10-Q 1 ni-2018930x10q.htm 10-Q Document
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
þ  QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2018
or
¨  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from              to             
Commission file number 001-16189
NiSource Inc.
(Exact name of registrant as specified in its charter)
Delaware               
 
35-2108964        
(State or other jurisdiction of
incorporation or organization)
 
(I.R.S. Employer
Identification No.)
 
 
 
801 East 86th Avenue
Merrillville, Indiana    
 
46410
(Address of principal executive offices)
 
(Zip Code)
(877) 647-5990
(Registrant’s telephone number, including area code)
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes þ    No ¨
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files.)
Yes þ    No ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer" "smaller reporting company," and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer þ                    Accelerated filer ¨        Emerging growth company ¨
Non-accelerated filer ¨                      Smaller reporting company ¨
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes ¨    No þ

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date: Common Stock, $0.01 Par Value: 363,286,952 shares outstanding at October 23, 2018.



NISOURCE INC.
FORM 10-Q QUARTERLY REPORT
FOR THE QUARTER ENDED SEPTEMBER 30, 2018
Table of Contents
 
 
 
 
Page
 
 
 
 
 
 
 
PART I
FINANCIAL INFORMATION
 
 
 
 
 
 
Item 1.
Financial Statements - unaudited
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Item 2.
 
 
 
 
 
Item 3.
 
 
 
 
 
Item 4.
 
 
 
PART II
OTHER INFORMATION
 
 
 
 
 
 
Item 1.
 
 
 
 
 
Item 1A.
 
 
 
 
 
Item 2.
 
 
 
 
 
Item 3.
 
 
 
 
 
Item 4.
 
 
 
 
 
Item 5.
 
 
 
 
 
Item 6.
 
 
 
 

2


DEFINED TERMS

The following is a list of frequently used abbreviations or acronyms that are found in this report:

 
NiSource Subsidiaries, Affiliates and Former Subsidiaries
Columbia of Kentucky
Columbia Gas of Kentucky, Inc.
Columbia of Maryland
Columbia Gas of Maryland, Inc.
Columbia of Massachusetts
Bay State Gas Company
Columbia of Ohio
Columbia Gas of Ohio, Inc.
Columbia of Pennsylvania
Columbia Gas of Pennsylvania, Inc.
Columbia of Virginia
Columbia Gas of Virginia, Inc.
NIPSCO
Northern Indiana Public Service Company LLC
NiSource ("we," "us" or “our”)
NiSource Inc.
 
 
Abbreviations and Other
 
ACE
Affordable Clean Energy
AFUDC
Allowance for funds used during construction
AMRP
Accelerated Main Replacement Program
AOCI
Accumulated Other Comprehensive Income (Loss)
ASC
Accounting Standards Codification
ASU
Accounting Standards Update
ATM
At-the-market
CAA
Clean Air Act
CCRs
Coal Combustion Residuals
CEP
Capital Expenditure Program
CERCLA
Comprehensive Environmental Response Compensation and Liability Act (also known as Superfund)
CO2
Carbon Dioxide
CPP
Clean Power Plan
DPU
Department of Public Utilities
EGUs
Electric Utility Generating Units
ELG
Effluent limitations guidelines
EPA
United States Environmental Protection Agency
EPS
Earnings per share
FAC
Fuel adjustment clause
FASB
Financial Accounting Standards Board
FERC
Federal Energy Regulatory Commission
GAAP
Generally Accepted Accounting Principles
GCA
Gas cost adjustment
GCR
Gas cost recovery
GHG
Greenhouse gases
GSEP
Gas System Enhancement Program
gwh
Gigawatt hours
IRP
Infrastructure Replacement Program
IRS
Internal Revenue Service
IURC
Indiana Utility Regulatory Commission
LDCs
Local distribution companies
LIBOR
London InterBank Offered Rate

3


DEFINED TERMS

LIFO
Last In, First Out
MGP
Manufactured Gas Plant
MISO
Midcontinent Independent System Operator
MMDth
Million dekatherms
NOL
Net operating loss
NTSB
National Transportation Safety Board
NYMEX
New York Mercantile Exchange
OPEB
Other Postretirement Benefits
PHMSA
Pipeline and Hazardous Materials Safety Administration
PSC
Public Service Commission
PUC
Public Utility Commission
PUCO
Public Utilities Commission of Ohio
Pure Air
Pure Air on the Lake LP
RCRA
Resource Conservation and Recovery Act
SEC
Securities and Exchange Commission
STRIDE
Strategic Infrastructure Development Enhancement
TCJA
An Act to provide for reconciliation pursuant to titles II and V of the concurrent resolution on the budget for fiscal year 2018 (commonly known as the Tax Cuts and Jobs Act of 2017)
TDSIC
Transmission, Distribution and Storage System Improvement Charge
VIE
Variable Interest Entities
VSCC
Virginia State Corporation Commission
WCE
Whiting Clean Energy
Note regarding forward-looking statements
This Quarterly Report on Form 10-Q contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the "Securities Act") and Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). Investors and prospective investors should understand that many factors govern whether any forward-looking statement contained herein will be or can be realized. Any one of those factors could cause actual results to differ materially from those projected. These forward-looking statements include, but are not limited to, statements concerning NiSource’s plans, strategies, objectives, expected performance, expenditures, recovery of expenditures through rates, stated on either a consolidated or segment basis, and any and all underlying assumptions and other statements that are other than statements of historical fact. All forward-looking statements are based on assumptions that management believes to be reasonable; however, there can be no assurance that actual results will not differ materially.
Factors that could cause actual results to differ materially from the projections, forecasts, estimates and expectations discussed in this Quarterly Report on Form 10-Q include, among other things, our debt obligations; any changes in our credit rating; our ability to execute our growth strategy; changes in general economic, capital and commodity market conditions; pension funding obligations; economic regulation and the impact of regulatory rate reviews; our ability to obtain expected financial or regulatory outcomes; advances in technology; any damage to our reputation; compliance with environmental laws and the costs of associated liabilities; fluctuations in demand from residential and commercial customers; economic conditions of certain industries; the success of NIPSCO's electric generation strategy; the price of energy commodities and related transportation costs; the reliability of customers and suppliers to fulfill their payment and contractual obligations; potential impairments of goodwill or definite-lived intangible assets; changes in taxation and accounting principles; potential incidents and other operating risks associated with our business; impacts from the Greater Lawrence Incident (as defined in this report) (including any changes in management's estimates or assumptions regarding financial impact, the timing and amount of insurance recoveries, the outcomes of governmental investigations, changes to state and federal legislation or regulation impacting our operating practices, and our ability to recover our costs through rates or offset them through operational or other cost savings); the impact of an aging infrastructure; the impact of climate change; potential cyber-attacks; construction risks and natural gas costs and supply risks; extreme weather conditions; the attraction and retention of a qualified workforce; the ability of our subsidiaries to generate cash; tax liabilities associated with the separation of Columbia Pipeline Group, Inc. on July 1, 2015; our ability to manage new initiatives and organizational changes; the performance of certain third-party suppliers upon which we rely; our ability to obtain sufficient insurance coverage; and other matters set forth in the “Risk Factors” section of this report and our Annual Report on Form 10-K for the fiscal year ended December

4


31, 2017, many of which risks are beyond our control. In addition, the relative contributions to profitability by each business segment, and the assumptions underlying the forward-looking statements relating thereto, may change over time.
All forward-looking statements are expressly qualified in their entirety by the foregoing cautionary statements. We undertake no obligation to, and expressly disclaim any such obligation to, update or revise any forward-looking statements to reflect changed assumptions, the occurrence of anticipated or unanticipated events or changes to the future results over time or otherwise, except as required by law.

5


Index
Page


6


PART I

ITEM 1. FINANCIAL STATEMENTS
NiSource Inc.
Condensed Statements of Consolidated Income (Loss) (unaudited)
  
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
(in millions, except per share amounts)
2018
 
2017
 
2018
 
2017
Operating Revenues
 
 
 
 
 
 
Customer revenues
$
855.8

 
$
883.4

 
$
3,555.1

 
$
3,386.0

Other revenues
39.2

 
33.6

 
97.7

 
120.3

Total Operating Revenues
895.0

 
917.0

 
3,652.8

 
3,506.3

Operating Expenses
 
 
 
 
 
 
 
Cost of sales (excluding depreciation and amortization)
222.0

 
233.6

 
1,259.7

 
1,062.7

Operation and maintenance
780.8

 
371.7

 
1,548.5

 
1,174.9

Depreciation and amortization
148.5

 
143.0

 
437.8

 
428.5

Loss (Gain) on sale of assets and impairments, net
0.7

 

 
0.4

 
(0.1
)
Other taxes
58.9

 
57.5

 
203.3

 
189.7

Total Operating Expenses
1,210.9

 
805.8

 
3,449.7

 
2,855.7

Operating Income (Loss)
(315.9
)
 
111.2

 
203.1

 
650.6

Other Income (Deductions)
 
 
 
 
 
 
 
Interest expense, net
(83.4
)
 
(87.9
)
 
(265.2
)
 
(260.8
)
Other, net
(1.7
)
 
(6.8
)
 
42.4

 
(0.3
)
Loss on early extinguishment of long-term debt
(33.0
)
 

 
(45.5
)
 
(111.5
)
Total Other Deductions, Net
(118.1
)
 
(94.7
)
 
(268.3
)
 
(372.6
)
Income (Loss) before Income Taxes
(434.0
)

16.5


(65.2
)

278.0

Income Taxes
(94.5
)
 
2.5

 
(26.3
)
 
97.1

Net Income (Loss)
(339.5
)
 
14.0

 
(38.9
)
 
180.9

Preferred dividends
(5.6
)
 

 
(6.9
)
 

Net Income (Loss) Available to Common Shareholders
(345.1
)
 
14.0

 
(45.8
)
 
180.9

Earnings (Loss) Per Share
 
 
 
 
 
 
 
Basic Earnings (Loss) Per Share
$
(0.95
)

$
0.04


$
(0.13
)

$
0.55

Diluted Earnings (Loss) Per Share
$
(0.95
)
 
$
0.04

 
$
(0.13
)
 
$
0.55

Dividends Declared Per Common Share
$
0.195

 
$
0.175

 
$
0.780

 
$
0.700

Basic Average Common Shares Outstanding
363.9

 
331.1

 
352.1

 
326.7

Diluted Average Common Shares
363.9

 
332.4

 
352.1

 
328.0


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

7

Table of Contents
ITEM 1. FINANCIAL STATEMENTS (continued)


NiSource Inc.
Condensed Statements of Consolidated Comprehensive Income (Loss) (unaudited)

 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
(in millions, net of taxes)
2018
 
2017
 
2018
 
2017
Net Income (Loss)
$
(339.5
)
 
$
14.0

 
$
(38.9
)
 
$
180.9

Other comprehensive income (loss):
 
 
 
 
 
 
 
 Net unrealized gain (loss) on available-for-sale securities(1)
0.1

 
0.1

 
(2.3
)
 
1.1

Net unrealized gain (loss) on cash flow hedges(2)
22.5

 
(9.3
)
 
56.5

 
(21.2
)
Unrecognized pension and OPEB benefit(3)
0.8

 
1.1

 
1.2

 
1.5

Total other comprehensive income (loss)
23.4

 
(8.1
)
 
55.4

 
(18.6
)
Comprehensive Income (Loss)
$
(316.1
)
 
$
5.9


$
16.5


$
162.3

(1) Net unrealized gain (loss) on available-for-sale securities, net of zero tax expense in the third quarter of 2018 and 2017, and $0.6 million tax benefit and $0.6 million tax expense for the nine months ended 2018 and 2017, respectively.
(2) Net unrealized gain (loss) on cash flow hedges, net of $7.5 million tax expense and $5.8 million tax benefit in the third quarter of 2018 and 2017, respectively, and $18.7 million tax expense and $13.1 million tax benefit for the nine months ended 2018 and 2017, respectively. See Note 8, "Risk Management Activities," for additional information.
(3) Unrecognized pension and OPEB benefit, net of zero and $0.5 million tax expense in the third quarter of 2018 and 2017, respectively, and $0.2 million and $0.8 million tax expense for the nine months ended 2018 and 2017, respectively.
The accompanying Notes to Condensed Consolidated Financial Statements (unaudited) are an integral part of these statements.

