10-Q 1 ni-2018630x10q.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 June 30, 2018
or
¨  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from              to             
Commission file number 001-16189
NiSource Inc.
(Exact name of registrant as specified in its charter)
Delaware               
 
35-2108964        
(State or other jurisdiction of
incorporation or organization)
 
(I.R.S. Employer
Identification No.)
 
 
 
801 East 86th Avenue
Merrillville, Indiana    
 
46410
(Address of principal executive offices)
 
(Zip Code)
(877) 647-5990
(Registrant’s telephone number, including area code)
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes þ    No ¨
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files.)
Yes þ    No ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer" "smaller reporting company," and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer þ                    Accelerated filer ¨        Emerging growth company ¨
Non-accelerated filer ¨                      Smaller reporting company ¨
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes ¨    No þ

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date: Common Stock, $0.01 Par Value: 363,036,685 shares outstanding at July 24, 2018.



NISOURCE INC.
FORM 10-Q QUARTERLY REPORT
FOR THE QUARTER ENDED JUNE 30, 2018
Table of Contents
 
 
 
 
Page
 
 
 
 
 
 
 
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
 
AFUDC
Allowance for funds used during construction
AOCI
Accumulated Other Comprehensive Income (Loss)
ASC
Accounting Standards Codification
ASU
Accounting Standards Update
ATM
At-the-market
CAA
Clean Air Act
CCRs
Coal Combustion Residuals
CEP
Capital Expenditure Program
CERCLA
Comprehensive Environmental Response Compensation and Liability Act (also known as Superfund)
CO2
Carbon Dioxide
CPP
Clean Power Plan
DPU
Department of Public Utilities
EGUs
Electric Utility Generating Units
ELG
Effluent limitations guidelines
EPA
United States Environmental Protection Agency
EPS
Earnings per share
FAC
Fuel adjustment clause
FASB
Financial Accounting Standards Board
FERC
Federal Energy Regulatory Commission
GAAP
Generally Accepted Accounting Principles
GCA
Gas cost adjustment
GCR
Gas cost recovery
GHG
Greenhouse gases
GSEP
Gas System Enhancement Program
gwh
Gigawatt hours
IRP
Infrastructure Replacement Program
IRS
Internal Revenue Service
IURC
Indiana Utility Regulatory Commission
LDCs
Local distribution companies
LIBOR
London InterBank Offered Rate
LIFO
Last In, First Out
MGP
Manufactured Gas Plant

3


DEFINED TERMS

MISO
Midcontinent Independent System Operator
MMDth
Million dekatherms
NOL
Net operating loss
NYMEX
New York Mercantile Exchange
OPEB
Other Postretirement Benefits
PSC
Public Service Commission
PUC
Public Utilities Commission
PUCO
Public Utilities Commission of Ohio
Pure Air
Pure Air on the Lake LP
RCRA
Resource Conservation and Recovery Act
SEC
Securities and Exchange Commission
TCJA
An Act to provide for reconciliation pursuant to titles II and V of the concurrent resolution on the budget for fiscal year 2018 (commonly known as the Tax Cuts and Jobs Act of 2017)
TDSIC
Transmission, Distribution and Storage System Improvement Charge
VIE
Variable Interest Entities
VSCC
Virginia State Corporation Commission
WCE
Whiting Clean Energy
Note regarding forward-looking statements
This Quarterly Report on Form 10-Q contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the "Securities Act") and Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). Investors and prospective investors should understand that many factors govern whether any forward-looking statement contained herein will be or can be realized. Any one of those factors could cause actual results to differ materially from those projected. These forward-looking statements include, but are not limited to, statements concerning NiSource’s plans, strategies, objectives, expected performance, expenditures, recovery of expenditures through rates, stated on either a consolidated or segment basis, and any and all underlying assumptions and other statements that are other than statements of historical fact. All forward-looking statements are based on assumptions that management believes to be reasonable; however, there can be no assurance that actual results will not differ materially.
Factors that could cause actual results to differ materially from the projections, forecasts, estimates and expectations discussed in this Quarterly Report on Form 10-Q include, among other things, our debt obligations; any changes in our credit rating; our ability to execute our growth strategy; changes in general economic, capital and commodity market conditions; pension funding obligations; economic regulation and the impact of regulatory rate reviews; our ability to obtain expected financial or regulatory outcomes; advances in technology; any damage to our reputation; compliance with environmental laws and the costs of associated liabilities; fluctuations in demand from residential and commercial customers; economic conditions of certain industries; the success of NIPSCO's electric generation strategy; the price of energy commodities and related transportation costs; the reliability of customers and suppliers to fulfill their payment and contractual obligations; potential impairments of goodwill or definite-lived intangible assets; changes in taxation and accounting principles; potential incidents and other operating risks associated with our business; the impact of an aging infrastructure; the impact of climate change; potential cyber-attacks; construction risks and natural gas costs and supply risks; extreme weather conditions; the attraction and retention of a qualified workforce; the ability of our subsidiaries to generate cash; tax liabilities associated with the separation of Columbia Pipeline Group, Inc. on July 1, 2015; our ability to manage new initiatives and organizational changes; the performance of certain third-party suppliers upon which we rely; our ability to obtain sufficient insurance coverage; and other matters set forth in the “Risk Factors” section of our Annual Report on Form 10-K for the fiscal year ended December 31, 2017, many of which risks are beyond our control. In addition, the relative contributions to profitability by each business segment, and the assumptions underlying the forward-looking statements relating thereto, may change over time.
All forward-looking statements are expressly qualified in their entirety by the foregoing cautionary statements. We undertake no obligation to, and expressly disclaim any such obligation to, update or revise any forward-looking statements to reflect changed assumptions, the occurrence of anticipated or unanticipated events or changes to the future results over time or otherwise, except as required by law.

4


Index
Page


5


PART I

ITEM 1. FINANCIAL STATEMENTS
NiSource Inc.
Condensed Statements of Consolidated Income (Loss) (unaudited)
  
Three Months Ended
June 30,
 
Six Months Ended
June 30,
(in millions, except per share amounts)
2018
 
2017
 
2018
 
2017
Operating Revenues
 
 
 
 
 
 
Customer revenues
$
982.1

 
$
960.1

 
$
2,699.3

 
$
2,502.6

Other revenues
24.9

 
30.6

 
58.5

 
86.7

Total Operating Revenues
1,007.0

 
990.7

 
2,757.8

 
2,589.3

Operating Expenses
 
 
 
 
 
 
 
Cost of sales (excluding depreciation and amortization)
313.3

 
276.8

 
1,037.7

 
829.1

Operation and maintenance
365.2

 
391.6

 
767.7

 
803.2

Depreciation and amortization
144.6

 
142.2

 
289.3

 
285.5

Gain on sale of assets and impairments, net

 
(0.1
)
 
(0.3
)
 
(0.1
)
Other taxes
65.5

 
56.2

 
144.4

 
132.2

Total Operating Expenses
888.6

 
866.7

 
2,238.8

 
2,049.9

Operating Income
118.4

 
124.0

 
519.0

 
539.4

Other Income (Deductions)
 
 
 
 
 
 
 
Interest expense, net
(88.7
)
 
(87.7
)
 
(181.8
)
 
(172.9
)
Other, net
12.8

 
4.2

 
44.1

 
6.5

Loss on early extinguishment of long-term debt
(12.5
)
 
(111.5
)
 
(12.5
)
 
(111.5
)
Total Other Deductions, Net
(88.4
)
 
(195.0
)
 
(150.2
)
 
(277.9
)
Income (Loss) before Income Taxes
30.0


(71.0
)

368.8


261.5

Income Taxes
5.5

 
(26.6
)
 
68.2

 
94.6

Net Income (Loss)
24.5

 
(44.4
)
 
300.6

 
166.9

Preferred dividends
(1.3
)
 

 
(1.3
)
 

Net Income (Loss) Available to Common Shareholders
23.2

 
(44.4
)
 
299.3

 
166.9

Earnings (Loss) Per Share
 
 
 
 
 
 
 
Basic Earnings (Loss) Per Share
$
0.07


$
(0.14
)

$
0.86


$
0.51

Diluted Earnings (Loss) Per Share
$
0.07

 
$
(0.14
)
 
$
0.86

 
$
0.51

Dividends Declared Per Common Share
$
0.195

 
$
0.175

 
$
0.585

 
$
0.525

Basic Average Common Shares Outstanding
354.2

 
325.1

 
346.2

 
324.4

Diluted Average Common Shares
355.2

 
325.1

 
347.1

 
325.8


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

6

Table of Contents
ITEM 1. FINANCIAL STATEMENTS (continued)


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

 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
(in millions, net of taxes)
2018
 
2017
 
2018
 
2017
Net Income (Loss)
$
24.5

 
$
(44.4
)
 
$
300.6

 
$
166.9

Other comprehensive income:
 
 
 
 
 
 
 
 Net unrealized gain (loss) on available-for-sale securities(1)
(0.7
)
 
0.6

 
(2.4
)
 
1.0

Net unrealized gain (loss) on cash flow hedges(2)
(1.4
)
 
(16.8
)
 
34.0

 
(11.9
)
Unrecognized pension and OPEB benefit(3)
0.2

 
0.2

 
0.4

 
0.4

Total other comprehensive income (loss)
(1.9
)
 
(16.0
)
 
32.0

 
(10.5
)
Comprehensive Income (Loss)
$
22.6

 
$
(60.4
)

$
332.6


$
156.4

(1) Net unrealized gain (loss) on available-for-sale securities, net of $0.2 million tax benefit and $0.4 million tax expense in the second quarter of 2018 and 2017, respectively, and $0.6 million tax benefit and $0.6 million tax expense for the six months ended 2018 and 2017, respectively.
(2) Net unrealized gain (loss) on cash flow hedges, net of $0.5 million and $10.3 million tax benefit in the second quarter of 2018 and 2017, respectively, and $11.2 million tax expense and $7.3 million tax benefit for the six months ended 2018 and 2017, respectively. See Note 9, "Risk Management Activities," for additional information.
(3) Unrecognized pension and OPEB benefit, net of $0.1 million and $0.2 million tax expense in the second quarter of 2018 and 2017, respectively, and $0.2 million and $0.3 million tax expense for the six months ended 2018 and 2017, respectively.
The accompanying Notes to Condensed Consolidated Financial Statements (unaudited) are an integral part of these statements.

