentage of total asset 35.90% 36.40%  
International Equities | Pension Plan      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount $ 205.0 $ 165.5  
Percentage of total asset 9.90% 8.90%  
International Equities | Other Postretirement Benefits      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount $ 40.7 $ 17.5  
Percentage of total asset 15.60% 8.10%  
Fixed Income | Pension Plan      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount $ 1,337.2 $ 1,241.9  
Percentage of total asset 64.20% 66.50%  
Fixed Income | Other Postretirement Benefits      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount $ 119.5 $ 115.1  
Percentage of total asset 45.70% 53.20%  
Real Estate | Pension Plan      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount $ 53.9 $ 52.7  
Percentage of total asset 2.60% 2.80%  
Real Estate | Other Postretirement Benefits      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount $ 0.0 $ 0.0  
Percentage of total asset 0.00% 0.00%  
Cash/Other [Member] | Pension Plan      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount $ 38.4 $ 52.1  
Percentage of total asset 1.80% 2.80%  
Cash/Other [Member] | Other Postretirement Benefits      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount $ 7.4 $ 4.9  
Percentage of total asset 2.80% 2.30%  
Commingled Funds | Short-Term Money Markets | Pension Plan      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount $ 14.8 [1] $ 18.3 [2]  
Commingled Funds | Short-Term Money Markets | Other Postretirement Benefits      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount 7.7 [1] 5.2 [2]  
Commingled Funds | International Equities | Pension Plan      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount 148.1 [1] 122.3 [2]  
Commingled Funds | International Equities | Other Postretirement Benefits      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount [1] 20.1    
Commingled Funds | Fixed Income | Pension Plan      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount 351.8 [1] 365.7 [2]  
Commingled Funds | United States Equities | Pension Plan      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount 305.9 [1] 245.2 [2]  
Commingled Funds | United States Equities | Other Postretirement Benefits      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount $ 12.1 [1] $ 10.4 [2]  
[1] This class of investments is measured at fair value using the net asset value per share and has not been classified in the fair value hierarchy.
[2] This class of investments is measured at fair value using the net asset value per share and has not been classified in the fair value hierarchy.
v3.19.3.a.u2
Pension and Other Postretirement Benefits (Schedule Of Fair Value Of Pension Plan Assets) (Details) - USD ($)
$ in Millions
Dec. 31, 2019
Dec. 31, 2018
Dec. 31, 2017
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount $ 2,342.3 $ 2,084.1  
Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount 436.3 538.6  
Significant Other Observable Inputs (Level 2) [Member]      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount 968.6 692.3  
Significant Unobservable Inputs (Level 3) [Member]      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount 0.0 86.1 $ 98.9
Due To Brokers Net [Member]      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount (2.8) [1] (1.1) [2]  
Due To Brokers Net [Member] | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount [1] 0.0    
Due To Brokers Net [Member] | Significant Other Observable Inputs (Level 2) [Member]      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount [1] (2.8)    
Due To Brokers Net [Member] | Significant Unobservable Inputs (Level 3) [Member]      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount [1] 0.0    
Accrued Investment Income Dividends [Member]      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount   8.6  
Receivables/Payables [Member]      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount 10.7    
Receivables/Payables [Member] | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount 10.7    
Receivables/Payables [Member] | Significant Other Observable Inputs (Level 2) [Member]      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount 0.0    
Receivables/Payables [Member] | Significant Unobservable Inputs (Level 3) [Member]      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount 0.0    
Private Equity Limited Partnerships [Member] | U.S. Multi-Strategy [Member] | Significant Unobservable Inputs (Level 3) [Member]      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount 0.0 18.5 26.7
Private Equity Limited Partnerships [Member] | International Multi-Strategy [Member] | Significant Unobservable Inputs (Level 3) [Member]      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount 0.0 12.5 19.1
Private Equity Limited Partnerships [Member] | Distressed Opportunities [Member] | Significant Unobservable Inputs (Level 3) [Member]      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount 0.0 2.4 3.2
Pension Plan      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Accumulated Benefit Obligation 2,111.5 1,965.6  
Defined Benefit Plan, Plan Assets, Amount 2,080.9 1,867.7 2,160.0
Defined Benefit Plan Fair Value Of Plan Assets Before Pending Items 2,073.0 1,860.3  
Defined Benefit Plan, Benefit Obligation 2,130.5 1,981.3 [3] 2,192.6 [3]
Defined Benefit Plan, Funded (Unfunded) Status of Plan (49.6) (113.6)  
Pension Plan | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan Fair Value Of Plan Assets Before Pending Items 204.1 329.3  
Pension Plan | Significant Other Observable Inputs (Level 2) [Member]      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan Fair Value Of Plan Assets Before Pending Items 971.4 693.4  
Pension Plan | Significant Unobservable Inputs (Level 3) [Member]      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan Fair Value Of Plan Assets Before Pending Items 0.0 86.1  
Pension Plan | Cash [Member]      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount 6.7 9.2  
Pension Plan | Cash [Member] | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount 6.7 8.8  
Pension Plan | Cash [Member] | Significant Other Observable Inputs (Level 2) [Member]      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount 0.0 0.4  
Pension Plan | Cash [Member] | Significant Unobservable Inputs (Level 3) [Member]      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount 0.0 0.0  
Pension Plan | International Equities      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount 205.0 165.5  
Pension Plan | Fixed Income      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount 1,337.2 1,241.9  
Pension Plan | Equity Securities [Member] | United States Equities      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount   0.2  
Pension Plan | Equity Securities [Member] | United States Equities | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount   0.2  
Pension Plan | Equity Securities [Member] | United States Equities | Significant Other Observable Inputs (Level 2) [Member]      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount   0.0  
Pension Plan | Equity Securities [Member] | United States Equities | Significant Unobservable Inputs (Level 3) [Member]      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount   0.0  
Pension Plan | Fixed Income Securities [Member] | Government      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount 319.6 250.2  
Pension Plan | Fixed Income Securities [Member] | Government | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount 0.0 0.0  
Pension Plan | Fixed Income Securities [Member] | Government | Significant Other Observable Inputs (Level 2) [Member]      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount 319.6 250.2  
Pension Plan | Fixed Income Securities [Member] | Government | Significant Unobservable Inputs (Level 3) [Member]      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount 0.0 0.0  
Pension Plan | Fixed Income Securities [Member] | Corporate [Member]      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount 651.8 442.8  
Pension Plan | Fixed Income Securities [Member] | Corporate [Member] | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount 0.0 0.0  
Pension Plan | Fixed Income Securities [Member] | Corporate [Member] | Significant Other Observable Inputs (Level 2) [Member]      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount 651.8 442.8  
Pension Plan | Fixed Income Securities [Member] | Corporate [Member] | Significant Unobservable Inputs (Level 3) [Member]      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount 0.0 0.0  
Pension Plan | Commingled Funds | International Equities      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount 148.1 [4] 122.3 [5]  
Pension Plan | Commingled Funds | Fixed Income      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount 351.8 [4] 365.7 [5]  
Pension Plan | Commingled Funds | United States Equities      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount 305.9 [4] 245.2 [5]  
Pension Plan | Commingled Funds | Short-Term Money Markets      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount 14.8 [4] 18.3 [5]  
Pension Plan | Private Equity Limited Partnerships [Member] | U.S. Multi-Strategy [Member]      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount 14.0 [6] 18.5 [7]  
Pension Plan | Private Equity Limited Partnerships [Member] | U.S. Multi-Strategy [Member] | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount 0.0 [6] 0.0 [7]  
Pension Plan | Private Equity Limited Partnerships [Member] | U.S. Multi-Strategy [Member] | Significant Other Observable Inputs (Level 2) [Member]      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount 0.0 [6] 0.0 [7]  
Pension Plan | Private Equity Limited Partnerships [Member] | U.S. Multi-Strategy [Member] | Significant Unobservable Inputs (Level 3) [Member]      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount 0.0 [6] 18.5 [7]  
Pension Plan | Private Equity Limited Partnerships [Member] | International Multi-Strategy [Member]      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount 8.5 [8] 12.5 [9]  
Pension Plan | Private Equity Limited Partnerships [Member] | International Multi-Strategy [Member] | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount 0.0 [8] 0.0 [9]  
Pension Plan | Private Equity Limited Partnerships [Member] | International Multi-Strategy [Member] | Significant Other Observable Inputs (Level 2) [Member]      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount 0.0 [8] 0.0 [9]  
Pension Plan | Private Equity Limited Partnerships [Member] | International Multi-Strategy [Member] | Significant Unobservable Inputs (Level 3) [Member]      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount 0.0 [8] 12.5 [9]  
Pension Plan | Private Equity Limited Partnerships [Member] | Distressed Opportunities [Member]      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount 0.5 2.4  
Pension Plan | Private Equity Limited Partnerships [Member] | Distressed Opportunities [Member] | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount 0.0 0.0  
Pension Plan | Private Equity Limited Partnerships [Member] | Distressed Opportunities [Member] | Significant Other Observable Inputs (Level 2) [Member]      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount 0.0 0.0  
Pension Plan | Private Equity Limited Partnerships [Member] | Distressed Opportunities [Member] | Significant Unobservable Inputs (Level 3) [Member]      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount 0.0 2.4  
Pension Plan | Real Estate [Member]      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount 53.9 52.7  
Pension Plan | Real Estate [Member] | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount 0.0 0.0  
Pension Plan | Real Estate [Member] | Significant Other Observable Inputs (Level 2) [Member]      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount 0.0 0.0  
Pension Plan | Real Estate [Member] | Significant Unobservable Inputs (Level 3) [Member]      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount 0.0 52.7  
Pension Plan | Mutual Funds [Member] | International Equities      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount 56.9 43.2  
Pension Plan | Mutual Funds [Member] | International Equities | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount 56.9 43.2  
Pension Plan | Mutual Funds [Member] | U.S. Multi-Strategy [Member]      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount 140.5 110.3  
Pension Plan | Mutual Funds [Member] | U.S. Multi-Strategy [Member] | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount 140.5 110.3  
Pension Plan | Mutual Funds [Member] | Fixed Income      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount   166.8  
Pension Plan | Mutual Funds [Member] | Fixed Income | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount   166.8  
Other Postretirement Benefits      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount 261.4 216.3 262.5
Defined Benefit Plan Fair Value Of Plan Assets Before Pending Items 261.4 216.3  
Defined Benefit Plan, Benefit Obligation 576.5 492.5 [3] $ 556.3 [3]
Defined Benefit Plan, Funded (Unfunded) Status of Plan (315.1) (276.2)  
Other Postretirement Benefits | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount   200.7  
Defined Benefit Plan Fair Value Of Plan Assets Before Pending Items 221.5    
Other Postretirement Benefits | Significant Other Observable Inputs (Level 2) [Member]      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount   0.0  
Defined Benefit Plan Fair Value Of Plan Assets Before Pending Items 0.0    
Other Postretirement Benefits | Significant Unobservable Inputs (Level 3) [Member]      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount   0.0  
Defined Benefit Plan Fair Value Of Plan Assets Before Pending Items 0.0    
Other Postretirement Benefits | International Equities      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount 40.7 17.5  
Other Postretirement Benefits | Fixed Income      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount 119.5 115.1  
Other Postretirement Benefits | Commingled Funds | International Equities      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount [4] 20.1    
Other Postretirement Benefits | Commingled Funds | United States Equities      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount 12.1 [4] 10.4 [5]  
Other Postretirement Benefits | Commingled Funds | Short-Term Money Markets      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount 7.7 [4] 5.2 [5]  
Other Postretirement Benefits | Mutual Funds [Member] | International Equities      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount 20.6 17.5  
Other Postretirement Benefits | Mutual Funds [Member] | International Equities | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount 20.6 17.5  
Other Postretirement Benefits | Mutual Funds [Member] | International Equities | Significant Other Observable Inputs (Level 2) [Member]      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount 0.0 0.0  
Other Postretirement Benefits | Mutual Funds [Member] | International Equities | Significant Unobservable Inputs (Level 3) [Member]      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount 0.0 0.0  
Other Postretirement Benefits | Mutual Funds [Member] | Fixed Income      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount 119.2 114.8  
Other Postretirement Benefits | Mutual Funds [Member] | Fixed Income | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount 119.2 114.8  
Other Postretirement Benefits | Mutual Funds [Member] | Fixed Income | Significant Other Observable Inputs (Level 2) [Member]      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount 0.0 0.0  
Other Postretirement Benefits | Mutual Funds [Member] | Fixed Income | Significant Unobservable Inputs (Level 3) [Member]      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount 0.0 0.0  
Other Postretirement Benefits | Mutual Funds [Member] | United States Equities      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount 81.7 68.4  
Other Postretirement Benefits | Mutual Funds [Member] | United States Equities | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount 81.7 68.4  
Other Postretirement Benefits | Mutual Funds [Member] | United States Equities | Significant Other Observable Inputs (Level 2) [Member]      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount 0.0 0.0  
Other Postretirement Benefits | Mutual Funds [Member] | United States Equities | Significant Unobservable Inputs (Level 3) [Member]      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount 0.0 0.0  
Underfunded Plan [Member] | Pension Plan      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Accumulated Benefit Obligation 637.6 0.0  
Defined Benefit Plan, Plan Assets, Amount 645.8 0.0  
Defined Benefit Plan, Benefit Obligation 637.6 0.0  
Defined Benefit Plan, Funded (Unfunded) Status of Plan 8.2 0.0  
Underfunded Plan [Member] | Pension Plan      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Accumulated Benefit Obligation 1,473.9 1,965.6  
Defined Benefit Plan, Plan Assets, Amount 1,435.1 1,867.7  
Defined Benefit Plan, Benefit Obligation 1,492.9 1,981.3  
Defined Benefit Plan, Funded (Unfunded) Status of Plan $ (57.8) $ (113.6)  
[1] This class represents pending trades with brokers.