8

Table of Contents
ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.
Condensed Consolidated Balance Sheets (unaudited)
(in millions)
September 30,
2018
 
December 31,
2017
ASSETS
 
 
 
Property, Plant and Equipment
 
 
 
Utility plant
$
22,328.2

 
$
21,026.6

Accumulated depreciation and amortization
(7,171.0
)
 
(6,953.6
)
Net utility plant
15,157.2

 
14,073.0

Other property, at cost, less accumulated depreciation
17.2

 
286.5

Net Property, Plant and Equipment
15,174.4

 
14,359.5

Investments and Other Assets
 
 
 
Unconsolidated affiliates
2.6

 
5.5

Other investments
214.5

 
204.1

Total Investments and Other Assets
217.1

 
209.6

Current Assets
 
 
 
Cash and cash equivalents
41.8

 
29.0

Restricted cash
12.0

 
9.4

Accounts receivable (less reserve of $13.0 and $18.3, respectively)
500.4

 
898.9

Gas inventory
320.2

 
285.1

Materials and supplies, at average cost
97.7

 
105.9

Electric production fuel, at average cost
49.0

 
80.1

Exchange gas receivable
37.3

 
45.8

Regulatory assets
221.0

 
176.3

Prepayments and other
89.7

 
132.8

Total Current Assets
1,369.1

 
1,763.3

Other Assets
 
 
 
Regulatory assets
1,907.4

 
1,624.9

Goodwill
1,690.7

 
1,690.7

Intangible assets, net
223.5

 
231.7

Deferred charges and other
117.2

 
82.0

Total Other Assets
3,938.8

 
3,629.3

Total Assets
$
20,699.4

 
$
19,961.7

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

9

Table of Contents
ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.
Condensed Consolidated Balance Sheets (unaudited) (continued)
(in millions, except share amounts)
September 30,
2018
 
December 31,
2017
CAPITALIZATION AND LIABILITIES
 
 
 
Capitalization
 
 
 
Stockholders’ Equity
 
 
 
Common stock - $0.01 par value, 400,000,000 shares authorized; 363,167,067 and 337,015,806 shares outstanding, respectively
$
3.7

 
$
3.4

Preferred stock - $1,000 par value, 20,000,000 shares authorized; 400,000 shares outstanding
393.9

 

Treasury stock
(99.9
)
 
(95.9
)
Additional paid-in capital
6,161.0

 
5,529.1

Retained deficit
(1,387.5
)
 
(1,073.1
)
Accumulated other comprehensive income (loss)
2.5

 
(43.4
)
Total Stockholders’ Equity
5,073.7

 
4,320.1

Long-term debt, excluding amounts due within one year
7,094.5

 
7,512.2

Total Capitalization
12,168.2


11,832.3

Current Liabilities
 
 
 
Current portion of long-term debt
48.6

 
284.3

Short-term borrowings
1,611.0

 
1,205.7

Accounts payable
433.7

 
625.6

Dividends payable - common stock
70.8

 

Dividends payable - preferred stock
11.6

 

Customer deposits and credits
238.4

 
262.6

Taxes accrued
150.0

 
208.1

Interest accrued
108.0

 
112.3

Risk management liabilities
4.8

 
43.2

Exchange gas payable
58.2

 
59.6

Regulatory liabilities
81.9

 
58.7

Legal and environmental
20.4

 
32.1

Accrued compensation and employee benefits
153.4

 
195.4

Claims accrued
365.9

 
12.5

Other accruals
54.5

 
78.3

Total Current Liabilities
3,411.2

 
3,178.4

Other Liabilities
 
 
 
Risk management liabilities
45.2

 
28.5

Deferred income taxes
1,291.7

 
1,292.9

Deferred investment tax credits
11.7

 
12.4

Accrued insurance liabilities
81.8

 
80.1

Accrued liability for postretirement and postemployment benefits
300.9

 
337.1

Regulatory liabilities
2,826.8

 
2,736.9

Asset retirement obligations
346.9

 
268.7

Other noncurrent liabilities
215.0

 
194.4

Total Other Liabilities
5,120.0

 
4,951.0

Commitments and Contingencies (Refer to Note 16, "Other Commitments and Contingencies")

 

Total Capitalization and Liabilities
$
20,699.4

 
$
19,961.7

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

10

Table of Contents
ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.
Condensed Statements of Consolidated Cash Flows (unaudited)

Nine Months Ended September 30, (in millions)
2018
 
2017
Operating Activities
 
 
 
Net Income (Loss)
$
(38.9
)
 
$
180.9

Adjustments to Reconcile Net Income to Net Cash from Operating Activities:
 
 
 
Loss on early extinguishment of debt
45.5

 
111.5

Depreciation and amortization
437.8

 
428.5

Deferred income taxes and investment tax credits
(26.4
)
 
96.3

Other adjustments
15.6

 
28.5

Changes in Assets and Liabilities:
 
 
 
Components of working capital
442.9

 
32.6

Regulatory assets/liabilities
61.3

 
(12.9
)
Postretirement and postemployment benefits
(41.4
)
 
(314.5
)
Deferred charges and other noncurrent assets
0.8

 
(3.7
)
Other noncurrent liabilities
30.0

 
(17.6
)
Net Cash Flows from Operating Activities
927.2

 
529.6

Investing Activities
 
 
 
Capital expenditures
(1,296.6
)
 
(1,216.4
)
Cost of removal
(72.6
)
 
(78.9
)
Purchases of available-for-sale securities
(71.4
)
 
(139.4
)
Sales of available-for-sale securities
58.5

 
129.4

Other investing activities
5.6

 
(1.4
)
Net Cash Flows used for Investing Activities
(1,376.5
)
 
(1,306.7
)
Financing Activities
 
 
 
Issuance of long-term debt
350.0

 
2,750.0

Repayments of long-term debt and capital lease obligations
(1,044.0
)
 
(1,352.4
)
Premiums and other debt related costs
(46.1
)
 
(139.8
)
Issuance of short-term debt (maturity > 90 days)
600.0

 

Change in short-term borrowings, net (maturity ≤ 90 days)
(194.6
)
 
(644.9
)
Issuance of common stock
611.6

 
332.6

Issuance of preferred stock
394.3

 

Acquisition of treasury stock
(4.0
)
 
(5.9
)
Dividends paid - common stock
(202.5
)
 
(170.2
)
Net Cash Flows from Financing Activities
464.7

 
769.4

Change in cash, cash equivalents and restricted cash
15.4

 
(7.7
)
Cash, cash equivalents and restricted cash at beginning of period
38.4

 
36.0

Cash, Cash Equivalents and Restricted Cash at End of Period
$
53.8

 
$
28.3


Supplemental Disclosures of Cash Flow Information
Nine Months Ended September 30, (in millions)
2018
 
2017
Non-cash transactions:
 
 
 
Capital expenditures included in current liabilities
$
167.5

 
$
219.1

Dividends declared but not paid
82.4

 
58.9

Reclassification of other property to regulatory assets(1)
245.3

 

Change in estimated costs of asset retirement obligations(2)
$
70.7

 
$

(1)See Note 16-D "Other Matters" for additional information.
(2)See Note 6 "Asset Retirement Obligations" for additional information.

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

11

Table of Contents
ITEM 1. FINANCIAL STATEMENTS (continued)


NiSource Inc.
Condensed Statements of Consolidated Equity (unaudited)
(in millions)
Common
Stock
 
Preferred Stock
 
Treasury
Stock
 
Additional
Paid-In
Capital
 
Retained
Deficit
 
Accumulated
Other
Comprehensive
Income (Loss)
 
Total
Balance as of January 1, 2018
$
3.4

 
$

 
$
(95.9
)
 
$
5,529.1

 
$
(1,073.1
)
 
$
(43.4
)
 
$
4,320.1

Comprehensive Income:
 
 
 
 
 
 
 
 
 
 
 
 
 
Net Loss

 

 

 

 
(38.9
)
 

 
(38.9
)
Other comprehensive income, net of tax

 

 

 

 

 
55.4

 
55.4

Common stock dividends ($0.78 per share)

 

 

 

 
(273.4
)
 

 
(273.4
)
Preferred stock dividends ($28.88 per share)

 

 

 

 
(11.6
)
 

 
(11.6
)
Treasury stock acquired

 

 
(4.0
)
 

 

 

 
(4.0
)
Cumulative effect of change in accounting principle(1)

 

 

 

 
9.5

 
(9.5
)
 

Stock issuances:
 
 
 
 
 
 
 
 
 
 
 
 
 
Common stock - private placement(2)
0.3

 

 

 
599.3

 

 

 
599.6

Preferred stock(2)

 
393.9

 

 

 

 

 
393.9

Employee stock purchase plan

 

 

 
4.2

 

 

 
4.2

Long-term incentive plan

 

 

 
11.5

 

 

 
11.5

401(k) and profit sharing

 

 

 
16.9

 

 

 
16.9

Balance as of September 30, 2018
$
3.7

 
$
393.9

 
$
(99.9
)
 
$
6,161.0

 
$
(1,387.5
)
 
$
2.5

 
$
5,073.7

(1) See Note 2, "Recent Accounting Pronouncements," for additional information.
(2) See Note 5, "Equity," for additional information.

