(in millions)
Customer Accounts Receivable, Billed (less reserve)⁽¹⁾

Customer Accounts Receivable, Unbilled (less reserve)⁽²⁾
Balance as of December 31, 2017 $ 477.0
$ 378.6
Balance as of December 31, 2018 540.5
349.1
Increase (Decrease) $ 63.5
$ (29.5 )

⁽¹⁾ ~~Customer billed receivables increased over the period due to November 2018 being colder than November 2017, leading to more gas usage included in December bills.~~

⁽²⁾ ~~Customer unbilled receivables decreased over the period due December 2018 being warmer than December 2017, leading to less estimated gas usage.~~

NISOURCE INC.

Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)


(in millions)	Customer Accounts Receivable, Billed (less reserve)(1)		Customer Accounts Receivable, Unbilled (less reserve)
Balance as of December 31, 2019	$	466.6	$	346.6
Balance as of December 31, 2020	400.0		327.2
Decrease	$	(66.6)	$	(19.4)

(1)Customer billed receivables decreased due to decreased natural gas costs and warmer weather in 2020 compared to 2019.

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. We maintain common utility credit risk mitigation practices, including requiring deposits and actively pursuing collection of past due amounts. Our regulated operations also utilize certain regulatory mechanisms that facilitate recovery of bad debt costs within tariff-based rates, which provides further evidence of collectibility. In connection with the COVID-19 pandemic, certain state regulatory commissions instituted regulatory moratoriums that impacted our ability to pursue our standard credit risk mitigation practices. Following the issuance of these moratoriums, certain of our regulated operations have been authorized to recognize a regulatory asset for bad debt costs above levels currently in rates. We have reinstated our common credit mitigation practices where moratoriums have expired (see Note 9, "Regulatory Matters," for additional information on regulatory moratoriums and regulatory assets). It is probable that substantially all of the consideration to which we are entitled from customers will be collected upon satisfaction of performance obligations.

~~Other Revenues.~~ ~~As permitted by accounting principles generally accepted~~Allowance for Credit Losses. We adopted ASC 326 effective January 1, 2020. See "Recently Adopted Accounting Pronouncements" in Note 2, "Recent Accounting Pronouncements," for more information about ASC 326.

Each of our business segments pool their customer accounts receivables based on similar risk characteristics, such as customer type, geography, payment terms, and related macro-economic risks. Expected credit loss exposure is evaluated separately for each of our accounts receivable pools. Expected credit losses are established using a model that considers historical collections experience, current information, and reasonable and supportable forecasts. Relevant and reliable internal and external inputs used in the ~~United States, regulated utilities have the ability~~model include, but are not limited to, ~~earn certain types~~energy consumption trends, revenue projections, actual charge-offs data, recoveries data, shut-off orders executed data, and final bill data. We continuously evaluate available reasonable and supportable information relevant to assessing collectibility of ~~revenue that are outside the scope~~current and future receivables. We evaluate creditworthiness of ~~ASC 606. These revenues primarily represent revenue earned under alternative revenue programs. Alternative revenue programs represent regulator-approved programs that allow~~specific customers periodically or when required by changes in facts and circumstances. When we become aware of a specific commercial or industrial customer's inability to pay, an allowance for expected credit losses is recorded for the ~~adjustment~~relevant amount. We also monitor other circumstances that could affect our overall expected credit losses; these include, but are not limited to, creditworthiness of ~~billings~~overall population in service territories, adverse conditions impacting an industry sector, and ~~revenue~~current economic conditions.

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NISOURCE INC.

Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

At each reporting period, we record expected credit losses using an allowance for credit losses account. When deemed to be uncollectible, customer accounts are written-off. A rollforward of our allowance for credit losses for the year ended December 31, 2020 are presented in the table below:



Year Ended December 31, 2020 (in millions)	Gas Distribution Operations	Electric Operations	Corporate and Other	Total
Beginning balance(1)	9.1	3.1	0.8	13.0
Current period provisions	45.3	9.3	0	54.6
Write-offs charged against allowance	(26.7)	(3.0)	0	(29.7)
Recoveries of amounts previously written off	14.1	0.3	0	14.4
Ending balance of the allowance for credit losses	41.8	9.7	0.8	52.3
(1)Total beginning balance differs from that presented in the Consolidated Balance Sheets as it excludes Columbia of Massachusetts. Columbia of Massachusetts' customer receivables and related allowance for credit losses were included in the sale of the Massachusetts Business that occurred on October 9, 2020.

As of December 31, 2020, we have also evaluated the adequacy of our allowance for credit losses in light of the suspension of shut-offs for nonpayment due to the COVID-19 pandemic that remain in effect 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,jurisdictions, as well as ~~normalization~~the economic downturn. Our evaluation included an analysis of customer payment trends in 2020, economic conditions, receivables aging, considerations of past economic downturns and the associated allowance for credit losses and customer account write-offs. In addition, we considered benefits available under governmental COVID-19 relief programs, the impact of unemployment benefits initiatives, and flexible payment plans being offered to customers affected by or experiencing hardship as a result of the pandemic, which could help to mitigate the potential for increasing customer account delinquencies. Based upon this evaluation, we have concluded that the allowance for credit losses as of December 31, 2020 adequately reflected the collection risk and net realizable value for our receivables. We will continue to monitor changing circumstances and will adjust ~~revenues~~our allowance for credit losses as additional information becomes available.

4. Variable Interest Entities

A VIE is an entity in which the controlling interest is determined through means other than a majority voting interest. The primary beneficiary of a VIE is the business enterprise which has the power to direct the activities of the VIE that most significantly impact the VIE’s economic performance. Also, the primary beneficiary either absorbs a significant amount of the VIE’s losses or has the right to receive benefits that could be significant to the VIE. We consider these qualitative elements in determining whether we are the primary beneficiary of a VIE, and we consolidate those VIEs for which we are determined to be the primary beneficiary.

Rosewater (a joint venture) owns and operates 102 MW of nameplate capacity wind generation assets. Members of the joint venture are NIPSCO (who is the managing member) and a tax equity partner. Earnings, tax attributes and cash flows are allocated to both NIPSCO and the tax equity partner in varying percentages by category and over the life of the partnership. Once the tax equity partner has earned their negotiated rate of return and we have reached the agreed upon contractual date, NIPSCO has the option to purchase at fair market value from the tax equity partner the remaining interest in the aforementioned joint venture. NIPSCO has an obligation to purchase, through a PPA at established market rates, 100% of the electricity generated by Rosewater.

As the managing member of Rosewater, we control decisions that are significant to its ongoing operations and economic results. Therefore, we have concluded that we are the primary beneficiary of Rosewater and have consolidated Rosewater even though we own less than 100% of the total equity membership interest.

We have determined that the use of HLBV accounting is reasonable and appropriate in order to attribute income and loss to the noncontrolling interest held by the tax equity partner. HLBV accounting was selected as the allocation of Rosewater's economic results to members differ from the members' relative ownership percentages. Using the HLBV method, our earnings are calculated based on how the partnership would distribute its cash if it were to hypothetically sell all of its assets for their carrying amounts and liquidate at each reporting period. Under HLBV, we calculate the liquidation value allocable to each partner at the beginning and end of each period based on the contractual terms of the related entity's operating agreement and adjust our income for the ~~effects~~period to reflect the change our associated book value.

Table of ~~weather~~Contents

NISOURCE INC.

Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

In December 2020, in exchange for their respective membership interests in Rosewater, NIPSCO contributed $0.7 million in cash, and the tax equity partner contributed $86.1 million in cash, the first of two contractual cash contributions for each partner, per the equity capital contribution agreement. NIPSCO's remaining economic interest was acquired by assuming an obligation of $69.7 million to the developer, which comes due in 2023 and is included in "Other noncurrent liabilities" in the Consolidated Balance Sheets. From the contributed funds, Rosewater paid $85.3 million to the developer of the wind generation assets. The developer of the facility is not a partner in the joint venture for federal income tax purposes and does not receive any share of earnings, tax attributes, or cash flows of Rosewater. Once asset construction is complete, NIPSCO and the tax equity partner will each make a second cash contribution of $0.1 million and $7.5 million, respectively, and NIPSCO will assume an additional obligation to the developer of $6.0 million, totaling contributions of $170.1 million for both partners. We did not provide any financial or other ~~external factors. Additionally,~~support during the year that was not previously contractually required, nor do we ~~maintain certain programs with future test periods that operate similarly~~expect to ~~FERC formula rate programs~~provide such support in the future.

At December 31, 2020, $156.4 million in net assets (as detailed in the table below) related to Rosewater and ~~allow for recovery~~the non-controlling interest attributable to the unrelated tax equity partner of ~~costs incurred~~$85.6 million were included in the Consolidated Balance Sheets. For the year ended December 31, 2020 $3.4 million was allocated to ~~replace aging infrastructure. When~~ the ~~criteria~~tax equity partner and is included in "Net income attributable to ~~recognize Alternative Revenue have been met, we establish a regulatory asset and present revenue from alternative revenue programs~~non-controlling interest" on the Statements of Consolidated Income (Loss) ~~as “Other revenues.” When amounts previously recognized under Alternative Revenue accounting guidance are billed, we reduce~~.

At December 31, 2020, our consolidated balance sheet included the ~~regulatory asset~~following assets and ~~record~~liabilities associated with Rosewater:


(in millions)
Net Property, Plant and Equipment	$	175.6
Current assets	1.7

Total assets(1)	$	177.3
Current liabilities	$	15.3
Asset retirement obligations	5.5
Other noncurrent liabilities	0.1
Total liabilities	$	20.9

(1)The assets of Rosewater represent assets of a ~~customer account receivable.~~consolidated VIE that can be used only to settle obligations of the consolidated VIE.

4.5. Earnings Per Share

Basic EPS is computed by dividing net income attributable to common shareholders by the weighted-average number of shares of common stock outstanding for the period. The weighted-average shares outstanding for diluted EPS includes the incremental effects of the various long-term incentive compensation plans and forward agreements when the impact of such plans and agreements would be dilutive. The calculation of diluted earnings per share ~~excludes the impact of forward agreements (see Note 12, "Equity"), which had an anti-dilutive effect~~ for the ~~periods outstanding. The computation of diluted average common shares for the year~~years ended December 31, 2020 and December 31, 2018 isdoes not ~~presented~~include any dilutive potential common shares as we ~~are presenting~~had a net loss on the Statements of Consolidated Income (Loss) for ~~the period,~~these periods, and any incremental shares would have had an anti-dilutive impact on EPS. The computation of diluted average common shares is as follows:


Year Ended December 31, (in thousands)	2020	2019	2018
Denominator
Basic average common shares outstanding	384,347	374,650	356,491
Dilutive potential common shares:

Shares contingently issuable under employee stock plans	0	929	0
Shares restricted under employee stock plans	0	154	0
Forward agreements	0	253	0
Diluted Average Common Shares	384,347	375,986	356,491

Year Ended December 31, (in thousands)
2017 2016
Denominator
Basic average common shares outstanding 329,388
321,805
Dilutive potential common shares:
Shares contingently issuable under employee stock plans 547
165
Shares restricted under stock plans 821
1,554
Diluted Average Common Shares 330,756
323,524

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NISOURCE INC.

Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

5.6. Property, Plant and Equipment

Our property, plant and equipment on the Consolidated Balance Sheets are classified as follows:


At December 31, (in millions)	2020		2019
Property, Plant and Equipment
Gas Distribution Utility(1)	$	14,010.2	$	14,989.7
Electric Utility(1)	6,478.0		8,902.3
Corporate	197.3		153.3
Construction Work in Process	572.6		457.3
Renewable Generation Assets(2)	175.7		0
Non-Utility and Other(3)	2,746.1		39.3
Total Property, Plant and Equipment	$	24,179.9	$	24,541.9
Accumulated Depreciation and Amortization
Gas Distribution Utility(1)	$	(3,292.9)	$	(3,556.0)
Electric Utility(1)	(2,305.0)		(3,973.8)
Corporate	(109.3)		(79.5)
Renewable Generation Assets(2)	(0.1)		0
Non-Utility and Other(3)	(1,853.1)		(20.4)
Total Accumulated Depreciation and Amortization	$	(7,560.4)	$	(7,629.7)
Net Property, Plant and Equipment	$	16,619.5	$	16,912.2

At December 31, (in millions)
2018 2017
Property, Plant and Equipment
Gas Distribution Utility⁽¹⁾
$ 13,776.0
$ 12,531.0
Electric Utility⁽¹⁾
8,374.2
7,403.8
Corporate 155.8
141.3
Construction Work in Process 474.8
950.5
Non-Utility and Other⁽²⁾
38.7
623.3
Total Property, Plant and Equipment $ 22,819.5
$ 21,649.9
Accumulated Depreciation and Amortization
Gas Distribution Utility⁽¹⁾
$ (3,373.8 ) $ (3,227.8 )
Electric Utility⁽¹⁾
(3,809.5 ) (3,673.2 )
Corporate (74.6 ) (52.6 )
Non-Utility and Other⁽²⁾
(19.1 ) (336.8 )
Total Accumulated Depreciation and Amortization $ (7,277.0 ) $ (7,290.4 )
Net Property, Plant and Equipment $ 15,542.5
$ 14,359.5

⁽¹⁾NIPSCO’s common utility plant and associated accumulated depreciation and amortization are allocated between Gas Distribution Utility and Electric Utility Property, Plant and Equipment.

⁽²⁾Our renewable generation assets are part of our electric segment and represent Non-Utility Property, owned and operated by Rosewater Wind Generation LLC, a joint venture between NIPSCO and unrelated tax equity partner, and depreciated straight-line over 30 years. Refer to Note 4, "Variable Interest Entities" for additional information.