7

Table of Contents
ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.
Condensed Consolidated Balance Sheets (unaudited)
(in millions)
June 30,
2018
 
December 31,
2017
ASSETS
 
 
 
Property, Plant and Equipment
 
 
 
Utility plant
$
21,914.8

 
$
21,026.6

Accumulated depreciation and amortization
(7,083.7
)
 
(6,953.6
)
Net utility plant
14,831.1

 
14,073.0

Other property, at cost, less accumulated depreciation
16.8

 
286.5

Net Property, Plant and Equipment
14,847.9

 
14,359.5

Investments and Other Assets
 
 
 
Unconsolidated affiliates
4.2

 
5.5

Other investments
199.6

 
204.1

Total Investments and Other Assets
203.8

 
209.6

Current Assets
 
 
 
Cash and cash equivalents
68.2

 
29.0

Restricted cash
12.9

 
9.4

Accounts receivable (less reserve of $24.2 and $18.3, respectively)
584.8

 
898.9

Gas inventory
182.8

 
285.1

Materials and supplies, at average cost
99.9

 
105.9

Electric production fuel, at average cost
53.8

 
80.1

Exchange gas receivable
29.6

 
45.8

Regulatory assets
174.6

 
176.3

Prepayments and other
109.1

 
132.8

Total Current Assets
1,315.7

 
1,763.3

Other Assets
 
 
 
Regulatory assets
1,918.7

 
1,624.9

Goodwill
1,690.7

 
1,690.7

Intangible assets, net
226.2

 
231.7

Deferred charges and other
104.9

 
82.0

Total Other Assets
3,940.5

 
3,629.3

Total Assets
$
20,307.9

 
$
19,961.7

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

8

Table of Contents
ITEM 1. FINANCIAL STATEMENTS (continued)

NiSource Inc.
Condensed Consolidated Balance Sheets (unaudited) (continued)
(in millions, except share amounts)
June 30,
2018
 
December 31,
2017
CAPITALIZATION AND LIABILITIES
 
 
 
Capitalization
 
 
 
Stockholders’ Equity
 
 
 
Common stock - $0.01 par value, 400,000,000 shares authorized; 362,915,039 and 337,015,806 shares outstanding, respectively
$
3.7

 
$
3.4

Preferred stock - $1,000 par value, 20,000,000 shares authorized; 400,000 shares outstanding
394.4

 

Treasury stock
(99.9
)
 
(95.9
)
Additional paid-in capital
6,151.2

 
5,529.1

Retained deficit
(965.5
)
 
(1,073.1
)
Accumulated other comprehensive loss
(20.9
)
 
(43.4
)
Total Stockholders’ Equity
5,463.0

 
4,320.1

Long-term debt, excluding amounts due within one year
7,092.5

 
7,512.2

Total Capitalization
12,555.5


11,832.3

Current Liabilities
 
 
 
Current portion of long-term debt
597.7

 
284.3

Short-term borrowings
600.0

 
1,205.7

Accounts payable
455.0

 
625.6

Dividends payable
70.8

 

Customer deposits and credits
158.0

 
262.6

Taxes accrued
165.8

 
208.1

Interest accrued
103.3

 
112.3

Risk management liabilities
4.0

 
43.2

Exchange gas payable
36.9

 
59.6

Regulatory liabilities
121.5

 
58.7

Legal and environmental
36.0

 
32.1

Accrued compensation and employee benefits
135.8

 
195.4

Other accruals
75.6

 
90.8

Total Current Liabilities
2,560.4

 
3,178.4

Other Liabilities
 
 
 
Risk management liabilities
44.9

 
28.5

Deferred income taxes
1,396.7

 
1,292.9

Deferred investment tax credits
11.9

 
12.4

Accrued insurance liabilities
86.0

 
80.1

Accrued liability for postretirement and postemployment benefits
311.7

 
337.1

Regulatory liabilities
2,821.4

 
2,736.9

Asset retirement obligations
334.6

 
268.7

Other noncurrent liabilities
184.8

 
194.4

Total Other Liabilities
5,192.0

 
4,951.0

Commitments and Contingencies (Refer to Note 17, "Other Commitments and Contingencies")

 

Total Capitalization and Liabilities
$
20,307.9

 
$
19,961.7

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

9

Table of Contents
ITEM 1. FINANCIAL STATEMENTS (continued)

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

Six Months Ended June 30, (in millions)
2018
 
2017
Operating Activities
 
 
 
Net Income
$
300.6

 
$
166.9

Adjustments to Reconcile Net Income to Net Cash from Operating Activities:
 
 
 
Loss on early extinguishment of debt
12.5

 
111.5

Depreciation and amortization
289.3

 
285.5

Deferred income taxes and investment tax credits
66.3

 
88.4

Other adjustments
11.3

 
22.4

Changes in Assets and Liabilities:
 
 
 
Components of working capital
12.4

 
(6.4
)
Regulatory assets/liabilities
141.7

 
23.2

Deferred charges and other noncurrent assets
1.2

 
(1.1
)
Other noncurrent liabilities
(25.8
)
 
(39.0
)
Net Cash Flows from Operating Activities
809.5

 
651.4

Investing Activities
 
 
 
Capital expenditures
(832.5
)
 
(732.2
)
Cost of removal
(46.1
)
 
(55.6
)
Purchases of available-for-sale securities
(46.8
)
 
(105.6
)
Sales of available-for-sale securities
47.5

 
106.6

Other investing activities
6.8

 
0.9

Net Cash Flows used for Investing Activities
(871.1
)
 
(785.9
)
Financing Activities
 
 
 
Issuance of long-term debt
350.0

 
2,000.0

Repayments of long-term debt and capital lease obligations
(491.2
)
 
(1,078.4
)
Premiums and other debt related costs
(15.2
)
 
(130.7
)
Issuance of short-term debt (maturity > 90 days)
600.0

 

Change in short-term borrowings, net (maturity ≤ 90 days)
(1,205.7
)
 
(586.7
)
Issuance of common stock
607.7

 
46.2

Issuance of preferred stock
394.4

 

Acquisition of treasury stock
(4.0
)
 
(5.9
)
Dividends paid - common stock
(131.7
)
 
(113.2
)
Net Cash Flows from Financing Activities
104.3

 
131.3

Change in cash, cash equivalents and restricted cash
42.7

 
(3.2
)
Cash, cash equivalents and restricted cash at beginning of period
38.4

 
36.0

Cash, Cash Equivalents and Restricted Cash at End of Period
$
81.1

 
$
32.8


Supplemental Disclosures of Cash Flow Information
Six Months Ended June 30, (in millions)
2018
 
2017
Non-cash transactions:
 
 
 
Capital expenditures included in current liabilities
$
191.9

 
$
206.9

Dividends declared but not paid
70.8

 
57.0

Reclassification of other property to regulatory assets(1)
245.3

 

Change in estimated costs of asset retirement obligations(2)
$
62.5

 
$

(1)See Note 17-D "Other Matters" for additional information.
(2)See Note 7 "Asset Retirement Obligations" for additional information.

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

10

Table of Contents
ITEM 1. FINANCIAL STATEMENTS (continued)


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

 
$

 
$
(95.9
)
 
$
5,529.1

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

Comprehensive Income (Loss):
 
 
 
 
 
 
 
 
 
 
 
 
 
Net Income

 

 

 

 
300.6

 

 
300.6

Other comprehensive income, net of tax

 

 

 

 

 
32.0

 
32.0

Common stock dividends ($0.585 per share)

 

 

 

 
(202.5
)
 

 
(202.5
)
Treasury stock acquired

 

 
(4.0
)
 

 

 

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

 

 

 

 
9.5

 
(9.5
)
 

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

 

 

 
599.3

 

 

 
599.6

Preferred stock

 
394.4

 

 

 

 

 
394.4

Employee stock purchase plan

 

 

 
2.7

 

 

 
2.7

Long-term incentive plan

 

 

 
8.2

 

 

 
8.2

401(k) and profit sharing

 

 

 
11.9

 

 

 
11.9

Balance as of June 30, 2018
$
3.7

 
$
394.4

 
$
(99.9
)
 
$
6,151.2

 
$
(965.5
)
 
$
(20.9
)
 
$
5,463.0

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

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

 
340,813

 
(3,797
)
 
337,016

Treasury Stock acquired

 

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

 
24,964

 

 
24,964

Preferred stock
400

 

 

 

Employee stock purchase plan

 
111

 

 
111

Long-term incentive plan

 
494

 

 
494

401(k) and profit sharing

 
496

 

 
496

Balance as of June 30, 2018
400

 
366,878

 
(3,963
)
 
362,915

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


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


11

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

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

Recently Issued Accounting Pronouncements

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


12

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

Standard
Description
Effective Date
Effect on the financial statements or other significant matters
ASU 2016-13, Financial Instruments-Credit Losses (Topic 326)
The pronouncement changes the impairment model for most financial assets, replacing the current "incurred loss" model. ASU 2016-13 will require the use of an "expected loss" model for instruments measured at amortized cost. It will also require entities to record allowances for available-for-sale debt securities rather than impair the carrying amount of the securities. Subsequent improvements to the estimated credit losses of available-for-sale securities will be recognized immediately in earnings instead of over time as they are under historic guidance.
Annual periods beginning after December 15, 2019, including interim periods therein. Early adoption is permitted for annual or interim periods beginning after December 15, 2018.
We maintain investments in U.S. Treasury, corporate and mortgage-backed debt securities which are pledged as collateral for trust accounts related to our wholly-owned insurance company. These debt securities are classified as available for sale. We are currently evaluating the impact of adoption, if any, on our Condensed Consolidated Financial Statements (unaudited) and Notes to Condensed Consolidated Financial Statements (unaudited).
ASU 2018-11, Leases (Topic 842): Targeted Improvements
The pronouncement allows entities the option to initially apply ASC 842 at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption.
Annual periods beginning after December 15, 2018, including interim periods therein. Early adoption is permitted.
We are the lessee for substantially all of our current leasing activity. Upon adopting ASC 842 we will begin recognizing right-of-use assets and liabilities associated with operating leases (other than short term operating leases) on our Condensed Consolidated Balance Sheets (unaudited). The impact of this change on the balance sheet is not reasonably estimable at this time. We do not anticipate the adoption of ASC 842 will have a material impact to our results of operations or cash flows. We are implementing a new lease accounting system, which we will utilize to capture, track, and account for lease data. We began system testing at the end of June 2018 and anticipate full system implementation prior to the effective date of these standards. ASC 842 provides lessees the option of electing an accounting policy, by class of underlying asset, in which the lessee may choose not to separate nonlease components from lease components. We currently anticipate adopting this practical expedient for certain classes of leases. Further, we tentatively expect to elect the "practical expedient package" described in ASC 842-10-65-1. We maintain a substantial number of easements and expect the provisions of ASU 2018-01 will ease the process of implementing ASC 842. We tentatively plan to elect the transition method provided in ASU 2018-11. We intend to adopt these standards effective January 1, 2019.
ASU 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842
The pronouncement offers a practical expedient for accounting for land easements under ASU 2016-02. This practical expedient allows an entity the option of not evaluating existing land easements under ASC 842. New or modified land easements will still require evaluation under ASC 842 on a prospective basis beginning on the date of adoption.
ASU 2016-02, Leases (Topic 842)
The pronouncement introduces a lessee model that brings most leases on the balance sheet. The standard requires that lessees recognize the following for all leases (with the exception of short-term leases, as that term is defined in the standard) at the lease commencement date: (1) a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and (2) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term.