 
Preferred
 
Common
(in thousands)
Shares
 
Shares
 
Treasury
 
Outstanding
Balance as of January 1, 2018

 
340,813

 
(3,797
)
 
337,016

Treasury Stock acquired

 

 
(166
)
 
(166
)
Issued:
 
 
 
 
 
 
 
Common stock - private placement(1)

 
24,964

 

 
24,964

Preferred stock(1)
400

 

 

 

Employee stock purchase plan

 
166

 

 
166

Long-term incentive plan

 
499

 

 
499

401(k) and profit sharing

 
688

 

 
688

Balance as of September 30, 2018
400

 
367,130

 
(3,963
)
 
363,167

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


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


12

Table of Contents
ITEM 1. FINANCIAL STATEMENTS (continued)
NiSource Inc.
Notes to Condensed Consolidated Financial Statements (unaudited)

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

Recently Issued Accounting Pronouncements

We are currently evaluating the impact of certain ASUs on our Condensed Consolidated Financial Statements (unaudited) and Notes to Condensed Consolidated Financial Statements (unaudited), which are described below:

Standard
Description
Effective Date
Effect on the financial statements or other significant matters
ASU 2018-14, Compensation—Retirement Benefits—Defined Benefit Plans—General (Subtopic 715-20): Disclosure Framework—Changes to the Disclosure Requirements for Defined Benefit Plans
The pronouncement modifies the disclosure requirements for defined benefit pension or other postretirement benefit plans. The guidance removes disclosures that are no longer considered cost beneficial, clarifies the specific requirements of disclosures and adds disclosure requirements identified as relevant. The modifications affect annual period disclosures and must be applied on a retrospective basis to all periods presented.
Annual periods ending after December 15, 2020. Early adoption is permitted.
We are currently evaluating the effects of this pronouncement on our Notes to Condensed Consolidated Financial Statements (unaudited), including potential early adoption in the fourth quarter of 2018.

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

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ITEM 1. FINANCIAL STATEMENTS (continued)
NiSource Inc.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

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

ASU 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842
The pronouncement offers a practical expedient for accounting for land easements under ASU 2016-02. This practical expedient allows an entity the option of not evaluating existing land easements under ASC 842. New or modified land easements will still require evaluation under ASC 842 on a prospective basis beginning on the date of adoption.
ASU 2016-02, Leases (Topic 842)
The pronouncement introduces a lessee model that brings most leases on the balance sheet. The standard requires that lessees recognize the following for all leases (with the exception of short-term leases, as that term is defined in the standard) at the lease commencement date: (1) a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and (2) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term.

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Table of Contents
ITEM 1. FINANCIAL STATEMENTS (continued)
NiSource Inc.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

Recently Adopted Accounting Pronouncements
Standard
Adoption
ASU 2018-15, Intangibles—Goodwill and Other— Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract
In August 2018, the FASB issued this ASU, which amends current guidance to align the accounting for costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing costs associated with developing or obtaining internal-use software.

We elected to early adopt the ASU on a prospective basis, effective October 1, 2018. As a result of adopting this ASU, we will defer onto the balance sheet those up-front implementation costs of cloud computing arrangements if they would have been capitalized in a similar on-premise software solution.
ASU 2018-02, Income Statement—Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income
We adopted this ASU effective March 31, 2018. Upon adoption, $9.5 million of tax effects that were stranded in accumulated other comprehensive income (loss) as a result of the implementation of the TCJA were reclassified to retained deficit. This change is reflected on our Condensed Statements of Consolidated Equity (unaudited).
ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force)
We adopted this ASU effective January 1, 2018. The adoption of this standard did not have a material impact on our Condensed Consolidated Financial Statements (unaudited) or Notes to Condensed Consolidated Financial Statements (unaudited).
ASU 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients
See Note 3, "Revenue Recognition," for our discussion of the effects of implementing these standards.
ASU 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations
ASU 2014-09, Revenue from Contracts with Customers (Topic 606)
We also adopted ASU 2017-07, Compensation -  Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, effective January 1, 2018. We continue to present the service cost component of net periodic benefit cost within "Operation and maintenance;" however, other components of the net periodic benefit cost (including regulatory deferrals and settlement charges) are now presented separately within "Other, net" on our Condensed Statements of Consolidated Income (Loss) (unaudited).

15

Table of Contents
ITEM 1. FINANCIAL STATEMENTS (continued)
NiSource Inc.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

Changes in income statement presentation were implemented on a retrospective basis. The impact of this ASU on previously issued annual financial statements is summarized in the tables below:
Year Ended December 31, 2016 (in millions)
 
As Previously Reported
 
Effect of Change(1)
 
As Adjusted
Operation and maintenance
 
$
1,453.7

 
$
(7.9
)
 
$
1,445.8

Total Operating Expenses
 
3,634.3

 
(7.9
)
 
3,626.4

Operating Income
 
858.2

 
7.9

 
866.1

Other Income (Deductions)
 
 
 
 
 
 
Other, net
 
1.5

 
(7.9
)
 
(6.4
)
Total Other Deductions
 
(348.0
)
 
(7.9
)
 
(355.9
)
Income before Income Taxes
 
$
510.2

 
$

 
$
510.2

(1) The effect of this change is attributable to our business segments: Gas Distribution Operations, Electric Operations, and Corporate and Other in the amounts of $4.3 million, $(9.8) million, and $(2.4) million, respectively.
Year Ended December 31, 2017 (in millions)
 
As Previously Reported
 
Effect of Change(1)
 
As Adjusted
Operation and maintenance
 
$
1,612.3

 
$
(10.6
)
 
$
1,601.7

Total Operating Expenses
 
3,964.0

 
(10.6
)
 
3,953.4

Operating Income
 
910.6

 
10.6

 
921.2

Other Income (Deductions)
 
 
 
 
 
 
Other, net
 
(2.8
)
 
(10.6
)
 
(13.4
)
Total Other Deductions
 
(467.5
)
 
(10.6
)
 
(478.1
)
Income before Income Taxes
 
$
443.1

 
$

 
$
443.1

(1) The effect of this change is attributable to our business segments: Gas Distribution Operations, Electric Operations, and Corporate and Other in the amounts of $(4.4) million, $(2.6) million, and $(3.6) million, respectively.
3.    Revenue Recognition
ASC 606 Adoption. In 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (ASC 606). ASU 2014-09 outlines a single, comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance. The core principle of the new standard is that an entity should recognize revenue to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. In 2016, the FASB issued ASU 2016-08, Revenue from Contracts with Customers (ASC 606): Principal versus Agent Considerations, and ASU 2016-12, Revenue from Contracts with Customers (ASC 606): Narrow-Scope Improvements and Practical Expedients. We adopted the provisions of ASC 606 beginning on January 1, 2018 using a modified retrospective method, which was applied to all contracts. No material adjustments were made to January 1, 2018 opening balances as a result of the adoption. As required under the modified retrospective method of adoption, results for reporting periods beginning after January 1, 2018 are presented under ASC 606, while prior period amounts are not adjusted and continue to be reported in accordance with ASC 605.

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Table of Contents
ITEM 1. FINANCIAL STATEMENTS (continued)
NiSource Inc.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)


The table below provides results for the three and nine months ended September 30, 2018 as if they had been prepared under historic accounting guidance. We included operating revenue information for the three and nine months ended September 30, 2017 for comparability.
 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
(in millions)
2018
 
2017
 
2018
 
2017
Operating Revenues
 
 
 
 
 
 
 
Gas Distribution
$
232.3

 
$
239.4

 
$
1,600.3

 
$
1,403.0

Gas Transportation
186.0

 
191.6

 
745.2

 
735.1

Electric
476.2

 
485.8

 
1,304.4

 
1,365.5

Other
0.5

 
0.2

 
2.9

 
2.7

Total Operating Revenues
$
895.0

 
$
917.0

 
$
3,652.8

 
$
3,506.3


Beginning in 2018 with the adoption of ASC 606, the Condensed Statements of Consolidated Income (Loss) (unaudited) disaggregates “Customer revenues” (i.e. ASC 606 Revenues) from “Other revenues,” both of which are discussed in more detail below.
Customer Revenues. Substantially all of our revenues are tariff-based, which we have concluded is within the scope of ASC 606. Under ASC 606, the recipients of our utility service meet the definition of a customer, while the operating company tariffs represent an agreement that meets the definition of a contract. ASC 606 defines a contract as an agreement between two or more parties, in this case us and the customer, which creates enforceable rights and obligations. In order to be considered a contract, we have determined that it is probable that substantially all of the consideration to which we are entitled from customers will be collected upon satisfaction of performance obligations. We maintain common utility credit risk mitigation practices, including requiring deposits and actively pursuing collection of past due amounts. In addition, our regulated operations utilize certain regulatory mechanisms that facilitate recovery of bad debt costs within tariff-based rates, which provides further evidence of collectibility.
We have identified our performance obligations created under tariff-based sales as 1) the commodity (natural gas or electricity, which includes generation and capacity) and 2) delivery. These commodities are sold and / or delivered to and generally consumed by customers simultaneously, leading to satisfaction of our performance obligations over time as gas or electricity is delivered to customers. Due to the at-will nature of utility customers, performance obligations are limited to the services requested and received to date. Once complete, we generally maintain no additional performance obligations.
Transaction prices for each performance obligation are generally prescribed by each operating company’s respective tariff. Rates include provisions to adjust billings for fluctuations in fuel and purchased power costs and cost of natural gas. Revenues are adjusted for differences between actual costs subject to reconciliation and the amounts billed in current rates. Under or over recovered revenues related to these cost recovery mechanisms are included in regulatory assets or liabilities on the Condensed Consolidated Balance Sheets (unaudited) and are recovered from or returned to customers through adjustments to tariff rates. As we provide and deliver service to customers, revenue is recognized based on the transaction price allocated to each performance obligation. In general, revenue recognized from tariff-based sales is equivalent to the value of natural gas or electricity supplied and billed each period, in addition to an estimate for deliveries completed during the period but not yet billed to the customer.
In addition to tariff-based sales, our Gas Distribution Operations segment enters into balancing and exchange arrangements of natural gas as part of our operations and off-system sales programs. We have concluded that these sales are within the scope of ASC 606. Performance obligations for these types of sales include transportation and storage of natural gas and can be satisfied at a point in time or over a period of time, depending on the specific transaction. For those transactions that span a period of time, we record a receivable or payable for any cumulative gas imbalances, as well as for any gas inventory borrowed or lent under a Gas Distributions Operations exchange agreement.
Revenue Disaggregation and Reconciliation. We disaggregate revenue from contracts with customers based upon reportable segment as well as by customer class. As our revenues are primarily earned over a period of time, and we do not earn a material amount of revenues at a point in time, revenues are not disaggregated as such below. The Gas Distribution Operations segment provides natural gas service and transportation for residential, commercial and industrial customers in Ohio, Pennsylvania, Virginia,

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Table of Contents
ITEM 1. FINANCIAL STATEMENTS (continued)
NiSource Inc.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

Kentucky, Maryland, Indiana and Massachusetts. The Electric Operations segment provides electric service in 20 counties in the northern part of Indiana.
The table below reconciles revenue disaggregation by customer class to segment revenue as well as to revenues reflected on the Condensed Statements of Consolidated Income (Loss) (unaudited):
Three Months Ended September 30, 2018
(in millions)
Gas Distribution Operations
 