(3)Non-Utility and Other as of December 31, ~~2017~~2020 includes net book value of ~~$247.8~~$903.8 million related to ~~Bailly~~R.M. Schahfer Generating Station, ~~(Units 7 and 8)~~ which was reclassified from Electric Utility in the ~~fourth~~second quarter of ~~2016. In May 2018, Units 7 and 8 were retired from service and~~2020. Depreciation expense for the remaining ~~balance was reclassified~~net book value continues to ~~"Regulatory assets (noncurrent)" on~~be recorded at the ~~Consolidated Balance Sheets.~~composite depreciation rate approved by the IURC. See Note ~~18-E,~~20-E, "Other ~~Matters," and Note 8, "Regulatory~~ Matters," for additional information.

The weighted average depreciation provisions for utility plant, as a percentage of the original cost, for the periods ended December 31, ~~2018, 2017~~2020, 2019 and ~~2016~~2018 were as follows:


	2020		2019		2018
Electric Operations(1)	3.4	%	2.8	%	2.9	%
Gas Distribution Operations	2.3	%	2.5	%	2.2	%

2018 2017 2016
Electric Operations⁽¹⁾
2.9 % 3.4 % 3.3 %
Gas Distribution Operations 2.2 % 2.1 % 2.1 %

⁽¹⁾~~Lower~~Increased rate beginning in 2020 primarily attributable to higher depreciation rates from the recent rate ~~in 2018 due to reduced EERM-related depreciation expense and higher depreciable base from transmission assets being placed into service in 2018.~~case proceeding.

We recognized depreciation expense of ~~$503.4~~$655.6 million, ~~$501.5~~$612.2 million and ~~$475.1~~$503.4 million for the years ended ~~2018, 2017~~2020, 2019 and ~~2016,~~2018, respectively.

Amortization of Software Costs. We amortized $56.7 million, $55.5 million and $54.1 million in 2020, 2019 and 2018, ~~$44.0 million in 2017 and $41.4 million in 2016~~respectively, related to software costs. Our unamortized software balance was ~~$159.5~~$136.4 million and ~~$189.0~~$169.6 million at December 31, 2020 and 2019, respectively.

Amortization of Cloud Computing Costs. We amortized $3.4 million, $1.6 million and $0.1 million in 2020, 2019 and 2018, respectively, related to cloud computing costs. Our unamortized cloud computing balance was $12.7 million and ~~2017,~~$14.2 million at December 31, 2020 and 2019, respectively.

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NISOURCE INC.

Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

7. Goodwill and Other Intangible Assets

Goodwill. Substantially all of our goodwill relates to the excess of cost over the fair value of the net assets acquired in the Columbia acquisition on November 1, 2000. The following presents our goodwill balance allocated by segment as of December 31, ~~2018:~~2020 and 2019:


(in millions)	2020		2019
Gas Distribution Operations	$	1,485.9	$	1,485.9
Electric Operations	0		0
Corporate and Other	0		0
Total	$	1,485.9	$	1,485.9

(in millions) Gas Distribution Operations Electric Operations Corporate and Other Total
Goodwill $ 1,690.7
$ —
$ —
$ 1,690.7

~~We applied the qualitative "step 0"~~For our annual goodwill impairment analysis ~~to our reporting units for the annual impairment test~~ performed as of May 1, ~~2018. For~~2020, we completed a quantitative ("step 1") fair value measurement of our reporting units. Fair value of this reporting unit was determined based on a weighting of income and market approaches. The income approach calculated discounted cash flows using updated cash flow projections, discount rates and return on equity assumptions. The market approach applied a combination of comparable company multiples and comparable transactions and used the most recent cash flow projections. The test ~~we assessed various assumptions, events and circumstances~~indicated that ~~would have affected~~ the ~~estimated~~ fair value of each of the reporting units ~~as compared~~that are allocated goodwill exceeded their carrying values, indicating that no impairment was necessary.

Columbia of Massachusetts was not considered to ~~their base line~~be a reporting unit for May 1, ~~2016 "step 1"~~2020 fair value ~~measurement. The results~~measurement as the goodwill balance had been reduced to 0 as of ~~this assessment indicated~~

~~Table~~December 31, 2019. During the fourth quarter of ~~Contents~~

NIS~~OURCE~~ INC.

~~Notes~~2019, in connection with the preparation of the year-end financial statements, we assessed the matters related to ~~Consolidated Financial Statements~~

~~ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)~~

~~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"~~then proposed sale of the Massachusetts Business and determined a new impairment analysis was ~~required.~~

~~In the third quarter of 2018, we determined the Greater Lawrence Incident (see Note 18, "Other Commitments and Contingencies") represented a triggering event that~~ required ~~an impairment analysis of goodwill. This incident specifically impacts~~for our Columbia of Massachusetts reporting unit. The fair value of the Columbia of Massachusetts reporting unit was determined in ~~which~~ the ~~associated goodwill totaled $204.8 million immediately prior to the incident. We performed a quantitative~~same manner as described above for our remaining reporting units. The 2019 year-end impairment analysis ~~as of September 30, 2018 and determined~~indicated that the fair value of the Columbia of Massachusetts reporting unit ~~continues to exceed~~was below its carrying value. Therefore, no goodwill impairment charges were recorded in the third quarter of 2018. This interim analysis was performed using then-current cash flow projections reflecting the estimated ongoing impacts of the Greater Lawrence Incident on Columbia of Massachusetts' operations. We also updated other significant inputs to the fair value calculation (e.g. discount rate, market multiples) to reflect then-current market conditions and increased risk and uncertainty resulting from the incident. No additional facts came to light since the third quarter impairment analysis was completed that would indicate it was more likely than not that the fair value ofAs a result, we reduced the Columbia of Massachusetts reporting unit ~~would have decreased below its carrying value; therefore no~~goodwill balance to 0 and recognized a goodwill impairment ~~charges were recorded~~charge totaling$204.8 million, which is non-deductible for tax purposes.

Intangible and Other Long-Lived Assets Impairment. We review our definite-lived intangible assets, along with other long-lived assets (utility plant), for impairment when events or changes in circumstances indicate the ~~fourth quarter of 2018. We will continue~~assets' fair value might be below their carrying amount. Prior to ~~monitor the impacts of the incident for events that could trigger a new impairment analysis including, but not limited to, unfavorable regulatory outcomes and NTSB investigation results.~~

~~Intangible Assets.~~ ~~Our~~December 31, 2019, our intangible assets, apart from goodwill, ~~consist~~consisted of franchise rights. Franchise rights were identified as part of the purchase price allocations associated with the acquisition in February 1999 of Columbia of Massachusetts. ~~These amounts~~

During the fourth quarter of 2019, in connection with the preparation of the year-end financial statements, we assessed the changes in circumstances that occurred during the quarter to determine if it was more likely than not that the fair value of our long-lived assets (including franchise rights) were ~~$220.7~~below their carrying amount. As a result, we performed a year-end impairment test of our held and used long-lived assets in which we compared the book value of the Columbia of Massachusetts asset group to its undiscounted future cash flow and determined the carrying value of the asset group was not recoverable. We estimated the fair value of the Columbia of Massachusetts asset group using a weighting of income and market approaches and determined that the fair value was less than the carrying value. The resulting impairment was allocated to reduce the entire franchise rights book value to its fair value of 0, which resulted in an impairment charge totaling $209.7 million ~~and $231.7 million, net of accumulated amortization of $221.5 million and $210.5 million, at~~recorded in the Gas Distribution Operations segment during the year ended December 31, ~~2018~~2019.

As of December 31, 2020 and ~~2017, respectively, and are being amortized on a straight-line basis over forty years from~~2019, the ~~date~~carrying amount of ~~acquisition through 2039. NiSource~~the franchise rights was 0. We recorded 0 amortization expense ofin 2020 and $11.0 million in ~~2018, 2017,~~2019 and ~~2016~~2018 related to ~~its~~our franchise ~~right~~rights intangible asset.

7.8. Asset Retirement Obligations

We have recognized asset retirement obligations associated with various legal obligations including costs to remove and dispose of certain construction materials located within many of our facilities, certain costs to retire pipeline, removal costs for certain underground storage tanks, removal of certain pipelines known to contain PCB contamination, closure costs for certain sites including ash ponds, solid waste management units and a landfill, as well as some other nominal asset retirement obligations. We also have ~~a significant~~an obligation associated with the decommissioning of our two hydro facilities located in Indiana. These hydro facilities have an indeterminate life, and as such, no asset retirement obligation has been recorded.

Table of Contents

NISOURCE INC.

Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

Changes in our liability for asset retirement obligations for the years ~~2018~~2020 and ~~2017~~2019 are presented in the table below:


(in millions)	2020			2019
Beginning Balance	$	416.9		$	352.0
Accretion recorded as a regulatory asset/liability	17.3			15.7
Additions	5.5			0
Settlements	(13.9)			(5.4)
Change in estimated cash flows	86.0		(1)	54.6		(2)
Other	(16.2)		(3)	0
Ending Balance	$	495.6		$	416.9

(in millions) 2018 2017
Beginning Balance $ 268.7
$ 262.6

Accretion recorded as a regulatory asset/liability 11.1
10.3

Additions 63.3
⁽¹⁾
2.4

Settlements (5.9 ) (15.6 )
Change in estimated cash flows
14.8
⁽¹⁾
9.0
⁽²⁾
Ending Balance $ 352.0
$ 268.7

⁽¹⁾~~In 2018, $59.8 million of additions and $17.7 million of the~~The change in estimated cash flows ~~are~~for 2020 is primarily attributed to revisions to the estimated costs associated with refining the CCR compliance ~~plan.~~plan, changes in estimated costs for electric generating stations and the changes in estimated costs for retirement of gas mains. See Note ~~18-D,~~20-D. "Environmental ~~Matters,"~~Matters" for additional information on CCRs.

⁽²⁾The change in estimated cash flows for ~~2017~~2019 is primarily attributed to changes in estimated costs and settlement timing for electric generating stations and the changes in estimated costs for retirement of gas mains.

(3)Represents the Columbia of Massachusetts Asset Retirement Obligations that were included in the sale of the Massachusetts Business that occurred on October 9, 2020.

Certain non-legal costs of removal that have been, and continue to be, included in depreciation rates and collected in the customer rates of the rate-regulated subsidiaries are classified as "Regulatory liabilities" on the Consolidated Balance Sheets.

~~Table of Contents~~9. Regulatory Matters

NIS~~OURCE~~ INC.

~~Notes to Consolidated Financial Statements~~

~~ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)~~


8.	~~Regulatory Matters~~

Regulatory Assets and Liabilities

We follow the accounting and reporting requirements of ASC Topic 980, which provides that regulated entities account for and report assets and liabilities consistent with the economic effect of regulatory rate-making procedures ifwhen the rates established are designed to recover the costs of providing the regulated service and it is probable that such rates ~~can~~will be charged and collected from customers. Certain expenses and credits subject to utility regulation or rate determination normally reflected in income or expense are deferred on the balance sheet and are recognized in the income statement as the related amounts are included in customer rates and recovered from or refunded to customers. We assess the probability of collection for all of our regulatory assets each period.

Table of Contents

NISOURCE INC.

Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

Regulatory assets were comprised of the following items:


At December 31, (in millions)	2020		2019
Regulatory Assets
Unrecognized pension and other postretirement benefit costs (see Note 12)	$	583.3	$	739.1
Deferred pension and other postretirement benefit costs (see Note 12)	72.4		91.3
Environmental costs (see Note 20-D)	56.6		73.4
Regulatory effects of accounting for income taxes (see Note 1-N and Note 11)	194.5		234.0
Under-recovered gas and fuel costs (see Note 1-J)	8.0		3.9
Depreciation	192.6		210.7

Post-in-service carrying charges	228.6		219.8



Safety activity costs	146.0		118.6
DSM programs	37.8		50.1
Bailly Generating Station	204.7		221.8
Losses on Commodity Price Risk Programs (See Note 10)	54.7		76.4
Deferred Property Taxes	62.9		60.3
Other	88.4		140.2
Total Regulatory Assets	$	1,930.5	$	2,239.6
Less: Current Portion	135.7		225.7
Total Noncurrent Regulatory Assets	$	1,794.8	$	2,013.9

At December 31, (in millions)
2018 2017
Regulatory Assets
Unrecognized pension and other postretirement benefit costs (see Note 11) $ 798.3
$ 733.5
Deferred pension and other postretirement benefit costs (see Note 11) 74.1
70.7
Environmental costs (see Note 18-D) 61.5
63.4
Regulatory effects of accounting for income taxes (see Note 1-N and Note 10) 233.1
238.8
Under-recovered gas and fuel costs (see Note 1-K) 34.7
25.5
Depreciation 209.6
181.0
Post-in-service carrying charges 206.6
173.3
Safety activity costs 91.7
66.5
DSM programs 45.5
40.0
Bailly Generating Station 244.3
—
Other 238.1
208.5
Total Regulatory Assets $ 2,237.5
$ 1,801.2

Regulatory liabilities were comprised of the following items:


At December 31, (in millions)	2018		2017		At December 31, (in millions)	2020		2019
Regulatory Liabilities					Regulatory Liabilities
Over-recovered gas and fuel costs (see Note 1-K)	$	32.0	$	27.6
Cost of removal (see Note 7)	1,076.0		1,096.8
Regulatory effects of accounting for income taxes (see Note 1-O and Note 10)	1,428.3		1,563.4
Deferred pension and other postretirement benefit costs (see Note 11)	62.7		59.0
Over-recovered gas and fuel costs (see Note 1-J)					Over-recovered gas and fuel costs (see Note 1-J)	$	47.8	$	42.6
Cost of removal (see Note 8)					Cost of removal (see Note 8)	775.2		1,047.5
Regulatory effects of accounting for income taxes (see Note 1-N and Note 11)					Regulatory effects of accounting for income taxes (see Note 1-N and Note 11)	1,105.1		1,307.0
Deferred pension and other postretirement benefit costs (see Note 12)					Deferred pension and other postretirement benefit costs (see Note 12)	69.5		64.7
Other	61.0		48.8		Other	67.9		50.4
Total Regulatory Liabilities	$	2,660.0	$	2,795.6	Total Regulatory Liabilities	$	2,065.5	$	2,512.2
Less: Current Portion					Less: Current Portion	161.3		160.2
Total Noncurrent Regulatory Liabilities					Total Noncurrent Regulatory Liabilities	$	1,904.2	$	2,352.0

Regulatory assets, including under-recovered gas and fuel ~~cost,~~costs and depreciation, of approximately ~~$1,552.6~~$1,260.6 million and $1,524.3 million as of December 31, ~~2018~~2020 and 2019, respectively, are not earning a return on investment. These costs are recovered over a remaining life, the longest of ~~up to~~which is 41 years. Regulatory assets of approximately $1,917.1 million include expenses that are recovered as components of the cost of service and are covered by regulatory orders. Regulatory assets of approximately $320.4 million at December 31, 2018, require specific rate action.