[2] This class represents pending trades with brokers.
[3] The change in benefit obligation for Pension Benefits represents the change in Projected Benefit Obligation while the change in benefit obligation for Other Postretirement Benefits represents the change in accumulated postretirement benefit obligation.
[4] This class of investments is measured at fair value using the net asset value per share and has not been classified in the fair value hierarchy.
[5] This class of investments is measured at fair value using the net asset value per share and has not been classified in the fair value hierarchy.
[6] This class includes limited partnerships/fund of funds that invest in a diverse portfolio of private equity strategies, including buy-outs, venture capital, growth capital, special situations and secondary markets, primarily inside the United States.
[7] This class includes limited partnerships/fund of funds that invest in a diverse portfolio of private equity strategies, including buy-outs, venture capital, growth capital, special situations and secondary markets, primarily inside the United States.
[8] This class includes limited partnerships/fund of funds that invest in diverse portfolio of private equity strategies, including buy-outs, venture capital, growth capital, special situations and secondary markets, primarily outside the United States.
[9]  This class includes limited partnerships/fund of funds that invest in a diverse portfolio of private equity strategies, including buy-outs, venture capital, growth capital, special situations and secondary markets, primarily outside the United States.
v3.19.3.a.u2
Pension and Other Postretirement Benefits (Schedule Of Changes In The Fair Value Of The Plan Level Three Assets) (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2019
Dec. 31, 2018
Defined Benefit Plan Disclosure [Line Items]    
Fair value of plan assets at beginning of year $ 2,084.1  
Fair value of plan assets at end of year 2,342.3 $ 2,084.1
Significant Unobservable Inputs (Level 3) [Member]    
Defined Benefit Plan Disclosure [Line Items]    
Fair value of plan assets at beginning of year 86.1 98.9
Total gains or losses (unrealized / realized)   2.7
Purchases   2.5
(Sales)   (18.0)
Fair value of plan assets at end of year 0.0 86.1
Defined Benefit Plan, Plan Assets Level 3 Reconciliation, Increase (Decrease) for Assets Transferred into (out of) Level 3 [1] (86.1)  
Real Estate [Member] | Significant Unobservable Inputs (Level 3) [Member]    
Defined Benefit Plan Disclosure [Line Items]    
Fair value of plan assets at beginning of year 52.7 49.9
Total gains or losses (unrealized / realized)   1.7
Purchases   1.8
(Sales)   (0.7)
Fair value of plan assets at end of year 0.0 52.7
Defined Benefit Plan, Plan Assets Level 3 Reconciliation, Increase (Decrease) for Assets Transferred into (out of) Level 3 [1] (52.7)  
Private Equity Limited Partnerships [Member] | U.S. Multi-Strategy [Member] | Significant Unobservable Inputs (Level 3) [Member]    
Defined Benefit Plan Disclosure [Line Items]    
Fair value of plan assets at beginning of year 18.5 26.7
Total gains or losses (unrealized / realized)   2.4
Purchases   0.7
(Sales)   (11.3)
Fair value of plan assets at end of year 0.0 18.5
Defined Benefit Plan, Plan Assets Level 3 Reconciliation, Increase (Decrease) for Assets Transferred into (out of) Level 3 [1] (18.5)  
Private Equity Limited Partnerships [Member] | International Multi-Strategy [Member] | Significant Unobservable Inputs (Level 3) [Member]    
Defined Benefit Plan Disclosure [Line Items]    
Fair value of plan assets at beginning of year 12.5 19.1
Total gains or losses (unrealized / realized)   (0.6)
Purchases   0.0
(Sales)   (6.0)
Fair value of plan assets at end of year 0.0 12.5
Defined Benefit Plan, Plan Assets Level 3 Reconciliation, Increase (Decrease) for Assets Transferred into (out of) Level 3 [1] (12.5)  
Private Equity Limited Partnerships [Member] | Distressed Opportunities [Member] | Significant Unobservable Inputs (Level 3) [Member]    
Defined Benefit Plan Disclosure [Line Items]    
Fair value of plan assets at beginning of year 2.4 3.2
Total gains or losses (unrealized / realized)   (0.8)
Purchases   0.0
(Sales)   0.0
Fair value of plan assets at end of year 0.0 $ 2.4
Defined Benefit Plan, Plan Assets Level 3 Reconciliation, Increase (Decrease) for Assets Transferred into (out of) Level 3 [1] $ (2.4)  
[1]
(1) Level 3 assets from the prior year were reclassified in the current year presentation and included within the fair value hierarchy table as of December 31, 2019 as “Not Classified" investments for which fair value is measured using net asset value per share, consistent with the definitions described above.
v3.19.3.a.u2
Pension and Other Postretirement Benefits (Schedule of Net Asset Value Per Share) (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2019
Dec. 31, 2018
Defined Benefit Plan Disclosure [Line Items]    
Net Asset Value Excluded From Fair Value By Input $ 860.5 $ 767.1
Commingled Funds | Short-Term Money Markets    
Defined Benefit Plan Disclosure [Line Items]    
Net Asset Value Excluded From Fair Value By Input $ 22.5 $ 23.5
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Investment Redemption, Frequency Daily Daily
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Investment Redemption, Notice Period 1 day 1 day
Commingled Funds | United States Equities    
Defined Benefit Plan Disclosure [Line Items]    
Net Asset Value Excluded From Fair Value By Input $ 318.0 $ 255.6
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Investment Redemption, Frequency Monthly Monthly
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Investment Redemption, Notice Period 3 days 3 days
Commingled Funds | International Equities    
Defined Benefit Plan Disclosure [Line Items]    
Net Asset Value Excluded From Fair Value By Input $ 168.2 $ 122.3
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Investment Redemption, Frequency Monthly Monthly
Commingled Funds | Fixed Income Funds    
Defined Benefit Plan Disclosure [Line Items]    
Net Asset Value Excluded From Fair Value By Input $ 351.8 $ 365.7
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Investment Redemption, Frequency Daily Monthly
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Investment Redemption, Notice Period 3 days 3 days
Minimum | Commingled Funds | International Equities    
Defined Benefit Plan Disclosure [Line Items]    
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Investment Redemption, Notice Period 10 days 14 days
Maximum | Commingled Funds | International Equities    
Defined Benefit Plan Disclosure [Line Items]    
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Investment Redemption, Notice Period 30 days 30 days
v3.19.3.a.u2
Pension and Other Postretirement Benefits (Schedule Of Reconciliation Of The Plans Funded Status And Amounts Reflected) (Details) - USD ($)
$ in Millions
 3 Months Ended 12 Months Ended
Dec. 31, 2019
Dec. 31, 2018
Dec. 31, 2019
Dec. 31, 2018
Dec. 31, 2017
Defined Benefit Plan Disclosure [Line Items]          
Fair value of plan assets at beginning of year     $ 2,084.1    
Fair value of plan assets at end of year $ 2,342.3 $ 2,084.1 2,342.3 $ 2,084.1  
Noncurrent liabilities (314.3) (275.4) (314.3) (275.4)  
Pension Plan          
Defined Benefit Plan Disclosure [Line Items]          
Benefit obligation at beginning of year [1]     1,981.3 2,192.6  
Service cost 29.2 31.3 29.2 31.3 $ 30.0
Interest cost 72.3 67.1 72.3 67.1 68.3
Plan participants' contributions     0.0 0.0  
Plan amendments     0.0 0.2  
Actuarial loss (gain)     204.3 (103.9)  
Settlement Loss     0.0 0.8  
Defined Benefit Plan, Benefit Obligation, Benefits Paid     156.6 206.8  
Benefits paid     (156.5) (206.8)  
Estimated benefits paid by incurred subsidy     0.0 0.0  
Projected benefit obligation at end of year 2,130.5 1,981.3 [1] 2,130.5 1,981.3 [1] 2,192.6 [1]
Fair value of plan assets at beginning of year     1,867.7 2,160.0  
Actual return on plan assets     366.8 (88.4)  
Employer contributions     2.9 2.9  
Defined Benefit Plan, Plan Assets, Contributions by Plan Participant     0.0 0.0  
Fair value of plan assets at end of year 2,080.9 1,867.7 2,080.9 1,867.7 2,160.0
Defined Benefit Plan, Funded (Unfunded) Status of Plan (49.6) (113.6) (49.6) (113.6)  
Noncurrent assets 8.2 0.0 8.2 0.0  
Current liabilities (3.0) (3.0) (3.0) (3.0)  
Noncurrent liabilities (54.8) (110.6) (54.8) (110.6)  
Net amount recognized at end of year [2] (49.6) (113.6) (49.6) (113.6)  
Unrecognized prior service cost [3] 3.0 3.2 3.0 3.2  
Unrecognized actuarial loss [3] 652.8 761.2 652.8 761.2  
Defined Benefit Plan Amounts Recognized In Other Comprehensive Income Or Regulatory Asset Or Liability [3] 655.8 764.4 655.8 764.4  
Other Postretirement Benefits          
Defined Benefit Plan Disclosure [Line Items]          
Benefit obligation at beginning of year [1]     492.5 556.3  
Service cost 5.1 5.0 5.1 5.0 4.8
Interest cost 19.2 17.6 19.2 17.6 17.8
Plan participants' contributions     4.8 5.7  
Plan amendments     5.1 0.1  
Actuarial loss (gain)     88.8 (51.7)  
Settlement Loss     0.0 0.0  
Defined Benefit Plan, Benefit Obligation, Benefits Paid     39.5 41.1  
Benefits paid     (39.5) (41.1)  
Estimated benefits paid by incurred subsidy     0.5 0.6  
Projected benefit obligation at end of year 576.5 492.5 [1] 576.5 492.5 [1] 556.3 [1]
Fair value of plan assets at beginning of year     216.3 262.5  
Actual return on plan assets     56.9 (31.8)  
Employer contributions     23.0 21.0  
Defined Benefit Plan, Plan Assets, Contributions by Plan Participant     4.7 5.7  
Fair value of plan assets at end of year 261.4 216.3 261.4 216.3 $ 262.5
Defined Benefit Plan, Funded (Unfunded) Status of Plan (315.1) (276.2) (315.1) (276.2)  
Noncurrent assets 0.0 0.0 0.0 0.0  
Current liabilities (0.8) (0.8) (0.8) (0.8)  
Net amount recognized at end of year [2] (315.1) (276.2) (315.1) (276.2)  
Unrecognized prior service cost [3] (10.7) (19.0) (10.7) (19.0)  
Unrecognized actuarial loss [3] 118.4 75.3 118.4 75.3  
Defined Benefit Plan Amounts Recognized In Other Comprehensive Income Or Regulatory Asset Or Liability [3] $ 107.7 $ 56.3 $ 107.7 $ 56.3  
[1] The change in benefit obligation for Pension Benefits represents the change in Projected Benefit Obligation while the change in benefit obligation for Other Postretirement Benefits represents the change in accumulated postretirement benefit obligation.
[2] recognize our Consolidated Balance Sheets underfunded and overfunded status of our various defined benefit postretirement plans, measured as the difference between the fair value of the plan assets and the benefit obligation.
[3] determined that for certain rate-regulated subsidiaries the future recovery of pension and other postretirement benefits costs is probable. These rate-regulated subsidiaries recorded regulatory assets and liabilities of $739.1 million and $0.1 million, respectively, as of December 31, 2019, and $798.3 million and $0.1 million, respectively, as of December 31, 2018 that would otherwise have been recorded to accumulated other comprehensive loss.
v3.19.3.a.u2
Pension and Other Postretirement Benefits (Schedule of Benefit Obligations in Excess of Fair Value) (Details) - USD ($)
$ in Millions
Dec. 31, 2019
Dec. 31, 2018
Dec. 31, 2017
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]      
Defined Benefit Plan, Plan Assets, Amount $ 2,342.3 $ 2,084.1  
Pension Plan      
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]      
Defined Benefit Plan, Accumulated Benefit Obligation 2,111.5 1,965.6  
Defined Benefit Plan, Benefit Obligation 2,130.5 1,981.3 [1] $ 2,192.6 [1]
Defined Benefit Plan, Plan Assets, Amount 2,080.9 1,867.7 $ 2,160.0
Defined Benefit Plan, Funded (Unfunded) Status of Plan (49.6) (113.6)  
Underfunded Plan [Member] | Pension Plan      
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]      
Defined Benefit Plan, Accumulated Benefit Obligation 1,473.9 1,965.6  
Defined Benefit Plan, Benefit Obligation 1,492.9 1,981.3  
Defined Benefit Plan, Plan Assets, Amount 1,435.1 1,867.7  
Defined Benefit Plan, Funded (Unfunded) Status of Plan $ (57.8) $ (113.6)  
[1] The change in benefit obligation for Pension Benefits represents the change in Projected Benefit Obligation while the change in benefit obligation for Other Postretirement Benefits represents the change in accumulated postretirement benefit obligation.