Electric Operations
 
Corporate and Other
 
Total
Customer Revenues(1)
 
 
 
 
 
 
 
Residential
$
257.0

 
$
154.7

 
$

 
$
411.7

Commercial
80.9

 
140.7

 

 
221.6

Industrial
39.0

 
153.6

 

 
192.6

Off-system
20.4

 

 

 
20.4

Miscellaneous
9.2

 
0.1

 
0.2

 
9.5

Total Customer Revenues
$
406.5

 
$
449.1

 
$
0.2

 
$
855.8

Other Revenues
12.1

 
27.1

 

 
39.2

Total Operating Revenues
$
418.6

 
$
476.2

 
$
0.2

 
$
895.0

(1) Customer revenue amounts exclude intersegment revenues. See Note 19, "Business Segment Information," for discussion of intersegment revenues.
Nine Months Ended September 30, 2018
(in millions)
Gas Distribution Operations
 
Electric Operations
 
Corporate and Other
 
Total
Customer Revenues(1)
 
 
 
 
 
 
 
Residential
$
1,540.3

 
$
382.3

 
$

 
$
1,922.6

Commercial
516.2

 
374.2

 

 
890.4

Industrial
161.3

 
468.1

 

 
629.4

Off-system
63.6

 

 

 
63.6

Miscellaneous
36.2

 
12.3

 
0.6

 
49.1

Total Customer Revenues
$
2,317.6

 
$
1,236.9

 
$
0.6

 
$
3,555.1

Other Revenues
30.2

 
67.5

 

 
97.7

Total Operating Revenues
$
2,347.8

 
$
1,304.4

 
$
0.6

 
$
3,652.8

(1) Customer revenue amounts exclude intersegment revenues. See Note 19, "Business Segment Information," for discussion of intersegment revenues.
Customer Accounts Receivable. Accounts receivable on our Condensed Consolidated Balance Sheets (unaudited) includes both billed and unbilled amounts as well as certain amounts that are not related to customer revenues. Unbilled amounts of accounts receivable relate to a portion of a customer’s consumption of gas or electricity from the date of the last cycle billing through the last day of the month (balance sheet date). Factors taken into consideration when estimating unbilled revenue include historical usage, customer rates and weather. The opening and closing balances of customer receivables for the nine months ended September 30, 2018 are presented in the table below. We had no significant contract assets or liabilities during the period. Additionally, we have not incurred any significant costs to obtain or fulfill contracts.
(in millions)
Customer Accounts Receivable, Billed (less reserve)(1)
 
Customer Accounts Receivable, Unbilled (less reserve)(2)
Balance as of December 31, 2017
$
477.0

 
$
356.0

Balance as of September 30, 2018
297.2

 
154.8

Increase (Decrease)
$
(179.8
)
 
$
(201.2
)
(1) Customer billed receivables decreased over the period due to the expected seasonal decrease in customer usage in September when compared to December.
(2) Customer unbilled receivables decreased over the period due to the expected seasonal decrease in customer usage in September when compared to December.


18

Table of Contents
ITEM 1. FINANCIAL STATEMENTS (continued)
NiSource Inc.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

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

4.    Earnings Per Share
Basic EPS is computed by dividing net income available to common shareholders by the weighted-average number of shares of common stock outstanding for the period. The weighted-average shares outstanding for diluted EPS includes the incremental effects of the various long-term incentive compensation plans. The computation of diluted average common shares for the three and nine months ended September 30, 2018 is not presented since we had a net loss on the Condensed Statements of Consolidated Income (Loss) (unaudited) during the periods, and any incremental shares would have had an anti-dilutive impact on EPS. The computation of diluted average common shares is as follows:
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
(in thousands)
 
2017
 
2017
Denominator
 
 
 
 
Basic average common shares outstanding
 
331,139

 
326,662

Dilutive potential common shares:
 
 
 
 
Shares contingently issuable under employee stock plans
 
604

 
503

Shares restricted under employee stock plans
 
653

 
866

Diluted Average Common Shares
 
332,396

 
328,031


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

 
10,612,915

 

 
11,931,376

Average price per share
$

 
$
26.67

 
$

 
$
26.58

Proceeds, net of fees (in millions)
$

 
$
281.0

 
$

 
$
314.7

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

19

Table of Contents
ITEM 1. FINANCIAL STATEMENTS (continued)
NiSource Inc.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

would have received approximately $168.7 million, based on a net price of $26.59 per share.
Private Placement of Common Stock. On May 4, 2018, we completed the sale of 24,964,163 shares of $0.01 par value common stock at a price of $24.28 per share in a private placement to selected institutional and accredited investors. The private placement resulted in $606.0 million of gross proceeds or $599.6 million of net proceeds, after deducting commissions and sale expenses. The common stock issued in connection with the private placement was registered on Form S-1, filed with the SEC on May 11, 2018.
Private Placement of Preferred Stock. On June 11, 2018, we completed the sale of 400,000 shares of 5.650% Series A Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Stock (the "Series A Preferred Stock") at a price of $1,000 per share. The transaction resulted in $400.0 million of gross proceeds or $393.9 million of net proceeds, after deducting commissions and sales expenses. The Series A Preferred Stock was issued in a private placement pursuant to SEC Rule 144A. We agreed pursuant to a registration rights agreement to file with the SEC a registration statement enabling holders to exchange their unregistered shares of Series A Preferred Stock for publicly registered shares with substantially identical terms.
Proceeds from the issuance of the Series A Preferred Stock were used to pay a portion of the notes tendered in June 2018 and the redemption of the remaining notes in July 2018. See Note 14, “Long-term Debt” for additional information regarding the tender offer and redemption.
Dividends on the Series A Preferred Stock accrue and are cumulative from the date the shares of Series A Preferred Stock were originally issued to, but not including, June 15, 2023 at a rate of 5.650% per annum of the $1,000 liquidation preference per share. On and after June 15, 2023, dividends on the Series A Preferred Stock will accumulate for each five year period at a percentage of the $1,000 liquidation preference equal to the five-year U.S. Treasury Rate plus (i) in respect of each five year period commencing on or after June 15, 2023 but before June 15, 2043, a spread of 2.843% (the “Initial Margin”), and (ii) in respect of each five year period commencing on or after June 15, 2043, the Initial Margin plus 1.000%. The Series A Preferred Stock may be redeemed by us at our option on June 15, 2023, or on each date falling on the fifth anniversary thereafter, or in connection with a ratings event (as defined in the Certificate of Designation of the Series A Preferred Stock).
Holders of Series A Preferred Stock generally have no voting rights, except for limited voting rights with respect to (i) potential amendments to our certificate of incorporation that would have a material adverse effect on the existing preferences, rights, powers or duties of the Series A Preferred Stock, (ii) the creation or issuance of any security ranking on a parity with the Series A Preferred Stock if the cumulative dividends payable on then outstanding Series A Preferred Stock are in arrears, or (iii) the creation or issuance of any security ranking senior to the Series A Preferred Stock. The Series A Preferred Stock does not have a stated maturity and is not subject to mandatory redemption or any sinking fund. The Series A Preferred Stock will remain outstanding indefinitely unless repurchased or redeemed by us. Any such redemption would be effected only out of funds legally available for such purposes and will be subject to compliance with the provisions of our outstanding indebtedness.

6.    Asset Retirement Obligations
During 2018, we made revisions to the estimated costs associated with refining the CCR compliance plan. The CCR rule requires the continued collection of data over time to determine the specific compliance solution. The change in estimated costs resulted in an increase to the asset retirement obligation liability of $70.7 million that was recorded in 2018. See Note 16-C, "Environmental Matters," for additional information on CCRs.
 
 
 
 
 
7.    Regulatory Matters
Gas Distribution Operations Regulatory Matters
Cost Recovery and Trackers. Comparability of Gas Distribution Operations line item operating results is impacted by regulatory trackers that allow for the recovery in rates of certain costs such as those described below. Increases in the expenses that are the subject of trackers generally result in a corresponding increase in operating revenues and therefore have essentially no impact on total operating income results.
Certain operating costs of our distribution companies are significant, recurring in nature and generally outside the control of the distribution companies. Some states allow the recovery of such costs through cost tracking mechanisms. Such tracking mechanisms allow for abbreviated regulatory proceedings in order for the distribution companies to implement charges and recover appropriate costs. Tracking mechanisms allow for more timely recovery of such costs as compared with more traditional cost recovery mechanisms. Examples of such mechanisms include GCR adjustment mechanisms, tax riders and bad debt recovery mechanisms.

20

Table of Contents
ITEM 1. FINANCIAL STATEMENTS (continued)
NiSource Inc.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