Assets:

Unrecognized pension and other postretirement benefit costs. ~~In 2007, we adopted certain updates of ASC 715 which required, among other things,~~ Represents the ~~recognition in~~deferred other comprehensive income or loss of the actuarial gains or losses and the prior service costs or credits that arise during the period but that are not immediately recognized as components of net periodic benefit ~~costs. Certain~~costs by certain subsidiaries ~~defer these gains or losses as a regulatory asset in accordance with regulatory orders or as a result of regulatory precedent, to~~that will ultimately be recovered through base rates.

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~~Notes to Consolidated Financial Statements~~

~~ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)~~

Deferred pension and other postretirement benefit costs. Primarily relates to the difference between ~~postretirement~~defined benefit plan expense recorded by certain subsidiaries due to regulatory orders and the ~~postretirement~~corresponding expense that would otherwise be recorded in accordance with GAAP. ~~These~~The majority of these amounts are driven by Columbia of Ohio. The timeframe for the recovery of these costs will be addressed in the next base rate case, and the costs are expected to be collected through future base rates, revenue riders or tracking mechanisms.

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Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

Environmental costs.Includes certain recoverable ~~costs of investigating, testing, remediating and other~~ costs related to gas plant sites, disposal sites or other sites onto which material may have ~~migrated. Certain~~migrated, the recovery of ~~our companies defer the costs as a regulatory asset in accordance with regulatory orders,~~which is to be ~~recovered~~addressed in future base rates, billing riders or tracking ~~mechanisms.~~mechanisms of certain of our subsidiaries.

Regulatory effects of accounting for income taxes. Represents the deferral and under collection of deferred taxes in the rate making process. In prior years, we have lowered customer rates in certain jurisdictions for the benefits of accelerated tax deductions. Amounts are expensed for financial reporting purposes as we recover deferred taxes in the rate making process.

Under-recovered gas and fuel costs. Represents the difference between the costs of gas and fuel and the recovery of such costs in revenue and is used to adjust future billings for such deferrals on a basis consistent with applicable state-approved tariff provisions. Recovery of these costs is achieved through tracking mechanisms.

Depreciation. Represents differences between depreciation expense incurred on a GAAP basis and that prescribed through regulatory order. ~~Significant components~~The majority of this balance ~~include:~~

is driven by Columbia of ~~Ohio depreciation rates~~. Prior to 2005, the PUCO-approved depreciation rates for rate-making had been lower than those which would have been utilized if Columbia of Ohio were not subject to regulation resulting in the creation of a regulatory asset. In 2005, the PUCO authorized Columbia of Ohio to revise its depreciation accrual rates for the period beginning January 1, 2005. The revised depreciation rates are now higher than those which would have been utilized if Columbia of Ohio were not subject to regulation allowing for amortization of the previously created regulatory asset. The amount of depreciation that would have been recorded from 2005 through 2018 had Columbia of Ohio not been subject to rate regulation is a cumulative $806.8 million, $92.2 million less than that reflected in rates. The resulting regulatory asset balance was $39.5 million and $49.3 million as of December 31, 2018 and 2017, respectively.

~~Columbia of Ohio~~Ohio's IRP and ~~CEP.~~ ~~Columbia of Ohio also has PUCO approval to defer depreciation and debt-based post-in-service carrying charges (see "Post-in-service carrying charges"~~ below) associated with its IRP and CEP. As of December 31, 2018, depreciation of $29.1 million and $76.0 million was deferred for the respective programs. Depreciation deferral balances for the respective programs as of December 31, 2017 were $26.5 million and $49.8 million.CEP deferrals. Recovery of ~~the IRP depreciation~~these amounts is approved annually through the ~~IRP rider. The equivalent of annual depreciation expense, based on the average life of the~~ related assets, is included in the calculation of the IRP rider approved by the PUCO and billed to customers. Deferred depreciation expense is recognized as the IRP rider is billed to customers. The recovery mechanism for depreciation associated with the CEP is discussed in "Additional Regulatory Matters," below.

riders.

~~NIPSCO ECRM.~~ NIPSCO obtained approval from the IURC to recover certain environmental related costs including operation and maintenance and depreciation expense once the environmental facilities become operational. The ECRM deferred charges represent expenses that will be recovered from customers through an annual ECRM Cost Tracker (ECT) which authorizes the collection of deferred balances over a six month period. Recovery of these costs will continue until such assets are included in rate base through an electric base rate case. Depreciation of $14.4 million and $13.9 million was deferred to a regulatory asset as of December 31, 2018 and 2017, respectively.

~~NIPSCO TDSIC.~~ NIPSCO obtained approval from the IURC to recover costs for certain system modernization projects outside of a base rate proceeding. Eighty percent of the related costs, including depreciation, property taxes, and debt and equity based carrying charges (see ~~"Post-in-service carrying charges"~~ below) are recovered through a semi-annual recovery mechanism. Recovery of these costs will continue through the TDSIC tracker until such assets are included in rate base through a gas or electric base rate case, respectively. The remaining twenty percent of the costs are deferred until the next base rate case. As of December 31, 2018 and 2017, depreciation of $16.5 million and $10.3 million, respectively, was deferred as a regulatory asset.

Post-in-service carrying charges. Represents deferred debt-based carrying charges incurred on certain assets placed into service but not yet included in customer rates. ~~This~~The majority of this balance ~~includes:~~

is driven by Columbia of ~~Ohio IRP and CEP.~~ ~~See description of~~Ohio's IRP and CEP ~~programs above under the heading "Depreciation." As of December 31, 2018 and 2017, Columbia of Ohio had deferred PISCC of $197.1 million and $164.6 million, respectively.~~

deferrals.

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~~Notes to Consolidated Financial Statements~~

~~ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)~~

~~NIPSCO TDSIC.~~ ~~See description of TDSIC program above under the heading "Depreciation~~." Deferral of equity-based carrying charges for the TDSIC program is allowed; however, such amounts are not reflected in regulatory asset balances for financial reporting as equity-based returns do not meet the definition of incurred costs under ASC 980. As of December 31, 2018 and 2017, NIPSCO had deferred PISCC of $9.5 million and $8.7 million, respectively.

Safety activity costs. Represents the difference between costs incurred by certain of our subsidiaries in eligible safety programs in compliance with PHMSA regulations in excess of those being recovered in rates. The eligible cost deferrals represent necessary business expenses incurred in compliance with PHMSA regulations and are targeted to enhance the safety of the pipeline systems. Certain subsidiaries defer the excess costs as a regulatory asset in accordance with regulatory orders and recovery of these costs will be address in future base rate proceedings.

DSM programs. Represents costs associated with Gas Distribution Operations and Electric Operations segments' energy efficiency and conservation programs. Costs are recovered through tracking mechanisms.

Bailly Generating Station. Represents the net book value of Units 7 and 8 of Bailly Generating Station that was retired during 2018. These amounts are currently being amortized at a rate consistent with their inclusion in customer rates.

~~Liabilities:~~Losses on Commodity Price Risk Programs. Represents the unrealized losses related to certain of our subsidiary's commodity price risk programs. These programs help to protect against the volatility of commodity prices and these amounts are collected from customers through their inclusion in customer rates.

Property Taxes. Represents the deferral and under collection of property taxes in the rate making process for Columbia of Ohio and is driven by the IRP and CEP deferrals.

Liabilities:

Over-recovered gas and fuel costs. Represents the difference between the cost of gas and fuel and the recovery of such costs in revenues and is the basis to adjust future billings for such refunds on a basis consistent with applicable state-approved tariff provisions. Refunding of these revenues is achieved through tracking mechanisms.

Cost of removal. Represents anticipated costs of removal for utility assets that have been ~~and continue to be, included in~~collected through depreciation rates ~~and collected in customer rates of the rate-regulated subsidiaries~~ for future costs to be incurred.

Regulatory effects of accounting for income taxes. Represents amounts owed to customers for deferred taxes collected at a higher rate than the current statutory rates and liabilities associated with accelerated tax deductions owed to ~~customers that are established during the rate making process.~~customers. Balance includes excess deferred taxes recorded upon implementation of the TCJA in December 2017, net of amounts amortized ~~during 2018.~~through 2020.

Deferred pension and other postretirement benefit costs. Primarily represents cash contributions in excess of postretirement benefit expense that is deferred by certain subsidiaries.

COVID-19 Regulatory Filings

In response to the COVID-19 pandemic, we have engaged, or have received directives from, the regulatory commissions in the states in which we operate, as described below.

Columbia of Ohio filed a Deferral Application and a Transition Plan with the PUCO on May 29, 2020. The Deferral Application requested approval to record a regulatory ~~liability by certain subsidiaries in accordance with regulatory orders.~~

~~Cost Recovery~~asset for pandemic incremental costs, foregone revenue from late payment fees, and ~~Trackers~~

Comparability of our line item operating results is impacted by regulatory trackers that allow for the recovery in rates of certain costs such as those described below. Increases in the expenses that are the subject of trackers generally result in a corresponding increase in operating revenues and therefore have essentially no impact on total operating income results.

Certain costs of our operating companies are significant, recurring in nature and generally outside the control of the operating companies. Some states allow the recovery of such costs through cost tracking mechanisms. Such tracking mechanisms allow for abbreviated regulatory proceedings in order for the operating companies to implement charges and recover appropriate costs. Tracking mechanisms allow for more timely recovery of such costs as compared with more traditional cost recovery mechanisms. Examples of such mechanisms include GCR adjustment mechanisms, tax riders, bad debt ~~recovery mechanisms, electric energy efficiency programs, MISO non-fuel costs and revenues, resource capacity charges, federally mandated costs and environmental-related costs.~~

~~A portion~~expense from certain classes of customers. An order approving the ~~Gas Distribution revenue is related to~~Deferral Application was received on July 15, 2020. The Transition Plan requested the ~~recovery~~resumption of ~~gas costs, the review and recovery of which occurs through standard regulatory proceedings. All states~~activities that were suspended in our operating area require periodic review of actual gas procurement activity to determine prudence and to permit the recovery of prudently incurred costs related to the supply of gas for customers. Our distribution companies have historically been found prudent in the procurement of gas supplies to serve customers.

A portion of the Electric Operations revenue is related to the recovery of fuel costs to generate power and the fuel costs related to purchased power. These costs are recovered through a FAC, a quarterly regulatory proceeding in Indiana.

~~Infrastructure Replacement and Federally-Mandated Compliance Programs~~

Certain of our operating companies have completed rate proceedings involving infrastructure replacement or enhancement or are embarking upon regulatory initiatives to replace significant portions of their operating systems that are nearing the end of their

March 2020,

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Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

including resumption of disconnects due to non-payment and billing of late payment fees beginning with the August 2020 billing cycle. The PUCO approved the Transition Plan on June 17, 2020. As of December 31, 2020, $2.0 million of incremental pandemic-related costs were deferred to a regulatory asset.

~~useful lives. Each operating company's approach~~NIPSCO received a COVID-19 pandemic order from the IURC on June 29, 2020. This order extended the disconnection moratorium and the suspension of collection of late payment fees, deposits and reconnection fees through August 14, 2020. The order requires utilities to ~~cost recovery may be unique, given~~offer payment arrangements of at least six months and requires NIPSCO to provide the ~~different laws, regulations and precedent that exist in each jurisdiction.~~

~~Columbia of Ohio, IRP~~ -IURC with information about NIPSCO’s communications with delinquent customers. On ~~December 3, 2008,~~August 12, 2020, the ~~PUCO~~IURC issued an order ~~which established Columbia of Ohio’s IRP. Pursuant to that order,~~affirming the IRP provides for recovery of costs resulting from: (1) the maintenance, repair and replacement of customer-owned service lines that have been determined by Columbia of Ohio to present an existing or probable hazard to persons and property; (2) Columbia of Ohio’s replacement of cast iron, wrought iron, unprotected coated steel and bare steel pipe and associated company and customer-owned metallic service lines; (3) the replacement of customer-owned natural gas risers identified by the PUCO as prone to failure; and (4) the installation of AMR devices on all residential and commercial meters served by Columbia of Ohio. Recoverable costs include a return on investment, depreciation and property taxes, offset by specified cost savings. Columbia of Ohio’s five-year IRP plan renewal was last approved on January 31, 2018 for the years 2018-2022.