v3.19.3.a.u2
Pension and Other Postretirement Benefits (Schedule Of Significant Actuarial Assumptions In Determining Funded Status Plan) (Details)
 12 Months Ended
Dec. 31, 2019
Dec. 31, 2018
Pension Plan    
Defined Benefit Plan Disclosure [Line Items]    
Discount Rate 3.12% 4.26%
Rate of Compensation Increases 4.00% 4.00%
Trend for Next Year 0.00% 0.00%
Ultimate Trend 0.00% 0.00%
Other Postretirement Benefits    
Defined Benefit Plan Disclosure [Line Items]    
Discount Rate 3.21% 4.31%
Rate of Compensation Increases 0.00% 0.00%
Trend for Next Year 6.68% 8.48%
Ultimate Trend 4.50% 4.50%
Year Ultimate Trend Reached 2028 2026
v3.19.3.a.u2
Pension and Other Postretirement Benefits (Schedule Of One-Percentage-Point Change In Assumed Health Care Cost Trend Rates) (Details)
$ in Millions
 12 Months Ended
Dec. 31, 2019
USD ($)
Defined Benefit Plan Disclosure [Line Items]  
Effect on service and interest components of net periodic cost, 1% point increase $ 1.2
Effect on service and interest components of net periodic cost, 1% point decrease (1.1)
Effect on accumulated postretirement benefit obligation, 1% point increase 30.1
Effect on accumulated postretirement benefit obligation, 1% point decrease $ (26.3)
v3.19.3.a.u2
Pension and Other Postretirement Benefits (Schedule Of Expected Payments To Participants In Pension Plan) (Details)
$ in Millions
Dec. 31, 2019
USD ($)
Pension Plan  
Defined Benefit Plan Disclosure [Line Items]  
2017 $ 178.8
2018 177.8
2019 175.8
2020 168.5
2021 164.4
2022-2026 723.7
Other Postretirement Benefits  
Defined Benefit Plan Disclosure [Line Items]  
2017 38.1
2018 38.6
2019 38.4
2020 38.1
2021 37.9
2022-2026 181.0
Postretirement Health Coverage [Member]  
Defined Benefit Plan Disclosure [Line Items]  
2017 0.5
2018 0.4
2019 0.4
2020 0.4
2021 0.4
2022-2026 $ 1.5
v3.19.3.a.u2
Pension and Other Postretirement Benefits (Components Of The Plans' Net Periodic Benefits Cost) (Details) - USD ($)
$ in Millions
 3 Months Ended 12 Months Ended
Dec. 31, 2019
Dec. 31, 2018
Dec. 31, 2019
Dec. 31, 2018
Dec. 31, 2017
Pension Plan          
Defined Benefit Plan Disclosure [Line Items]          
Service Cost $ 29.2 $ 31.3 $ 29.2 $ 31.3 $ 30.0
Interest cost 72.3 67.1 72.3 67.1 68.3
Expected return on assets (108.8) (142.3)     (123.1)
Defined Benefit Plan, Amortization of Prior Service Cost (Credit) 0.2 (0.4) 0.2 (0.4) (0.7)
Recognized actuarial loss 45.2 40.6 45.2 40.6 52.9
Settlement loss 9.5 18.5 9.5 18.5 13.7
Total Net Periodic Benefits Cost     47.6 14.8 41.1
Other Postretirement Benefits          
Defined Benefit Plan Disclosure [Line Items]          
Service Cost 5.1 5.0 5.1 5.0 4.8
Interest cost 19.2 17.6 19.2 17.6 17.8
Expected return on assets (13.1) (14.9)     (15.9)
Defined Benefit Plan, Amortization of Prior Service Cost (Credit) (3.2) (4.0) (3.2) (4.0) (4.4)
Recognized actuarial loss 2.0 3.8 2.0 3.8 3.0
Settlement loss $ 0.0 $ 0.0 0.0 0.0 0.0
Total Net Periodic Benefits Cost     $ 10.0 $ 7.5 $ 5.3
v3.19.3.a.u2
Pension and Other Postretirement Benefits (Schedule Of Key Assumptions That Were Used To Calculate The Net Periodic Benefits Cost) (Details)
 12 Months Ended
Dec. 31, 2019
Dec. 31, 2018
Dec. 31, 2017
Defined Benefit Plan Disclosure [Line Items]      
Expected Long-Term Rate of Return on Plan Assets 6.10%    
Pension Plan      
Defined Benefit Plan Disclosure [Line Items]      
Discount Rate 4.48% [1] 3.79% 4.40% [1]
Defined Benefit Plan Assumptions Used In Calculating Net Periodic Cost Discount Rate for Interest Cost 3.84% [1] 3.15% 3.31% [1]
Expected Long-Term Rate of Return on Plan Assets 6.10% 7.00% 7.25%
Rate of Compensation Increases 4.00% 4.00% 4.00%
Other Postretirement Benefits      
Defined Benefit Plan Disclosure [Line Items]      
Discount Rate [1] 4.59% 3.89% 4.58%
Defined Benefit Plan Assumptions Used In Calculating Net Periodic Cost Discount Rate for Interest Cost [1] 3.94% 3.27% 3.48%
Expected Long-Term Rate of Return on Plan Assets 5.83% 5.80% 6.99%
Rate of Compensation Increases 0.00% 0.00% 0.00%
[1] In January 2017, we changed the method used to estimate the service and interest components of net periodic benefit cost for pension and other postretirement benefits. This change, compared to the previous method, resulted in a decrease in the actuarially-determined service and interest cost components. Historically, we estimated service and interest cost utilizing a single weighted-average discount rate derived from the yield curve used to measure the benefit obligation at the beginning of the period. For fiscal 2017 and beyond, we now utilize a full yield curve approach to estimate these components by applying the specific spot rates along the yield curve used in the determination of the benefit obligation to the relevant projected cash flows.
v3.19.3.a.u2
Pension and Other Postretirement Benefits (Schedule Of Changes In Plan Assets And Projected Benefit Obligations Recognized In Other Comprehensive Income) (Details) - USD ($)
$ in Millions
 3 Months Ended 12 Months Ended
Dec. 31, 2019
Dec. 31, 2018
Dec. 31, 2019
Dec. 31, 2018
Dec. 31, 2017
Pension Plan          
Net prior service cost/(credit)     $ 0.0 $ 0.2  
Net actuarial (gain)/loss     (53.8) 127.5  
Settlements $ (9.5) $ (18.5) (9.5) (18.5) $ (13.7)
Defined Benefit Plan, Amortization of Prior Service Cost (Credit) (0.2) 0.4 (0.2) 0.4 0.7
Less: amortization of net actuarial (gain) loss (45.2) (40.6) (45.2) (40.6) (52.9)
Total Recognized in Other Comprehensive Income or Regulatory Asset or Liability     (108.7) 69.0  
Amount Recognized in Net Periodic Benefits Cost and Other Comprehensive Income or Regulatory Asset or Liability (61.1) 83.8 (61.1) 83.8  
Other Postretirement Benefits          
Net prior service cost/(credit)     5.1 0.1  
Net actuarial (gain)/loss     45.1 (5.0)  
Settlements 0.0 0.0 0.0 0.0 0.0
Defined Benefit Plan, Amortization of Prior Service Cost (Credit) 3.2 4.0 3.2 4.0 4.4
Less: amortization of net actuarial (gain) loss (2.0) (3.8) (2.0) (3.8) $ (3.0)
Total Recognized in Other Comprehensive Income or Regulatory Asset or Liability     51.4 (4.7)  
Amount Recognized in Net Periodic Benefits Cost and Other Comprehensive Income or Regulatory Asset or Liability $ 61.4 $ 2.8 $ 61.4 $ 2.8  
v3.19.3.a.u2
Equity (Narrative) (Details)
$ / shares in Units, $ in Millions
 1 Months Ended 3 Months Ended 12 Months Ended
Feb. 20, 2020
$ / shares
Dec. 11, 2019
USD ($)
$ / shares
Nov. 21, 2019
USD ($)
$ / shares
Aug. 01, 2019
Dec. 10, 2018
$ / shares
shares
Nov. 06, 2018
USD ($)
$ / shares
Nov. 01, 2018
USD ($)
Jun. 11, 2018
USD ($)
May 04, 2018
USD ($)
$ / shares
shares
May 03, 2017
USD ($)
Dec. 31, 2018
USD ($)
$ / shares
shares
Dec. 31, 2019
USD ($)
$ / shares
shares
Dec. 31, 2019
USD ($)
$ / shares
shares
Dec. 31, 2018
USD ($)
$ / shares
shares
Dec. 31, 2017
USD ($)
$ / shares
shares
Jun. 15, 2023
$ / shares
Dec. 05, 2018
shares
Dec. 31, 2016
shares
Forward Contract Indexed to Issuer's Equity [Line Items]                                    
Common stock, shares authorized | shares                     400,000,000 600,000,000 600,000,000 400,000,000        
Preferred Stock, Shares Authorized | shares                     20,000,000 20,000,000 20,000,000 20,000,000        
Common Stock, Shares, Outstanding | shares                     372,363,656 382,135,680 382,135,680 372,363,656        
Preferred Stock, Shares Outstanding | shares                     420,000 440,000 440,000 420,000        
Common Stock, Dividends, Per Share, Declared                         $ 0.80 $ 0.78 $ 0.70      
Shares, Issued | shares                     372,363,000 382,136,000 382,136,000 372,363,000 337,016,000     323,160,000
Common stock, par value                     $ 0.01 $ 0.01 $ 0.01 $ 0.01        
Proceeds from Issuance of Preferred Stock and Preference Stock | $                         $ 0.0 $ 880.0 $ 0.0      
Preferred Stock, Par or Stated Value Per Share                     $ 0.01 $ 0.01 $ 0.01 $ 0.01        
Dividends Payable, Date to be Paid                         Feb. 20, 2020          
Dividends Payable, Date of Record                         Feb. 11, 2020          
Series A Preferred Stock                                    
Forward Contract Indexed to Issuer's Equity [Line Items]                                    
Preferred Stock, Shares Outstanding | shares                       400,000 400,000          
Preferred Stock, Shares Issued | shares                       400,000 400,000          
Preferred Stock, Dividend Rate, Percentage               5.65%                    
Preferred Stock, Liquidation Preference Per Share                       $ 1,000 $ 1,000          
Preferred Stock, Dividend Rate, Initial Margin               2.843%                    
Preferred Stock, Dividend Rate, Initial Margin Plus 1.000%               1.00%                    
Preferred Stock, Amount of Preferred Dividends in Arrears | $                         $ 1.0          
Preferred Stock, Per Share Amounts of Preferred Dividends in Arrears                         $ 2.51          
Preferred Stock, Liquidation Preference, Value | $                       $ 400.0 $ 400.0          
Series B Preferred Stock                                    
Forward Contract Indexed to Issuer's Equity [Line Items]                                    
Preferred Stock, Shares Outstanding | shares                       20,000 20,000          
Preferred Stock, Dividend Rate, Percentage                     6.50%              
Preferred Stock, Liquidation Preference Per Share                       $ 25,000.00 $ 25,000.00          
Preferred Stock, Dividend Rate, Initial Margin                     3.632%              
Preferred Stock, Dividend Rate, Initial Margin Plus 1.000%                     1.00%              
Preferred Stock, Amount of Preferred Dividends in Arrears | $                         $ 1.4 $ 2.4        
Preferred Stock, Per Share Amounts of Preferred Dividends in Arrears                         $ 72.23 $ 121.88        
Preferred Stock Depositary Shares Issued | shares                                 20,000,000  
Preferred Stock, Liquidation Preference, Value | $                       $ 500.0 $ 500.0          
Depositary Stock Liquidation Preference                       $ 25 $ 25          
Series B-1 Preferred Stock                                    
Forward Contract Indexed to Issuer's Equity [Line Items]                                    
Preferred Stock, Shares Issued | shares                       20,000 20,000          
Gross Proceeds | Series A Preferred Stock                                    
Forward Contract Indexed to Issuer's Equity [Line Items]                                    
Proceeds from Issuance of Preferred Stock and Preference Stock | $               $ 400.0                    
Gross Proceeds | Series B Preferred Stock                                    
Forward Contract Indexed to Issuer's Equity [Line Items]                                    
Proceeds from Issuance of Preferred Stock and Preference Stock | $                     $ 500.0              
Common Stock                                    
Forward Contract Indexed to Issuer's Equity [Line Items]                                    
Shares, Issued | shares                 24,964,163   376,326,000 386,099,000 386,099,000 376,326,000 340,813,000     326,664,000
Common stock, par value                 $ 0.01                  
Sale of Stock, Price Per Share                 $ 24.28                  
Common Stock | Gross Proceeds                                    
Forward Contract Indexed to Issuer's Equity [Line Items]                                    
Proceeds from Issuance of Private Placement | $                 $ 606.0                  
Common Stock | Net Proceeds                                    
Forward Contract Indexed to Issuer's Equity [Line Items]                                    
Proceeds from Issuance of Private Placement | $                 $ 599.6                  
At The Market Program                                    
Forward Contract Indexed to Issuer's Equity [Line Items]                                    
Number Of Equity Distribution Agreements       4     5     4                
Common Stock Aggregate Sale Price | $             $ 500.0     $ 500.0   $ 434.4 $ 434.4          
Derivative, Forward Price         $ 26.55                          
Forward Contract Indexed to Issuer's Equity, Shares | shares         4,708,098                          
ATM Program Equity Remaining Available for Issuance | $                         $ 200.7          
Forward Agreement                                    
Forward Contract Indexed to Issuer's Equity [Line Items]                                    
Derivative, Forward Price   $ 28.83 $ 26.01     $ 26.43                        
Forward Contract Indexed to Issuer's Equity, Settlement Alternatives, Cash, at Fair Value | $   $ 107.1 $ 122.5     $ 167.7                        
Forward Agreement 19                                    
Forward Contract Indexed to Issuer's Equity [Line Items]                                    
Derivative, Forward Price                       $ 29.26            
Forward Contract Indexed to Issuer's Equity, Shares | shares                       3,714,400            
Preferred Stock                                    
Forward Contract Indexed to Issuer's Equity [Line Items]                                    
Shares, Issued | shares                     420,000 440,000 440,000 420,000 0     0
Preferred Stock | Series A Preferred Stock                                    
Forward Contract Indexed to Issuer's Equity [Line Items]                                    