A portion of the distribution companies' revenue is related to the recovery of gas costs, the review and recovery of which occurs through standard regulatory proceedings. All states in our operating area require periodic review of actual gas procurement activity to determine prudence and to permit the recovery of prudently incurred costs related to the supply of gas for customers. Our distribution companies have historically been found prudent in the procurement of gas supplies to serve customers.
Certain of our distribution companies have completed rate proceedings involving infrastructure replacement or are embarking upon regulatory initiatives to replace significant portions of their operating systems that are nearing the end of their useful lives. Each LDC's approach to cost recovery may be unique, given the different laws, regulations and precedent that exist in each jurisdiction.
Columbia of Ohio. On January 10, 2018, the PUCO issued an entry to investigate the impacts of the TCJA including an invitation to utilities and other interested stakeholders to file public comments including: (1) those components of utility rates that the PUCO will need to reconcile with the TCJA; and (2) the process and mechanics for how the PUCO should do so. The PUCO also directed utilities to record a regulatory liability for the estimated reduction in federal income tax resulting from the TCJA. On February 15, 2018, Columbia of Ohio filed comments proposing to: (1) reflect the impact of the TCJA on its application to adjust rates associated with its IRP rider, subsequently filed on February 27, 2018; and (2) file a reduction in other base rates reflecting the impact of the TCJA. The PUCO issued a procedural schedule on May 24, 2018 and a hearing was held on July 10, 2018. As discussed in further detail below, on October 25, 2018, Columbia of Ohio filed a joint stipulation and recommendation with the PUCO related to its CEP. Included in that stipulation were terms that would serve to resolve all remaining TCJA-related considerations for Columbia of Ohio.
On January 31, 2018, the PUCO approved Columbia of Ohio’s application to extend its IRP for an additional five years (2018-2022), allowing Columbia of Ohio to continue to invest and recover on its accelerated main replacements. The Office of the Ohio Consumers’ Counsel filed an application for rehearing asserting certain issues with Columbia of Ohio's application. On May 9, 2018, the PUCO issued an order denying the application for rehearing.
As referred to above, Columbia of Ohio filed its most recent application to adjust rates associated with its IRP rider on February 27, 2018, which requested authority to increase annual billings by approximately $2.3 million (net of the impact of the TCJA) reflecting recovery of and return on approximately $207 million of incremental IRP capital additions in 2017. A stipulation was filed with the PUCO on March 28, 2018. On April 25, 2018, the PUCO approved Columbia of Ohio’s annual IRP tracker adjustment with rates effective May 1, 2018.
On December 1, 2017, Columbia of Ohio filed an application that requested authority to implement a rider to begin recovering plant and associated deferrals related to its CEP. The CEP was established in 2011 and allows for deferral of interest, depreciation and property taxes on certain plant investments not recovered through its IRP modernization tracker. The application requested authority to increase annual revenues, through the requested rider, by approximately $70 million, with biennial increases up to approximately $98 million in 2022. On May 9, 2018, the PUCO appointed an independent auditor to assist the PUCO with the review of the accounting accuracy, prudency and compliance of Columbia of Ohio with its PUCO-approved CEP deferrals. The independent audit report was filed on September 4, 2018 and the PUCO Staff's Report on the investigation was filed on September 14, 2018. On October 25, 2018, a joint stipulation and recommendation was filed recommending an initial revenue requirement of $74.5 million to recover CEP investments and deferrals through December 31, 2017, with annual adjustments for capital investments made in subsequent years. Additionally, the signatory parties to the stipulation agreed to a reduction in rates to adjust for the impacts of the TCJA and for a base rate case filing to be made by Columbia of Ohio with a test period of calendar year 2021. A hearing on the stipulation is expected to occur on November 6, 2018.
NIPSCO Gas. On January 3, 2018, the IURC initiated an investigation to review and consider the possible implications of the TCJA on utility rates. The IURC ordered a two phase investigation. Phase 1 solely dealt with the prospective changes in rates to reflect the change in tax rates. In accordance with the procedural schedule, on March 26, 2018, NIPSCO filed revised gas tariffs reflecting the impact of the change in tax rate for its applicable rates and charges. The IURC approved NIPSCO's Phase 1 filing on April 26, 2018. The revised tariffs were effective May 1, 2018. The stipulation and settlement agreement filed on April 20, 2018, in NIPSCO’s gas rate case (discussed immediately below) resolved all issues in Phase 2.
On September 27, 2017, NIPSCO filed a base rate case with the IURC, seeking an annual revenue increase of $143.5 million (inclusive of amounts being recovered through various tracker programs). As part of this filing and among other items, NIPSCO proposed to update base rates for ongoing infrastructure improvements, revised depreciation rates and ongoing level of expenses to reflect the current costs of providing natural gas service. NIPSCO submitted a rebuttal on March 28, 2018 updating its request, including the impact of the TCJA, seeking a revised annual revenue increase of $138.1 million. On April 20, 2018, a settlement agreement was filed with the IURC seeking, among other items, an annual revenue increase of $107.3 million. An order approving

21

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ITEM 1. FINANCIAL STATEMENTS (continued)
NiSource Inc.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

the settlement agreement, as filed, was issued by the IURC on September 19, 2018. Rates will be implemented in three steps, with implementation of step 1 rates effective October 1, 2018, reflecting an annual revenue increase of $84.3 million. Step 2 rates will be effective on or about March 1, 2019, and step 3 rates will be effective on January 1, 2020. The IURC’s order also approved NIPSCO’s dismissal from phase 2 of the IURC’s TCJA investigation.
On November 8, 2017, NIPSCO filed a petition with the IURC seeking approval of NIPSCO’s federally mandated pipeline safety compliance plan. As part of the aforementioned settlement agreement filed in NIPSCO’s gas base rate case proceeding, NIPSCO and the parties to the settlement agreement settled all issues in this proceeding as well, including moving certain costs from the base rate proceeding to this pipeline safety compliance plan. The updated four year compliance plan includes a total estimated $91.5 million of capital costs and $35.5 million of expected operating and maintenance costs. NIPSCO received approval for accounting and ratemaking relief, including establishment of a periodic rate adjustment mechanism. NIPSCO anticipates filing the first tracker proceeding in this case on or around December 1, 2018.
On April 30, 2013, the Governor of Indiana signed Senate Enrolled Act 560, the TDSIC statute, into law. Among other provisions, this legislation provides for cost recovery outside of a base rate proceeding for new or replacement electric and gas transmission, distribution and storage projects that a public utility undertakes for the purposes of safety, reliability, system modernization or economic development. Provisions of the TDSIC statute require that, among other things, requests for recovery include a seven-year plan of eligible investments. Once the plan is approved by the IURC, eighty percent of eligible costs can be recovered using a periodic rate adjustment mechanism. The cost recovery mechanism is referred to as a TDSIC mechanism. Recoverable costs include a return on, and of, the investment, including AFUDC, post-in-service carrying charges, operation and maintenance expenses, depreciation and property taxes. The remaining twenty percent of recoverable costs are to be deferred for future recovery in the public utility’s next general rate case. The periodic rate adjustment mechanism is capped at an annual increase of no more than two percent of total retail revenues. On April 2, 2018, NIPSCO filed a new seven-year gas TDSIC plan with the IURC beginning in 2019 seeking approval of a total capital expenditure level of approximately $1.25 billion. On September 4, 2018, the IURC dismissed the filing without prejudice. The initial seven-year gas TDSIC plan, approving a total capital expenditure level of approximately $767 million remains in effect as approved by the IURC in April 2014. A new seven-year gas TDSIC plan may be filed with IURC once the considerations in the pending TDSIC tracker appeal discussed below are resolved.
On February 27, 2018, NIPSCO filed TDSIC-8 requesting to recover an incremental increase to revenue of $0.8 million (net of the impacts of TCJA) associated with incremental capital investment of $77.9 million made in the second half of 2017. On June 20, 2018, the Indiana Supreme Court issued an order reversing the IURC and the Court of Appeals in NIPSCO’s gas TDSIC-4 proceeding. The Indiana Supreme Court order stated that periodic rate increases are available only for specific projects designated in the threshold proceeding and multiple-unit-projects not identified with particularity are not recoverable through the tracker. In the second quarter of 2018, NIPSCO recorded a liability of $2.5 million associated with the TDSIC-4 through TDSIC-8 filings for a related passback of revenue previously billed to customers. A revised TDSIC-8 was filed on July 18, 2018 and reduced the previous February 27, 2018 request by $0.2 million associated with incremental capital investment of approximately $54 million. On August 22, 2018, the IURC issued an order approving the requested rates, subject to refund. On August 28, 2018, NIPSCO filed TDSIC-9 requesting an incremental decrease to revenue of $0.5 million associated with incremental capital investment of $72.9 million through June 30, 2018. The filing included the pass back of the revenue associated with multiple-unit-projects from prior TDSIC filings and the pass back of TCJA revenues of $7.1 million for associated tax expense collected from January 1, 2018 through April 30, 2018. On September 26, 2018, NIPSCO filed a revised TDSIC-9 decreasing the requested revenue amount by an additional $7.6 million to reflect assets being included in the base rate amounts for the step 1 rate implementation discussed above. An IURC order is expected in the fourth quarter of 2018.
Columbia of Massachusetts. On February 2, 2018, the Massachusetts DPU opened an investigation into the effect of the reduction in federal income tax rates on the rates charged by utility companies. Columbia of Massachusetts was directed to account for any revenues associated with the difference between previous and current income tax rates and excess deferred income taxes as regulatory liabilities effective January 1, 2018. Companies were ordered to submit a proposal to revise rates by May 1, 2018. The order indicates that if a company files a base rate case prior to the conclusion of the investigation, it must address the TCJA issues as part of the case. Since CMA filed a base rate case on April 13, 2018, the changes in base rates and the regulatory liability disposition related to the TCJA are reflected in the case. On June 29, 2018, the Massachusetts DPU required companies in a rate case to reduce rates as of July 1, 2018 or, in the alternative, defer this rate reduction to coincide with the effective date of new rates in a rate case, provided that tax savings from July 1, 2018 through the effective date of new rates accrue interest at prime rate. On July 2, 2018, Columbia of Massachusetts filed tariffs reflecting revised rates incorporating the lower federal corporate income tax rate for effect July 1, 2018. In the filing, Columbia of Massachusetts noted the Massachusetts DPU stated it would address the refund of any tax savings accrued from January 1, 2018, through June 30, 2018, in a separate phase of its investigation. On July

22

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ITEM 1. FINANCIAL STATEMENTS (continued)
NiSource Inc.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