~~NIPSCO Gas and Electric, TDSIC~~ - On April 30, 2013, the Indiana Governor signed Senate Enrolled Act 560, known as the TDSIC statute, into law. Among other provisions, the TDSIC statute provides for cost recovery outside of a base rate proceeding for new or replacement electric and gas transmission, distribution, and storage projects that a public utility undertakes for the purposes of safety, reliability, system modernization or economic development. Provisionsexpiration of the ~~TDSIC statute require~~disconnect moratorium after August 14, 2020, while requiring that ~~among other things, requests~~six month payment plans be offered to all customers and extending the suspension for ~~recovery include~~collection of late payment fees, deposits, and reconnection fees through October 12, 2020 for residential customers only. On October 7, 2020 the Office of Utility Consumer Counselor ("OUCC") filed a seven-year plan of eligible investments. Once the plan is approved by the IURC, eighty percent of eligible costs can be recovered using a periodic rate adjustment mechanism, known as the TDSIC mechanism. Recoverable costs include a return on the investment, including AFUDC, PISCC, operation and maintenance expenses, depreciation and property taxes. The remaining twenty percent of recoverable costs are deferredmotion for ~~future recovery in NIPSCO's next general rate case. The semi-annual rate adjustment mechanism is capped at an annual increase of two percent of total retail revenues.~~

~~NIPSCO Electric, ECRM~~ ~~- NIPSCO has approval from~~ the IURC to ~~recover certain environmental related costs through~~extend these temporary consumer protections for an ~~ECT (environmental cost tracker). Under~~additional 60 days. On October 27, the ~~ECT, NIPSCO is permitted to recover (1) AFUDC and~~IURC issued a ~~return on~~docket entry denying the ~~capital investment expended by~~OUCC's motion. The June 29, 2020 order also authorized NIPSCO to ~~implement environmental compliance plan projects and (2) related operation and maintenance and depreciation expenses once the environmental facilities become operational.~~

~~NIPSCO Gas and Electric, FMCA~~ ~~- The FMCA statute provides~~create a regulatory asset for cost recovery outside of a base rate proceeding for projected federally mandated costs. Once the plan is approved by the IURC, eighty percent of eligible costs can be recovered using a periodic rate adjustment mechanism, knownpandemic-related incremental bad debt expense as well as the ~~FMCA mechanism. Recoverable~~ costs ~~include a return on~~to implement the investment, including AFUDC, PISCC, mandated operation and maintenance expenses, depreciation and property taxes. The remaining twenty percent of recoverable costs are deferred for future recovery in NIPSCO's next general rate case. Actual costs that exceed the projected federally mandated costsrequirements of the ~~approved compliance project by more than twenty-five percent shall require specific justification by NIPSCO~~order. As of December 31, 2020, $9.2 million of incremental bad debt expense and ~~specific approval by~~costs to implement the ~~IURC before being authorized in the next general rate case.~~

~~Columbia of Massachusetts, GSEP~~ ~~- On July 7, 2014, the Governor of Massachusetts signed into law Chapter 149~~requirements of the Acts of 2014, an Act Relative to Natural Gas Leaks (“the Act”). The Act authorizes natural gas distribution companies to file a GSEP for capital investments made on or after January 1, 2015, that are not included in the Company’s current rate base as determined in the most recent base rate case, with the Massachusetts DPU to (1) address the replacement or improvement of existing aging natural gas pipeline infrastructure to improve public safety or infrastructure reliability, and (2) reduce the lost and unaccounted for natural gas through a reduction in natural gas system leaks. In addition, the Act provides that the Massachusetts DPU may, after review of the plan, allow the proposed estimated costs of the plan into rates as of May 1 of the subsequent year. Recoverable costs include a return on investment, depreciation and property taxes, offset by identified operations and maintenance cost savings. Rates are subjectorder were deferred to a capped annual revenue increase of one and a half percent of total annual delivery and cost of gas revenues from sales and transportation, including imputed gas revenues for transportation, for the calendar year preceding the projected GSEP calendar year being filed. At the end of each 12-month period, in May of the subsequent year, Columbia of Massachusetts must file a reconciliation of the amount collected and actual costs. Any over-collection or under-collection balance is passed back to, or recovered from, customers over a 12-month period beginning in November. Once new base rates are established under a base rate proceeding, the GSEP factor is re-set to remove the capital investment and associated revenue reflected in the base rates.regulatory asset.

Columbia of Pennsylvania ~~DSIC~~ ~~- On February 14, 2012, the Governor of Pennsylvania signed into law Act 11 of 2012, which provided~~received a DSIC mechanism for certain utilities to recover costs related to repair, replacement or improvement of eligible distribution property that has not previously been reflected in rates or rate base. Through a DSIC, a utility may recover the fixed costs of eligible infrastructure incurred during the three months ended one month prior to the effective date of the charge, thereby reducing the historical regulatory lag associated with cost recovery through the traditional rate-making process. On March 14, 2013,secretarial letter issued by the Pennsylvania PUC ~~approved Columbia of Pennsylvania’s petition~~on May 13, 2020 authorizing Pennsylvania utilities to ~~implement~~create a ~~DSIC as of April 1, 2013. Accordingly,~~regulatory asset for incremental bad debt expense incurred since March 13, 2020, above levels currently in rates. While Columbia of Pennsylvania is not authorized to ~~recover~~defer any other incremental costs, it is required to track extraordinary non-recurring costs, and any offsetting benefits received, in connection with the ~~cost~~COVID-19 pandemic. On October 13, 2020, the Pennsylvania PUC entered an order modifying its March 13, 2020 emergency order that had established a moratorium on utility service terminations. As modified, the moratorium still applies to residential customers with incomes at or below 300% of ~~eligible plant associated~~the federal poverty income guidelines (“protected customers”). For all other customers, the moratorium was lifted on November 9, 2020, but utilities must comply with ~~repair, replacement~~several notice requirements beyond those already in place in Pennsylvania in order to proceed with service terminations. For residential customers who are subject to termination under the revised moratorium, as of December 1, 2020, the standard winter service moratorium will be in effect until April 1, 2021, which will render service termination for delinquent accounts impractical during that period. Additionally, the October 13, 2020 order authorizes utilities to create a regulatory asset for any incremental expenses incurred above those embedded in rates resulting from the directives contained in the Order. As of December 31, 2020, $5.4 million of incremental bad debt expense was deferred to a regulatory asset.

On March 16, 2020, the VSCC ordered a moratorium on service disconnections for unpaid bills due to the effects of the COVID-19 pandemic. The order also suspended late payment fees, required utilities to offer payment plans of up to 12 months, and required utilities to provide certain information about customer accounts receivables to the VSCC. Columbia of Virginia received an order from the VSCC on April 29, 2020 authorizing Columbia of Virginia to create a regulatory asset for incremental bad debt expense, suspended late payment fees, reconnection costs, carrying costs and other incremental prudently incurred costs related to the pandemic. The VSCC moratorium expired on October 6, 2020; however, the directives requiring utilities to offer payment plans of up to 12 months and suspending service disconnections or ~~improvement~~charging of late payment fees to customers that are current on such payment plans remain in effect. On November 18, 2020, legislation was enacted that extended the moratorium on residential service disconnections and late payment fees until the Governor determines that the economic and public health conditions have improved such that the prohibition does not need to be in place, or until at least 60 days after such declared state of emergency ends, whichever is sooner. Recovery of any regulatory asset will be addressed in future base rate proceedings and is subject to an earnings test review.

On August 31, 2020, the Maryland PSC issued an emergency order that extended the Governor's order prohibiting residential service terminations through October 1, 2020. The emergency order also requires Maryland utilities that proceed with residential service terminations after that date to provide at least 45 days notice prior to terminating service; to offer structured payment plans to applicable residential customers with a minimum of 12 months to repay, or 24 months for certified low income customers; the requirement or collection of down payments or deposits as a condition of beginning a payment plan by any residential customer; and cannot refuse to negotiate or deny a payment plan to a residential customer due to such customer's failure to meet the terms and conditions of an alternate payment plan during the past 18 months. Columbia of Maryland received an order issued by the Maryland PSC on April 9, 2020, authorizing Maryland utilities to create a regulatory asset for incremental COVID-19 pandemic-related costs, including incremental bad debt expense, incurred to ensure that customers have essential utility service during the state of emergency in Maryland. Such incremental costs must be offset by any benefit

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Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

~~previously reflected~~received in rate base and has been placed in service during the applicable three-month period. After the initial charge is established, the DSIC is updated quarterly to recover the cost of further plant additions and cannot exceed five percent of distribution revenues. Recoverable costs include a return on investment, exclusive of accumulated deferred income taxes from the calculation of rate base, and depreciation. Once new base rates are established under a base rate proceeding, the DSIC is set to zero. Additionally, the DSIC rate is also reset to zero if, in any quarter, the data reflected in the Columbia of Pennsylvania's most recent quarterly financial earnings report show that the utility will earn an overall rate of return that would exceed the allowable rate of return used to calculate its fixed costs under the DSIC mechanism. A utility is exempt from filing a quarterly financial earnings report when a base rate proceeding is pending before the Pennsylvania PUC.

~~Columbia of Virginia, SAVE -~~ On March 11, 2010, the Virginia Governor signed legislation into law that allows natural gas utilities to implement programs to replace qualifying infrastructure on an expedited basis and provides for timely cost recovery. Known as the SAVE Act, the law allows natural gas utilities to file programsconnection with the VSCC providing a timeline and estimated costs for replacing eligible infrastructure. Eligible infrastructure replacement projects are those that (1) enhance safety or reliability by reducing system integrity risks associated with customer outages, corrosion, equipment failures, material failures, or natural forces; (2) do not increase revenues by directly connecting the infrastructure replacement to new customers; (3) reduce or have the potential to reduce greenhouse gas emissions; (4) are not included in the natural gas utility’s rate base in its most recent rate case; and (5) are commenced on or after January 1, 2010. The SAVE Act provides for recoverypandemic. As of costs associated with the eligible infrastructure through a rate rider. Recoverable costs include a return on investment, depreciation and property taxes. Columbia of Virginia’s current five year SAVE plan was approved by the VSCC in 2016 and amended in 2017 for the years 2016 through 2020.

~~Columbia of Kentucky, AMRP~~ - On October 26, 2009, the Kentucky PSC approved a mechanism for recovering the costs of Columbia of Kentucky’s AMRP not previously reflected in rate base through an annual fixed monthly rate rider filed in October.In its 2013 rate case, Columbia of Kentucky was allowed to base the AMRP rider on the expected annual cost of service. Recoverable costs include a return on investment, depreciation and property taxes, offset by specific cost savings. At the end of each 12-month period, Columbia of Kentucky must file a reconciliation of the amount collected and actual costs. Any over-collection or under-collection balance is passed back to, or recovered from, customers through the surcharge over a 12-month period beginning in June of the subsequent year. Once new base rates are established under a base rate proceeding, the AMRP rider is set to zero.

December 31, 2020, Columbia of Maryland ~~STRIDE~~ - On May 2, 2013, the Governor of Maryland signed Senate Bill 8 into law, authorizing gas companies to accelerate recovery of eligible infrastructure replacement, effective June 1, 2013. The STRIDE statute provides recovery for gas pipeline upgrades outside of the context of a base rate proceeding through an annual surcharge, IRIS, as approved by, Maryland PSC. The STRIDE statute directs gas utilities to file a plan to invest in eligible infrastructure replacement projects and to list the specific projects and elements in any such STRIDE plan with the Maryland PSC. The calendar year projected capital projects to be placed into plant in service and included in Columbia of Maryland's surcharge recovery request must satisfy a number of criteria per the statute, including a requirement that they be designed to improve public safety or infrastructure reliability. Columbia of Maryland’s five-year STRIDE Plan renewal for years 2019 through 2023, as with the preceding five years, is focused on replacing (1) existing cast iron and bare steel mains, (2) associated services and meters, and (3) identified prone-to-failure vintage plastic piping. Columbia of Maryland’s IRIS mechanism recovers a return on investment, depreciation and property taxes of the STRIDE-eligible capital infrastructure statutorily capped at $2 per month for residential customers, and proportionally capped for commercial and industrial customer classes, and is reconciled to actual costs on an annual basis. Any over-collection or under-collection balance is passed back to, or recovered from, customers through the surcharge effective in May of the subsequent year.