Proceeds from Issuance of Preferred Stock and Preference Stock | $               $ 393.9                    
Preferred Stock | Net Proceeds | Series B Preferred Stock                                    
Forward Contract Indexed to Issuer's Equity [Line Items]                                    
Proceeds from Issuance of Preferred Stock and Preference Stock | $                     $ 486.1              
Subsequent Event                                    
Forward Contract Indexed to Issuer's Equity [Line Items]                                    
Common Stock, Dividends, Per Share, Declared $ 0.21                                  
Subsequent Event | Series A Preferred Stock                                    
Forward Contract Indexed to Issuer's Equity [Line Items]                                    
Preferred Stock, Liquidation Preference Per Share                               $ 1,000    
v3.19.3.a.u2
Equity (Schedule of Stock Offering Program) (Details) - USD ($)
$ / shares in Units, $ in Millions
 12 Months Ended
Dec. 31, 2019
Dec. 31, 2018
Dec. 31, 2017
At The Market Stock Offering [Line Items]      
Stock Issued During Period, Shares, New Issues   24,964,000  
Proceeds, net of fees (in millions) $ 244.4 $ 848.2 $ 336.7
At The Market Program      
At The Market Stock Offering [Line Items]      
Stock Issued During Period, Shares, New Issues 8,422,498 8,883,014 11,931,376
Common Stock Issued Average Price Per Share $ 27.75 $ 26.85 $ 26.58
Proceeds, net of fees (in millions) $ 229.1 $ 232.5 $ 314.7
v3.19.3.a.u2
Equity (Schedule of Stock by Class - Preferred) (Details) - USD ($)
$ / shares in Units, $ in Millions
 12 Months Ended
Dec. 31, 2019
Dec. 31, 2018
Dec. 31, 2017
Class of Stock [Line Items]      
Preferred Stock, Shares Outstanding 440,000 420,000  
Preferred Stock, Dividends Per Share, Declared $ 0.00 $ 28.88 $ 0.00
Preferred Stock, Value, Outstanding $ 880.0 $ 880.0  
Series A Preferred Stock      
Class of Stock [Line Items]      
Preferred Stock, Liquidation Preference Per Share $ 1,000    
Preferred Stock, Shares Outstanding 400,000    
Preferred Stock, Dividends Per Share, Declared $ 56.50 $ 28.88 0
Preferred Stock, Value, Outstanding $ 393.9 $ 393.9  
Series B Preferred Stock      
Class of Stock [Line Items]      
Preferred Stock, Liquidation Preference Per Share $ 25,000.00    
Preferred Stock, Shares Outstanding 20,000    
Preferred Stock, Dividends Per Share, Declared $ 1,674.65 $ 0 $ 0
Preferred Stock, Value, Outstanding $ 486.1 $ 486.1  
v3.19.3.a.u2
Share-Based Compensation (Narrative) (Details) - USD ($)
$ in Millions
 12 Months Ended 36 Months Ended
Dec. 31, 2019
Dec. 31, 2018
Dec. 31, 2017
Dec. 31, 2021
Dec. 31, 2020
Dec. 31, 2019
May 12, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]              
Common stock available for awards, shares             8,000,000
Common stock reserved for future awards, shares 3,313,183         3,313,183  
Stock-based employee compensation expense $ 16.3 $ 15.2 $ 15.3        
Related tax benefits 4.0 3.7 5.9        
Excess Tax Benefit from Share-based Compensation, Operating Activities 0.8 1.0 4.4        
Unrecognized compensation cost related to nonvested awards $ 19.5         $ 19.5  
Weighted-average remaining requisite service period, years 1 year 9 months 18 days            
RTSR Modifier 25.00%            
Defined Contribution Plan, Employer Matching Contribution, Percent of Employees' Gross Pay 3.00%            
401(k) match, profit sharing and non-elective expense $ 37.5 $ 37.6 $ 37.6        
Restricted Stock Units (RSUs)              
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]              
Shares granted 166,031            
Shares nonvested 302,606 178,678       302,606  
Performance Shares              
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]              
Shares granted 552,389 514,338 660,750        
Fair value of shares granted     $ 12.9        
Shares nonvested 1,503,251 1,634,718       1,503,251  
Shares vesting period, (years)           3 years  
Performance Shares | NOEPS [Member]              
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]              
Fair value of shares granted $ 11.7 $ 9.2          
Performance Shares | CVI [Member]              
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]              
Fair value of shares granted $ 2.5 $ 2.4          
Omnibus Plan | Restricted Stock Units (RSUs)              
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]              
Units issued 165,768            
Director Plan | Non-Employee Director Award              
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]              
Shares nonvested 49,926         49,926  
2019 Award | Restricted Stock Units (RSUs)              
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]              
Shares granted 166,031            
Fair value of shares granted $ 4.1            
Shares nonvested 157,786         157,786  
2019 Award | Performance Shares | NOEPS [Member]              
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]              
Shares nonvested 422,825         422,825  
2019 Award | Performance Shares | CVI [Member]              
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]              
Shares nonvested 97,574         97,574  
2018 Award | Restricted Stock Units (RSUs)              
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]              
Shares granted   158,689          
Fair value of shares granted   $ 3.5          
Shares nonvested 136,820         136,820  
2018 Award | Performance Shares | NOEPS [Member]              
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]              
Shares nonvested 368,811         368,811  
2018 Award | Performance Shares | CVI [Member]              
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]              
Shares nonvested 85,111         85,111  
2017 Performance Awards | Performance Shares              
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]              
Shares nonvested 528,928         528,928  
Subsequent Event | Restricted Stock Units (RSUs)              
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]              
Shares vesting period, (years)       3 years 3 years    
Subsequent Event | Performance Shares              
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]              
Shares vesting period, (years)       3 years 3 years    
v3.19.3.a.u2
Share-Based Compensation (Schedule Of Transactions Of Restricted Stock Unit) (Details) - Restricted Stock Units (RSUs)
 12 Months Ended
Dec. 31, 2019
$ / shares
shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]  
Nonvested, Other Than Options | shares 178,678
Nonvested, Weighted Average Grant Date Fair Value | $ / shares $ 21.82
Granted, Other Than Options | shares 166,031
Granted, Weighted Average Grant Date Fair Value | $ / shares $ 24.93
Forfeited, Other Than Options | shares (21,547)
Forfeited, Weighted Average Grant Date Fair Value | $ / shares $ 22.99
Vested, Other Than Options | shares (20,556)
Vested, Weighted Average Grant Date Fair Value | $ / shares $ 21.08
Nonvested, Other Than Options | shares 302,606
Nonvested, Weighted Average Grant Date Fair Value | $ / shares $ 23.49
v3.19.3.a.u2
Share-Based Compensation (Schedule Of Transactions Of Contingent Awards) (Details) - Performance Shares - $ / shares
 12 Months Ended
Dec. 31, 2019
Dec. 31, 2018
Dec. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]      
Nonvested, Other Than Options 1,634,718    
Nonvested, Weighted Average Grant Date Fair Value $ 20.45    
Granted, Other Than Options 552,389 514,338 660,750
Granted, Weighted Average Grant Date Fair Value $ 25.77    
Forfeited, Other Than Options (156,700)    
Forfeited, Weighted Average Grant Date Fair Value $ 26.72    
Vested, Other Than Options (527,156)    
Vested, Weighted Average Grant Date Fair Value $ 28.11    
Nonvested, Other Than Options 1,503,251 1,634,718  
Nonvested, Weighted Average Grant Date Fair Value $ 22.74 $ 20.45  
v3.19.3.a.u2
Long-Term Debt (Narrative) (Details) - USD ($)
$ in Millions
 6 Months Ended 12 Months Ended
Jul. 16, 2018
Jun. 30, 2018
Dec. 31, 2019
Dec. 31, 2018
Dec. 31, 2017
Aug. 12, 2019
Apr. 01, 2019
Jun. 11, 2018
Mar. 15, 2018
Debt Instrument [Line Items]                  
Debt Instrument Tendered       $ 209.0          
Loss on early extinguishment of long-term debt $ 33.0 $ 12.5 $ 0.0 (45.5) $ (111.5)        
Debt Instrument, Convertible, Conversion Ratio     61.70%            
Security interest and other subset of asset     $ 150.0            
Asset sale covenant percentage of consolidated total assets     10.00%            
Cross default provision on default relating to any indebtedness     $ 50.0            
Percentage of additional subset of assets capped     10.00%            
Senior Notes                  
Debt Instrument [Line Items]                  
Face amount of notes           $ 750.0      
Maximum                  
Debt Instrument [Line Items]                  
Cross default provision on default relating to any indebtedness     $ 50.0            
Minimum                  
Debt Instrument [Line Items]                  
Cross default provision on default relating to any indebtedness     $ 5.0            
5.85% Notes Due 2019                  
Debt Instrument [Line Items]                  
Debt Instrument, Repurchase Amount             $ 41.0    
Interest rate on debt             5.85%    
2.95% Notes Due 2029                  
Debt Instrument [Line Items]                  
Interest rate on debt     2.95%            
2.95% Notes Due 2029 | Senior Notes                  
Debt Instrument [Line Items]                  
Proceeds from Debt, Net of Issuance Costs     $ 742.4            
6.40% Notes Due 2018                  
Debt Instrument [Line Items]                  
Debt Instrument, Repurchased Face Amount                 $ 275.1
Interest rate on debt                 6.40%
6.80% Notes Due 2019                  
Debt Instrument [Line Items]                  
Debt Instrument, Repurchased Face Amount       $ 551.1          
Interest rate on debt       6.80%          
5.45% Notes due 2020                  
Debt Instrument [Line Items]                  
Interest rate on debt       5.45%          
3.65% Notes Due 2023                  
Debt Instrument [Line Items]                  
Interest rate on debt       3.65%          
3.65% Notes Due 2023 | Senior Notes                  
Debt Instrument [Line Items]                  
Face amount of notes               $ 350.0  
Proceeds from Issuance of Debt       $ 346.6          
Senior Note Redeemed 2018                  
Debt Instrument [Line Items]                  
Loss on early extinguishment of long-term debt $ 33.0                
6.13% Notes Due 2022                  
Debt Instrument [Line Items]                  
Interest rate on debt       6.125%          
Revolving Credit Facility | Maximum                  
Debt Instrument [Line Items]                  
Debt Instrument, Convertible, Conversion Ratio     70.00%            
Private Placement [Member] | Maximum                  
Debt Instrument [Line Items]                  
Debt Instrument, Convertible, Conversion Ratio     75.00%            
v3.19.3.a.u2
Long-Term Debt (Schedule of Consolidated Long-Term Debt (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2019
Dec. 31, 2018
Debt Instrument [Line Items]    
Senior Notes $ 7,581.6 $ 6,831.6
Medium-Term Notes 157.0 157.0
Capital Lease Obligations 201.5 194.3
Debt Instrument, Unamortized Discount (Premium) and Debt Issuance Costs, Net (70.5) (68.5)
Long-term Debt, Excluding Current Maturities $ 7,869.6 7,155.4
NiSource | 4.45% Notes Due 2021    
Debt Instrument [Line Items]    
Debt Instrument, Maturity Date Dec. 31, 2021  
Debt, Weighted Average Interest Rate 4.45%  
Senior Notes $ 63.6 63.6
NiSource | 2.65% Notes Due 2022    
Debt Instrument [Line Items]    
Debt Instrument, Maturity Date Nov. 30, 2022  
Debt, Weighted Average Interest Rate 2.65%  
Senior Notes $ 500.0 500.0
NiSource | 3.85% Notes Due 2023    
Debt Instrument [Line Items]    
Debt Instrument, Maturity Date Feb. 28, 2023  
Debt, Weighted Average Interest Rate 3.85%  
Senior Notes $ 250.0 250.0
NiSource | 3.65% Notes Due 2023    
Debt Instrument [Line Items]    
Debt Instrument, Maturity Date Jun. 30, 2023  
Debt, Weighted Average Interest Rate 3.65%  
Senior Notes $ 350.0 350.0
NiSource | 5.89% Notes Due 2025    
Debt Instrument [Line Items]    
Debt Instrument, Maturity Date Nov. 30, 2025  
Debt, Weighted Average Interest Rate 5.89%  
Senior Notes $ 265.0 265.0
NiSource | 3.49% Notes due 2027    
Debt Instrument [Line Items]    
Debt Instrument, Maturity Date May 31, 2027  
Debt, Weighted Average Interest Rate 3.49%  
Senior Notes $ 1,000.0 1,000.0
NiSource | 6.78% Notes Due 2027    
Debt Instrument [Line Items]    
Debt Instrument, Maturity Date Dec. 31, 2027  
Debt, Weighted Average Interest Rate 6.78%  
Senior Notes $ 3.0 3.0
NiSource | 2.95% Notes Due 2029    
Debt Instrument [Line Items]    
Debt Instrument, Maturity Date Sep. 30, 2029  
Debt, Weighted Average Interest Rate 2.95%  
Senior Notes $ 750.0 0.0
NiSource | 6.25% Notes Due 2040    
Debt Instrument [Line Items]    
Debt Instrument, Maturity Date Dec. 31, 2040  
Debt, Weighted Average Interest Rate 6.25%  
Senior Notes $ 250.0 250.0
NiSource | 5.95% Notes Due 2041    
Debt Instrument [Line Items]    
Debt Instrument, Maturity Date Jun. 30, 2041  
Debt, Weighted Average Interest Rate 5.95%  
Senior Notes $ 400.0 400.0
NiSource | 5.80% Notes Due 2042    
Debt Instrument [Line Items]    
Debt Instrument, Maturity Date Feb. 28, 2042  