13

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

14

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.

15

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 six months ended June 30, 2018 as if they had been prepared under historic accounting guidance. We included operating revenue information for the three and six months ended June 30, 2017 for comparability.
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
(in millions)
2018
 
2017
 
2018
 
2017
Operating Revenues
 
 
 
 
 
 
 
Gas Distribution
$
384.2

 
$
327.1

 
$
1,368.0

 
$
1,163.6

Gas Transportation
216.9

 
204.9

 
559.1

 
543.5

Electric
405.0

 
458.0

 
828.3

 
879.7

Other
0.9

 
0.7

 
2.4

 
2.5

Total Operating Revenues
$
1,007.0

 
$
990.7

 
$
2,757.8

 
$
2,589.3


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

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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 June 30, 2018 (in millions)
Gas Distribution Operations
 
Electric Operations
 
Corporate and Other
 
Total
Customer Revenues(1)
 
 
 
 
 
 
 
Residential
$
389.7

 
$
113.1

 
$

 
$
502.8

Commercial
127.0

 
116.6

 

 
243.6

Industrial
47.7

 
152.0

 

 
199.7

Off-system
20.9

 

 

 
20.9

Miscellaneous
10.2

 
4.7

 
0.2

 
15.1

Total Customer Revenues
$
595.5

 
$
386.4

 
$
0.2

 
$
982.1

Other Revenues
6.4

 
18.5

 

 
24.9

Total Operating Revenues
$
601.9

 
$
404.9

 
$
0.2

 
$
1,007.0

(1) Customer revenue amounts exclude intersegment revenues. See Note 20, "Business Segment Information," for discussion of intersegment revenues.
Six Months Ended June 30, 2018 (in millions)
Gas Distribution Operations
 
Electric Operations
 
Corporate and Other
 
Total
Customer Revenues(1)
 
 
 
 
 
 
 
Residential
$
1,283.3

 
$
227.6

 
$

 
$
1,510.9

Commercial
435.3

 
233.5

 

 
668.8

Industrial
122.3

 
314.5

 

 
436.8

Off-system
43.2

 

 

 
43.2

Miscellaneous
27.0

 
12.2

 
0.4

 
39.6

Total Customer Revenues
$
1,911.1

 
$
787.8

 
$
0.4

 
$
2,699.3

Other Revenues
18.1

 
40.4

 

 
58.5

Total Operating Revenues
$
1,929.2

 
$
828.2

 
$
0.4

 
$
2,757.8

(1) Customer revenue amounts exclude intersegment revenues. See Note 20, "Business Segment Information," for discussion of intersegment revenues.
Customer Accounts Receivable. Accounts receivable on our Condensed Consolidated Balance Sheets (unaudited) includes both billed and unbilled amounts as well as certain amounts that are not related to customer revenues. Unbilled amounts of accounts receivable relate to a portion of a customer’s consumption of gas or electricity from the date of the last cycle billing date through the last day of the month (balance sheet date). Factors taken into consideration when estimating unbilled revenue include historical usage, customer rates and weather. The opening and closing balances of customer receivables for the six months ended June 30, 2018 are presented in the table below. We had no significant contract assets or liabilities during the period. Additionally, we have not incurred any significant costs to obtain or fulfill contracts.
(in millions)
Customer Accounts Receivable, Billed (less reserve)(1)
 
Customer Accounts Receivable, Unbilled (less reserve)(2)
Balance as of December 31, 2017
$
477.0

 
$
356.0

Balance as of June 30, 2018
373.6

 
155.1

Increase (Decrease)
$
(103.4
)
 
$
(200.9
)
(1) Customer billed receivables decreased over the period due to the expected seasonal decrease in customer usage in June when compared to December.
(2) Customer unbilled receivables decreased over the period due to the expected seasonal decrease in customer usage in June when compared to December.


17

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 calculation of diluted earnings per share excludes the impact of forward agreements (see Note 5, "Equity"), which had an anti-dilutive effect for the periods outstanding. The computation of diluted average common shares for the three months ended June 30, 2017 is not presented since we had a net loss on the Condensed Statements of Consolidated Income (Loss) (unaudited) during the period and any incremental shares would have had an anti-dilutive impact on EPS. The computation of diluted average common shares is as follows:
 
Three Months Ended
 
Six Months Ended
 
June 30,
 
June 30,
(in thousands)
2018
 
2018
 
2017
Denominator
 
 
 
 
 
Basic average common shares outstanding
354,229

 
346,165

 
324,386

Dilutive potential common shares:
 
 
 
 
 
Shares contingently issuable under employee stock plans
861

 
789

 
452

Shares restricted under employee stock plans
71

 
167

 
975

Diluted Average Common Shares
355,161

 
347,121

 
325,813


5.    Equity
ATM Program and Forward Sale Agreement. On May 3, 2017, we entered into four separate equity distribution agreements, pursuant to which we may sell, from time to time, up to an aggregate of $500.0 million of our common stock. During the three and six months ended June 30, 2017, we issued 1,318,461 shares of common stock under the program at an average price of $25.88 per share, receiving proceeds, net of fees, of $33.8 million. There was no activity under the ATM program in 2018. As of June 30, 2018, the ATM program (including impacts of forward sales agreements discussed below) had approximately $10.0 million of equity available for issuance. The program expires on December 31, 2018.
On November 13, 2017, under the ATM program, we executed a forward agreement, which allows us to issue a fixed number of shares at a price to be settled in the future. From November 13, 2017 to December 8, 2017, 6,345,860 shares were borrowed from third parties and sold by the dealer at a weighted average price of $27.24 per share. We may settle this agreement in shares, cash, or net shares by November 12, 2018. Had we settled all 6,345,860 shares under the forward agreement at June 30, 2018, we would have received approximately $169.4 million, based on a net price of $26.70 per share.
Private Placement of Common Stock. On May 4, 2018, we completed the sale of 24,964,163 shares of $0.01 par value common stock at a price of $24.28 per share in a private placement to selected institutional and accredited investors. The private placement resulted in $606.0 million of gross proceeds or $599.6 million of net proceeds, after deducting commissions and sale expenses.

18

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

The common stock issued in connection with the private placement was registered on Form S-1, filed with the SEC on May 11, 2018.
Private Placement of Preferred Stock. On June 11, 2018, we completed the sale of 400,000 shares of 5.650% Series A Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Stock (the "Series A Preferred Stock") at a price of $1,000 per share. The transaction resulted in $400.0 million of gross proceeds or $394.4 million of net proceeds, after deducting commissions and sales expenses. The Series A Preferred Stock was issued in a private placement pursuant to SEC Rule 144A. We agreed pursuant to a registration rights agreement to file with the SEC a registration statement enabling holders to exchange their unregistered shares of Series A Preferred Stock for publicly registered shares with substantially identical terms.
Proceeds from the issuance of the Series A Preferred Stock were used to pay a portion of the notes tendered in June 2018 and the redemption of the remaining notes in July 2018. See Note 15, “Long-term Debt” for additional information regarding the tender offer and redemption.
Dividends on the Series A Preferred Stock accrue and are cumulative from the date the shares of Series A Preferred Stock were originally issued to, but not including, June 15, 2023 at a rate of 5.650% per annum of the $1,000 liquidation preference per share. On and after June 15, 2023, dividends on the Series A Preferred Stock will accumulate for each five year period at a percentage of the $1,000 liquidation preference equal to the five-year U.S. Treasury Rate plus (i) in respect of each five year period commencing on or after June 15, 2023 but before June 15, 2043, a spread of 2.843% (the “Initial Margin”), and (ii) in respect of each five year period commencing on or after June 15, 2043, the Initial Margin plus 1.000%. The Series A Preferred Stock may be redeemed by us at our option on June 15, 2023, or on each date falling on the fifth anniversary thereafter, or in connection with a ratings event (as defined in the Certificate of Designation of the Series A Preferred Stock).
Holders of Series A Preferred Stock generally have no voting rights, except for limited voting rights with respect to (i) potential amendments to our certificate of incorporation that would have a material adverse effect on the existing preferences, rights, powers or duties of the Series A Preferred Stock, (ii) the creation or issuance of any security ranking on a parity with the Series A Preferred Stock if the cumulative dividends payable on then outstanding Series A Preferred Stock are in arrears, or (iii) the creation or issuance of any security ranking senior to the Series A Preferred Stock. The Series A Preferred Stock does not have a stated maturity and is not subject to mandatory redemption or any sinking fund. The Series A Preferred Stock will remain outstanding indefinitely unless repurchased or redeemed by us. Any such redemption would be effected only out of funds legally available for such purposes and will be subject to compliance with the provisions of our outstanding indebtedness.
 