10, 2018, the Massachusetts DPU approved the tariffs effective July 1, 2018, finding the adjustment is in the public interest, as it provides an immediate benefit to ratepayers.
As noted above, on April 13, 2018, Columbia of Massachusetts filed a rate case with the Massachusetts DPU, seeking approval for an annual revenue increase of approximately $43.8 million which is offset by revenue decreases in other rate factors of $19.7 million, representing a net increase in operating revenues of $24.1 million. Included in the filing was a proposal to adjust rates and address the regulatory liability disposition related to the TCJA. As a result of the incident that occurred on September 13, 2018, involving a series of fires and explosions that occurred in Lawrence, Andover and North Andover, Massachusetts related to the delivery of natural gas by Columbia of Massachusetts (the “Greater Lawrence Incident”), Columbia of Massachusetts filed a motion with the Massachusetts DPU on September 19, 2018, seeking to withdraw its petition for a base rate revenue increase in the interest of focusing its efforts on the on-going service restoration and customer assistance in the area. Refer to Note 16, "Other Commitments and Contingencies," in the Notes to Condensed Consolidated Financial Statements (unaudited) for additional information regarding the Greater Lawrence Incident. On October 9, 2018, Columbia of Massachusetts filed an application with the Massachusetts DPU, seeking authority to pass back approximately $95.8 million in excess deferred taxes with an effective date of rates to be determined by the Massachusetts DPU.
On July 7, 2014, the Governor of Massachusetts signed into law Chapter 149 of the Acts of 2014, An Act Relative to Natural Gas Leaks (“the Act”). The Act authorizes natural gas distribution companies to file gas infrastructure replacement plans with the Massachusetts DPU to address the replacement of aging natural gas pipeline infrastructure. In addition, the Act provides that the Massachusetts DPU may, after review of the plans, allow the proposed estimated costs of the plan into rates as of May 1 of the subsequent year. On October 31, 2017, Columbia of Massachusetts filed its GSEP for the 2018 construction year which proposed to recover incremental revenue of $9.7 million associated with incremental capital investment of $83.9 million to be made during calendar year 2018. The filing included a request for approval of a waiver to allow collection of the $3.1 million revenue requirement that exceeds the GSEP cap provision. On January 29, 2018, Columbia of Massachusetts filed a revision to its GSEP tracker for the 2018 construction season reducing the proposed revenue requirement by $2.4 million to reflect the impact of the TCJA. On June 21, 2018, the Massachusetts DPU issued an order granting the waiver on the revenue cap allowing an incremental revenue requirement of $6.5 million with new rates effective July 1, 2018. On October 31, 2018, Columbia of Massachusetts filed its GSEP for the 2019 construction year, proposing to recover an incremental revenue requirement of $10.7 million associated with incremental capital of $64.0 million. The filing included a request for approval of a waiver to allow collection of the $2.9 million revenue requirement that exceeds the GSEP cap provision. An order is expected from the Massachusetts DPU in the second quarter of 2019, with new rates effective May 1, 2019.
Columbia of Pennsylvania. On February 12, 2018, the Pennsylvania PUC established a docket to investigate the impact of the TCJA on customer rates. The Pennsylvania PUC directed Pennsylvania utilities to account for any revenues associated with the difference between previous and current income tax rates and excess deferred taxes as regulatory liabilities effective January 1, 2018. On May 17, 2018, the Pennsylvania PUC issued an order directing utilities that do not have a pending rate case to implement a negative surcharge in their billings to reflect the annual reduction in federal tax expense and associated revenue requirement for each utility, effective July 1, 2018.
On March 16, 2018, Columbia of Pennsylvania filed a rate case with the Pennsylvania PUC, incorporating the impacts of the TCJA and seeking approval for an annual revenue increase of $46.9 million. On March 21, 2018, Columbia of Pennsylvania filed a supplement to the rate case, under which it proposed to hold the overcollection of taxes during 2018 until the effective date of new base rates as credit to rate base for a period beginning January 2019 not to exceed three years. On August 31, 2018 a partial settlement was filed with the Pennsylvania PUC which included a revenue increase of $26.0 million and provided for the TCJA federal tax expense reduction of $22.5 million to be returned to customers over an 18 month period beginning December 16, 2018. On September 18, 2018 the administrative law judge issued a recommended decision approving the partial settlement without modification. A final order is expected in the fourth quarter of 2018 with new rates anticipated to be implemented in December 2018.
Columbia of Virginia. On January 8, 2018, the VSCC issued an order regarding the TCJA requiring Columbia of Virginia and other Virginia utilities subject to the TCJA to accrue regulatory liabilities reflecting the impacts of the reduced corporate income tax rate effective January 1, 2018. On August 28, 2018 Columbia of Virginia filed a request with the VSCC requesting a $22.2 million increase in base rates. The filing seeks to recover costs associated with ongoing infrastructure investment programs and incorporates the impacts of the TCJA. Columbia of Virginia proposed that the TCJA regulatory liability associated with lower federal income tax expense accrued prior to the implementation of new rates be considered in future VSCC reviews that assess earnings for the associated time period. Rates will be implemented on an interim basis, subject to refund, effective February 1, 2019, with a final order expected from the VSCC in the second half of 2019.

23

Table of Contents
ITEM 1. FINANCIAL STATEMENTS (continued)
NiSource Inc.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

Columbia of Kentucky. On January 26, 2018, in accordance with the Kentucky PSC investigation related to the TCJA, Columbia of Kentucky filed testimony and proposed a reduction to base rates effective May 1, 2018, to reflect the tax expense reduction as a result of the TCJA. Columbia of Kentucky was directed to account for any revenues associated with the difference between previous and current income tax rates and excess deferred taxes as regulatory liabilities effective January 1, 2018. Columbia of Kentucky proposed to include the impact of the excess deferred taxes in rates effective October 2018 and to return the revenue related to the regulatory liability subsequent to this date. On April 30, 2018 Columbia of Kentucky received an order from the Kentucky PSC requiring implementation of interim proposed rates that are subject to future adjustment effective May 1, 2018. The order directed Columbia of Kentucky to file, by September 1, 2018, revised TCJA adjustment factors reflecting the tax expense savings from January 1, 2018, through April 30, 2018, and an estimate of the annual reduction due to the excess deferred taxes to be effective with the first billing cycle of October 2018. On August 31, 2018, Columbia of Kentucky filed updated rate schedules with the Kentucky PSC for rates proposed to be effective October 1, 2018. On September 27, 2018, Columbia of Kentucky received a PSC order suspending the filing for five months. No procedural time line beyond the five month suspension period has been set.
On October 15, 2018, Columbia of Kentucky filed an application to adjust rates associated with its AMRP, requesting authority to increase annual revenues by $3.6 million associated with incremental capital investment of $30.1 million to be made during calendar year 2019. An order is anticipated from the Kentucky PSC in December 2018, with new rates effective January 2019.
Columbia of Maryland. On February 13, 2018, Columbia of Maryland filed a proposal with the Maryland PSC to reduce rates as a result of TCJA with an annual revenue decrease of $1.3 million. Columbia of Maryland was directed to account for any revenues associated with the difference between previous and current income tax rates and excess deferred taxes as regulatory liabilities effective January 1, 2018. On March 14, 2018, Columbia of Maryland received approval, effective April 2, 2018, to implement new rates and pass-back the overcollection of taxes from the first quarter of 2018.
On April 13, 2018, Columbia of Maryland filed a request with the Maryland PSC to increase base rates by $6.1 million, inclusive of the impacts of the TCJA. On July 31, 2018, Columbia of Maryland filed a settlement with the Maryland PSC. If approved as filed, the settlement would result in an annual revenue increase of $3.7 million. On October 2, 2018, the assigned judge issued a proposed order which recommended that the settlement be approved. A final order from the Maryland PSC is expected in the fourth quarter of 2018 with rates anticipated to be effective November 2018.
On April 6, 2018, Columbia of Maryland filed an application requesting authority to extend its STRIDE plan for an additional five years (2019-2023). The proposed order issued on August 28, 2018 was not appealed or modified and therefore it became final on September 28, 2018.
Electric Operations Regulatory Matters
Cost Recovery and Trackers. Comparability of Electric Operations line item operating results is impacted by regulatory trackers that allow for the recovery in rates of certain costs such as those described below. Increases in the expenses that are the subject of trackers result in a corresponding increase in operating revenues and therefore have essentially no impact on total operating income results.
Certain operating costs of the Electric Operations are significant, recurring in nature, and generally outside the control of NIPSCO. The IURC allows for recovery of such costs through cost tracking mechanisms. Such tracking mechanisms allow for abbreviated regulatory proceedings in order for NIPSCO to implement charges and recover appropriate costs. Tracking mechanisms allow for more timely recovery of such costs as compared with more traditional cost recovery mechanisms. Examples of such mechanisms include electric energy efficiency programs, MISO non-fuel costs and revenues, resource capacity charges, federally mandated costs and environmental-related costs.
A portion of NIPSCO's revenue is related to the recovery of fuel costs to generate power and the fuel costs related to purchased power. These costs are recovered through a FAC, a quarterly regulatory proceeding in Indiana.
As noted above in the NIPSCO Gas regulatory matters, the IURC initiated an investigation on January 3, 2018, to review and consider the implications of the TCJA on utility rates. The commission ordered a two phase investigation. Phase 1 solely dealt with the prospective changes in rates to reflect the change in tax rates. On March 26, 2018, NIPSCO filed revised electric tariffs reflecting the impact of the change in tax rate for its applicable rates and charges. The IURC approved NIPSCO's phase 1 filing on April 26, 2018. The revised tariffs were effective May 1, 2018. On July 31, 2018, NIPSCO filed an unopposed motion requesting that the over-collection of income taxes from January 1, 2018 through April 30, 2018 be passed back in NIPSCO’s TDSIC-4 filing, also filed on July 31, 2018, and requesting that all other phase 2 issues be handled in a rate case filing to be made in the fourth

24

Table of Contents
ITEM 1. FINANCIAL STATEMENTS (continued)
NiSource Inc.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

quarter of 2018. On August 15, 2018, the IURC approved the motion to pass back the over-collection and stated that all other phase 2 issues will be addressed in the to-be-filed base rate case, as discussed below.
On October 31, 2018 NIPSCO filed a request for an increase in base rates with the IURC for a proposed $21.4 million increase in revenues in part, to address anticipated revenue loss resulting from the WCE filing discussed below, as well as to address phase 2 issues of the TCJA. The filing also addresses the appropriate depreciation rates for the accelerated retirement of NIPSCO’s aging coal fleet, as discussed in the 2018 Integrated Resource Plan below. An order is expected from the IURC in the third quarter of 2019 with rates anticipated to be effective September 2019.
Also on October 31, 2018, NIPSCO submitted its 2018 Integrated Resource Plan with the IURC. The plan evaluated demand-side and supply-side resource alternatives to reliably and cost effectively meet NIPSCO customers' future energy requirements over the ensuing 20 years. Refer to Note 16-D, "Other Matters," in the Notes to Condensed Consolidated Financial Statements (unaudited) for additional information.
On March 29, 2018, WCE, which is currently owned by BP p.l.c ("BP") and BP Products North America, which operates the BP Refinery, filed a petition at the IURC asking that the combined operations of WCE and BP be treated as a single premise, and the WCE generation be dedicated primarily to BP Refinery operations beginning in May 2019 as WCE has self-certified as a qualifying facility at FERC. BP Refinery planned to continue to purchase electric service from NIPSCO at a reduced demand level beginning in May 2019. NIPSCO is currently in discussions with BP.
On January 30, 2018, NIPSCO made a TDSIC-3 rate adjustment mechanism filing requesting a revenue decrease of $1.8 million to be billed over six months, associated with $75.0 million of incremental capital expenditures made from May 1, 2017 to November 30, 2017. The decrease was due to the impact of the TCJA as well as a shorter billing period compared to TDSIC-2. TDSIC-3 was approved on May 30, 2018 and became effective for the first billing cycle of June. Additionally, the TDSIC-2 rates revised for tax reform approved as a part of NIPSCO’s Phase 1 filing described above were made effective on May 1, 2018, until TDSIC-3 rates went into effect. The impact of TCJA on TDSIC-2 was an approximate decrease in revenue of $1.2 million for the period from January through May 2018. NIPSCO made a TDSIC-4 rate adjustment mechanism filing on July 31, 2018, which was modified on October 25, 2018, seeking an incremental semi-annual revenue decrease of $11.2 million due primarily to the pass back of a $14.1 million TCJA electric base rate customer refund for the period January through May 2018. The TCJA refund offsets a $2.8 million increase associated with $72.2 million of incremental capital expenditures from December 2017 through May 2018. An order approving the request is expected in the fourth quarter of 2018.
On February 1, 2018, NIPSCO and certain other MISO transmission owners filed with the FERC a request for waiver of tariff provisions to allow for implementation of TCJA provisions into 2018 transmission formula rates as soon as possible. On March 15, 2018, the FERC issued an order granting the request for waiver and set the effective date of the waiver at January 1, 2018. In the March billing cycle, the MISO began billing the new transmission rates reflecting the lower federal tax rate. In addition, the MISO began to re-bill January and February 2018 affected revenues and costs in the March 2018 billing cycle, and completed the re-settlement in the April 2018 billing cycle. The new 2018 transmission formula rates will lower revenue by approximately $8.5 million in 2018 associated with NIPSCO's multi-value projects.
Material Updates to Regulatory Assets and Liabilities Since December 31, 2017
TCJA-Related Regulatory Liabilities. As referenced above, during the nine months ended September 30, 2018, we recorded additional TCJA-related regulatory liabilities of $69.9 million to reflect 2018 collections from customers which we believe are probable of being refunded back to customers once new customer rates are approved by our regulators.
As discussed in Note 12, "Income Taxes," in 2018 we began amortizing regulatory liabilities associated with excess deferred taxes, which resulted in a $6.8 million and $24.6 million income tax benefit for the three and nine months ended September 30, 2018, respectively. Related to this activity, we recorded an offsetting reserve of $3.6 million and $15.9 million (net of tax) in "Customer revenues" to reflect the probable future passback of this earnings benefit to customers for the three and nine months ended September 30, 2018, respectively. In certain jurisdictions, we received additional regulatory guidance on the treatment and passback period of excess deferred income taxes, indicating that such a reserve was not required as of September 30, 2018.
Bailly Generating Station. On February 1, 2018, as previously approved by the MISO, NIPSCO commenced a four-month outage of Bailly Generating Station Unit 8 in order to begin work on converting the unit to a synchronous condenser (a piece of equipment designed to maintain voltage to ensure continued reliability on the transmission system). Approximately $15 million of net book value of Unit 8 remained in “Net Utility Plant” as it is expected to remain used and useful upon completion of the synchronous condenser, while the remaining net book value of approximately $142 million was reclassified to “Regulatory assets (noncurrent)”