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~~Notes to Consolidated Financial Statements~~

~~ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)~~

~~The following table describes regulatory programs to recover infrastructure replacement and other federally-mandated compliance investments currently in rates and those pending commission approval:~~

(in millions)
Company Program Incremental Revenue Incremental Capital Investment Investment Period Filed Status
Rates
Effective
Columbia of Ohio
IRP - 2018⁽¹⁾
$ 2.3
$ 207.0
1/17-12/17 February 27, 2018 Approved
April 25, 2018 May 2018
NIPSCO - Gas TDSIC 7 $ 1.5
$ 59.0
1/17-6/17 August 31, 2017 Approved
December 28, 2017 January 2018
NIPSCO - Gas TDSIC 8 $ 1.8
$ 54.0
7/17-12/17 February 27, 2018 Approved
August 22, 2018 September 2018
NIPSCO - Gas
TDSIC 9⁽¹⁾⁽²⁾
$ (10.6 ) $ 54.4
1/18 - 6/18 August 28, 2018 Approved
December 27, 2018 January 2019
NIPSCO - Gas FMCA 1 $ 9.9
$ 1.5
11/17-9/18 November 30, 2018 Order Expected
Q1 2019 April 2019
Columbia of Massachusetts
GSEP - 2018⁽¹⁾⁽³⁾
$ 6.5
$ 80.0
1/18-12/18 October 31, 2017 Approved
April 30, 2018 May 2018
Columbia of Massachusetts
GSEP - 2019⁽⁴⁾
$ 10.7
$ 64.0
1/19-12/19 October 31, 2018 Order expected
Q2 2019 May 2019
Columbia of Pennsylvania DSIC - 2018 $ 0.4
$ 14.8
12/17-2/18 March 22, 2018 Approved
March 29, 2018 April 2018
Columbia of Pennsylvania DSIC - 2018 $ 0.9
$ 31.8
3/18-5/18 June 20, 2018 Approved
June 28, 2018 July 2018
Columbia of Pennsylvania DSIC - 2018 $ 1.6
$ 55.4
6/18-8/18 September 20, 2018 Approved
September 28, 2018 October 2018
Columbia of Virginia SAVE - 2018 $ 2.9
$ 33.3
1/18-12/18 August 18, 2017 Approved
December 13, 2017 January 2018
Columbia of Virginia SAVE - 2019 $ 2.4
$ 36.0
1/19-12/19 August 17, 2018 Approved
October 26, 2018 January 2019
Columbia of Kentucky AMRP - 2018 $ 4.5
$ 24.0
1/18-12/18 October 13, 2017 Approved
December 22, 2017 January 2018
Columbia of Kentucky AMRP - 2019 $ 3.6
$ 30.1
1/19-12/19 October 15, 2018 Approved
December 5, 2018 January 2019
Columbia of Maryland STRIDE - 2018 $ 1.2
$ 20.8
1/18-12/18 November 1, 2017 Approved
December 20, 2017 January 2018
Columbia of Maryland STRIDE - 2019 $ 1.2
$ 19.7
1/19-12/19 November 1, 2018 Approved
December 12, 2018 January 2019
NIPSCO - Electric TDSIC - 3 $ (2.0 ) $ 75.0
5/17-11/17 January 30, 2018 Approved
May 30, 2018 June 2018
NIPSCO - Electric
TDSIC - 4⁽¹⁾
$ (11.8 ) $ 72.2
12/17-5/18 July 31, 2018 Approved
November 28, 2018 December 2018
NIPSCO - Electric
TDSIC - 5⁽¹⁾
$ 15.9
$ 58.8
6/18-11/18 January 29, 2019 Order Expected
Q2 2019 June 2019
NIPSCO - Electric ECRM - 31 $ (2.1 ) $ 2.9
6/17-12/17 January 31, 2018 Approved
April 25, 2018 May 2018
NIPSCO - Electric ECRM - 32 $ 1.0
$ —
1/18-6/18 July 31, 2018 Approved
October 11, 2018 November 2018
NIPSCO - Electric FMCA - 8 $ 1.3
$ 4.4
4/17-9/17 November 1, 2017 Approved
January 31, 2018 February 2018
NIPSCO - Electric FMCA - 9 $ 4.1
$ 90.2
10/17-3/18 April 27, 2018 Approved
July 25, 2018 August 2018
NIPSCO - Electric FMCA - 10 $ 2.2
$ 45.7
4/18-8/18 October 18, 2018 Approved
January 29, 2019 February 2019

⁽¹⁾~~Incremental revenue is net of amounts due back to customers as a result of the TCJA.~~

⁽²⁾~~Incremental revenue is net of $5.2~~has deferred $0.7 million of ~~adjustments in the TDSIC-9 settlement.~~

⁽³⁾~~A cap waiver was approved by the Massachusetts DPU on June 21, 2018~~incremental bad debt expense and ~~related rates became effective July 2018.~~

⁽⁴⁾~~The filing included a request for approval of a waiver to allow collection of the $2.9 million revenue requirement that exceeds the GSEP cap provision.~~

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~~Notes to Consolidated Financial Statements~~

~~ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)~~

~~Rate Case Actions~~

~~The following table describes current rate case actions as applicable in each of our jurisdictions net of tracker impacts:~~

(in millions)
Company Requested Incremental Revenue Approved Incremental Revenue Filed Status
Rates
Effective
NIPSCO - Gas⁽¹⁾
$ 138.1
$ 107.3
September 27, 2017 Approved
September 19, 2018 October 2018
Columbia of Massachusetts $ 24.1
N/A
April 13, 2018 Withdrawn
September 19, 2018 N/A
Columbia of Pennsylvania $ 46.9
$ 26.0
March 16, 2018 Approved
December 6, 2018 December 2018
Columbia of Virginia⁽²⁾
$ 14.2
In process
August 28, 2018 Order expected
Second half of 2019 February 2019
Columbia of Maryland $ 4.6
$ 2.2
April 13, 2018 Approved
November 21, 2018 November 2018
NIPSCO - Electric $ 21.4
In process
October 31, 2018 Order expected
Q3 2019 September 2019

⁽¹⁾Rates will be implemented in three steps, with implementation of step 1 rates effective October 1, 2018. Step 2 rates will be effective on or about March 1, 2019, and step 3 rates will be effective on January 1, 2020. The IURC’s order also dismissed NIPSCO from phase 2 of the IURC’s TCJA investigation.

⁽²⁾~~Rates implemented subject to refund pending a final order from the VSCC.~~

~~Additional Regulatory Matters~~

~~Columbia of Ohio.~~ On December 1, 2017, Columbia of Ohio filed an application that requested authority to implement a rider to begin recovering plant and associated deferrals related to its CEP. The CEP was established in 2011 and allows for deferral of interest, depreciation and property taxes on certain plant investments not recovered through its IRP modernization tracker. The application requested authority to increase annual revenues, through the requested rider, by approximately $70 million, with biennial increases up to approximately $98 million in 2022. On May 9, 2018, the PUCO appointed an independent auditor to assist the PUCO with the review of the accounting accuracy, prudency and compliance of Columbia of Ohio with its PUCO-approved CEP deferrals. The independent audit report was filed on September 4, 2018 and the PUCO Staff's Report on the investigation was filed on September 14, 2018. On October 25, 2018, a joint stipulation and recommendation was filed recommending an initial revenue requirement of $74.5 million to recover CEP investments and deferrals through December 31, 2017, with annual adjustments for capital investments made in subsequent years. Additionally, the signatory parties to the stipulation agreedpandemic-related costs to a reduction in rates to adjust for the impacts of the TCJA and for a base rate case filing to be made by Columbia of Ohio with a test period of calendar year 2021. On November 28, 2018 the PUCO issued an order unanimously approving the settlement filed on October 25, 2018, without modification, for rates effective beginning November 29, 2018. This order finalizes Columbia of Ohio's TCJA resolution related to the CEP tracker, as well as base rates.regulatory asset.

~~NIPSCO Gas.~~ 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 settlement agreement filed in NIPSCO’s gas base rate case proceeding, NIPSCO and the parties to the settlement agreement settled all issues in this proceeding as well, including moving certain costs from the base rate proceeding to this pipeline safety compliance plan. The updated four year compliance plan includes a total estimated $91.5 million of capital costs and $35.5 million of expected operating and maintenance costs. NIPSCO received approval for accounting and rate-making relief, including establishment of a periodic rate adjustment mechanism. NIPSCO filed the first tracker proceeding in this case on November 30, 2018. On December 31, 2018, NIPSCO filed a petition with the IURC seeking approval of an additional PHMSA compliance plan including capital expenditures of $228.8 million. An IURC order is expected in the second half of 2019.

On January 3, 2018, the IURC initiated an investigation to review and consider the possible implications of the TCJA on utility rates. The IURC ordered a two phase investigation. Phase 1 solely dealt with the prospective changes in rates to reflect the change in tax rates. In accordance with the procedural schedule, on March 26, 2018, NIPSCO filed revised gas tariffs reflecting the impact of the change in tax rate for its applicable rates and charges. The IURC approved NIPSCO's Phase 1 filing on April 26, 2018. The revised tariffs were effective May 1, 2018. The stipulation and settlement agreement filed on April 20, 2018, in NIPSCO’s gas rate case resolved all issues in Phase 2, including the return of excess income tax revenue recovered through its base rates and any

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~~Notes to Consolidated Financial Statements~~

~~ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)~~

~~applicable charges between January 1, 2018 and April 30, 2018. Beginning January 2019, and continuing through June 2019, NIPSCO is passing back the excess tax expense through the TDSIC mechanism.~~

On December 27, 2018, the IURC issued an order for TDSIC-9 approving the settlement agreement filed on November 4, 2018. This order, along with the Court of Appeals dismissal on December 31, 2018 and January 8, 2019, resolved all outstanding issues related to the appeals of TDSIC-4 though TDSIC-8.

~~Columbia of Massachusetts.~~ On October 9, 2018, Columbia of Massachusetts filed an application with the Massachusetts DPU, seeking authority to pass back approximately $95.8 million in excess deferred taxes associated with TCJA with an effective date of rates to be determined by the Massachusetts DPU. On December 21, 2018 the Massachusetts DPU issued an order approving the treatment of TCJA-related excess deferred taxes. Columbia Gas of Massachusetts filed a compliance filing on January 4, 2019, reflecting revised LDAF rates inclusive of credit factors to return excess deferred taxes associated with TCJA to customers for rates effective on February 1, 2019, per the Massachusetts DPU’s order.

~~Columbia of Kentucky.~~ ~~On April 30, 2018,~~ Columbia of Kentucky received an order from the Kentucky PSC ~~requiring implementation~~on September 21, 2020 lifting the disconnection moratorium for all customers, effective October 20, 2020. The September 21, 2020 order also lifted the suspension of ~~interim proposed rates effective May~~late payment and reconnection fees for non-residential customers as of October 20, 2020. For residential customers, the moratorium on late payment and reconnection fees is extended to December 31, 2020 and tracking of lost revenue is required. Residential customers with accumulated arrearages for service provided on or after March 16, 2020 through October 1, ~~2018 reflecting~~2020 will be notified and placed on a default payment plan of equal installments for nine months beginning with the ~~impact of TCJA subject~~November 2020 billing cycle. Residential customers on a payment plan that default shall be offered another payment plan. Carrying charges may be applied to ~~future adjustment.~~all arrearages arising during the default payment plan period at a rate no greater than the utility’s long-term debt rate. The Kentucky PSC order ~~directed~~allows Columbia of Kentucky to ~~file, by September 1, 2018, revised TCJA adjustment factors reflecting~~create a regulatory asset for carrying charges on all arrearages arising during the ~~tax expense savings from January 1, 2018 through April 30, 2018, and~~default payment plan period. As of December 31, 2020, an ~~estimate~~immaterial amount of ~~the annual reduction due~~carrying charges were deferred to the excess deferred taxes to be effective with the first billing cycle of October 2018. On August 31, 2018, Columbia of Kentucky filed updated rate schedules with the Kentucky PSC for rates proposed to be effective October 1, 2018. On October 25, 2018, the Kentucky PSC authorized the TCJA adjustment factors, as proposed, with an October 29, 2018 effective date to pass-back the overcollection of taxes over a ~~six month period.~~regulatory asset.

~~Columbia of Maryland.~~ On February 13, 2018, Columbia of Maryland filed a proposal with the Maryland PSC to reduce rates as a result of TCJA with an annual revenue decrease of $1.3 million. Columbia of Maryland was directed to account for any revenues associated with the difference between previous and current income tax rates and excess deferred taxes as regulatory liabilities effective January 1, 2018. On March 14, 2018, Columbia of Maryland received approval, effective April 2, 2018, to implement new rates and pass-back the overcollection of taxes from the first quarter of 2018 over a seven month period.

~~NIPSCO Electric.~~ On October 31, 2018, NIPSCO submitted its 2018 Integrated Resource Plan with the IURC. The plan evaluated demand-side and supply-side resource alternatives to reliably and cost effectively meet NIPSCO customers' future energy requirements over the ensuing 20 years. Refer to Note 18-E, "Other Matters," in the Notes to Consolidated Financial Statements for additional information.

On March 29, 2018, WCE, which is currently owned by BP p.l.c ("BP") and BP Products North America, which operates the BP Refinery, filed a petition at the IURC asking that the combined operations of WCE and BP be treated as a single premise, and the WCE generation be dedicated primarily to BP Refinery operations beginning in May 2019 as WCE has self-certified as a qualifying facility at FERC. BP Refinery planned to continue to purchase electric service from NIPSCO at a reduced demand level beginning in May 2019. A settlement agreement was filed on November 2, 2018 agreeing that BP and WCE would not move forward with construction of a private transmission line to serve BP until conclusion of NIPSCO’s pending electric rate case.

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 tax rate change provisions into 2018 transmission formula rates. 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 reduce revenue by $8.5 million in 2018 associated with NIPSCO's multi-value projects. Additionally, on November 1, 2018, MISO submitted revised tariffs to provide for adjustments to income tax, including accumulated deferred income tax, resulting from tax law or rate changes. On December 20, 2018, FERC accepted the submission, effective January 1, 2019, as requested.

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,

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~~Notes to Consolidated Financial Statements~~

~~ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)~~

also filed on July 31, 2018, and requesting that all other phase 2 issues be handled in a rate case filing to be made in the fourth quarter of 2018. On August 15, 2018, the IURC approved the motion to pass back the over-collection through the TDSIC-4 rates effective December 2018 through May 2019. All other phase 2 issues are addressed in the base rate case filed October 31, 2018.


9.	10. Risk Management Activities

We are exposed to certain risks ~~relating~~related 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 interest rate exposure and limit volatility in the price of natural gas.