 
 
 
 
 
 
 
6.    Gas in Storage
We use both the LIFO inventory methodology and the weighted-average cost methodology to value natural gas in storage. Gas Distribution Operations prices natural gas storage injections at the average of the costs of natural gas supply purchased during the year. For interim periods, the difference between current projected replacement cost and the LIFO cost for quantities of gas temporarily withdrawn from storage is recorded as a temporary LIFO liquidation credit or debit within the Condensed Consolidated Balance Sheets (unaudited). Due to seasonality requirements, we expect interim variances in LIFO layers to be replenished by year end. We had a temporary LIFO liquidation debit of $12.9 million and zero as of June 30, 2018 and December 31, 2017, respectively, for certain gas distribution companies recorded within “Prepayments and other,” on the Condensed Consolidated Balance Sheets (unaudited).
7.    Asset Retirement Obligations
In the second quarter of 2018, we made revisions to the estimated costs associated with refining the CCR compliance plan. The CCR rule requires the continued collection of data over time to determine the specific compliance solution. The change in estimated costs resulted in an increase to the asset retirement obligation liability of $62.5 million that was recorded in June 2018. See Note 17-C, "Environmental Matters," for additional information on CCRs.
 
 
 
 
 
8.    Regulatory Matters
Gas Distribution Operations Regulatory Matters
Cost Recovery and Trackers. Comparability of Gas Distribution Operations line item operating results is impacted by regulatory trackers that allow for the recovery in rates of certain costs such as those described below. Increases in the expenses that are the subject of trackers generally result in a corresponding increase in operating revenues and therefore have essentially no impact on total operating income results.

19

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

Certain operating costs of our distribution companies are significant, recurring in nature and generally outside the control of the distribution companies. Some states allow the recovery of such costs through cost tracking mechanisms. Such tracking mechanisms allow for abbreviated regulatory proceedings in order for the distribution companies to implement charges and recover appropriate costs. Tracking mechanisms allow for more timely recovery of such costs as compared with more traditional cost recovery mechanisms. Examples of such mechanisms include GCR adjustment mechanisms, tax riders and bad debt recovery mechanisms.
A portion of the distribution companies' revenue is related to the recovery of gas costs, the review and recovery of which occurs through standard regulatory proceedings. All states in our operating area require periodic review of actual gas procurement activity to determine prudence and to permit the recovery of prudently incurred costs related to the supply of gas for customers. Our distribution companies have historically been found prudent in the procurement of gas supplies to serve customers.
Certain of our distribution companies have completed rate proceedings involving infrastructure replacement or are embarking upon regulatory initiatives to replace significant portions of their operating systems that are nearing the end of their useful lives. Each LDC's approach to cost recovery may be unique, given the different laws, regulations and precedent that exist in each jurisdiction.
Columbia of Ohio. On January 10, 2018, the PUCO issued an entry to investigate the impacts of the TCJA including an invitation to utilities and other interested stakeholders to file public comments including: (1) those components of utility rates that the PUCO will need to reconcile with the TCJA; and (2) the process and mechanics for how the PUCO should do so. The PUCO also directed utilities to record a regulatory liability for the estimated reduction in federal income tax resulting from the TCJA. On February 15, 2018, Columbia of Ohio filed comments proposing to: (1) reflect the impact of the TCJA on its application to adjust rates associated with its IRP rider, subsequently filed on February 27, 2018; and (2) file a reduction in other base rates no later than October 15, 2018 reflecting the impact of the TCJA. The PUCO issued a procedural schedule on May 24, 2018 and a hearing was held on July 10, 2018.
On January 31, 2018, the PUCO approved Columbia of Ohio’s application to extend its IRP for an additional five years (2018-2022), allowing Columbia of Ohio to continue to invest and recover on its accelerated main replacements. The Office of the Ohio Consumers’ Counsel filed an application for rehearing asserting certain issues with Columbia of Ohio's application. On May 9, 2018, the PUCO issued an order denying the application for rehearing.
As referred to above, Columbia of Ohio filed its most recent application to adjust rates associated with its IRP rider on February 27, 2018, which requested authority to increase annual billings by approximately $2.3 million (net of the impact of the TCJA) reflecting recovery of and return on approximately $207 million of incremental IRP capital additions in 2017. A stipulation was filed with the PUCO on March 28, 2018. On April 25, 2018, the PUCO approved Columbia of Ohio’s annual IRP tracker adjustment with rates effective May 1, 2018.
On December 1, 2017, Columbia of Ohio filed an application that requested authority to implement a rider to begin recovering plant and associated deferrals related to its CEP. The CEP was established in 2011 and allows for deferral of interest, depreciation and property taxes on certain plant investments not recovered through its IRP modernization tracker. The application requested authority to increase annual revenues, through the requested rider, by approximately $70 million, with biennial increases up to approximately $98 million in 2022. On May 9, 2018, the PUCO appointed an independent auditor to assist the PUCO with the review of the accounting accuracy, prudency and compliance of Columbia of Ohio with its Commission-approved CEP deferrals. The audit of the CEP is expected to be completed by September 4, 2018 at which point we anticipate a full procedural schedule will be established.
NIPSCO Gas. On January 3, 2018, the IURC initiated an investigation to review and consider the possible implications of the TCJA on utility rates. The Commission ordered a two phase investigation. Phase 1 solely dealt with the prospective changes in rates to reflect the change in tax rates. In accordance with the procedural schedule, on March 26, 2018, NIPSCO filed revised gas tariffs reflecting the impact of the change in tax rate for its applicable rates and charges. The IURC approved NIPSCO's Phase 1 filing on April 26, 2018. The revised tariffs were effective May 1, 2018. The stipulation and settlement agreement filed on April 20, 2018, in NIPSCO’s gas rate case (discussed immediately below) resolved all issues in Phase 2.
On September 27, 2017, NIPSCO filed a base rate case with the IURC, seeking an annual revenue increase of $143.5 million (inclusive of amounts being recovered through various tracker programs). As part of this filing and among other items, NIPSCO proposed to update base rates for ongoing infrastructure improvements, revised depreciation rates and ongoing level of expenses to reflect the current costs of providing natural gas service. NIPSCO submitted a rebuttal on March 28, 2018 updating its request, including the impact of the TCJA, seeking a revised annual revenue increase of $138.1 million. On April 20, 2018, a settlement

20

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

agreement was filed with the IURC seeking, among other items, an annual revenue increase of $107.3 million. An order from the IURC is expected in the third quarter of 2018 with rates expected to be effective October 1, 2018 for Phase 1 implementation.
On November 8, 2017, NIPSCO filed a petition with the IURC seeking approval of NIPSCO’s federally mandated pipeline safety compliance plan. As part of the aforementioned settlement agreement filed in NIPSCO’s gas base rate case proceeding, NIPSCO and the parties to the settlement agreement settled all issues in this proceeding as well, including moving certain costs from the base rate proceeding to this pipeline safety compliance plan. The updated four year compliance plan includes a total estimated $91.5 million of capital costs and $35.5 million of expected operating and maintenance costs. NIPSCO is requesting all associated accounting and ratemaking relief, including establishment of a periodic rate adjustment mechanism. An IURC order is expected in the third quarter of 2018.
On April 30, 2013, the Governor of Indiana signed Senate Enrolled Act 560, the TDSIC statute, into law. Among other provisions, this legislation provides for cost recovery outside of a base rate proceeding for new or replacement electric and gas transmission, distribution and storage projects that a public utility undertakes for the purposes of safety, reliability, system modernization or economic development. Provisions of the TDSIC statute require that, among other things, requests for recovery include a seven-year plan of eligible investments. Once the plan is approved by the IURC, eighty percent of eligible costs can be recovered using a periodic rate adjustment mechanism. The cost recovery mechanism is referred to as a TDSIC mechanism. Recoverable costs include a return on, and of, the investment, including AFUDC, post-in-service carrying charges, operation and maintenance expenses, depreciation and property taxes. The remaining twenty percent of recoverable costs are to be deferred for future recovery in the public utility’s next general rate case. The periodic rate adjustment mechanism is capped at an annual increase of no more than two percent of total retail revenues. On April 2, 2018, NIPSCO filed a new seven-year gas TDSIC plan with the IURC beginning in 2019. The filing seeks approval of a total capital expenditure level of approximately $1.25 billion. An IURC order is expected in the fourth quarter of 2018.
On February 27, 2018, NIPSCO filed TDSIC-8 requesting to recover an incremental increase to revenue of $0.8 million (net of the impacts of TCJA) associated with incremental capital investment of $77.9 million made in the second half of 2017. An IURC order was expected in the second quarter of 2018, with new rates effective in July. On June 20, 2018, the Indiana Supreme Court issued an order reversing the IURC and the Court of Appeals in NIPSCO’s gas TDSIC-4 proceeding and held that periodic rate increases are available only for specific projects designated in the threshold proceeding and multiple-unit-projects not identified with particularity are not recoverable through the tracker. A revised TDSIC-8 was filed on July 18, 2018 and reduced the previous February 27, 2018 request by $0.2 million associated with incremental capital investment of approximately $54 million. An order on the revised filing is expected in the third quarter of 2018. In the second quarter of 2018, NIPSCO recorded a liability of $2.5 million associated with the TDSIC-4 through TDSIC-8 filings for a related passback of revenue previously billed to customers. Timing of this passback has not yet been determined.
Columbia of Massachusetts. On February 2, 2018, the Massachusetts DPU opened an investigation into the effect of the reduction in federal income tax rates on the rates charged by utility companies. Columbia of Massachusetts was directed to account for any revenues associated with the difference between previous and current income tax rates and excess deferred income taxes as regulatory liabilities effective January 1, 2018. Companies were ordered to submit a proposal to revise rates by May 1, 2018. The order indicates that if a company files a base rate case prior to the conclusion of the investigation, it must address the TCJA issues as part of the case. Since CMA filed a base rate case on April 13, 2018, the changes in base rates and the regulatory liability disposition related to the TCJA are reflected in the case. On June 29, 2018, the Massachusetts DPU required companies in a rate case to reduce rates as of July 1, 2018 or, in the alternative, defer this rate reduction to coincide with the effective date of new rates in a rate case, provided that tax savings from July 1, 2018 through the effective date of new rates accrue interest at prime rate. On July 2, 2018, Columbia of Massachusetts filed tariffs reflecting revised rates incorporating the lower federal corporate income tax rate for effect July 1, 2018. In the filing, Columbia of Massachusetts noted the Massachusetts DPU stated it would address the refund of any tax savings accrued from January 1, 2018, through June 30, 2018, in a separate phase of its investigation. On July 10, 2018, the Massachusetts DPU approved the tariffs effective July 1, 2018, finding the adjustment is in the public interest, as it provides an immediate benefit to ratepayers.
As noted above, on April 13, 2018, Columbia of Massachusetts filed a rate case with the Massachusetts DPU, seeking approval for an annual revenue increase of approximately $43.8 million which is offset by revenue decreases in other rate factors of $19.7 million, representing a net increase in operating revenues of $24.1 million. Included in the filing is a proposal to adjust rates and address the regulatory liability disposition related to the TCJA. Rates are expected to go into effect March 1, 2019, upon approval from the Massachusetts DPU. On June 29, 2018, Columbia of Massachusetts filed a letter with a settlement negotiations update noting the Office of the Attorney General and Columbia of Massachusetts continue to discuss the possibility of a negotiated settlement.