Debt, Weighted Average Interest Rate 5.80%  
Senior Notes $ 250.0 250.0
NiSource | 5.25% Notes Due 2043    
Debt Instrument [Line Items]    
Debt Instrument, Maturity Date Feb. 28, 2043  
Debt, Weighted Average Interest Rate 5.25%  
Senior Notes $ 500.0 500.0
NiSource | 4.80% Notes due 2044    
Debt Instrument [Line Items]    
Debt Instrument, Maturity Date Feb. 29, 2044  
Debt, Weighted Average Interest Rate 4.80%  
Senior Notes $ 750.0 750.0
NiSource | 5.65% Notes Due 2045    
Debt Instrument [Line Items]    
Debt Instrument, Maturity Date Feb. 28, 2045  
Debt, Weighted Average Interest Rate 5.65%  
Senior Notes $ 500.0 500.0
NiSource | 4.375% Notes due 2047    
Debt Instrument [Line Items]    
Debt Instrument, Maturity Date May 31, 2047  
Debt, Weighted Average Interest Rate 4.38%  
Senior Notes $ 1,000.0 1,000.0
NiSource | 3.95% Notes Due 2048    
Debt Instrument [Line Items]    
Debt Instrument, Maturity Date Mar. 31, 2048  
Debt, Weighted Average Interest Rate 3.95%  
Senior Notes $ 750.0 750.0
NiSource | 7.99% Notes Due 2027    
Debt Instrument [Line Items]    
Debt, Weighted Average Interest Rate 7.99%  
Medium-Term Notes $ 49.0 49.0
NiSource | 7.99% Notes Due 2027 | Maximum    
Debt Instrument [Line Items]    
Debt Instrument, Maturity Date May 31, 2027  
NiSource | 7.99% Notes Due 2027 | Minimum    
Debt Instrument [Line Items]    
Debt Instrument, Maturity Date Apr. 30, 2022  
Columbia Of Massachusetts | 6.30% Notes Due 2028    
Debt Instrument [Line Items]    
Debt, Weighted Average Interest Rate 6.30%  
Medium-Term Notes $ 40.0 40.0
Columbia Of Massachusetts | 6.30% Notes Due 2028 | Maximum    
Debt Instrument [Line Items]    
Debt Instrument, Maturity Date Feb. 28, 2028  
Columbia Of Massachusetts | 6.30% Notes Due 2028 | Minimum    
Debt Instrument [Line Items]    
Debt Instrument, Maturity Date Dec. 31, 2025  
Columbia Of Massachusetts | 5.49% notes Due 2043    
Debt Instrument [Line Items]    
Debt, Weighted Average Interest Rate 5.49%  
Capital Lease Obligations $ 44.3 45.7
Columbia Of Massachusetts | 5.49% notes Due 2043 | Maximum    
Debt Instrument [Line Items]    
Debt Instrument, Maturity Date Nov. 30, 2043  
Columbia Of Massachusetts | 5.49% notes Due 2043 | Minimum    
Debt Instrument [Line Items]    
Debt Instrument, Maturity Date Dec. 31, 2033  
NIPSCO | 7.61% Notes Due 2027    
Debt Instrument [Line Items]    
Debt, Weighted Average Interest Rate 7.61%  
Medium-Term Notes $ 68.0 68.0
NIPSCO | 7.61% Notes Due 2027 | Maximum    
Debt Instrument [Line Items]    
Debt Instrument, Maturity Date Aug. 31, 2027  
NIPSCO | 7.61% Notes Due 2027 | Minimum    
Debt Instrument [Line Items]    
Debt Instrument, Maturity Date Aug. 31, 2022  
NIPSCO | 5.85% Notes Due 2019    
Debt Instrument [Line Items]    
Debt, Weighted Average Interest Rate 5.85%  
Long-term Pollution Control Bond $ 0.0 41.0
NIPSCO | 5.85% Notes Due 2019 | Maximum    
Debt Instrument [Line Items]    
Debt Instrument, Maturity Date Apr. 30, 2019  
Columbia Of Ohio | 6.16% Notes Due 2044    
Debt Instrument [Line Items]    
Debt, Weighted Average Interest Rate 6.16%  
Capital Lease Obligations $ 94.8 91.5
Columbia Of Ohio | 6.16% Notes Due 2044 | Maximum    
Debt Instrument [Line Items]    
Debt Instrument, Maturity Date Mar. 31, 2044  
Columbia Of Ohio | 6.16% Notes Due 2044 | Minimum    
Debt Instrument [Line Items]    
Debt Instrument, Maturity Date Oct. 31, 2021  
NiSource Corporate Services | 3.47% Notes Due 2023    
Debt Instrument [Line Items]    
Debt, Weighted Average Interest Rate 3.47%  
Capital Lease Obligations $ 22.3 11.6
NiSource Corporate Services | 3.47% Notes Due 2023 | Maximum    
Debt Instrument [Line Items]    
Debt Instrument, Maturity Date Nov. 30, 2023  
NiSource Corporate Services | 3.47% Notes Due 2023 | Minimum    
Debt Instrument [Line Items]    
Debt Instrument, Maturity Date Jan. 31, 2020  
Columbia Of Virginia | 6.31% Notes Due 2039    
Debt Instrument [Line Items]    
Debt, Weighted Average Interest Rate 6.31%  
Capital Lease Obligations $ 19.1 15.2
Columbia Of Virginia | 6.31% Notes Due 2039 | Maximum    
Debt Instrument [Line Items]    
Debt Instrument, Maturity Date Nov. 30, 2039  
Columbia Of Virginia | 6.31% Notes Due 2039 | Minimum    
Debt Instrument [Line Items]    
Debt Instrument, Maturity Date Jul. 31, 2029  
Columbia Of Kentucky | 3.79% Notes Due 2027    
Debt Instrument [Line Items]    
Debt Instrument, Maturity Date May 31, 2027  
Debt, Weighted Average Interest Rate 3.79%  
Capital Lease Obligations $ 0.3 0.3
Columbia Of Pennsylvania | 5.67% Notes Due 2035    
Debt Instrument [Line Items]    
Debt, Weighted Average Interest Rate 5.67%  
Capital Lease Obligations $ 20.7 $ 30.0
Columbia Of Pennsylvania | 5.67% Notes Due 2035 | Maximum    
Debt Instrument [Line Items]    
Debt Instrument, Maturity Date May 31, 2035  
Columbia Of Pennsylvania | 5.67% Notes Due 2035 | Minimum    
Debt Instrument [Line Items]    
Debt Instrument, Maturity Date Aug. 31, 2027  
v3.19.3.a.u2
Short-Term Borrowings (Narrative) (Details) - USD ($)
$ in Millions
Apr. 17, 2019
Dec. 31, 2019
Dec. 31, 2018
Short-term Debt [Line Items]      
Commercial paper outstanding   $ 570.0 $ 978.0
Line of Credit Facility, Amount Outstanding   0.0 0.0
Accounts receivable securitization facility borrowings   353.2 399.2
Commercial Paper      
Short-term Debt [Line Items]      
Revolving credit facility, maximum   1,500.0  
Revolving Credit Facility      
Short-term Debt [Line Items]      
Revolving credit facility, maximum   1,850.0  
Term Loan      
Short-term Debt [Line Items]      
Debt Instrument, Basis Spread on Variable Rate 0.60%    
Term Loan   $ 850.0 600.0
Maximum | Term Loan      
Short-term Debt [Line Items]      
Term Loan $ 850.0   $ 600.0
Debt Outstanding | Term Loan      
Short-term Debt [Line Items]      
Term Loan $ 850.0    
v3.19.3.a.u2
Short-Term Borrowings (Schedule Of Short-Term Borrowings) (Details) - USD ($)
$ in Millions
Dec. 31, 2019
Dec. 31, 2018
Short-term Debt [Line Items]    
Commercial Paper weighted-average interest rate of 2.03% and 2.96% at December 31, 2019 and 2018, respectively $ 570.0 $ 978.0
Accounts receivable securitization facility borrowings 353.2 399.2
Total short-term borrowings $ 1,773.2 $ 1,977.2
Commercial Paper    
Short-term Debt [Line Items]    
Commercial Paper/credit facilities borrowings, weighted average interest rate 2.03% 2.96%
Term Loan    
Short-term Debt [Line Items]    
Term loan weighted-average interest rate of 2.40% and 3.07% at December 31, 2019 and 2018, respectively $ 850.0 $ 600.0
Commercial Paper/credit facilities borrowings, weighted average interest rate 2.40% 3.07%
v3.19.3.a.u2
Leases (Narrative) (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2019
Dec. 31, 2018
Dec. 31, 2017
Jan. 01, 2019
Lessee, Lease, Description [Line Items]        
Operating Lease, Right-of-Use Asset $ 64.2     $ 57.0
Lessee, Lease Renewal Term 25 years      
Lessee, Operating Lease, Renewal Term 1 year      
Lessee, Finance Lease, Term of Contract 4 years      
Payments made in connection with operating leases $ 52.5 $ 49.1 $ 49.5  
Fleet Lease        
Lessee, Lease, Description [Line Items]        
Lessee, Finance Lease, Term of Contract 1 year      
Minimum        
Lessee, Lease, Description [Line Items]        
Lessee, Operating Lease, Term of Contract 1 year      
Minimum | Office Lease        
Lessee, Lease, Description [Line Items]        
Remaining Lease Term 1 year      
Maximum        
Lessee, Lease, Description [Line Items]        
Lessee, Operating Lease, Term of Contract 3 years      
Maximum | Office Lease        
Lessee, Lease, Description [Line Items]        
Remaining Lease Term 24 years      
v3.19.3.a.u2
Leases (Lease Cost) (Details)
$ in Millions
 12 Months Ended
Dec. 31, 2019
USD ($)
Finance lease cost  
Amortization of right-of-use assets $ 15.5
Interest on lease liabilities 11.3
Total finance lease cost 26.8
Operating lease cost 17.9
Short-term lease cost 1.0
Total lease cost $ 45.7
v3.19.3.a.u2
Leases (Right-of-Use Assets and Liabilities) (Details) - USD ($)
$ in Millions
Dec. 31, 2019
Jan. 01, 2019
Lessee, Lease, Description [Line Items]    
Finance Lease, Right-of-Use Asset, Statement of Financial Position [Extensible List] us-gaap:NetPropertyPlantandEquipment  
Finance Lease, Right-of-Use Asset $ 179.5  
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible List] us-gaap:DeferredChargesAndOther  
Operating Lease, Right-of-Use Asset $ 64.2 $ 57.0
Total leased assets $ 243.7  
Finance Lease, Liability, Current, Statement of Financial Position [Extensible List] us-gaap:Currentportionoflong-termdebt  
Finance Lease, Liability, Current $ 13.4  
Operating Lease, Liability, Current, Statement of Financial Position [Extensible List] us-gaap:OtherAccruals  
Operating Lease, Liability, Current $ 13.2  
Finance Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List] us-gaap:Long-termDebtExcludingAmountsDueWithinOneYear  
Finance Lease, Liability, Noncurrent $ 188.1  
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List] us-gaap:OtherNoncurrentLiabilities  
Operating Lease, Liability, Noncurrent $ 51.6  
Total Lease Liability $ 266.3  
v3.19.3.a.u2
Leases (Lease Information) (Details)
$ in Millions
 12 Months Ended
Dec. 31, 2019
USD ($)
Rate
Leases [Abstract]  
Finance Lease, Interest Payment on Liability $ 11.3
Operating Lease, Payments 17.9
Finance Lease, Principal Payments 10.6
Right-of-Use Asset Obtained in Exchange for Finance Lease Liability 26.4
Right-of-Use Asset Obtained in Exchange for Operating Lease Liability $ 13.4
Finance Lease, Weighted Average Remaining Lease Term 14 years 9 months 18 days
Operating Lease, Weighted Average Remaining Lease Term 9 years 2 months 12 days
Finance Lease, Weighted Average Discount Rate, Percent | Rate 5.90%
Operating Lease, Weighted Average Discount Rate, Percent | Rate 4.30%
v3.19.3.a.u2
Leases (Lease Maturity) (Details) - USD ($)
$ in Millions
Dec. 31, 2019
Dec. 31, 2018
Lease Maturity [Line Items]    
Total Future Minimum Lease Payments Due, Next Twelve Months $ 42.8 $ 34.0
Total Future Minimum Lease Payments, Due in Two Years 36.7 29.8
Total Future Minimum Lease Payments, Due in Three Years 35.0 28.7
Total Future Minimum Lease Payments, Due in Four Years 30.7 26.3
Total Future Minimum Lease Payments, Due in Five Years 26.5 22.6
Total Future Minimum Lease Payments, Due Thereafter 233.3 226.9
Total Future Minimum Lease Payments Due 405.0 $ 368.3
Undiscounted Excess Amount (116.6)  
Total Lease Liability 266.3  
Short-term Lease Liability 26.6  
Long-term Lease Liability 239.7  
Finance Leases, Future Minimum Payments Due, Next Twelve Months [1] 27.2  
Finance Leases, Future Minimum Payments Due in Two Years [1] 27.3  
Finance Leases, Future Minimum Payments Due in Three Years [1] 26.8  
Finance Leases, Future Minimum Payments Due in Four Years [1] 23.1  
Finance Leases, Future Minimum Payments Due in Five Years [1] 19.9  
Finance Leases, Future Minimum Payments Due Thereafter [1] 201.6  
Finance Lease, Liability, Payment, Due [1] 325.9  
Finance Lease, Liability, Current 13.4  
Finance Lease, Liability, Noncurrent 188.1  
Operating Leases, Future Minimum Payments Due, Next Twelve Months [2] 15.6  
Operating Leases, Future Minimum Payments, Due in Two Years [2] 9.4  
Operating Leases, Future Minimum Payments, Due in Three Years [2] 8.2  
Operating Leases, Future Minimum Payments, Due in Four Years [2] 7.6  
Operating Leases, Future Minimum Payments, Due in Five Years [2] 6.6  
Operating Leases, Future Minimum Payments, Due Thereafter [2] 31.7  
Lessee, Operating Lease, Liability, Payments, Due [2] 79.1  
Leases Not Yet Commenced [3] (22.1)  
Operating Lease, Liability, Current 13.2  
Operating Lease, Liability, Noncurrent 51.6  
Interconnection facilities    
Lease Maturity [Line Items]    
Leases Not Yet Commenced (22.1)  
Finance Lease    
Lease Maturity [Line Items]    
Finance Leases, Future Minimum Payments Due, Next Twelve Months 27.2  
Finance Leases, Future Minimum Payments Due in Two Years 27.3  
Finance Leases, Future Minimum Payments Due in Three Years 26.8  
Finance Leases, Future Minimum Payments Due in Four Years 23.1  
Finance Leases, Future Minimum Payments Due in Five Years 19.9  
Finance Leases, Future Minimum Payments Due Thereafter 201.6  
Finance Lease, Liability, Payment, Due 325.9  
Finance Lease, Liability, Undiscounted Excess Amount (102.3)  
Finance Lease, Liability 201.5  
Finance Lease, Liability, Current 13.4  
Finance Lease, Liability, Noncurrent 188.1  
Leases Not Yet Commenced [3] (22.1)  
Operating Lease    
Lease Maturity [Line Items]    
Operating Leases, Future Minimum Payments Due, Next Twelve Months 15.6  
Operating Leases, Future Minimum Payments, Due in Two Years 9.4  
Operating Leases, Future Minimum Payments, Due in Three Years 8.2  
Operating Leases, Future Minimum Payments, Due in Four Years 7.6  
Operating Leases, Future Minimum Payments, Due in Five Years 6.6  
Operating Leases, Future Minimum Payments, Due Thereafter 31.7  
Lessee, Operating Lease, Liability, Payments, Due 79.1  
Lessee, Operating Lease, Liability, Undiscounted Excess Amount (14.3)  
Leases Not Yet Commenced [3] 0.0  
Operating Lease, Liability 64.8  
Operating Lease, Liability, Current 13.2  
Operating Lease, Liability, Noncurrent $ 51.6  
Maximum    
Lease Maturity [Line Items]    
Lessee, Finance Lease, Lease Not yet Commenced, Term of Contract 20 years  
Minimum    
Lease Maturity [Line Items]    
Lessee, Finance Lease, Lease Not yet Commenced, Term of Contract 4 years  
[1] Finance lease payments shown above are inclusive of interest totaling $108.3 million.