Risk management assets and liabilities on our derivatives are presented on the Consolidated Balance Sheets as shown below:


December 31, (in millions)	2020		2019
Risk Management Assets - Current(1)
Interest rate risk programs	$	0	$	0
Commodity price risk programs	10.4		0.6
Total	$	10.4	$	0.6
Risk Management Assets - Noncurrent(2)
Interest rate risk programs	$	0	$	0
Commodity price risk programs	2.8		3.8
Total	$	2.8	$	3.8
Risk Management Liabilities - Current
Interest rate risk programs	$	70.9	$	0
Commodity price risk programs	7.3		12.6
Total	$	78.2	$	12.6
Risk Management Liabilities - Noncurrent
Interest rate risk programs	$	99.5	$	76.2
Commodity price risk programs	45.1		57.8
Total	$	144.6	$	134.0

December 31, (in millions)
2018 2017
Risk Management Assets - Current⁽¹⁾

Interest rate risk programs $ —
$ 14.0
Commodity price risk programs 1.1
0.5
Total $ 1.1
$ 14.5
Risk Management Assets - Noncurrent⁽²⁾

Interest rate risk programs $ 18.5
$ 5.6
Commodity price risk programs 4.4
1.0
Total $ 22.9
$ 6.6
Risk Management Liabilities - Current
Interest rate risk programs $ —
$ 38.6
Commodity price risk programs 5.0
4.6
Total $ 5.0
$ 43.2
Risk Management Liabilities - Noncurrent
Interest rate risk programs $ 9.5
$ —
Commodity price risk programs 37.2
28.5
Total $ 46.7
$ 28.5

⁽¹⁾Presented in "Prepayments and other" on the Consolidated Balance Sheets.

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

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NISOURCE INC.

Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (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 range from five to ~~ten~~10 years and is limited to ~~twenty percent~~20% of NIPSCO’s average annual GCA purchase volume. Gains and losses on these derivative contracts are deferred as regulatory liabilities or assets and are remitted to or collected from customers through NIPSCO’s quarterly GCA mechanism. These instruments are not designated as accounting hedges.

Interest Rate Risk Management

As of December 31, ~~2018,~~2020, we have two forward-starting interest rate swaps with an aggregate notional value totaling $500.0 million to hedge the variability in cash flows attributable to changes in the benchmark interest rate during the periods from the effective dates of the swaps to the anticipated dates of forecasted debt issuances, which are expected to take place by the end of 2024. These interest rate swaps are designated as cash flow hedges. The ~~effective portions of the~~ gains and losses related to these swaps are

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~~Notes to Consolidated Financial Statements~~

~~ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)~~

recorded to AOCI and ~~are~~will be recognized in "Interest expense, net" concurrently with the recognition of interest expense on the associated debt, once issued. If it becomes probable that a hedged forecasted transaction will no longer occur, the accumulated gains or losses on the derivative will be recognized currently in "Other, net" in the Statements of Consolidated Income (Loss).

The passage of the TCJA and Greater Lawrence Incident led to significant changes to our long-term financing plan. As a result, during 2018, we settled forward-starting interest rate swaps with a notional value of $750.0 million. These derivative contracts were accounted for as cash flow hedges. As part of the transactions, the associated net unrealized gain of $46.2 million was recognized immediately in "Other, net" onin the Statements of Consolidated Income (Loss) ~~due to the probability associated with~~as it became probable the forecasted borrowing transactions would no longer ~~occurring.~~

occur.

There were no0 amounts excluded from effectiveness testing for derivatives in cash flow hedging relationships at December 31, ~~2018, 2017~~2020, 2019 and ~~2016.~~2018.

Our derivative instruments measured at fair value as of December 31, ~~2018~~2020 and ~~2017~~2019 do not contain any credit-risk-related contingent features.

~~10.~~

11. Income Taxes

On December 22, 2017, the President signed into law the TCJA, which, among other things, enacted significant changes to the Internal Revenue Code, as amended, including a reduction in the maximum U.S. federal corporate income tax rate from 35% to 21%, and certain other provisions related specifically to the public utility industry, including the continuation of certain interest expense deductibility. These changes were effective January 1, 2018. Under GAAP, the effects of a change in tax law are recorded as a discrete item in the period of enactment.

Rates for our regulated customers include provisions for the collection of U.S. federal income taxes. Accordingly, accounting effects related to changes in tax rates here that would normally be recognized as a componentIncome Tax Expense. The components of income tax expense ~~may instead be deferred~~(benefit) were as a regulatory asset or liability and reflected in future rate-making. In December 2017, we remeasured our deferred tax assets and liabilities to the new federal corporate income tax rate. The result of this remeasurement was a reduction in the net deferred tax liability of approximately $1.3 billion, including approximately $0.4 billion of regulatory "gross up" to account for over-collection of past taxes from customers. Offsetting the reduction in net deferred tax liabilities was an increase in regulatory liabilities of approximately $1.5 billion and an increase in income tax expense of $0.2 billion. In 2018, we received regulatory orders from most of the jurisdictions in which we operate regarding the treatment and pass back of excess deferred taxes. As a result of these orders we reduced our regulatory liability related to excess deferred income taxes by $120.7 million (net of tax). This adjustment is reflected in "Income Taxes" on our Consolidated Statements of Income (Loss).follows:

On December 22, 2017, the SEC issued Staff Accounting Bulletin 118 (“SAB 118”), which provides guidance on accounting for tax effects of the TCJA. SAB 118 provides a measurement period that should not extend beyond one year from the TCJA enactment date for companies to complete the accounting under ASC 740. There were no adjustments recorded in the SAB 118 remeasurement period in 2018.


Year Ended December 31, (in millions)	2020		2019		2018
Income Taxes
Current
Federal	$	0.2	$	0	$	0
State	11.7		5.2		8.2
Total Current	11.9		5.2		8.2
Deferred
Federal	(0.4)		110.7		(209.4)
State	(27.4)		9.0		22.2
Total Deferred	(27.8)		119.7		(187.2)
Deferred Investment Credits	(1.2)		(1.4)		(1.0)
Income Taxes	$	(17.1)	$	123.5	$	(180.0)

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NISOURCE INC.

Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

Statutory Rate Reconciliation.The ~~components~~following table represents a reconciliation of income tax expense ~~(benefit) were as follows:~~

Year Ended December 31, (in millions)
2018 2017 2016
Income Taxes
Current
Federal $ —
$ —
$ —
State 8.2
7.8
(0.1 )
Total Current 8.2
7.8
(0.1 )
Deferred
Federal (209.4 ) 302.7
165.6
State 22.2
5.0
18.0
Total Deferred (187.2 ) 307.7
183.6
Deferred Investment Credits (1.0 ) (1.0 ) (1.4 )
Income Taxes $ (180.0 ) $ 314.5
$ 182.1

~~Total income taxes were different from the amount that would be computed by applying~~at the statutory federal income tax rate to ~~book~~the actual income ~~before income tax. The major reasons for this difference were as follows:~~tax expense from continuing operations:


Year Ended December 31, (in millions)	2018					2017					2016					Year Ended December 31, (in millions)	2020				2019				2018
Book income (loss) before income taxes	$	(230.6	)			$	443.0				$	513.6				Book income (loss) before income taxes	$	(31.3)			$	506.6			$	(230.6)
Tax expense (benefit) at statutory federal income tax rate	(48.4		)	21.0	%	155.0			35.0	%	179.8			35.0	%	Tax expense (benefit) at statutory federal income tax rate	(6.6)		21.0	%	106.5		21.0	%	(48.4)		21.0	%
Increases (reductions) in taxes resulting from:																Increases (reductions) in taxes resulting from:
State income taxes, net of federal income tax benefit	24.7			(10.7	)	6.9			1.5		11.3			2.2		State income taxes, net of federal income tax benefit	(11.7)		37.4		10.1		2.0		24.7		(10.7)
Amortization of regulatory liabilities	(29.3		)	12.7		(2.4		)	(0.5	)	(1.5		)	(0.3	)	Amortization of regulatory liabilities	(38.4)		122.7		(29.4)		(5.8)		(29.3)		12.7
Goodwill impairment																Goodwill impairment	0		0		43.0		8.5		0		0
Fines and penalties																Fines and penalties	11.8		(37.7)		11.5		2.3		0.2		(0.1)

Charitable contribution carryover	—			—		(1.2		)	(0.3	)	2.8			0.5		Charitable contribution carryover	0		0		(2.5)		(0.5)		0		0
State regulatory proceedings	(127.8		)	55.4		—			—		—			—		State regulatory proceedings	0		0		(9.5)		(1.9)		(127.8)		55.4
Remeasurement due to TCJA	—			—		161.1			36.4		—			—
Employee stock ownership plan dividends and other compensation	(2.2		)	1.0		(6.5		)	(1.5	)	(9.5		)	(1.8	)	Employee stock ownership plan dividends and other compensation	(1.3)		4.2		(2.0)		(0.4)		(2.2)		1.0

Deferred taxes on TCJA regulatory liability divested																Deferred taxes on TCJA regulatory liability divested	23.3		(74.5)		0		0		0		0
Tax accrual adjustments																Tax accrual adjustments	8.9		(28.4)		0		0		0		0
Federal tax credits																Federal tax credits	(2.5)		8.0		0		0		0		0
Other adjustments	3.0			(1.3	)	1.6			0.4		(0.8		)	(0.1	)	Other adjustments	(0.6)		1.9		(4.2)		(0.8)		2.8		(1.2)
Income Taxes	$	(180.0	)	78.1	%	$	314.5		71.0	%	$	182.1		35.5	%	Income Taxes	$	(17.1)	54.6	%	$	123.5	24.4	%	$	(180.0)	78.1	%

113

Year Ended December 31, (in millions)
2018 2017 2016
Operating Revenues
Gas Distribution Operations
Unaffiliated $ 3,406.4
$ 3,087.9
$ 2,818.2
Intersegment 13.1
14.2
12.4
Total 3,419.5
3,102.1
2,830.6
Electric Operations
Unaffiliated 1,707.4
1,785.7
1,660.8
Intersegment 0.8
0.8
0.8
Total 1,708.2
1,786.5
1,661.6
Corporate and Other
Unaffiliated 0.7
1.0
13.5
Intersegment 517.6
510.8
413.3
Total 518.3
511.8
426.8
Eliminations (531.5 ) (525.8 ) (426.5 )
Consolidated Operating Revenues $ 5,114.5
$ 4,874.6
$ 4,492.5

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Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)


Year Ended December 31, (in millions)	2020		2019		2018
Operating Income (Loss)
Gas Distribution Operations(1)	$	199.1	$	675.4	$	(254.1)
Electric Operations	348.8		406.8		386.1
Corporate and Other(2)	2.9		(191.5)		(7.3)
Consolidated Operating Income	$	550.8	$	890.7	$	124.7
Depreciation and Amortization
Gas Distribution Operations	$	363.1	$	403.2	$	301.0
Electric Operations	321.3		277.3		262.9
Corporate and Other	41.5		36.9		35.7
Consolidated Depreciation and Amortization	$	725.9	$	717.4	$	599.6
Assets
Gas Distribution Operations	$	13,433.0	$	14,224.5	$	13,527.0
Electric Operations	6,443.1		6,027.6		5,735.2
Corporate and Other	2,164.4		2,407.7		2,541.8
Consolidated Assets	$	22,040.5	$	22,659.8	$	21,804.0
Capital Expenditures(3)
Gas Distribution Operations	$	1,266.9	$	1,380.3	$	1,315.3
Electric Operations	422.8		468.9		499.3
Corporate and Other	31.1		18.6		0
Consolidated Capital Expenditures	$	1,720.8	$	1,867.8	$	1,814.6

(1)In 2020, Gas Distribution Operations reflects the loss of $412.4 millionon the sale of the Massachusetts Business. For additional information, see Note 1, "Nature of Operations and Summary of Significant Accounting Policies".

Year Ended December 31, (in millions)
2018 2017 2016
Operating Income (Loss)
Gas Distribution Operations $ (254.1 ) $ 550.1
$ 569.7
Electric Operations 386.1
367.4
301.3
Corporate and Other (7.3 ) 3.7
(4.9 )
Consolidated Operating Income $ 124.7
$ 921.2
$ 866.1
Depreciation and Amortization
Gas Distribution Operations $ 301.0
$ 269.3
$ 252.9
Electric Operations 262.9
277.8
274.5
Corporate and Other 35.7
23.2
19.7
Consolidated Depreciation and Amortization $ 599.6
$ 570.3
$ 547.1
Assets
Gas Distribution Operations $ 13,527.0
$ 12,048.8
$ 11,096.4
Electric Operations 5,735.2
5,478.6
5,233.3
Corporate and Other 2,541.8
2,434.3
2,362.2
Consolidated Assets $ 21,804.0
$ 19,961.7
$ 18,691.9
Capital Expenditures⁽¹⁾

Gas Distribution Operations $ 1,315.3
$ 1,125.6
$ 1,054.4
Electric Operations 499.3
592.4
420.6
Corporate and Other —
35.8
15.4
Consolidated Capital Expenditures $ 1,814.6

$ 1,753.8
$ 1,490.4
(2)In 2019, Corporate and Other reflects an impairment charge of $204.8 million for goodwill related to Columbia of Massachusetts. For additional information, see Note 7, "Goodwill and Other Intangible Assets."

⁽¹(3)Amounts differ from those presented on the Statements of Consolidated Cash Flows primarily due to the inclusion of capital expenditures ~~included~~ in current liabilities, the capitalized portion of the Corporate Incentive Plan payout, and AFUDC Equity.

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Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

25. Quarterly Financial Data (Unaudited)


~~23.~~	~~Quarterly Financial Data (Unaudited)~~

Quarterly financial data does not always reveal the trend of our business operations due to nonrecurring items and seasonal weather patterns, which affect earnings and related components of revenue and operating income.