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

On July 7, 2014, the Governor of Massachusetts signed into law Chapter 149 of the Acts of 2014, An Act Relative to Natural Gas Leaks (“the Act”). The Act authorizes natural gas distribution companies to file gas infrastructure replacement plans with the Massachusetts DPU to address the replacement of aging natural gas pipeline infrastructure. In addition, the Act provides that the Massachusetts DPU may, after review of the plans, allow the proposed estimated costs of the plan into rates as of May 1 of the subsequent year. On October 31, 2017, Columbia of Massachusetts filed its GSEP for the 2018 construction year. Columbia of Massachusetts proposed to recover incremental revenue of $9.7 million associated with incremental capital investment of $83.9 million to be made during calendar year 2018. The filing included a request for approval of an alternative calculation or a waiver to allow collection of the $3.1 million revenue requirement that exceeds the GSEP cap provision as previously calculated. On January 29, 2018, Columbia of Massachusetts filed a revision to its GSEP tracker for the 2018 construction season reducing the proposed revenue requirement to reflect the impact of the TCJA. The revenue requirement was reduced by $2.4 million due to the TCJA. An order was received from the Massachusetts DPU on April 30, 2018, approving an incremental revenue requirement of $6.1 million associated with the incremental capital investment of $83.9 million, with new rates effective May 1, 2018. The order did not approve the alternative cap calculation and the portion of the revenue requirement that exceeds the GSEP cap provision. On May 21, 2018, Columbia of Massachusetts filed a motion for reconsideration on the Massachusetts DPU’s denial of Columbia of Massachusetts’s request for a waiver on the 1.5% revenue cap calculation. On June 21, 2018, the Massachusetts DPU issued an order granting a waiver on the revenue cap allowing an incremental revenue requirement of $6.5 million with new rates effective July 1, 2018.
Columbia of Pennsylvania. On February 12, 2018, the Pennsylvania PUC established a docket to investigate the impact of the TCJA on customer rates. The Pennsylvania PUC directed Pennsylvania utilities to account for any revenues associated with the difference between previous and current income tax rates and excess deferred income taxes as regulatory liabilities effective January 1, 2018. On May 17, 2018, the Pennsylvania PUC issued an order directing utilities that do not have a pending rate case to implement a negative surcharge in their billings to reflect the annual reduction in federal tax expense and associated revenue requirement for each utility, effective July 1, 2018. Since Columbia of Pennsylvania has a pending rate case, it is not required to implement the negative surcharge, and it has made a proposal in its pending rate case regarding the use of 2018 tax over-collection proceeds.
As highlighted above, on March 16, 2018, Columbia of Pennsylvania filed a rate case with the Pennsylvania PUC, seeking approval for an annual revenue increase of $46.9 million. Included in the filing is a proposal to adjust rates as a result of the TCJA. On March 21, 2018, Columbia of Pennsylvania filed a supplement to the rate case, under which it proposes to hold the overcollection of taxes during 2018 until the effective date of new base rates as credit to rate base for a period beginning January 2019 not to exceed three years. A decision on Columbia of Pennsylvania’s rate request is expected in the fourth quarter of 2018 with new rates to be implemented in December 2018.
Columbia of Virginia. On January 8, 2018, the VSCC issued an order regarding the TCJA requiring Columbia of Virginia and other Virginia utilities subject to the TCJA to accrue regulatory liabilities reflecting the impacts of the reduced corporate income tax rate effective January 1, 2018. In addition, pursuant to the order, Columbia of Virginia is required to reflect the impacts of the TCJA in its annual informational filing, including: (1) the expected cost of service impacts through calendar year 2018; (2) the amount of protected and unprotected excess accumulated deferred income taxes as of December 31, 2017, and the estimated reversal of such excess deferred income taxes during calendar year 2018; and (3) such additional information that the utility wishes to include addressing the financial and cost of service impacts of the TCJA and the appropriate treatment of the accrued regulatory liabilities. On April 25, 2018 the VSCC, by order, supplemented the above annual informational filing requirements of the January 8, 2018 order to include a proposed rate reduction that reflects the cost savings from the TCJA. This April 25, 2018 order directs that if a utility desires to propose an alternative method for returning the tax savings to customers, then it may instead file a rate case that incorporates the income tax savings. As a result of these orders, Columbia of Virginia made the decision to file a rate case. This rate case is expected to be filed by August 28, 2018.
Columbia of Kentucky. On January 26, 2018, in accordance with the Kentucky PSC investigation related to the TCJA, Columbia of Kentucky filed testimony and proposed a reduction to base rates effective May 1, 2018, to reflect the tax expense reduction as a result of the TCJA. Columbia of Kentucky was directed to account for any revenues associated with the difference between previous and current income tax rates and excess deferred income taxes as regulatory liabilities effective January 1, 2018. Columbia of Kentucky proposed to include the impact of the excess deferred taxes in rates effective October 2018 and to return the revenue related to the regulatory liability subsequent to this date. On April 30, 2018 Columbia of Kentucky received an order from the Kentucky PSC requiring implementation of interim proposed rates that are subject to future adjustment effective May 1, 2018. The order directs Columbia of Kentucky to file, by September 1, 2018, revised TCJA adjustment factors reflecting the tax expense savings from January 1, 2018, through April 30, 2018, and an estimate of the annual reduction due to the excess accumulated deferred income taxes to be effective with the first billing cycle of October 2018.

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

Columbia of Maryland. On February 13, 2018, Columbia of Maryland filed a proposal with the Maryland PSC to reduce rates as a result of TCJA with an annual revenue decrease of $1.3 million. Columbia of Maryland was directed to account for any revenues associated with the difference between previous and current income tax rates and excess deferred income taxes as regulatory liabilities effective January 1, 2018. On March 14, 2018, Columbia of Maryland received approval, effective April 2, 2018, to implement new rates and pass-back the overcollection of taxes from the first quarter of 2018.
On April 13, 2018, Columbia of Maryland filed a request with the Maryland PSC to increase base rates by $6.1 million, inclusive of the impacts of the TCJA. On July 31, 2018, Columbia of Maryland filed a settlement with the Maryland PSC. If approved as filed, the settlement would result in an annual revenue increase of $3.7 million. An order from the PSC is expected in the fourth quarter of 2018.
Electric Operations Regulatory Matters
Cost Recovery and Trackers. Comparability of Electric Operations line item operating results is impacted by regulatory trackers that allow for the recovery in rates of certain costs such as those described below. Increases in the expenses that are the subject of trackers result in a corresponding increase in operating revenues and therefore have essentially no impact on total operating income results.
Certain operating costs of the Electric Operations are significant, recurring in nature, and generally outside the control of NIPSCO. The IURC allows for recovery of such costs through cost tracking mechanisms. Such tracking mechanisms allow for abbreviated regulatory proceedings in order for NIPSCO to implement charges and recover appropriate costs. Tracking mechanisms allow for more timely recovery of such costs as compared with more traditional cost recovery mechanisms. Examples of such mechanisms include electric energy efficiency programs, MISO non-fuel costs and revenues, resource capacity charges, federally mandated costs and environmental-related costs.
A portion of NIPSCO's revenue is related to the recovery of fuel costs to generate power and the fuel costs related to purchased power. These costs are recovered through a FAC, a quarterly regulatory proceeding in Indiana.
As noted above in the NIPSCO Gas regulatory matters, the IURC initiated an investigation on January 3, 2018, to review and consider the implications of the TCJA on utility rates. The commission ordered a two phase investigation. Phase 1 solely dealt with the prospective changes in rates to reflect the change in tax rates. On March 26, 2018, NIPSCO filed revised electric tariffs reflecting the impact of the change in tax rate for its applicable rates and charges. The IURC approved NIPSCO's Phase 1 filing on April 26, 2018. The revised tariffs were effective May 1, 2018. On July 31, 2018, NIPSCO filed an unopposed motion requesting that the over-collection of income taxes from January 1, 2018 through April 30, 2018 be passed back in NIPSCO’s TDSIC-4 filing, also filed on July 31, 2018, and requesting that all other Phase 2 issues be handled in a rate case filing to be made in the fourth quarter of 2018. The impact on NIPSCO electric of the Phase 2 investigation is unknown at this time.
On March 29, 2018, WCE, which is currently owned by BP p.l.c ("BP") and BP Products North America, which operates the BP Refinery, filed a petition at the IURC asking that the combined operations of WCE and BP be treated as a single premise, and the WCE generation be dedicated primarily to BP Refinery operations beginning in May 2019 as WCE has self-certified as a qualifying facility at FERC. BP Refinery plans to continue to purchase electric service from NIPSCO at a reduced demand level beginning in May 2019. NIPSCO is currently evaluating the impact of the WCE petition, including the associated impacts on revenue. NIPSCO anticipates filing an electric rate case in the fourth quarter of 2018, in part, to address anticipated revenue loss resulting from this filing. NIPSCO also anticipates filing an updated Integrated Resource Plan in the fourth quarter of 2018, which will evaluate demand-side and supply-side resource alternatives to reliably and cost effectively meet NIPSCO customers' future energy requirements over the ensuing 20 years.  
On January 30, 2018, NIPSCO made a TDSIC-3 rate adjustment mechanism filing requesting a revenue decrease of $1.8 million to be billed over six months, associated with $75.0 million of incremental capital expenditures made from May 1, 2017 to November 30, 2017. The decrease was due to the impact of the TCJA as well as a shorter billing period compared to TDSIC-2. TDSIC-3 was approved on May 30, 2018 and became effective for the first billing cycle of June. Additionally, the TDSIC-2 rates revised for tax reform approved as a part of NIPSCO’s Phase 1 filing described above were made effective on May 1, 2018, until TDSIC-3 rates went into effect. The impact of TCJA on TDSIC-2 was an approximate decrease in revenue of $1.2 million for the period from January through May 2018. NIPSCO made a TDSIC-4 rate adjustment mechanism filing on July 31, 2018 seeking an incremental semi-annual revenue decrease of $10.6 million due primarily to the pass back of a $14.1 million TCJA electric base rate customer refund for the period January through May 2018. The TCJA refund offsets a $3.5 million increase associated with $77.1 million of incremental capital expenditures from December 2017 through May 2018. An order approving the request is expected in the fourth quarter of 2018.