[2] Operating lease payments shown above are inclusive of interest totaling $14.3 million. Operating lease balances do not include obligations for possible fleet vehicle lease renewals beyond the initial lease term. While we have the ability to renew these leases beyond the initial term, we are not reasonably certain (as that term is defined in ASC 842) to do so. If we were to continue the fleet vehicle leases outstanding at December 31, 2019, payments would be $34.5 million in 2020, $28.3 million in 2021, $23.4 million in 2022, $19.9 million in 2023, $15.2 million in 2024 and $15.2 million thereafter.
[3] Expected payments include obligations for leases not yet commenced of approximately $22.1 million for IT assets and interconnection facilities. These leases have terms between 4 years and 20 years, with estimated commencements in the first quarter of 2020 and in the third quarter of 2020.
v3.19.3.a.u2
Leases (Lease Maturity under ASC 840) (Details) - USD ($)
$ in Millions
Dec. 31, 2019
Dec. 31, 2018
Lease Maturity under 840 [Line Items]    
Total Future Minimum Lease Payments Due, Next Twelve Months $ 42.8 $ 34.0
Total Future Minimum Lease Payments, Due in Two Years 36.7 29.8
Total Future Minimum Lease Payments, Due in Three Years 35.0 28.7
Total Future Minimum Lease Payments, Due in Four Years 30.7 26.3
Total Future Minimum Lease Payments, Due in Five Years 26.5 22.6
Total Future Minimum Lease Payments, Due Thereafter 233.3 226.9
Total Future Minimum Lease Payments Due $ 405.0 368.3
Capital Leases, Future Minimum Payments, Interest Included in Payments   114.6
Fleet Lease    
Lease Maturity under 840 [Line Items]    
Operating Leases, Future Minimum Payments Due, Next Twelve Months   26.7
Operating Leases, Future Minimum Payments, Due in Two Years   22.4
Operating Leases, Future Minimum Payments, Due in Three Years   16.6
Operating Leases, Future Minimum Payments, Due in Four Years   12.3
Operating Leases, Future Minimum Payments, Due in Five Years   9.3
Operating Leases, Future Minimum Payments, Due Thereafter   8.8
Operating Lease    
Lease Maturity under 840 [Line Items]    
Operating Leases, Future Minimum Payments Due, Next Twelve Months [1]   11.0
Operating Leases, Future Minimum Payments, Due in Two Years [1]   7.3
Operating Leases, Future Minimum Payments, Due in Three Years [1]   6.1
Operating Leases, Future Minimum Payments, Due in Four Years [1]   4.2
Operating Leases, Future Minimum Payments, Due in Five Years [1]   2.8
Operating Leases, Future Minimum Payments, Due Thereafter [1]   14.5
Operating Leases, Future Minimum Payments Due [1]   45.9
Capital Lease Obligations    
Lease Maturity under 840 [Line Items]    
Capital Leases, Future Minimum Payments Due, Next Twelve Months [2]   23.0
Capital Leases, Future Minimum Payments Due in Two Years [2]   22.5
Capital Leases, Future Minimum Payments Due in Three Years [2]   22.6
Capital Leases, Future Minimum Payments Due in Four Years [2]   22.1
Capital Leases, Future Minimum Payments Due in Five Years [2]   19.8
Capital Leases, Future Minimum Payments Due Thereafter [2]   212.4
Capital Leases, Future Minimum Payments Due [2]   $ 322.4
[1] Operating lease balances do not include obligations for possible fleet vehicle lease renewals beyond the initial lease term. While we have the ability to renew these leases beyond the initial term, we are not reasonably certain to do so. Expected payments are $26.7 million in 2019, $22.4 million in 2020, $16.6 million in 2021, $12.3 million in 2022, $9.3 million in 2023 and $8.8 million thereafter.
[2] Capital lease payments shown above are inclusive of interest totaling $114.6 million.
v3.19.3.a.u2
Fair Value (Narrative) (Details)
$ in Millions
 3 Months Ended 12 Months Ended
Dec. 31, 2019
USD ($)
Dec. 31, 2019
USD ($)
Fair Value Disclosure [Line Items]    
Transfers between Fair Value Hierarchies   $ 0.0
U.S. Treasury debt securities    
Fair Value Disclosure [Line Items]    
Available-for-sale securities, maturities of less than a year $ 7.7 7.7
Corporate/Other debt securities    
Fair Value Disclosure [Line Items]    
Available-for-sale securities, maturities of less than a year 6.0 $ 6.0
Columbia Of Massachusetts    
Fair Value Disclosure [Line Items]    
Goodwill, Impairment Loss 204.8  
Impairment of Intangible Assets, Finite-lived $ 209.7  
v3.19.3.a.u2
Fair Value (Fair Value Of Financial Assets And Liabilities Measured On A Recurring Basis) (Details) - USD ($)
$ in Millions
Dec. 31, 2019
Dec. 31, 2018
Fair Value Assets And Liabilities Measured On Recurring Basis [Line Items]    
Risk management assets $ 4.4 $ 24.0
Available-for-sale securities 154.2 138.3
Total 158.6 162.3
Risk management liabilities 146.6 51.7
Total 146.6 51.7
Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]    
Fair Value Assets And Liabilities Measured On Recurring Basis [Line Items]    
Risk management assets 0.0 0.0
Available-for-sale securities 0.0 0.0
Total 0.0 0.0
Risk management liabilities 0.0 0.0
Total 0.0 0.0
Significant Other Observable Inputs (Level 2) [Member]    
Fair Value Assets And Liabilities Measured On Recurring Basis [Line Items]    
Risk management assets 4.4 24.0
Available-for-sale securities 154.2 138.3
Total 158.6 162.3
Risk management liabilities 146.6 51.7
Total 146.6 51.7
Significant Unobservable Inputs (Level 3) [Member]    
Fair Value Assets And Liabilities Measured On Recurring Basis [Line Items]    
Risk management assets 0.0 0.0
Available-for-sale securities 0.0 0.0
Total 0.0 0.0
Risk management liabilities 0.0 0.0
Total $ 0.0 $ 0.0
v3.19.3.a.u2
Fair Value (Available-For-Sale Securities) (Details) - USD ($)
$ in Millions
Dec. 31, 2019
Dec. 31, 2018
Fair Value Disclosure [Line Items]    
Amortized Cost $ 150.1 $ 141.3
Gross Unrealized Gains 4.3 0.5
Gross Unrealized Losses 0.2 3.5
Fair Value 154.2 138.3
U.S. Treasury debt securities    
Fair Value Disclosure [Line Items]    
Amortized Cost 31.4 23.6
Gross Unrealized Gains 0.1 0.1
Gross Unrealized Losses 0.1 0.1
Fair Value 31.4 23.6
Corporate/Other debt securities    
Fair Value Disclosure [Line Items]    
Amortized Cost 118.7 117.7
Gross Unrealized Gains 4.2 0.4
Gross Unrealized Losses 0.1 3.4
Fair Value $ 122.8 $ 114.7
v3.19.3.a.u2
Fair Value (Carrying Amount And Estimated Fair Values Of Financial Instruments) (Details) - USD ($)
$ in Millions
Dec. 31, 2019
Dec. 31, 2018
Fair Value Disclosures [Abstract]    
Long-term debt (including current portion), Carrying Amount $ 7,869.6 $ 7,155.4
Long-term debt (including current portion), Estimated Fair Value $ 8,764.4 $ 7,228.3
v3.19.3.a.u2
Transfers Of Financial Assets (Narrative) (Details) - USD ($)
$ in Millions
 3 Months Ended 12 Months Ended
Dec. 31, 2019
Dec. 31, 2018
Dec. 31, 2019
Dec. 31, 2018
Dec. 31, 2017
Assets and Associated Liabilities of Transfers Accounted for as Secured Borrowings [Line Items]          
Cash from financing activities     $ 46.0 $ 62.5  
Securitization transaction fees $ 2.6 $ 2.6 2.6 $ 2.6 $ 2.5
Accounts Receivable Program          
Assets and Associated Liabilities of Transfers Accounted for as Secured Borrowings [Line Items]          
Seasonal Limit $ 465.0   $ 465.0    
v3.19.3.a.u2
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
Dec. 31, 2019
Dec. 31, 2018
Transfers and Servicing [Abstract]    
Gross Receivables interest $ 569.1 $ 694.4
Less: Receivables not transferred 215.9 295.2
Net receivables transferred 353.2 399.2
Accounts receivable securitization agreements outstanding $ 353.2 $ 399.2
v3.19.3.a.u2
Other Commitments And Contingencies (Narrative) (Details)
 3 Months Ended 4 Months Ended 12 Months Ended 16 Months Ended
Oct. 31, 2019
MW
Jul. 31, 2008
MW
Dec. 31, 2019
USD ($)
Sep. 30, 2019
USD ($)
 [1]
Jun. 30, 2019
USD ($)
 [1]
Mar. 31, 2019
USD ($)
 [1]
Dec. 31, 2018
USD ($)
Dec. 31, 2019
USD ($)
Rate
MW
Dec. 31, 2018
USD ($)
Dec. 31, 2017
USD ($)
Dec. 31, 2019
USD ($)
Jul. 26, 2019
USD ($)
Jan. 01, 2019
Rate
MW
Other Commitments And Contingencies [Line Items]                          
Payments made in connection with operating leases               $ 52,500,000 $ 49,100,000 $ 49,500,000      
Wind power purchase agreement capacity | MW   100                      
Each wind power purchase agreement capacity | MW   50                      
Major Rail Operators     3         3     3    
Line of Credit Facility, Amount Outstanding     $ 0       $ 0 $ 0 0   $ 0    
Safety Recommendations Remaining to implement               1          
Gas Meters moved from inside to outside 2,200                        
Proposed Class Action Settlement                       $ 143,000,000  
Expenses Related to Third-Party Claims, Fines, Penalties, and settlements             757,000,000 $ 284,000,000     1,041,000,000    
Liability Insurance for Damages     800,000,000         800,000,000     800,000,000    
Proceeds From Insurance Settlement     130,000,000 [1] $ 260,000,000 $ 297,000,000 $ 108,000,000.0         800,000,000    
Recorded reserves to cover environmental remediation at various sites     $ 104,400,000       101,200,000 $ 104,400,000 101,200,000   104,400,000    
Coal-fired Generating Capacity | MW               2,080          
Coal-fired Generating Capacity, Percent of Total Capacity | Rate               72.00%          
Coal-fired Generating Capacity, Percent of Total Coal-Fired Capacity | Rate               100.00%          
Wind Power Purchase Agreement, Purchase Percentage | Rate                         100.00%
Expenses Other Than Third Party Claims             266,000,000 $ 154,000,000     420,000,000    
Costs Resulting from the Greater Lawrence Incident             1,023,000,000 $ 438,000,000     $ 1,461,000,000    
MGP Sites                          
Other Commitments And Contingencies [Line Items]                          
Number of waste disposal sites identified by program     63         63     63    
Liability for estimated remediation costs     $ 102,200,000       97,500,000 $ 102,200,000 97,500,000   $ 102,200,000    
Reasonably possible remediation costs variance from reserve     20,000,000         20,000,000     20,000,000    
NIPSCO                          
Other Commitments And Contingencies [Line Items]                          
Estimated Cost of Compliance with Effluent Limitations Guidelines               $ 170,000,000.0          
Columbia Of Massachusetts                          
Other Commitments And Contingencies [Line Items]                          
Gas Meters Affected               7,500          
Businesses Impacted by Incident               700          
Miles of Affected Cast Iron and Bare Steel Pipeline System               45          
Pipeline Replacement Expenses                     258,000,000    
Deferred Tax Assets, Net     50,000,000         $ 50,000,000     50,000,000    
Maximum                          
Other Commitments And Contingencies [Line Items]                          
Long term purchase commitment time period               20 years          
Maximum | Columbia Of Massachusetts                          
Other Commitments And Contingencies [Line Items]                          
Civil Penalty Assessed for Violation of Federal Pipeline Safety Regulations               $ 218,647          
Civil Penalty Assessed for Series of Violations of Federal Pipeline Safety Regulations               2,200,000          
Penalty Per Violation of Emergency Response Plan               250,000          
Penalty for Violations of Emergency Response Plan               20,000,000          
Penalty Per Violation of Operational Directives During Restoration Efforts               $ 1,000,000          
Expenses Related to Third-Party Claims, Fines, Penalties, and settlements                     1,065,000,000    
Expenses Other Than Third Party Claims                     460,000,000    
Minimum                          
Other Commitments And Contingencies [Line Items]                          
Long term purchase commitment time period               15 years          
Minimum | Columbia Of Massachusetts                          
Other Commitments And Contingencies [Line Items]                          
Expenses Related to Third-Party Claims, Fines, Penalties, and settlements                     1,041,000,000    
Expenses Other Than Third Party Claims                     450,000,000    
Coal Transportation | Maximum                          
Other Commitments And Contingencies [Line Items]                          
Long Term Purchase Commitment Expiration Year               2021          
Purchase Power Agreements - Jan 2019                          
Other Commitments And Contingencies [Line Items]                          
Long term purchase commitment time period               20 years          
Build Transfer Agreement                          
Other Commitments And Contingencies [Line Items]                          
Nameplate Capacity | MW 300                       100
Standby Letters of Credit                          
Other Commitments And Contingencies [Line Items]                          
Line of Credit Facility, Amount Outstanding     $ 10,200,000       $ 10,200,000 $ 10,200,000 $ 10,200,000   $ 10,200,000    
[1] $5 million of insurance recoveries were collected during 2018.