(in millions, except per share data)	First Quarter(1)		Second Quarter(2)		Third Quarter(3)		Fourth Quarter(4)
2020
Operating Revenues	$	1,605.5	$	962.7	$	902.5	$	1,211.0
Operating Income	148.2		91.7		92.8		218.1
Net Income (Loss)	75.6		(4.7)		(172.9)		87.8
Net income attributable to noncontrolling interest	0		0		0		3.4
Net Income (Loss) attributable to NiSource	75.6		(4.7)		(172.9)		84.4
Preferred Dividends	(13.8)		(13.8)		(13.8)		(13.7)
Net Income (Loss) Available to Common Shareholders	61.8		(18.5)		(186.7)		70.7

Earnings (Loss) Per Share
Basic Earnings (Loss) Per Share	$	0.16	$	(0.05)	$	(0.49)	$	0.18
Diluted Earnings (Loss) Per Share	$	0.16	$	(0.05)	$	(0.49)	$	0.18
2019
Operating Revenues	$	1,869.8	$	1,010.4	$	931.5	$	1,397.2
Operating Income (Loss)	374.2		463.5		91.0		(38.0)


Net Income (Loss)	218.9		296.9		6.6		(139.3)
Preferred Dividends	(13.8)		(13.8)		(13.8)		(13.7)
Net Income (Loss) Available to Common Shareholders	205.1		283.1		(7.2)		(153.0)
Earnings (Loss) Per Share
Basic Earnings (Loss) Per Share	$	0.55	$	0.76	$	(0.02)	$	(0.41)
Diluted Earnings (Loss) Per Share	$	0.55	$	0.75	$	(0.02)	$	(0.41)

(in millions, except per share data)
First
Quarter⁽¹⁾

Second
Quarter⁽²⁾

Third
Quarter⁽³⁾

Fourth
Quarter⁽⁴⁾
2018
Operating Revenues $ 1,750.8
$ 1,007.0
$ 895.0
$ 1,461.7
Operating Income (Loss) 400.6
118.4
(315.9 ) (78.4 )
Net Income (Loss) 276.1
24.5
(339.5 ) (11.7 )
Preferred Dividends —
(1.3 ) (5.6 ) (8.1 )
Net Income (Loss) Available to Common Shareholders 276.1
23.2
(345.1 ) (19.8 )
Earnings (Loss) Per Share
Basic Earnings (Loss) Per Share $ 0.82
$ 0.07
$ (0.95 ) $ (0.05 )
Diluted Earnings (Loss) Per Share $ 0.81
$ 0.07
$ (0.95 ) $ (0.05 )
2017
Operating Revenues $ 1,598.6
$ 990.7
$ 917.0
$ 1,368.3
Operating Income 415.4
124.0
111.2
270.6
Net Income (Loss) 211.3
(44.4 ) 14.0
(52.4 )
Earnings (Loss) Per Share
Basic Earnings (Loss) Per Share $ 0.65
$ (0.14 ) $ 0.04
$ (0.16 )
Diluted Earnings (Loss) Per Share $ 0.65
$ (0.14 ) $ 0.04
$ (0.16 )

⁽¹⁾Net income for the first quarter of ~~2018~~2020 was impacted by ~~an interest rate swap settlement gain~~$280.2 million loss on sale of ~~$21.2~~the Massachusetts Business. Net income for the first quarter of 2019 was impacted by $108.0 million in insurance recoveries (pretax). related to the Greater Lawrence Incident. See Note ~~9, "Risk Management Activities"~~1, "Company Structure and Principles of Consolidation" and Note 20-E, "Other Matters" for additional information.

⁽²⁾Net income for the second quarter of ~~2017~~2020 was impacted by ~~a $111.5~~an additional $84.4 million loss ~~(pretax)~~ on ~~an early extinguishment~~sale of ~~long-term debt. See Note 14, "Long-Term Debt" for additional information.~~

⁽³⁾the Massachusetts Business. Net income for the ~~third~~second quarter of ~~2018~~2019 was impacted by ~~approximately $462~~$297.0 million in ~~expenses~~insurance recoveries (pretax) related to the Greater Lawrence ~~Incident restoration~~Incident. See Note 1, "Company Structure and ~~a $33.0~~Principles of Consolidation" and Note 20-E, "Other Matters" for additional information.

(3) Net loss for the third quarter of 2020 was impacted by $243.4 million loss ~~(pretax)~~ on an early ~~extinguishment~~extinguishments of long-term debt. See Note ~~18-E, "Other Matters" and Note 14,~~15, "Long-Term Debt" for additional information.

⁽⁴⁾Net ~~income~~loss for the fourth quarter of ~~2018~~2019 was impacted by ~~approximately $426~~an impairment charge of $204.8 million for goodwill and an impairment charge of $209.7 million for franchise rights, in ~~expenses (pretax, net of insurance recoveries)~~each case related to ~~the Greater Lawrence Incident restoration, partially offset by an interest rate swap settlement gain~~Columbia of ~~$25.0 million (pretax)~~Massachusetts. For additional information, see Note 7, "Goodwill and a $120.7 million income tax benefit from true-ups to reflect regulatory outcomes associated with excess deferred income taxes. Net income for the fourth quarter of 2017 was impacted by a $161.1 million increase in tax expense as a result of implementing the provisions of the TCJA. See Note 18-E, "Other Matters,Other Intangible Assets." ~~Note 9, "Risk Management Activities" and Note 10, "Income Taxes" for additional information.~~

~~112~~

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NISOURCE INC.

Notes to Consolidated Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

~~24.~~26. Supplemental Cash Flow Information

The following table provides additional information regarding our Consolidated Statements of Cash Flows for the years ended December 31, ~~2018, 2017~~2020, 2019 and ~~2016:~~2018:


Year Ended December 31, (in millions)	2020		2019		2018
Supplemental Disclosures of Cash Flow Information
Non-cash transactions:
Capital expenditures included in current liabilities	$	170.4	$	223.6	$	152.0
Assets acquired under a finance lease	59.3		26.4		54.6
Assets acquired under an operating lease	10.9		13.4		0
Reclassification of other property to regulatory assets(1)	0		0		245.3
Assets recorded for asset retirement obligations(2)	91.5		54.6		78.1
Obligation to developer at formation of joint venture(3)	69.7		0		0
Schedule of interest and income taxes paid:
Cash paid for interest, net of interest capitalized amounts	$	349.0	$	349.7	$	354.2
Cash paid for income taxes, net of refunds(4)	(1.0)		10.8		3.3

Year Ended December 31, (in millions)
2018 2017 2016
Supplemental Disclosures of Cash Flow Information
Non-cash transactions:
Capital expenditures included in current liabilities $ 152.0
$ 173.0
$ 125.3
Assets acquired under a capital lease 54.6
11.5
4.0
Reclassification of other property to regulatory assets⁽¹⁾
245.3
—
—
Assets recorded for asset retirement obligations⁽²⁾
78.1
11.4
6.9
Schedule of interest and income taxes paid:
Cash paid for interest, net of interest capitalized amounts $ 354.2
$ 339.9
$ 337.8
Cash paid for income taxes, net of refunds 3.3
5.5
8.0

⁽¹⁾See Note 89 "Regulatory Matters" for additional information.

⁽²⁾See Note 78 "Asset Retirement Obligations" for additional information.

(3)Represents investing non-cash activity. See Note 4 "Variable Interest Entities" for additional information.

(4)Amount of refunds in 2020 was greater than the amount of tax payments due to overpayments in 2019.

~~113~~

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

NISOURCE INC.

SCHEDULE II – VALUATION AND QUALIFYING ACCOUNTS


Twelve months ended December 31, 2020
			Additions
($ in millions)	Balance Jan. 1, 2020		Charged to Costs and Expenses		Charged to Other Account (1)		Deductions for Purposes for which Reserves were Created		Balance Dec. 31, 2020
Reserves Deducted in Consolidated Balance Sheet from Assets to Which They Apply:
Reserve for accounts receivable	$	19.2	$	31.6	$	33.0	$	31.5	$	52.3
Reserve for other investments	3.0		0		0		3.0		0



Twelve months ended December 31, 2019
			Additions
($ in millions)	Balance Jan. 1, 2019		Charged to Costs and Expenses		Charged to Other Account (1)		Deductions for Purposes for which Reserves were Created		Balance Dec. 31, 2019
Reserves Deducted in Consolidated Balance Sheet from Assets to Which They Apply:
Reserve for accounts receivable	$	21.1	$	21.6	$	41.3	$	64.8	$	19.2
Reserve for other investments	3.0		0		0		0		3.0



Twelve months ended December 31, 2018
			Additions
($ in millions)	Balance Jan. 1, 2018		Charged to Costs and Expenses		Charged to Other Account (1)		Deductions for Purposes for which Reserves were Created		Balance Dec. 31, 2018
Reserves Deducted in Consolidated Balance Sheet from Assets to Which They Apply:
Reserve for accounts receivable	$	18.3	$	20.2	$	43.7	$	61.1	$	21.1
Reserve for other investments	3.0		0		0		0		3.0

Twelve months ended December 31, 2018

Additions
($ in millions) Balance Jan. 1, 2018 Charged to Costs and Expenses
Charged to Other Account ⁽¹⁾
Deductions for Purposes for which Reserves were Created Balance Dec. 31, 2018
Reserves Deducted in Consolidated Balance Sheet from Assets to Which They Apply:
Reserve for accounts receivable $ 18.3
$ 20.2
$ 43.7
$ 61.1
$ 21.1
Reserve for other investments 3.0
—
—
—
3.0

Twelve months ended December 31, 2017
Additions
($ in millions) Balance
Jan. 1, 2017 Charged to Costs and Expenses
Charged to Other Account ⁽¹⁾
Deductions for Purposes for which Reserves were Created Balance
Dec. 31, 2017
Reserves Deducted in Consolidated Balance Sheet from Assets to Which They Apply:
Reserve for accounts receivable $ 23.3
$ 14.8
$ 39.1
$ 58.9
$ 18.3
Reserve for other investments 3.0
—
—
—
3.0

Twelve months ended December 31, 2016
Additions
($ in millions) Balance
Jan. 1, 2016 Charged to Costs and Expenses
Charged to Other Account ⁽¹⁾
Deductions for Purposes for which Reserves were Created Balance
Dec. 31, 2016
Reserves Deducted in Consolidated Balance Sheet from Assets to Which They Apply:
Reserve for accounts receivable $ 20.3
$ 19.7
$ 48.5
$ 65.2
$ 23.3
Reserve for other investments 3.0
—
—
—
3.0

⁽¹⁾ Charged to Other Accounts reflects the deferral of bad debt expense to a regulatory asset.

~~114~~

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NISOURCE INC.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Our chief executive officer and chief financial officer are responsible for evaluating the effectiveness of disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)). Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by the Company in reports that are filed or submitted under the Exchange Act are accumulated and communicated to management, including our chief executive officer and chief financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon that evaluation, our chief executive officer and chief financial officer concluded that, as of the end of the period covered by this report, disclosure controls and procedures were effective to provide reasonable assurance that financial information was processed, recorded and reported accurately.

Management’s Annual Report on Internal Control over Financial Reporting

Our management, including our chief executive officer and chief financial officer, are responsible for establishing and maintaining internal control over financial reporting, as such term is defined under Rule 13a-15(f) or Rule 15d-15(f) promulgated under the Exchange Act. However, management would note that a control system can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Our management has adopted the 2013 framework set forth in the Committee of Sponsoring Organizations of the Treadway Commission report, Internal Control - Integrated Framework, the most commonly used and understood framework for evaluating internal control over financial reporting, as its framework for evaluating the reliability and effectiveness of internal control over financial reporting. During ~~2018,~~2020, we conducted an evaluation of our internal control over financial reporting. Based on this evaluation, management concluded that our internal control over financial reporting was effective as of the end of the period covered by this annual report.

Deloitte & Touche LLP, our independent registered public accounting firm, issued an attestation report on our internal controls over financial reporting which is ~~contained in Item 8, “Financial Statements and Supplementary Data.”~~included herein.

Changes in Internal Controls

There have been no changes in our internal control over financial reporting during the most recently completed quarter covered by this report that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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ITEM 9A. CONTROLS AND PROCEDURES

NISOURCE INC.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the shareholders and the Board of Directors of NiSource Inc.

Opinion on Internal Control over Financial Reporting

We have audited the internal control over financial reporting of NiSource Inc. and subsidiaries (the “Company”) as of December 31, 2020, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control — Integrated Framework (2013) issued by COSO.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as of and for the year ended December 31, 2020, of the Company and our report dated February 17, 2021, expressed an unqualified opinion on those financial statements.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ DELOITTE & TOUCHE LLP

Columbus, Ohio

February 17, 2021

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ITEM 9B. OTHER INFORMATION

NISOURCE INC.

Not applicable.

~~115~~

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NIS~~OURCE~~ INC.

PART III

NISOURCE INC.