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

On February 1, 2018, NIPSCO and certain other MISO transmission owners filed with the FERC a request for waiver of tariff provisions to allow for implementation of TCJA provisions into 2018 transmission formula rates as soon as possible. On March 15, 2018, the FERC issued an order granting the request for waiver and set the effective date of the waiver at January 1, 2018. In the March billing cycle, the MISO began billing the new transmission rates reflecting the lower federal tax rate. In addition, the MISO began to re-bill January and February 2018 affected revenues and costs in the March 2018 billing cycle, and completed the re-settlement in the April 2018 billing cycle. The new 2018 transmission formula rates will lower revenue by approximately $8.5 million in 2018 associated with NIPSCO's multi-value projects.
Material Updates to Regulatory Assets and Liabilities Since December 31, 2017
TCJA-Related Regulatory Liabilities. As referenced above, during the six months ended June 30, 2018, we recorded additional TCJA-related regulatory liabilities of $65.0 million to reflect 2018 collections from customers which we believe are probable of being refunded back to customers once new customer rates are approved by our regulators.
As discussed in Note 13, "Income Taxes," in 2018 we began amortizing regulatory liabilities associated with excess deferred income taxes, which resulted in a $7.4 million and $17.8 million income tax benefit for the three and six months ended June 30, 2018, respectively. Related to this activity, we recorded an offsetting reserve of $4.7 million and $12.4 million (net of tax) in "Customer revenues" to reflect the probable future passback of this earnings benefit to customers for the three and six months ended June 30, 2018, respectively. In certain jurisdictions, we received additional regulatory guidance on the treatment and passback period of excess deferred income taxes, indicating that such a reserve was not required as of June 30, 2018.
Bailly Generating Station. During the six months ended June 30, 2018, we reclassified approximately $245 million from "Other property, at cost, less accumulated depreciation" to “Regulatory assets (noncurrent)” on the Condensed Consolidated Balance Sheets (unaudited) in connection with the retirement of Bailly Generating Station Units 7 and 8. Refer to Note 17-D, "Other Matters," in the Notes to Condensed Consolidated Financial Statements (unaudited) for additional information.
9.    Risk Management Activities
We are exposed to certain risks relating to our ongoing business operations, namely commodity price risk and interest rate risk. We recognize that the prudent and selective use of derivatives may help to lower our cost of debt capital, manage our interest rate exposure and limit volatility in the price of natural gas.
Risk management assets and liabilities on our derivatives are presented on the Condensed Consolidated Balance Sheets (unaudited) as shown below:
(in millions)
June 30, 2018
 
December 31, 2017
Risk Management Assets - Current(1)
 
 
 
Interest rate risk programs
$
1.7

 
$
14.0

Commodity price risk programs
0.5

 
0.5

Total
$
2.2

 
$
14.5

Risk Management Assets - Noncurrent(2)
 
 
 
Interest rate risk programs
$
23.5

 
$
5.6

Commodity price risk programs
1.8

 
1.0

Total
$
25.3

 
$
6.6

Risk Management Liabilities - Current
 
 
 
Interest rate risk programs
$

 
$
38.6

Commodity price risk programs
4.0

 
4.6

Total
$
4.0

 
$
43.2

Risk Management Liabilities - Noncurrent
 
 
 
Interest rate risk programs
$

 
$

Commodity price risk programs
44.9

 
28.5

Total
$
44.9

 
$
28.5

(1)Presented in "Prepayments and other" on the Condensed Consolidated Balance Sheets (unaudited).
(2)Presented in "Deferred charges and other" on the Condensed Consolidated Balance Sheets (unaudited).

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

Commodity Price Risk Management
We, along with our utility customers, are exposed to variability in cash flows associated with natural gas purchases and volatility in natural gas prices. We purchase natural gas for sale and delivery to our retail, commercial and industrial customers, and for most customers the variability in the market price of gas is passed through in their rates. Some of our utility subsidiaries offer programs whereby variability in the market price of gas is assumed by the respective utility. The objective of our commodity price risk programs is to mitigate the gas cost variability, for us or on behalf of our customers, associated with natural gas purchases or sales by economically hedging the various gas cost components using a combination of futures, options, forwards or other derivative contracts.
NIPSCO received IURC approval to lock in a fixed price for its natural gas customers using long-term forward purchase instruments. The term of these instruments may range from five to ten years and is limited to twenty percent of NIPSCO’s average annual GCA purchase volume. Gains and losses on these derivative contracts are deferred as regulatory liabilities or assets and are remitted to or collected from customers through NIPSCO’s quarterly GCA mechanism. These instruments are not designated as accounting hedges.
Interest Rate Risk Management
As of June 30, 2018, we have forward-starting interest rate swaps with an aggregate notional value totaling $750.0 million to hedge the variability in cash flows attributable to changes in the benchmark interest rate during the periods from the effective dates of the swaps to the anticipated dates of forecasted debt issuances, which are expected to take place by the end of 2019. These interest rate swaps are designated as cash flow hedges. The effective portions of the gains and losses related to these swaps are recorded to AOCI and are recognized in "Interest expense, net" concurrently with the recognition of interest expense on the associated debt, once issued. If it becomes probable that a hedged forecasted transaction will no longer occur, the accumulated gains or losses on the derivative will be recognized currently in "Other, net."
In March 2018, we initiated settlement of forward-starting interest rate swaps with a notional value of $250.0 million. These derivative contracts were accounted for as cash flow hedges. As part of the transaction, the associated net unrealized gain of $21.2 million was recognized immediately in "Other, net" on the Condensed Statements of Consolidated Income (Loss) (unaudited) due to the probability associated with the forecasted borrowing transaction no longer occurring.
There were no amounts excluded from effectiveness testing for derivatives in cash flow hedging relationships at June 30, 2018 and December 31, 2017.
Our derivative instruments measured at fair value as of June 30, 2018 and December 31, 2017 do not contain any credit-risk-related contingent features.
10.    Fair Value
 
A.    Fair Value Measurements
Recurring Fair Value Measurements. The following tables present financial assets and liabilities measured and recorded at fair value on our Condensed Consolidated Balance Sheets (unaudited) on a recurring basis and their level within the fair value hierarchy as of June 30, 2018 and December 31, 2017:
 
Recurring Fair Value Measurements
June 30, 2018
(in millions)
Quoted Prices in
Active Markets
for Identical
Assets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
 
Balance as of June 30, 2018
Assets
 
 
 
 
 
 
 
Risk management assets
$

 
$
27.4

 
$
0.1

 
$
27.5

Available-for-sale securities

 
130.1

 

 
130.1

Total
$

 
$
157.5

 
$
0.1

 
$
157.6

Liabilities
 
 
 
 
 
 
 
Risk management liabilities
$

 
$
48.9

 
$

 
$
48.9

Total
$

 
$
48.9

 
$

 
$
48.9



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

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

 
$
21.1

 
$

 
$
21.1

Available-for-sale securities

 
133.9

 

 
133.9

Total
$

 
$
155.0

 
$

 
$
155.0

Liabilities
 
 
 
 
 
 
 
Risk management liabilities
$

 
$
71.4

 
$
0.3

 
$
71.7

Total
$

 
$
71.4

 
$
0.3

 
$
71.7


Risk management assets and liabilities include interest rate swaps, exchange-traded NYMEX futures and NYMEX options and non-exchange-based forward purchase contracts. When utilized, exchange-traded derivative contracts are based on unadjusted quoted prices in active markets and are classified within Level 1. These financial assets and liabilities are secured with cash on deposit with the exchange; therefore, nonperformance risk has not been incorporated into these valuations. Certain non-exchange-traded derivatives are valued using broker or over-the-counter, on-line exchanges. In such cases, these non-exchange-traded derivatives are classified within Level 2. Non-exchange-based derivative instruments include swaps, forwards, options and treasury lock agreements. In certain instances, these instruments may utilize models to measure fair value. We use a similar model to value similar instruments. Valuation models utilize various inputs that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, other observable inputs for the asset or liability and market-corroborated inputs, (i.e., inputs derived principally from or corroborated by observable market data by correlation or other means). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized within Level 2. Certain derivatives trade in less active markets with a lower availability of pricing information and models may be utilized in the valuation. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized within Level 3. Credit risk is considered in the fair value calculation of derivative instruments that are not exchange-traded. Credit exposures are adjusted to reflect collateral agreements which reduce exposures. As of June 30, 2018 and December 31, 2017, there were no material transfers between fair value hierarchies. Additionally, there were no changes in the method or significant assumptions used to estimate the fair value of our financial instruments.
We have entered into forward-starting interest rate swaps to hedge the interest rate risk on coupon payments of forecasted issuances of long-term debt. These derivatives are designated as cash flow hedges. Credit risk is considered in the fair value calculation of each agreement. As they are based on observable data and valuations of similar instruments, the hedges are categorized within Level 2 of the fair value hierarchy. There was no exchange of premium at the initial date of the swaps, and we can settle the contracts at any time. For additional information, see Note 9, "Risk Management Activities."
NIPSCO has entered into long-term forward natural gas purchase instruments that range from five to ten years to lock in a fixed price for its natural gas customers. We value these contracts using a pricing model that incorporates market-based information when available, as these instruments trade less frequently and are classified within Level 2 of the fair value hierarchy. For additional information, see Note 9, “Risk Management Activities.”
Available-for-sale securities are investments pledged as collateral for trust accounts related to our wholly-owned insurance company. Available-for-sale securities are included within “Other investments” in the Condensed Consolidated Balance Sheets (unaudited). We value U.S. Treasury, corporate debt and mortgage-backed securities using a matrix pricing model that incorporates market-based information. These securities trade less frequently and are classified within Level 2. Total unrealized gains and losses from available-for-sale securities are included in other comprehensive income. The amortized cost, gross unrealized gains and losses and fair value of available-for-sale securities at June 30, 2018 and December 31, 2017 were: 

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

June 30, 2018 (in millions)
Amortized
Cost
 
Gross Unrealized Gains
 
Gross Unrealized Losses
 
Fair
Value
Available-for-sale securities
 
 
 
 
 
 
 
U.S. Treasury debt securities
$
16.8

 
$

 
$
(0.1
)
 
$
16.7

Corporate/Other debt securities
116.1

 
0.3

 
(3.0
)
 
113.4

Total
$
132.9

 
$
0.3

 
$
(3.1
)
 
$
130.1

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

 
$

 
$
(0.1
)
 
$
26.8

Corporate/Other debt securities
106.8

 
0.9

 
(0.6
)
 
107.1

Total
$
133.7

 
$
0.9

 
$
(0.7
)
 
$
133.9

Realized gains and losses on available-for-sale securities were immaterial for the three and six months ended June 30, 2018 and 2017.
The cost of maturities sold is based upon specific identification. At June 30, 2018, approximately $3.2 million of U.S. Treasury debt securities and approximately $3.7 million of Corporate/Other debt securities have maturities of less than a year.