v3.19.3.a.u2
Other Commitments And Contingencies Other Commitments and Contingencies (Contractual Obligation, Fiscal Year Maturity Schedule) (Details) - USD ($)
$ in Millions
Dec. 31, 2019
Dec. 31, 2018
Long-term Purchase Commitment [Line Items]    
Long-term Debt, Future Minimum Payments Due [1] $ 7,738.6  
Long-term Debt, Future Minimum Payments Due, Next Twelve Months [1] 0.0  
Long-term Debt, Future Minimum Payments, Due in Two Years [1] 63.6  
Long-term Debt, Future Minimum Payments, Due in Three Years [1] 530.0  
Long-term Debt, Future Minimum Payments, Due in Four Years [1] 600.0  
Long-term Debt, Future Minimum Payments, Due in Five Years [1] 0.0  
Long-term Debt, Future Minimum Payments, Due Thereafter [1] 6,545.0  
Interest Payments on Long-term Debt, Future Minimum Payments Due 6,214.2  
Interest Payments on Long-term Debt, Future Minimum Payments Due, Next Twelve Months 342.0  
Interest Payments on Long-term Debt, Future Minimum Payments, Due in Two Years 340.7  
Interest Payments on Long-term Debt, Future Minimum Payments, Due in Three Years 337.1  
Interest Payments on Long-term Debt, Future Minimum Payments, Due in Four Years 311.1  
Interest Payments on Long-term Debt, Future Minimum Payments, Due in Five Years 299.9  
Interest Payments on Long-term Debt, Future Minimum Payments, Due Thereafter 4,583.4  
Finance Leases, Future Minimum Payments Due [2] 325.9  
Finance Leases, Future Minimum Payments Due, Next Twelve Months [2] 27.2  
Finance Leases, Future Minimum Payments Due in Two Years [2] 27.3  
Finance Leases, Future Minimum Payments Due in Three Years [2] 26.8  
Finance Leases, Future Minimum Payments Due in Four Years [2] 23.1  
Finance Leases, Future Minimum Payments Due in Five Years [2] 19.9  
Finance Leases, Future Minimum Payments Due Thereafter [2] 201.6  
Operating Leases, Future Minimum Payments Due [3] 79.1  
Operating Leases, Future Minimum Payments Due, Next Twelve Months [3] 15.6  
Operating Leases, Future Minimum Payments, Due in Two Years [3] 9.4  
Operating Leases, Future Minimum Payments, Due in Three Years [3] 8.2  
Operating Leases, Future Minimum Payments, Due in Four Years [3] 7.6  
Operating Leases, Future Minimum Payments, Due in Five Years [3] 6.6  
Operating Leases, Future Minimum Payments, Due Thereafter [3] 31.7  
Energy Commodity Contracts, Future Minimum Payments Due [4] 95.9  
Energy Commodity Contracts, Future Minimum Payments Due, Next Twelve Months [4] 65.5  
Energy Commodity Contracts, Future Minimum Payments, Due in Two Years [4] 30.4  
Energy Commodity Contracts, Future Minimum Payments, Due in Three Years [4] 0.0  
Energy Commodity Contracts, Future Minimum Payments, Due in Four Years [4] 0.0  
Energy Commodity Contracts, Future Minimum Payments, Due in Five Years [4] 0.0  
Energy Commodity Contracts, Future Minimum Payments, Due Thereafter [4] 0.0  
Service Obligations, Pipeline Service Obligations, Future Minimum Payments Due 3,450.7  
Service Obligations, Pipeline Service Obligations, Future Minimum Payments Due, Next Twelve Months 605.0  
Service Obligations, Pipeline Service Obligations, Future Minimum Payments, Due in Two Years 590.1  
Service Obligations, Pipeline Service Obligations, Future Minimum Payments, Due in Three Years 546.8  
Service Obligations, Pipeline Service Obligations, Future Minimum Payments, Due in Four Years 357.2  
Service Obligations, Pipeline Service Obligations, Future Minimum Payments, Due in Five Years 237.5  
Service Obligations, Pipeline Service Obligations, Future Minimum Payments, Due Thereafter 1,114.1  
Service Obligations, IT Service Obligations, Future Minimum Payments Due 153.2  
Service Obligations, IT Service Obligations, Future Minimum Payments Due, Next Twelve Months 63.6  
Service Obligations, IT Service Obligations, Future Minimum Payments, Due in Two Years 49.4  
Service Obligations, IT Service Obligations, Future Minimum Payments, Due in Three Years 38.0  
Service Obligations, IT Service Obligations, Future Minimum Payments, Due in Four Years 1.1  
Service Obligations, IT Service Obligations, Future Minimum Payments, Due in Five Years 1.1  
Service Obligations, IT Service Obligations, Future Minimum Payments, Due Thereafter 0.0  
Service Obligations, Other Service Obligations, Future Minimum Payments Due 59.8  
Service Obligations, Other Service Obligations, Future Minimum Payments Due, Next Twelve Months 45.8  
Service Obligations, Other Service Obligations, Future Minimum Payments, Due in Two Years 14.0  
Service Obligations, Other Service Obligations, Future Minimum Payments, Due in Three Years 0.0  
Service Obligations, Other Service Obligations, Future Minimum Payments, Due in Four Years 0.0  
Service Obligations, Other Service Obligations, Future Minimum Payments, Due in Five Years 0.0  
Service Obligations, Other Service Obligations, Future Minimum Payments, Due Thereafter 0.0  
Other Liabilities, Future Minimum Payments Due 27.3  
Other Liabilities, Future Minimum Payments Due, Next Twelve Months 27.3  
Other Liabilities, Future Minimum Payments, Due in Two Years 0.0  
Other Liabilities, Future Minimum Payments, Due in Three Years 0.0  
Other Liabilities, Future Minimum Payments, Due in Four Years 0.0  
Other Liabilities, Future Minimum Payments, Due in Five Years 0.0  
Other Liabilities, Future Minimum Payments, Due Thereafter 0.0  
Total Future Minimum Lease Payments Due 18,144.7  
Total Future Minimum Lease Payments Due, Next Twelve Months 1,192.0  
Total Future Minimum Lease Payments, Due in Two Years 1,124.9  
Total Future Minimum Lease Payments, Due in Three Years 1,486.9  
Total Future Minimum Lease Payments, Due in Four Years 1,300.1  
Total Future Minimum Lease Payments, Due in Five Years 565.0  
Total Future Minimum Lease Payments, Due Thereafter 12,475.8  
Debt Instrument, Unamortized Discount (Premium) and Debt Issuance Costs, Net (70.5) $ (68.5)
Finance Leases, Future Minimum Payments, Interest Included in Payments 108.3  
Operating Leases, Future Minimum Payaments, Interest Included in Payments 14.3  
Coal [Member]    
Long-term Purchase Commitment [Line Items]    
Energy Commodity Contracts, Future Minimum Payments Due 14.4  
Fleet Lease    
Long-term Purchase Commitment [Line Items]    
Operating Leases, Future Minimum Payments Due, Next Twelve Months 34.5  
Operating Leases, Future Minimum Payments, Due in Two Years 28.3  
Operating Leases, Future Minimum Payments, Due in Three Years 23.4  
Operating Leases, Future Minimum Payments, Due in Four Years 19.9  
Operating Leases, Future Minimum Payments, Due in Five Years 15.2  
Operating Leases, Future Minimum Payments, Due Thereafter $ 15.2  
[1] Long-term debt balance excludes unamortized issuance costs and discounts of $70.5 million.
[2] Finance lease payments shown above are inclusive of interest totaling $108.3 million.
[3] Operating lease payments shown above are inclusive of interest totaling $14.3 million. Operating lease balances do not include obligations for possible fleet vehicle lease renewals beyond the initial lease term. While we have the ability to renew these leases beyond the initial term, we are not reasonably certain (as that term is defined in ASC 842) to do so. If we were to continue the fleet vehicle leases outstanding at December 31, 2019, payments would be $34.5 million in 2020, $28.3 million in 2021, $23.4 million in 2022, $19.9 million in 2023, $15.2 million in 2024 and $15.2 million thereafter.
[4] In January 2020, NIPSCO signed new coal contract commitments of $14.4 million for 2020. These contracts are not included above.
v3.19.3.a.u2
Other Commitments And Contingencies Other Commitments and Contingencies (Expense Incurred and Insurance Recoveries) (Details) - USD ($)
$ in Millions
 3 Months Ended 4 Months Ended 12 Months Ended 16 Months Ended
Dec. 31, 2019
 [1]
Sep. 30, 2019
 [1]
Jun. 30, 2019
 [1]
Mar. 31, 2019
 [1]
Dec. 31, 2018
Dec. 31, 2019
Dec. 31, 2019
Expense and Insurance Recoveries [Line Items]              
Third-Party Claims, fines, penalties, and settlements         $ 757 $ 284 $ 1,041
Other incident-related costs         266 154 420
Total         1,023 438 1,461
Insurance Recoveries $ (130) $ 0 $ (435) $ (100) (135) (665) (800)
Impact to income (loss) before income taxes         $ 888 $ (227) $ 661
[1] $5 million of insurance recoveries were collected during 2018.
v3.19.3.a.u2
Other Commitments And Contingencies Other Commitments and Contingencies (Insurance Recoveries and Cash Collected) (Details) - USD ($)
$ in Millions
 3 Months Ended 4 Months Ended 12 Months Ended 16 Months Ended
Dec. 31, 2019
Sep. 30, 2019
Jun. 30, 2019
Mar. 31, 2019
Dec. 31, 2018
Dec. 31, 2019
Dec. 31, 2019
Commitments and Contingencies Disclosure [Abstract]              
Insurance Settlements Receivable [1] $ 0.0 $ 0.0 $ 260.0 $ 122.0 $ 130.0 $ 0.0 $ 0.0
Insurance recoveries recorded 130.0 [1] 0.0 [1] 435.0 [1] 100.0 [1] $ 135.0 $ 665.0 800.0
Cash collected from insurance recoveries $ (130.0) [1] $ (260.0) [1] $ (297.0) [1] $ (108.0) [1]     $ (800.0)
[1] $5 million of insurance recoveries were collected during 2018.
v3.19.3.a.u2
Accumulated Other Comprehensive Loss (Components Of Accumulated Other Comprehensive Loss) (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2019
Dec. 31, 2018
Dec. 31, 2017
Dec. 31, 2016
Accumulated Other Comprehensive Income (Loss) [Line Items]        
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax [1] $ (55.9) $ 48.4 $ (21.7)  
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax [1] 0.5 (32.7) 3.4  
Net current-period other comprehensive income (loss) [1] (55.4) 15.7 (18.3)  
New Accounting Pronouncement or Change in Accounting Principle, Cumulative Effect of Change on Equity or Net Assets   (9.5)    
Accumulated other comprehensive loss [1] (92.6) (37.2) (43.4) $ (25.1)
Gains and Losses on Securities        
Accumulated Other Comprehensive Income (Loss) [Line Items]        
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax [1] 6.1 (3.0) 0.6  
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax [1] (0.4) 0.4 0.2  
Net current-period other comprehensive income (loss) [1] 5.7 (2.6) 0.8  
New Accounting Pronouncement or Change in Accounting Principle, Cumulative Effect of Change on Equity or Net Assets [1]   0.0    
Accumulated other comprehensive loss [1] 3.3 (2.4) 0.2 (0.6)
Gains and Losses on Cash Flow Hedges        
Accumulated Other Comprehensive Income (Loss) [Line Items]        
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax [1] (64.3) 55.8 (24.2)  
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax [1] 0.1 (33.1) 1.7  
Net current-period other comprehensive income (loss) [1] (64.2) 22.7 (22.5)  
New Accounting Pronouncement or Change in Accounting Principle, Cumulative Effect of Change on Equity or Net Assets [1]   (6.3)    
Accumulated other comprehensive loss [1] (77.2) (13.0) (29.4) (6.9)
Pension and OPEB Items        
Accumulated Other Comprehensive Income (Loss) [Line Items]        
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax [1] 2.3 (4.4) 1.9  
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax [1] 0.8 0.0 1.5  
Net current-period other comprehensive income (loss) [1] 3.1 (4.4) 3.4  
New Accounting Pronouncement or Change in Accounting Principle, Cumulative Effect of Change on Equity or Net Assets [1]   (3.2)    
Accumulated other comprehensive loss [1] $ (18.7) $ (21.8) $ (14.2) $ (17.6)
[1] All amounts are net of tax. Amounts in parentheses indicate debits.
v3.19.3.a.u2
Other, Net (Schedule Of Other Net) (Details) - USD ($)
$ in Millions
 3 Months Ended 12 Months Ended
Dec. 31, 2018
Dec. 31, 2019
Dec. 31, 2018
Dec. 31, 2017
Other Nonoperating Income (Expense) [Abstract]        
Charitable Contributions, Greater Lawrence Incident $ 20.7      
Interest income   $ 7.7 $ 6.6 $ 4.6
AFUDC equity   8.0 14.2 12.6
Charitable Contributions $ 20.0 (5.1) [1] (45.3) [1] (19.9) [1]
Pension and Other Postretirement Non Service Cost [2]   (16.5) 18.0 (10.6)
Interest rate swap settlement gain [3]     46.2 0.0
Miscellaneous   0.7 3.8 (0.2)
Total Other, net   $ (5.2) $ 43.5 $ (13.5)
[1] (1) 2018 charitable contributions include $20.7 million related to the Greater Lawrence Incident and $20.0 million of discretionary contributions made to the
[2]
(2) See Note 11, "Pension and Other Postretirement Benefits" for additional information.