25

Table of Contents
ITEM 1. FINANCIAL STATEMENTS (continued)
NiSource Inc.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

on the Condensed Consolidated Balance Sheets (unaudited). On May 31, 2018, Units 7 and 8 were retired from service. As a result, the remaining net book value of Unit 7 of approximately $103 million was reclassified to “Regulatory assets (noncurrent)” on the Condensed Consolidated Balance Sheets (unaudited).These amounts continue to be amortized at a rate consistent with their inclusion in customer rates.
8.    Risk Management Activities
We are exposed to certain risks relating to our ongoing business operations, namely commodity price risk and interest rate risk. We recognize that the prudent and selective use of derivatives may help to lower our cost of debt capital, manage our interest rate exposure and limit volatility in the price of natural gas.
Risk management assets and liabilities on our derivatives are presented on the Condensed Consolidated Balance Sheets (unaudited) as shown below:
(in millions)
September 30, 2018
 
December 31, 2017
Risk Management Assets - Current(1)
 
 
 
Interest rate risk programs
$
21.4

 
$
14.0

Commodity price risk programs
1.0

 
0.5

Total
$
22.4

 
$
14.5

Risk Management Assets - Noncurrent(2)
 
 
 
Interest rate risk programs
$
32.6

 
$
5.6

Commodity price risk programs
2.6

 
1.0

Total
$
35.2

 
$
6.6

Risk Management Liabilities - Current
 
 
 
Interest rate risk programs
$

 
$
38.6

Commodity price risk programs
4.8

 
4.6

Total
$
4.8

 
$
43.2

Risk Management Liabilities - Noncurrent
 
 
 
Interest rate risk programs
$

 
$

Commodity price risk programs
45.2

 
28.5

Total
$
45.2

 
$
28.5

(1)Presented in "Prepayments and other" on the Condensed Consolidated Balance Sheets (unaudited).
(2)Presented in "Deferred charges and other" on the Condensed Consolidated Balance Sheets (unaudited).
Commodity Price Risk Management
We, along with our utility customers, are exposed to variability in cash flows associated with natural gas purchases and volatility in natural gas prices. We purchase natural gas for sale and delivery to our retail, commercial and industrial customers, and for most customers the variability in the market price of gas is passed through in their rates. Some of our utility subsidiaries offer programs whereby variability in the market price of gas is assumed by the respective utility. The objective of our commodity price risk programs is to mitigate the gas cost variability, for us or on behalf of our customers, associated with natural gas purchases or sales by economically hedging the various gas cost components using a combination of futures, options, forwards or other derivative contracts.
NIPSCO received IURC approval to lock in a fixed price for its natural gas customers using long-term forward purchase instruments. The term of these instruments may range from five to ten years and is limited to twenty percent of NIPSCO’s average annual GCA purchase volume. Gains and losses on these derivative contracts are deferred as regulatory liabilities or assets and are remitted to or collected from customers through NIPSCO’s quarterly GCA mechanism. These instruments are not designated as accounting hedges.
Interest Rate Risk Management
As of September 30, 2018, we have forward-starting interest rate swaps with an aggregate notional value totaling $750.0 million to hedge the variability in cash flows attributable to changes in the benchmark interest rate during the periods from the effective dates of the swaps to the anticipated dates of forecasted debt issuances, which are expected to take place by the end of 2019. These interest rate swaps are designated as cash flow hedges. The effective portions of the gains and losses related to these swaps are

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Table of Contents
ITEM 1. FINANCIAL STATEMENTS (continued)
NiSource Inc.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

recorded to AOCI and are recognized in "Interest expense, net" concurrently with the recognition of interest expense on the associated debt, once issued. If it becomes probable that a hedged forecasted transaction will no longer occur, the accumulated gains or losses on the derivative will be recognized currently in "Other, net."
In April 2018, we settled forward-starting interest rate swaps with a notional value of $250.0 million. These derivative contracts were accounted for as cash flow hedges. As part of the transaction, the associated net unrealized gain of $21.2 million was recognized immediately in "Other, net" on the Condensed Statements of Consolidated Income (Loss) (unaudited) due to the probability associated with the forecasted borrowing transaction no longer occurring.
There were no amounts excluded from effectiveness testing for derivatives in cash flow hedging relationships at September 30, 2018 and December 31, 2017.
Our derivative instruments measured at fair value as of September 30, 2018 and December 31, 2017 do not contain any credit-risk-related contingent features.
9.    Fair Value
 
A.    Fair Value Measurements
Recurring Fair Value Measurements. The following tables present financial assets and liabilities measured and recorded at fair value on our Condensed Consolidated Balance Sheets (unaudited) on a recurring basis and their level within the fair value hierarchy as of September 30, 2018 and December 31, 2017:
 
Recurring Fair Value Measurements
September 30, 2018
(in millions)
Quoted Prices in
Active Markets
for Identical
Assets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
 
Balance as of September 30, 2018
Assets
 
 
 
 
 
 
 
Risk management assets
$

 
$
57.6

 
$

 
$
57.6

Available-for-sale securities

 
143.8

 

 
143.8

Total
$

 
$
201.4

 
$

 
$
201.4

Liabilities
 
 
 
 
 
 
 
Risk management liabilities
$

 
$
50.0

 
$

 
$
50.0

Total
$

 
$
50.0

 
$

 
$
50.0


Recurring Fair Value Measurements
December 31, 2017
(in millions)
Quoted Prices in
Active Markets
for Identical
Assets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
 
Balance as of
December 31, 2017
Assets
 
 
 
 
 
 
 
Risk management assets
$

 
$
21.1

 
$

 
$
21.1

Available-for-sale securities

 
133.9

 

 
133.9

Total
$

 
$
155.0

 
$

 
$
155.0

Liabilities
 
 
 
 
 
 
 
Risk management liabilities
$

 
$
71.4

 
$
0.3

 
$
71.7

Total
$

 
$
71.4

 
$
0.3

 
$
71.7


Risk management assets and liabilities include interest rate swaps, exchange-traded NYMEX futures and NYMEX options and non-exchange-based forward purchase contracts. When utilized, exchange-traded derivative contracts are based on unadjusted quoted prices in active markets and are classified within Level 1. These financial assets and liabilities are secured with cash on deposit with the exchange; therefore, nonperformance risk has not been incorporated into these valuations. Certain non-exchange-traded derivatives are valued using broker or over-the-counter, on-line exchanges. In such cases, these non-exchange-traded

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Table of Contents
ITEM 1. FINANCIAL STATEMENTS (continued)
NiSource Inc.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

derivatives are classified within Level 2. Non-exchange-based derivative instruments include swaps, forwards, options and treasury lock agreements. In certain instances, these instruments may utilize models to measure fair value. We use a similar model to value similar instruments. Valuation models utilize various inputs that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, other observable inputs for the asset or liability and market-corroborated inputs, (i.e., inputs derived principally from or corroborated by observable market data by correlation or other means). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized within Level 2. Certain derivatives trade in less active markets with a lower availability of pricing information and models may be utilized in the valuation. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized within Level 3. Credit risk is considered in the fair value calculation of derivative instruments that are not exchange-traded. Credit exposures are adjusted to reflect collateral agreements which reduce exposures. As of September 30, 2018 and December 31, 2017, there were no material transfers between fair value hierarchies. Additionally, there were no changes in the method or significant assumptions used to estimate the fair value of our financial instruments.
We have entered into forward-starting interest rate swaps to hedge the interest rate risk on coupon payments of forecasted issuances of long-term debt. These derivatives are designated as cash flow hedges. Credit risk is considered in the fair value calculation of each agreement. As they are based on observable data and valuations of similar instruments, the hedges are categorized within Level 2 of the fair value hierarchy. There was no exchange of premium at the initial date of the swaps, and we can settle the contracts at any time. For additional information, see Note 8, "Risk Management Activities."
NIPSCO has entered into long-term forward natural gas purchase instruments that range from five to ten years to lock in a fixed price for its natural gas customers. We value these contracts using a pricing model that incorporates market-based information when available, as these instruments trade less frequently and are classified within Level 2 of the fair value hierarchy. For additional information, see Note 8, “Risk Management Activities.”
Available-for-sale securities are investments pledged as collateral for trust accounts related to our wholly-owned insurance company. Available-for-sale securities are included within “Other investments” in the Condensed Consolidated Balance Sheets (unaudited). We value U.S. Treasury, corporate debt and mortgage-backed securities using a matrix pricing model that incorporates market-based information. These securities trade less frequently and are classified within Level 2. Total unrealized gains and losses from available-for-sale securities are included in other comprehensive income. The amortized cost, gross unrealized gains and losses and fair value of available-for-sale securities at September 30, 2018 and December 31, 2017 were: 
September 30, 2018 (in millions)
Amortized
Cost
 
Gross Unrealized Gains
 
Gross Unrealized Losses
 
Fair
Value
Available-for-sale securities
 
 
 
 
 
 
 
U.S. Treasury debt securities
$
29.7

 
$

 
$
(0.2
)
 
$
29.5

Corporate/Other debt securities
116.8

 
0.4

 
(2.9
)
 
114.3

Total
$
146.5

 
$
0.4

 
$
(3.1
)
 
$
143.8

 
 
 
 
 
 
 
 
December 31, 2017 (in millions)
Amortized
Cost
 
Gross Unrealized Gains
 
Gross Unrealized Losses
 
Fair
Value
Available-for-sale securities
 
 
 
 
 
 
 
U.S. Treasury debt securities
$
26.9

 
$

 
$
(0.1
)
 
$
26.8

Corporate/Other debt securities
106.8

 
0.9

 
(0.6
)
 
107.1

Total
$
133.7

 
$
0.9

 
$
(0.7
)
 
$
133.9

Realized gains and losses on available-for-sale securities were immaterial for the three and nine months ended September 30, 2018 and 2017.
The cost of maturities sold is based upon specific identification. At September 30, 2018, approximately $14.9 million of U.S. Treasury debt securities and approximately $3.0 million of Corporate/Other debt securities have maturities of less than a year.