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

Non-recurring Fair Value Measurements. There were no significant non-recurring fair value measurements recorded during the three and six months ended June 30, 2018.
B.    Other Fair Value Disclosures for Financial Instruments. The carrying amount of cash and cash equivalents, restricted cash, customer deposits and short-term borrowings is a reasonable estimate of fair value due to their liquid or short-term nature. Our long-term borrowings are recorded at historical amounts.
The following method and assumptions were used to estimate the fair value of each class of financial instruments.
Long-term Debt. The fair value of outstanding long-term debt is estimated based on the quoted market prices for the same or similar securities. Certain premium costs associated with the early settlement of long-term debt are not taken into consideration in determining fair value. These fair value measurements are classified within Level 2 of the fair value hierarchy. For the six months ended June 30, 2018, there was no change in the method or significant assumptions used to estimate the fair value of long-term debt.
The carrying amount and estimated fair values of these financial instruments were as follows: 
(in millions)
Carrying
Amount as of
June 30, 2018
 
Estimated Fair
Value as of
June 30, 2018
 
Carrying
Amount as of
Dec. 31, 2017
 
Estimated Fair
Value as of
Dec. 31, 2017
Long-term debt (including current portion)
$
7,690.2

 
$
7,996.1

 
$
7,796.5

 
$
8,603.4


11.    Transfers of Financial Assets
Columbia of Ohio, NIPSCO and Columbia of Pennsylvania each maintain a receivables agreement whereby they transfer their customer accounts receivables to third party financial institutions through wholly-owned and consolidated special purpose entities. The three agreements expire between August 2018 and March 2019 and may be further extended if mutually agreed to by the parties thereto.

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

All receivables transferred to third parties are valued at face value, which approximates fair value due to their short-term nature. The amount of the undivided percentage ownership interest in the accounts receivables transferred is determined in part by required loss reserves under the agreements.
Transfers of accounts receivable are accounted for as secured borrowings resulting in the recognition of short-term borrowings on the Condensed Consolidated Balance Sheets (unaudited). As of June 30, 2018, the maximum amount of debt that could be recognized related to our accounts receivable programs is $320.0 million.
The following table reflects the gross receivables balance and net receivables transferred as well as short-term borrowings related to the securitization transactions as of June 30, 2018 and December 31, 2017:
 
(in millions)
June 30, 2018
 
December 31, 2017
Gross Receivables
$
470.7

 
$
635.3

Less: Receivables not transferred
470.7

 
298.6

Net receivables transferred
$

 
$
336.7

Short-term debt due to asset securitization
$

 
$
336.7

For the six months ended June 30, 2018 and 2017, $336.7 million and $11.7 million, respectively, was recorded as cash flows used for financing activities related to the change in short-term borrowings due to securitization transactions. Fees associated with the securitization transactions were $0.7 million and $0.6 million for the three months ended June 30, 2018 and 2017, respectively and $1.5 million and $1.3 million for the six months ended June 30, 2018 and 2017, respectively. We remain responsible for collecting on the receivables securitized, and the receivables cannot be transferred to another party.

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

 
$

 
$

 
$
1,690.7


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

13.    Income Taxes
Our interim effective tax rates reflect the estimated annual effective tax rates for 2018 and 2017, adjusted for tax expense associated with certain discrete items. The effective tax rates for the three months ended June 30, 2018 and 2017 were 18.3% and 37.5%, respectively. The effective tax rates for six months ended June 30, 2018 and 2017 were 18.5% and 36.2%, respectively. These effective tax rates differ from the Federal statutory tax rate of 21% in 2018 and 35% in 2017, primarily due to the effects of tax credits, state income taxes, utility ratemaking and other permanent book-to-tax differences.
The decrease in the three month effective tax rate in 2018 versus the same period in 2017 is primarily due to the change in the Federal statutory rate due to the enactment of the TCJA. Additionally, in 2018 we began amortizing a portion of our regulatory liability associated with excess deferred taxes which resulted in a current year income tax benefit of $7.4 million and $17.8 million for the three and six months ended June 30, 2018, respectively. Refer to Note 8, "Regulatory Matters," for additional information.
There were no material changes recorded in 2018 to our uncertain tax positions as of December 31, 2017.
14.    Pension and Other Postretirement Benefits
We provide defined contribution plans and noncontributory defined benefit retirement plans that cover certain of our employees. Benefits under the defined benefit retirement plans reflect the employees’ compensation, years of service and age at retirement. Additionally, we provide health care and life insurance benefits for certain retired employees. The majority of employees may

28

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 six months ended June 30, 2018, we contributed $1.4 million to our pension plans and $11.3 million to our other postretirement benefit plans.
The following table provides the components of the plans’ actuarially determined net periodic benefit cost for the three and six months ended June 30, 2018 and 2017:

Pension Benefits
 
Other Postretirement
Benefits
Three Months Ended June 30, (in millions)
2018
 
2017
 
2018
 
2017
Components of Net Periodic Benefit Cost(1)
 
 
 
 
 
 
 
Service cost
$
7.9

 
$
7.5

 
$
1.3

 
$
1.2

Interest cost
16.6

 
17.2

 
4.4

 
4.4

Expected return on assets
(36.2
)
 
(30.2
)
 
(3.7
)
 
(3.9
)
Amortization of prior service credit
(0.1
)
 
(0.2
)
 
(1.0
)
 
(1.1
)
Recognized actuarial loss
10.2

 
13.4

 
0.9

 
0.7

Settlement loss
3.5

 

 

 

Total Net Periodic Benefit Cost
$
1.9

 
$
7.7

 
$
1.9

 
$
1.3

(1)The service cost component, and all non-service cost components, of net periodic benefit cost are presented in "Operation and maintenance" and "Other, net", respectively, on the Condensed Statements of Consolidated Income (Loss) (unaudited).
 
Pension Benefits
 
Other Postretirement
Benefits
Six Months Ended June 30, (in millions)
2018
 
2017
 
2018
 
2017
Components of Net Periodic Benefit Cost(1)
 
 
 
 
 
 
 
Service cost
$
15.8

 
$
15.0

 
$
2.6

 
$
2.4

Interest cost
33.2

 
34.4

 
8.8

 
8.9

Expected return on assets
(72.5
)
 
(60.5
)
 
(7.4
)
 
(7.9
)
Amortization of prior service credit
(0.2
)
 
(0.4
)
 
(2.0
)
 
(2.2
)
Recognized actuarial loss
20.4

 
26.8

 
1.8

 
1.5

Settlement loss
3.5

 

 

 

Total Net Periodic Benefit Cost
$
0.2

 
$
15.3

 
$
3.8

 
$
2.7

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

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

29

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

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

30

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)
June 30,
2018
 
December 31,
2017
Commercial paper weighted-average interest rate of 1.97% at December 31, 2017
$

 
$
869.0

Accounts receivable securitization facility borrowings

 
336.7

Term loan weighted-average interest rate of 2.64% at June 30, 2018
600.0

 

Total Short-Term Borrowings
$
600.0

 
$
1,205.7

Other than for the term loan, cash flows related to the borrowings and repayments of the items listed above are presented net in the Condensed Statements of Consolidated Cash Flows (unaudited) as their maturities are less than 90 days.

17.    Other Commitments and Contingencies
A. Guarantees and Indemnities. We and certain of our subsidiaries enter into various agreements providing financial or performance assurance to third parties on behalf of certain subsidiaries as a part of normal business. Such agreements include guarantees and stand-by letters of credit. These agreements are entered into primarily to support or enhance the creditworthiness otherwise attributed to a subsidiary on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish the subsidiaries’ intended commercial purposes. As of June 30, 2018 and December 31, 2017, we had issued stand-by letters of credit of $10.2 million and $11.1 million, respectively.  
 B. Legal Proceedings. We are party to certain claims and legal proceedings arising in the ordinary course of business, none of which are deemed to be individually material at this time. Due to the inherent uncertainty of litigation, there can be no assurance that the resolution of any particular claim or proceeding would not have a material adverse effect on our results of operations, financial position or liquidity. If one or more of such matters were decided against us, the effects could be material to our results of operations in the period in which we would be required to record or adjust the related liability and could also be material to our cash flows in the periods that we would be required to pay such liability.
C. Environmental Matters. Our operations are subject to environmental statutes and regulations related to air quality, water quality, hazardous waste and solid waste. We believe that we are in substantial compliance with the environmental regulations currently applicable to our operations.
It is management's continued intent to address environmental issues in cooperation with regulatory authorities in such a manner as to achieve mutually acceptable compliance plans. However, there can be no assurance that fines and penalties will not be incurred. Management expects a significant portion of environmental assessment and remediation costs to be recoverable through rates for certain of our companies.
As of June 30, 2018 and December 31, 2017, we had recorded a liability of approximately $109.7 million and $111.4 million, respectively, to cover environmental remediation at various sites. The current portion of this liability is included in "Legal and environmental" in the Condensed Consolidated Balance Sheets (unaudited). The noncurrent portion is included in "Other noncurrent liabilities" in the Condensed Consolidated Balance Sheets (unaudited). We recognize costs associated with environmental remediation obligations when the incurrence of such costs is probable and the amounts can be reasonably estimated. The original estimates for remediation activities may differ materially from the amount ultimately expended. The actual future expenditures depend on many factors, including currently enacted laws and regulations, the nature and extent of impact and the method of remediation. These expenditures are not currently estimable at some sites. We periodically adjust our liability as information is collected and estimates become more refined.
Electric Operations' compliance estimates disclosed below are reflective of NIPSCO's Integrated Resource Plan submitted to the IURC on November 1, 2016. See section D, "Other Matters," below for additional information.
Air
The actions listed below could require further reductions in emissions from various emission sources. We will continue to closely monitor developments in these matters.
Future legislative and regulatory programs could significantly limit allowed GHG emissions or impose a cost or tax on GHG emissions. Additionally, rules that increase methane leak detection, require emission reductions or impose additional requirements