[3]
(3) See Note 9, "Risk Management Activities" for additional information.
v3.19.3.a.u2
Interest Expense, Net (Details) - USD ($)
$ in Millions
 3 Months Ended 12 Months Ended
Dec. 31, 2019
Dec. 31, 2018
Dec. 31, 2019
Dec. 31, 2018
Dec. 31, 2017
Interest Expense [Abstract]          
Interest on long-term debt     $ 327.7 $ 342.2 $ 354.8
Interest on short-term borrowings     50.8 31.8 14.9
Debt discount/cost amortization     8.3 7.7 7.2
Accounts receivable securitization fees $ 2.6 $ 2.6 2.6 2.6 2.5
Allowance for borrowed funds used and interest capitalized during construction     (7.5) (9.1) (6.2)
Debt-based post-in-service carrying charges     (18.7) (35.0) (36.4)
Other     15.7 13.1 16.4
Total Interest Expense, net     $ 378.9 $ 353.3 $ 353.2
v3.19.3.a.u2
Segments Of Business (Narrative) (Details)
$ in Millions
 3 Months Ended 12 Months Ended
Dec. 31, 2019
USD ($)
Dec. 31, 2019
Goodwill [Line Items]    
Number of Reportable Segments   2
Number of counties in which electric service provided by Electric Operations   20
Columbia Of Massachusetts    
Goodwill [Line Items]    
Goodwill, Impairment Loss $ 204.8  
v3.19.3.a.u2
Segments Of Business (Schedule Of Operating Income Derived From Revenues And Expenses By Segment) (Details) - USD ($)
$ in Millions
 3 Months Ended 12 Months Ended
Dec. 31, 2019
Sep. 30, 2019
Jun. 30, 2019
Mar. 31, 2019
Dec. 31, 2018
Sep. 30, 2018
Jun. 30, 2018
Mar. 31, 2018
Dec. 31, 2019
Dec. 31, 2018
Dec. 31, 2017
Segment Reporting Information [Line Items]                      
Operating Revenues                 $ 5,208.9 $ 5,114.5 $ 4,874.6
Operating Income (Loss) $ (38.0) $ 91.0 $ 463.5 $ 374.2 $ (78.4) $ (315.9) $ 118.4 $ 400.6 890.7 124.7 921.2
Consolidated Depreciation and Amortization                 717.4 599.6 570.3
Consolidated Assets 22,659.8       21,804.0       22,659.8 21,804.0 19,961.7
Payments to Acquire Property Plant and Equipment Including Captial Expenditures From Current Liabilities And Equity Method Investments [1]                 1,867.8 1,814.6 1,753.8
Gas Distribution Operations                      
Segment Reporting Information [Line Items]                      
Operating Revenues                 3,509.7 3,406.4  
Intersegment                 3,522.8 3,419.5 3,102.1
Operating Income (Loss)         (254.1)       675.4   550.1
Consolidated Depreciation and Amortization                 403.2 301.0 269.3
Consolidated Assets 14,224.5       13,527.0       14,224.5 13,527.0 12,048.8
Payments to Acquire Property Plant and Equipment Including Captial Expenditures From Current Liabilities And Equity Method Investments [1]                 1,380.3 1,315.3 1,125.6
Electric Operations                      
Segment Reporting Information [Line Items]                      
Operating Revenues                 1,698.4 1,707.4  
Intersegment                 1,699.2 1,708.2 1,786.5
Operating Income (Loss)         386.1       406.8   367.4
Consolidated Depreciation and Amortization                 277.3 262.9 277.8
Consolidated Assets 6,027.6       5,735.2       6,027.6 5,735.2 5,478.6
Payments to Acquire Property Plant and Equipment Including Captial Expenditures From Current Liabilities And Equity Method Investments [1]                 468.9 499.3 592.4
Corporate and Other                      
Segment Reporting Information [Line Items]                      
Operating Revenues                 0.8 0.7  
Intersegment                 468.9 518.3 511.8
Operating Income (Loss)         (7.3)       (191.5)   3.7
Consolidated Depreciation and Amortization                 36.9 35.7 23.2
Consolidated Assets $ 2,407.7       $ 2,541.8       2,407.7 2,541.8 2,434.3
Payments to Acquire Property Plant and Equipment Including Captial Expenditures From Current Liabilities And Equity Method Investments [1]                 18.6 0.0 35.8
Eliminations                      
Segment Reporting Information [Line Items]                      
Intersegment                 (482.0) (531.5) (525.8)
Unaffiliated | Gas Distribution Operations                      
Segment Reporting Information [Line Items]                      
Operating Revenues                 3,509.7 3,406.4 3,087.9
Unaffiliated | Electric Operations                      
Segment Reporting Information [Line Items]                      
Operating Revenues                 1,698.4 1,707.4 1,785.7
Unaffiliated | Corporate and Other                      
Segment Reporting Information [Line Items]                      
Operating Revenues                 0.8 0.7 1.0
Intersegment | Gas Distribution Operations                      
Segment Reporting Information [Line Items]                      
Intersegment                 13.1 13.1 14.2
Intersegment | Electric Operations                      
Segment Reporting Information [Line Items]                      
Intersegment                 0.8 0.8 0.8
Intersegment | Corporate and Other                      
Segment Reporting Information [Line Items]                      
Intersegment                 $ 468.1 $ 517.6 $ 510.8
[1] Amounts differ from those presented on the Statements of Consolidated Cash Flows primarily due to the inclusion of capital expenditures included in current liabilities and AFUDC Equity.
(2) In 2019, Corporate and Other reflects an impairment charge of $204.8 million for goodwill related to Columbia of Massachusetts. For additional information, see Note 6, "Goodwill and Other Intangible Assets."
v3.19.3.a.u2
Quarterly Financial Data (Narrative) (Details) - USD ($)
$ in Millions
 3 Months Ended 6 Months Ended 12 Months Ended 16 Months Ended
Jul. 16, 2018
Dec. 31, 2019
Sep. 30, 2019
 [1]
Jun. 30, 2019
 [1]
Mar. 31, 2019
 [1]
Jun. 30, 2018
Dec. 31, 2019
Dec. 31, 2018
Dec. 31, 2017
Dec. 31, 2019
Quarterly Financial Data [Line Items]                    
Proceeds From Insurance Settlement   $ 130.0 [1] $ 260.0 $ 297.0 $ 108.0         $ 800.0
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Amount             $ 0.0 $ 0.0 $ 161.1  
Increase (Decrease) in Income Taxes               120.7    
Loss on early extinguishment of long-term debt $ 33.0         $ 12.5 0.0 (45.5) $ (111.5)  
Goodwill   1,485.9         1,485.9 1,690.7   1,485.9
Intangible Assets, Net (Excluding Goodwill)   0.0         0.0 220.7   $ 0.0
Interest Rate Swap Settled                    
Quarterly Financial Data [Line Items]                    
Derivative, Gain (Loss) on Derivative, Net             $ 0.0 [2] $ 46.2    
Columbia Of Massachusetts                    
Quarterly Financial Data [Line Items]                    
Expenses Related to Third Party Claims and Other Expenses   462.0                
Goodwill, Impairment Loss   204.8                
Impairment of Intangible Assets, Finite-lived   $ 209.7                
[1] $5 million of insurance recoveries were collected during 2018.
[2]
(3) See Note 9, "Risk Management Activities" for additional information.
v3.19.3.a.u2
Quarterly Financial Data (Schedule Of Quarterly Financial Data) (Details) - USD ($)
$ / shares in Units, $ in Millions
 3 Months Ended 12 Months Ended
Dec. 31, 2019
Sep. 30, 2019
Jun. 30, 2019
Mar. 31, 2019
Dec. 31, 2018
Sep. 30, 2018
Jun. 30, 2018
Mar. 31, 2018
Dec. 31, 2019
Dec. 31, 2018
Dec. 31, 2017
Quarterly Financial Data [Abstract]                      
Operating Revenues $ 1,397.2 $ 931.5 $ 1,010.4 $ 1,869.8 $ 1,461.7 $ 895.0 $ 1,007.0 $ 1,750.8 $ 5,208.9 $ 5,114.5 $ 4,874.6
Operating Income (Loss) (38.0) 91.0 463.5 374.2 (78.4) (315.9) 118.4 400.6 890.7 124.7 921.2
Net Income (Loss) (139.3) [1] 6.6 [2] 296.9 218.9 [3] (11.7) (339.5) 24.5   383.1 (50.6) 128.5
Preferred Dividends (13.7) (13.8) (13.8) (13.8) (8.1) (5.6) (1.3) 0.0 (55.1) (15.0) 0.0
Net Income (Loss) Available to Common Stockholders $ (153.0) [1] $ (7.2) [2] $ 283.1 $ 205.1 [3] $ (19.8) [1] $ (345.1) $ 23.2 [4] $ 276.1 $ 328.0 $ (65.6) $ 128.5
Basic Earnings (Loss) Per Share $ (0.41) $ (0.02) $ 0.76 $ 0.55 $ (0.05) $ (0.95) $ 0.07 $ 0.82 $ 0.88 $ (0.18) $ 0.39
Diluted Earnings (Loss) Per Share $ (0.41) $ (0.02) $ 0.75 $ 0.55 $ (0.05) $ (0.95) $ 0.07 $ 0.81 $ 0.87 $ (0.18) $ 0.39
[1] (4) Net loss for the fourth quarter of 2019 was impacted by an impairment charge of $204.8 million for goodwill and an impairment charge of $209.7 million for franchise rights, in each case related to Columbia of Massachusetts. For additional information, see Note 6, "Goodwill and Other Intangible Assets."
[2] Net loss for the third quarter of 2018 was impacted by approximately $462 million in expenses (pretax) related to the Greater Lawrence Incident restoration and a $33.0 million loss (pretax) on an early extinguishment of long-term debt. See Note 19-E, "Other Matters" and Note 14, "Long-Term Debt" for additional information.
[3]
(1) Net income for the first quarter of 2019 was impacted by $108.0 million in insurance recoveries (pretax) related to the Greater Lawrence Incident. See Note 19-E, "Other Matters" for additional information.
[4] Net income for the second quarter of 2019 was impacted by $297.0 million in insurance recoveries (pretax) related to the Greater Lawrence Incident. See Note 19-E, "Other Matters" for additional information.
v3.19.3.a.u2
Supplemental Cash Flow Information (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2019
Dec. 31, 2018
Dec. 31, 2017
Non-cash transactions:      
Capital expenditures included in current liabilities $ 223.6 $ 152.0 $ 173.0
Assets acquired under a finance lease 26.4 54.6 11.5
Assets acquired under an operating lease 13.4 0.0 0.0
Reclassification of other property to regulatory assets [1] 0.0 245.3 0.0
Assets recorded for asset retirement obligations [2] 54.6 78.1 11.4
Schedule of interest and income taxes paid:      
Cash paid for interest, net of interest capitalized amounts 349.7 354.2 339.9
Cash paid for income taxes, net of refunds $ 10.8 $ 3.3 $ 5.5
[1] See Note 8 "Regulatory Matters" for additional information.
[2] See Note 7 "Asset Retirement Obligations" for additional information.
v3.19.3.a.u2
Subsequent Event (Narrative) (Details) - Subsequent Event
$ in Millions
Feb. 26, 2020
USD ($)
Subsequent Event [Line Items]  
Purchase Price $ 1,100
Gain (Loss) on Sale of Assets and Asset Impairment Charges $ 360
v3.19.3.a.u2
Valuation and Qualifying Accounts (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2019
Dec. 31, 2018
Dec. 31, 2017
Reserve For Accounts Receivable [Member]      
SEC Schedule, 12-09, Valuation and Qualifying Accounts Disclosure [Line Items]      
Beginning Balance $ 21.1 $ 18.3 $ 23.3
Valuation Allowances and Reserves, Charged to Cost and Expense 21.6 20.2 14.8
Valuation Allowances and Reserves, Charged to Other Accounts [1] 41.3 43.7 39.1
Deductions for Purposes for which Reserves were Created 64.8 61.1 58.9
Ending Balance 19.2 21.1 18.3
Reserve For Other Investments [Member]      
SEC Schedule, 12-09, Valuation and Qualifying Accounts Disclosure [Line Items]      
Beginning Balance 3.0 3.0 3.0
Valuation Allowances and Reserves, Charged to Cost and Expense 0.0 0.0 0.0
Valuation Allowances and Reserves, Charged to Other Accounts [1] 0.0 0.0 0.0
Deductions for Purposes for which Reserves were Created 0.0 0.0 0.0
Ending Balance $ 3.0 $ 3.0 $ 3.0
[1] Charged to Other Accounts reflects the deferral of bad debt expense to a regulatory asset.