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


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Table of Contents
ITEM 1. FINANCIAL STATEMENTS (continued)
NiSource Inc.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

Non-recurring Fair Value Measurements. There were no significant non-recurring fair value measurements recorded during the three and nine months ended September 30, 2018.
B.    Other Fair Value Disclosures for Financial Instruments. The carrying amount of cash and cash equivalents, restricted cash, customer deposits and short-term borrowings is a reasonable estimate of fair value due to their liquid or short-term nature. Our long-term borrowings are recorded at historical amounts.
The following method and assumptions were used to estimate the fair value of each class of financial instruments.
Long-term Debt. The fair value of outstanding long-term debt is estimated based on the quoted market prices for the same or similar securities. Certain premium costs associated with the early settlement of long-term debt are not taken into consideration in determining fair value. These fair value measurements are classified within Level 2 of the fair value hierarchy. For the nine months ended September 30, 2018, there was no change in the method or significant assumptions used to estimate the fair value of long-term debt.
The carrying amount and estimated fair values of these financial instruments were as follows: 
(in millions)
Carrying
Amount as of
September 30, 2018
 
Estimated Fair
Value as of
September 30, 2018
 
Carrying
Amount as of
Dec. 31, 2017
 
Estimated Fair
Value as of
Dec. 31, 2017
Long-term debt (including current portion)
$
7,143.1

 
$
7,280.1

 
$
7,796.5

 
$
8,603.4


10.    Transfers of Financial Assets
Columbia of Ohio, NIPSCO and Columbia of Pennsylvania each maintain a receivables agreement whereby they transfer their customer accounts receivables to third party financial institutions through wholly-owned and consolidated special purpose entities. The three agreements expire between March 2019 and October 2019 and may be further extended if mutually agreed to by the parties thereto.
All receivables transferred to third parties are valued at face value, which approximates fair value due to their short-term nature. The amount of the undivided percentage ownership interest in the accounts receivables transferred is determined in part by required loss reserves under the agreements.
Transfers of accounts receivable are accounted for as secured borrowings resulting in the recognition of short-term borrowings on the Condensed Consolidated Balance Sheets (unaudited). As of September 30, 2018, the maximum amount of debt that could be recognized related to our accounts receivable programs is $265.0 million.
The following table reflects the gross receivables balance and net receivables transferred as well as short-term borrowings related to the securitization transactions as of September 30, 2018 and December 31, 2017:
 
(in millions)
September 30, 2018
 
December 31, 2017
Gross Receivables
$
410.9

 
$
635.3

Less: Receivables not transferred
145.9

 
298.6

Net receivables transferred
$
265.0

 
$
336.7

Short-term debt due to asset securitization
$
265.0

 
$
336.7

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


29

Table of Contents
ITEM 1. FINANCIAL STATEMENTS (continued)
NiSource Inc.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

11.    Goodwill
 The following presents our goodwill balance allocated by segment as of September 30, 2018:
(in millions)
 
Gas Distribution Operations
 
Electric Operations
 
Corporate and Other
 
Total
Goodwill
 
$
1,690.7

 
$

 
$

 
$
1,690.7


We applied the qualitative "step 0" analysis to our reporting units for the annual impairment test performed as of May 1, 2018. For this test, we assessed various assumptions, events and circumstances that would have affected the estimated fair value of the reporting units as compared to their base line May 1, 2016 "step 1" fair value measurement. The results of this assessment indicated that it was not more likely than not that our reporting unit fair values were less than the reporting unit carrying values, accordingly, no "step 1" analysis was required.

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

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

30

Table of Contents
ITEM 1. FINANCIAL STATEMENTS (continued)
NiSource Inc.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

become eligible for these benefits if they reach retirement age while working for us. The expected cost of such benefits is accrued during the employees’ years of service. For most plans, cash contributions are remitted to grantor trusts.
For the nine months ended September 30, 2018, we contributed $2.1 million to our pension plans and $16.8 million to our other postretirement benefit plans.
The following table provides the components of the plans’ actuarially determined net periodic benefit cost for the three and nine months ended September 30, 2018 and 2017:

Pension Benefits
 
Other Postretirement
Benefits
Three Months Ended September 30, (in millions)
2018
 
2017
 
2018
 
2017
Components of Net Periodic Benefit Cost(1)
 
 
 
 
 
 
 
Service cost
$
7.8

 
$
7.4

 
$
1.3

 
$
1.2

Interest cost
16.8

 
17.1

 
4.4

 
4.4

Expected return on assets
(35.4
)
 
(30.8
)
 
(3.7
)
 
(3.9
)
Amortization of prior service credit
(0.1
)
 
(0.1
)
 
(1.0
)
 
(1.1
)
Recognized actuarial loss
10.2

 
13.2

 
0.9

 
0.7

Settlement loss
8.3

 
10.6

 

 

Total Net Periodic Benefit Cost
$
7.6

 
$
17.4

 
$
1.9

 
$
1.3

(1)The service cost component, and all non-service cost components, of net periodic benefit cost are presented in "Operation and maintenance" and "Other, net", respectively, on the Condensed Statements of Consolidated Income (Loss) (unaudited).
 
Pension Benefits
 
Other Postretirement
Benefits
Nine Months Ended September 30, (in millions)
2018
 
2017
 
2018
 
2017
Components of Net Periodic Benefit Cost(1)
 
 
 
 
 
 
 
Service cost
$
23.6

 
$
22.4

 
$
3.9

 
$
3.6

Interest cost
50.0

 
51.5

 
13.2

 
13.4

Expected return on assets
(107.9
)
 
(91.3
)
 
(11.1
)
 
(11.9
)
Amortization of prior service credit
(0.3
)
 
(0.5
)
 
(3.0
)
 
(3.3
)
Recognized actuarial loss
30.6

 
40.0

 
2.7

 
2.2

Settlement loss
11.8

 
10.6

 

 

Total Net Periodic Benefit Cost
$
7.8

 
$
32.7

 
$
5.7

 
$
4.0

(1)The service cost component, and all non-service cost components, of net periodic benefit cost are presented in "Operation and maintenance" and "Other, net", respectively, on the Condensed Statements of Consolidated Income (Loss) (unaudited).

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

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

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Table of Contents
ITEM 1. FINANCIAL STATEMENTS (continued)
NiSource Inc.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)


The following table provides the key assumptions that were used to calculate the pension benefit obligation and the net periodic benefit cost for the plans that triggered settlement accounting at the measurement dates of August 31, 2018, May 31, 2018 and December 31, 2017:
 
August 31,
2018
 
May 31,
2018
 
December 31, 2017
Weighted-average Assumption to Determine Benefit Obligation:
 
 
 
 
 
Discount rate
4.08
%
 
4.03
%
 
3.58
%
Weighted-average Assumptions to Determine Net Periodic Benefit Costs for the period ended:
 
 
 
 
 
Discount rate - service cost
3.79
%
 
3.79
%
 
4.40
%
Discount rate - interest cost
3.15
%
 
3.15
%
 
3.31
%
Expected return on assets
6.30
%
 
6.30
%
 
7.25
%

14.    Long-Term Debt
On March 15, 2018, we redeemed $275.1 million of 6.40% senior unsecured notes at maturity.
In June 2018, we executed a tender offer for $209.0 million of outstanding notes consisting of a combination of our 6.80% notes due 2019, 5.45% notes due 2020 and 6.125% notes due 2022. In conjunction with the debt retired, we recorded a $12.5 million loss on early extinguishment of long-term debt, primarily attributable to early redemption premiums.
On June 11, 2018, we closed our private placement of $350.0 million of 3.65% senior unsecured notes maturing in 2023 which resulted in approximately $346.6 million of net proceeds after deducting commissions and expenses. We used the net proceeds from this private placement to pay a portion of the redemption price for the notes subject to the tender offer described above.
In July 2018, we redeemed $551.1 million of outstanding notes representing the remainder of our 6.80% notes due 2019, 5.45% notes due 2020 and 6.125% notes due 2022. During the third quarter of 2018, we recorded a $33.0 million loss on early extinguishment of long-term debt, primarily attributable to early redemption premiums.
15.    Short-Term Borrowings
We generate short-term borrowings from our revolving credit facility, commercial paper program, letter of credit issuances, accounts receivable transfer programs and term loan borrowings. Each of these borrowing sources is described further below.
We maintain a revolving credit facility to fund ongoing working capital requirements, including the provision of liquidity support for our commercial paper program, provide for issuance of letters of credit and also for general corporate purposes. Our revolving credit facility has a program limit of $1.85 billion and is comprised of a syndicate of banks led by Barclays. At September 30, 2018 and December 31, 2017, we had no outstanding borrowings under this facility.
Our commercial paper program has a program limit of up to $1.5 billion with a dealer group comprised of Barclays, Citigroup, Credit Suisse and Wells Fargo. We had $746.0 million and $869.0 million of commercial paper outstanding as of September 30, 2018 and December 31, 2017, respectively.
As of September 30, 2018 and December 31, 2017, we had $10.2 million and $11.1 million of stand-by letters of credit, respectively. All stand-by letters of credit were under the revolving credit facility.
Transfers of accounts receivable are accounted for as secured borrowings resulting in the recognition of short-term borrowings on the Condensed Consolidated Balance Sheets (unaudited). We had $265.0 million in transfers as of September 30, 2018 and $336.7 million as of December 31, 2017. Refer to Note 10, "Transfers of Financial Assets," for additional information.
On April 18, 2018, we entered into a multiple-draw $600.0 million term loan agreement with a syndicate of banks led by MUFG Bank, Ltd. The term loan matures April 17, 2019, at which point any and all outstanding borrowings under the agreement are due. Interest charged on borrowings depends on the variable rate structure we elected at the time of each borrowing. Under the agreement, we borrowed an initial tranche of $150.0 million on April 18, 2018 with an interest rate of LIBOR plus 50 basis points and a second tranche of $450.0 million on May 31, 2018 with an interest rate of LIBOR plus 55 basis points.

32

Table of Contents
ITEM 1. FINANCIAL STATEMENTS (continued)
NiSource Inc.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)

Short-term borrowings were as follows: 
(in millions)
September 30,
2018
 
December 31,
2017
Commercial paper weighted-average interest rate of 2.57% and 1.97% at September 30, 2018 and December 31, 2017, respectively
$