31

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

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

On February 9, 2016, the U.S. Supreme Court stayed implementation of the CPP until litigation is decided on its merits. On October 16, 2017, the EPA published in the Federal Register a Notice of Proposed Rulemaking that would repeal the CPP. On December 28, 2017, in a separate but related action, the EPA published an Advanced Notice of Proposed Rulemaking in the Federal Register to solicit information from the public about a potential future rulemaking to limit greenhouse gas emissions from existing fossil-fuel EGUs. NIPSCO will continue to monitor this matter and cannot estimate its impact at this time. Should costs be incurred to comply with the CPP, NIPSCO believes such costs will be eligible for recovery through customer rates.
Waste
CERCLA. Our subsidiaries are potentially responsible parties at waste disposal sites under the CERCLA (commonly known as Superfund) and similar state laws. Under CERCLA, each potentially responsible party can be held jointly, severally and strictly liable for the remediation costs as the EPA, or state, can allow the parties to pay for remedial action or perform remedial action themselves and request reimbursement from the potentially responsible parties. Our affiliates have retained CERCLA environmental liabilities, including remediation liabilities, associated with certain current and former operations. These liabilities are not material to the Condensed Consolidated Financial Statements (unaudited).
MGP. A program has been instituted to identify and investigate former MGP sites where Gas Distribution Operations subsidiaries or predecessors may have liability. The program has identified 64 such sites where liability is probable. Remedial actions at many of these sites are being overseen by state or federal environmental agencies through consent agreements or voluntary remediation agreements.
We utilize a probabilistic model to estimate future remediation costs related to our MGP sites. The model was prepared with the assistance of a third party and incorporates our experience and general industry experience with remediating MGP sites. We complete an annual refresh of the model in the second quarter of each fiscal year. No material changes to the estimated future remediation costs were noted as a result of the refresh completed as of June 30, 2018. Our total estimated liability related to the facilities subject to remediation was $105.5 million and $106.9 million at June 30, 2018 and December 31, 2017, respectively. The liability represents our best estimate of the probable cost to remediate the facilities. We believe that it is reasonably possible that remediation costs could vary by as much as $25 million in addition to the costs noted above. Remediation costs are estimated based on the best available information, applicable remediation standards at the balance sheet date and experience with similar facilities.
CCRs. On April 17, 2015, the EPA issued a final rule for regulation of CCRs. The rule regulates CCRs under the RCRA Subtitle D, which determines them to be nonhazardous. The rule is implemented in phases and requires increased groundwater monitoring, reporting, recordkeeping and posting of related information to the Internet. The rule also establishes requirements related to CCR management and disposal. The rule will allow NIPSCO to continue its byproduct beneficial use program.
The publication of the CCR rule resulted in revisions to previously recorded legal obligations associated with the retirement of certain NIPSCO facilities. The actual asset retirement costs related to the CCR rule may vary substantially from the estimates used to record the increased asset retirement obligation due to the uncertainty about the compliance strategies that will be used and the preliminary nature of available data used to estimate costs. In addition, to comply with the rule, NIPSCO will be required to incur future capital expenditures to modify its infrastructure and manage CCRs. Capital compliance costs are currently expected to total approximately $193 million. As allowed by the EPA, NIPSCO will continue to collect data over time to determine the specific compliance solutions and associated costs and, as a result, the actual costs may vary.
NIPSCO filed a petition on November 1, 2016 with the IURC seeking approval of the projects and recovery of the costs associated with CCR compliance. On June 9, 2017, NIPSCO filed with the IURC a settlement reached with certain parties regarding the CCR projects and treatment of associated costs. The IURC approved the settlement in an order on December 13, 2017.

32

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

Water
ELG. On November 3, 2015, the EPA issued a final rule to amend the ELG and standards for the Steam Electric Power Generating category. The final rule became effective January 4, 2016. The rule imposes new water treatment and discharge requirements on NIPSCO's electric generating facilities to be applied between 2018 and 2023. On April 25, 2017, the EPA published notice in the Federal Register that the EPA is reconsidering the ELG in response to several petitions for reconsideration. On September 18, 2017, the EPA postponed the earliest compliance dates for flue gas desulfurization wastewater and bottom ash transport water requirements from 2018 to 2020 to potentially consider revisions to technology and numeric limits achievable. NIPSCO is unable to estimate the financial impact of the EPA reconsideration at this time. Based upon a preliminary study of the November 3, 2015 final rule, capital compliance costs were expected to be approximately $170 million. On November 1, 2016, NIPSCO filed a petition with the IURC seeking approval of the projects and recovery of the costs associated with ELG compliance. Given the current postponement of certain compliance dates under the ELG rule, NIPSCO has agreed with the settling parties, as part of the settlement agreement discussed in the "CCRs" subsection above, that these ELG projects and related costs would be addressed in a later proceeding.
D. Other Matters.
NIPSCO 2016 Integrated Resource Plan. Environmental, regulatory and economic factors, including low natural gas prices and aging coal-fired units, have led NIPSCO to pursue modification of its current electric generation supply mix to include less coal-fired generation. Due to enacted CCR and ELG (subsequently postponed) regulations, NIPSCO would expect to have incurred over $1 billion in operating, maintenance, environmental and other costs if the current fleet of coal-fired generating units were to remain operational.
On November 1, 2016, NIPSCO submitted its 2016 Integrated Resource Plan with the IURC. The plan evaluated demand-side and supply-side resource alternatives to reliably and cost effectively meet NIPSCO customers' future energy requirements over the ensuing 20 years. The 2016 Integrated Resource Plan indicated that the most viable option for customers and NIPSCO involves the retirement of Bailly Generating Station (Units 7 and 8) as soon as mid-2018 and two units (Units 17 and 18) at the R.M. Schahfer Generating Station by 2023. It is projected over the long term that the cost to customers to retire these units at these dates will be lower than maintaining and upgrading them for continued generation.
We committed to the retirement of the Bailly Generating Station units in connection with the filing of the 2016 Integrated Resource Plan, pending approval by the MISO. In the fourth quarter of 2016, the MISO approved NIPSCO's plan to retire the Bailly Generating Station units by May 31, 2018.
On February 1, 2018, as previously approved by the MISO, NIPSCO commenced a four-month outage of Bailly Generating Station Unit 8 in order to begin work on converting the unit to a synchronous condenser (a piece of equipment designed to maintain voltage to ensure continued reliability on the transmission system). Approximately $15 million of net book value of Unit 8 remained in “Net Utility Plant” as it is expected to remain used and useful upon completion of the synchronous condenser, while the remaining net book value of approximately $142 million was reclassified to “Regulatory assets (noncurrent)” on the Condensed Consolidated Balance Sheets (unaudited). On May 31, 2018, Units 7 and 8 were retired from service. As a result, the remaining net book value of Unit 7 of approximately $103 million was reclassified to “Regulatory assets (noncurrent)” on the Condensed Consolidated Balance Sheets (unaudited).These amounts continue to be amortized at a rate consistent with their inclusion in customer rates.
NIPSCO anticipates updating its Integrated Resource Plan in a filing by the end of 2018.
NIPSCO Pure Air. NIPSCO had a service agreement with Pure Air, a general partnership between Air Products and Chemicals, Inc. and First Air Partners LP, under which Pure Air provided scrubber services to reduce sulfur dioxide emissions for Units 7 and 8 at the Bailly Generating Station. Services under this contract commenced on July 1, 1992 and expired on June 30, 2012. The agreement was renewed effective July 1, 2012 for ten years, requiring NIPSCO to pay for the services under a combination of fixed and variable charges. We made an exhaustive effort to obtain information needed from Pure Air to determine the status of Pure Air as a VIE. However, NIPSCO was not able to obtain this information and, as a result, it was not determined whether Pure Air was a VIE and whether NIPSCO was the primary beneficiary. Payments under this agreement were $7.6 million and $10.4 million for the six months ended June 30, 2018 and 2017, respectively. In accordance with GAAP, the renewed agreement was evaluated to determine whether the arrangement qualified as a lease. Based on the terms of the agreement, the arrangement qualified for capital lease accounting. As the effective date of the new agreement was July 1, 2012, we capitalized this lease beginning in the third quarter of 2012.
As further discussed above in this Note 17 under the heading "NIPSCO 2016 Integrated Resource Plan," NIPSCO retired the generation station units serviced by Pure Air on May 31, 2018. In December 2016, as allowed by the provisions of the service

33

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

agreement, NIPSCO provided Pure Air formal notice of intent to terminate the service agreement, effective May 31, 2018. Providing this notice to Pure Air triggered a contract termination liability of $16 million, which was recorded in fourth quarter of 2016. In connection with the closure of Bailly Units 7 and 8, NIPSCO paid the termination payment to Pure Air during the second quarter of 2018. Cash flows associated with this payment are presented within operating activities on the Condensed Statements of Consolidated Cash Flows (unaudited).

34

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

18.    Accumulated Other Comprehensive Loss
The following tables display the components of Accumulated Other Comprehensive Loss:
Three Months Ended June 30, 2018 (in millions)
Gains and Losses on Securities(1)
 
Gains and Losses on Cash Flow Hedges(1)
 
Pension and OPEB Items(1)
 
Accumulated
Other
Comprehensive
Loss(1)
Balance as of April 1, 2018
$
(1.5
)
 
$
(0.3
)
 
$
(17.2
)