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE



~~Delaware~~ DE		35-2108964
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

801 East 86th Avenue ~~Merrillville, Indiana~~		~~46410~~
Merrillville,	IN	46410
(Address of principal executive offices)		(Zip Code)



	Title of ~~each class~~ Each Class	Trading Symbol(s)		Name of ~~each exchange~~Each Exchange on ~~which registered~~	Which Registered
	Common Stock, par value $0.01 per share	NI		~~New York~~NYSE
Depositary Shares, each representing a 1/1,000th ownership interest in a share of 6.50% Series B	NI PR B		NYSE
Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Stock, par value $0.01 per share, liquidation preference $25,000 per share and a 1/1,000th ownership interest in a share of Series B-1 Preferred Stock, par value $0.01 per share, liquidation preference $0.01 per share



~~Large accelerated filer~~ þ	~~Accelerated filer~~ ¨	~~Emerging growth company~~ ¨
~~Non-accelerated filer~~ ¨	~~Smaller reporting company~~ ¨



		Page No.
Defined Terms		3
Part I
Item 1.	Business	6
Item 1A.	Risk Factors	911
Item 1B.	Unresolved Staff Comments	1924
Item 2.	Properties	1924
Item 3.	Legal Proceedings	1924
Item 4.4	Mine Safety Disclosures	1924
~~Supplemental Item. Executive Officers of the Registrant~~	20
Part II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	2126
Item 6.	Selected Financial Data	2327
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	2528
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	4449
Item 8.	Financial Statements and Supplementary Data	4550
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	~~115~~118
Item 9A.	Controls and Procedures	~~115~~118
Item 9B.	Other Information	~~115~~120
Part III
Item 10.	Directors, Executive Officers and Corporate Governance	~~116~~121
Item 11.	Executive Compensation	~~116~~121
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	~~116~~121
Item 13.	Certain Relationships and Related Transactions, and Director Independence	~~116~~121
Item 14.	Principal Accounting Fees and Services	~~116~~121
Part IV
Item 15.	Exhibits, Financial Statement Schedules	~~117~~122
Item 16.	Form 10-K Summary	128
Signatures		~~122~~129


DEFINED TERMS

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

NiSource Subsidiaries, Affiliates and Former Subsidiaries
~~Capital Markets (former subsidiary)~~		~~NiSource Capital Markets, Inc.~~
~~Columbia (former subsidiary)~~	~~Columbia Energy Group~~
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.
Company			NiSource Inc. and its subsidiaries, unless otherwise indicated by the context
~~CPG (former subsidiary)~~NIPSCO			~~Columbia Pipeline Group, Inc.~~
~~NIPSCO~~	Northern Indiana Public Service Company LLC
NiSource ("we," "us" or "our")			NiSource Inc.
NiSource Corporate Services			NiSource Corporate Services Company
~~NiSource Finance (former subsidiary)~~				~~NiSource Finance Corporation~~
Abbreviations
~~Abbreviations~~ACE
~~ACE~~	Affordable clean energy
AFUDC			Allowance for funds used during construction
AMR			Automatic meter reading
~~AMRP~~AOCI			~~Accelerated Main Replacement Program~~
~~AOCI~~	Accumulated Other Comprehensive Income
ASC			Accounting Standards Codification
ASU			Accounting Standards Update
ATM			At-the-market
Board			Board of Directors
BTA			Build-transfer agreement
~~CAA~~CAP			~~Clean Air Act~~
~~CAP~~	Compliance Assurance Process
CCGT			Combined Cycle Gas Turbine
CCRs			Coal Combustion Residuals
CEP			Capital Expenditure Program
CERCLA			Comprehensive Environmental Response Compensation and Liability Act (also known as Superfund)
CO2 COVID-19 ("the COVID-19 pandemic" or "the pandemic")			~~Carbon dioxide~~Novel Coronavirus 2019
~~CPP~~DPA			~~Clean Power Plan~~Deferred prosecution agreement
DPU			Department of Public Utilities
DSIC			Distribution System Investment Charge
DSM			Demand Side Management
~~ECT~~	~~Environmental Cost Tracker~~
~~EERM~~	~~Environmental Expense Recovery Mechanism~~
~~EGUs~~	~~Electric Utility Steam Generating Units~~

~~DEFINED TERMS~~

~~ELG~~		~~Effluence limitations guidelines~~
~~EPA~~
EPA		United States Environmental Protection Agency
EPS		Earnings per share
FAC		Fuel adjustment clause
FASB		Financial Accounting Standards Board
FERC		Federal Energy Regulatory Commission
FMCA		Federally Mandated Cost Adjustment
~~FTRs~~GAAP		~~Financial Transmission Rights~~
~~GAAP~~	Generally Accepted Accounting Principles
GCA		Gas cost adjustment
~~GCR~~		~~Gas cost recovery~~
GHG		Greenhouse gas
~~GSEP~~GWh		~~Gas System Enhancement Program~~Gigawatt hours


~~GWh~~			~~Gigawatt hours~~DEFINED TERMS
~~IRIS~~HLBV		~~Infrastructure Replacement and Improvement Surcharge~~Hypothetical Liquidation at Book Value
IRP		Infrastructure Replacement Program
IRS		Internal Revenue Service
IURC		Indiana Utility Regulatory Commission
LDCs		Local distribution companies
LIBOR		London inter-bank offered rate
LIFO		Last-in, first-out
~~MGP~~MA DOR		Massachusetts Department of Revenue
Massachusetts Business		All of the assets sold to, and liabilities assumed by, Eversource pursuant to the Asset Purchase Agreement
MGP		Manufactured Gas Plant
MISO		Midcontinent Independent System Operator
~~Mizuho~~MMDth		~~Mizuho Corporate Bank Ltd.~~Million dekatherms
~~MMDth~~MW		~~Million dekatherms~~Megawatts
MWMWh		~~Megawatts~~Megawatt hours
~~MWh~~NOL		~~Megawatt hours~~
~~NOL~~	Net Operating Loss
NTSB		National Transportation Safety Board
NYMEX		The New York Mercantile Exchange
NYSE		The New York Stock Exchange
OPEB		Other Postretirement and Postemployment Benefits
PCB		Polychlorinated biphenyls
PHMSA		U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration
~~PISCC~~PPA		~~Post-in-service carrying charges~~Power Purchase Agreement
~~PPA~~PSC		~~Purchase plan agreement~~
~~PSC~~	Public Service Commission
~~PTC~~	~~Production Tax Credits~~
~~PUC~~	~~Public Utility Commission~~
~~PUCO~~	~~Public Utilities Commission of Ohio~~
~~RCRA~~	~~Resource Conservation and Recovery Act~~
~~ROU~~	~~Right of use~~
~~SAB~~	~~Staff accounting bulletin~~
~~SAVE~~	~~Steps to Advance Virginia's Energy Plan~~

~~DEFINED TERMS~~

~~Separation~~PUC		The separation of our natural gas pipeline, midstream and storage business from our natural gas and electric utility business accomplished through a pro rata distribution to holders of our outstanding common stock of all the outstanding shares of common stock of CPG. The separation was completed on July 1, 2015.Public Utility Commission
~~SEC~~PUCO		Public Utilities Commission of Ohio
RCRA		Resource Conservation and Recovery Act
ROE		Return on Equity
Rosewater		Rosewater Wind Generation LLC
ROU		Right of use

SAVE		Steps to Advance Virginia's Energy Plan
SEC		Securities and Exchange Commission
~~STRIDE~~SMRP		Safety Modification and Replacement Program
SMS		Safety Management System
STRIDE		Strategic Infrastructure Development and Enhancement
Sugar Creek		Sugar Creek electric generating plant
TCJA		Tax Cuts and Jobs Act of 2017
TDSIC		Transmission, Distribution and Storage System Improvement Charge
~~VIE~~TSA		Transition Service Agreement
U.S. Attorney's Office		U.S. Attorney's Office for the District of Massachusetts
VIE		Variable Interest Entity
VSCC		Virginia State Corporation Commission
~~WCE~~	~~Whiting Clean Energy~~


(in millions)
Company	Proposed ROE		Approved ROE		Requested Incremental Revenue		Approved Incremental Revenue		Filed	Status	Rates Effective


NIPSCO - Electric(1)	10.80	%	9.75	%	$	21.4	$	(53.5)	October 31, 2018	Approved December 4, 2019	January 2020
Columbia of Pennsylvania(2)	9.86	%	N/A		$	76.8	In process		April 24, 2020	Order Expected Q1 2021	January 2021

Columbia of Maryland	10.95	%	None specified(3)		$	5.0	$	2.0	May 15, 2020	Approved November 7, 2020	December 2020



Year Ended December 31, (dollars in millions except per share data)	2018			2017		2016		2015		2014
Statement of Income Data:
Total Operating Revenues	$	5,114.5		$	4,874.6	$	4,492.5	$	4,651.8	$	5,272.4
Net Income (Loss) Available to Common Shareholders	(65.6		)	128.5		331.5		198.6		256.2
Balance Sheet Data:
Total Assets	21,804.0			19,961.7		18,691.9		17,492.5		24,589.8
Capitalization
Stockholders’ equity	5,750.9			4,320.1		4,071.2		3,843.5		6,175.3
Long-term debt, excluding amounts due within one year	7,105.4			7,512.2		6,058.2		5,948.5		8,151.5
Total Capitalization	$	12,856.3		$	11,832.3	$	10,129.4	$	9,792.0	$	14,326.8
Per Share Data:
Basic Earnings (Loss) Per Share ($)	$	(0.18	)	$	0.39	$	1.02	$	0.63	$	0.81
Diluted Earnings (Loss) Per Share ($)	$	(0.18	)	$	0.39	$	1.01	$	0.63	$	0.81
Other Data:
Dividends declared per common share ($)	$	0.78		$	0.70	$	0.64	$	0.83	$	1.02
Common shares outstanding at the end of the year (in thousands)	372,363			337,016		323,160		319,110		316,037
Number of common stockholders	19,889			21,009		22,272		30,190		25,233
Dividends declared per Series A preferred share ($)	$	28.88		$	—	$	—	$	—	$	—
Capital expenditures	$	1,814.6		$	1,753.8	$	1,490.4	$	1,367.5	$	1,339.6
Number of employees	8,087			8,175		8,007		7,596		8,982



Index		Page
Executive Summary		2528
Summary of Consolidated Financial Results		2630
Results and Discussion of Segment Operations		2931
~~Gas Distribution Operations~~	30
~~Electric Operations~~	33
Gas Distribution Operations		32
Electric Operations		36
Liquidity and Capital Resources		3740
Off Balance Sheet Arrangements		4045
Market Risk Disclosures		4145
Other Information		4246


Year Ended December 31, (in millions, except per share amounts)	2020		2019		2018		2020 vs. 2019		2019 vs. 2018
Operating Revenues	$	4,681.7	$	5,208.9	$	5,114.5	$	(527.2)	$	94.4
Operating Expenses
Cost of energy	1,109.3		1,534.8		1,761.3		(425.5)		(226.5)
Other Operating Expenses	3,021.6		2,783.4		3,228.5		238.2		(445.1)
Total Operating Expenses	4,130.9		4,318.2		4,989.8		(187.3)		(671.6)
Operating Income	550.8		890.7		124.7		(339.9)		766.0
Total Other Deductions, Net	(582.1)		(384.1)		(355.3)		(198.0)		(28.8)
Income Taxes	(17.1)		123.5		(180.0)		(140.6)		303.5
Net Income (Loss)	(14.2)		383.1		(50.6)		(397.3)		433.7
Net income attributable to noncontrolling interest	3.4		—		—		3.4		—
Net Income (Loss) attributable to NiSource	(17.6)		383.1		(50.6)		(400.7)		433.7
Preferred dividends	(55.1)		(55.1)		(15.0)		—		(40.1)
Net Income (Loss) Available to Common Shareholders	(72.7)		328.0		(65.6)		(400.7)		393.6
Basic Earnings (Loss) Per Share	$	(0.19)	$	0.88	$	(0.18)	$	(1.07)	$	1.06
Basic Average Common Shares Outstanding	384.3		374.6		356.5		9.7		18.1



Year Ended December 31, (in millions, except per share amounts)	2018			2017			2016			2018 vs. 2017			2017 vs. 2016
Operating Revenues	$	5,114.5		$	4,874.6		$	4,492.5		$	239.9		$	382.1
Cost of sales (excluding depreciation and amortization)	1,761.3			1,518.7			1,390.2			242.6			128.5
Total Net Revenues	3,353.2			3,355.9			3,102.3			(2.7		)	253.6
Other Operating Expenses	3,228.5			2,434.7			2,236.2			793.8			198.5
Operating Income	124.7			921.2			866.1			(796.5		)	55.1
Total Other Deductions, Net	(355.3		)	(478.2		)	(352.5		)	122.9			(125.7		)
Income Taxes	(180.0		)	314.5			182.1			(494.5		)	132.4
Net Income (Loss)	(50.6		)	128.5			331.5			(179.1		)	(203.0		)
Preferred dividends	(15.0		)	—			—			(15.0		)	—
Net Income (Loss) Available to Common Shareholders	(65.6		)	128.5			331.5			(194.1		)	(203.0		)
Basic Earnings (Loss) Per Share	$	(0.18	)	$	0.39		$	1.03		$	(0.57	)	$	(0.64	)
Basic Average Common Shares Outstanding	356.5			329.4			321.8			27.1			7.6


(in millions)
Company	Program	Incremental Revenue		Incremental Capital Investment		Investment Period	Costs Covered(1)	Rates Effective


Columbia of Ohio	IRP - 2020	$	32.9	$	234.4	1/19-12/19	Replacement of (1) hazardous service lines, (2) cast iron, wrought iron, uncoated steel, and bare steel pipe, (3) natural gas risers prone to failure and installation of AMR devices.	May 2020


Columbia of Ohio	CEP - 2020	$	18.0	$	185.1	1/19-12/19	Assets not included in the IRP.	September 2020





NIPSCO - Gas	TDSIC 1	$	0.6	$	26.0	1/20-6/20	New or replacement projects undertaken for the purpose of safety, reliability, system modernization or economic development.	January 2021



NIPSCO - Gas	FMCA 5	$	4.8	$	42.3	4/20-9/20	Project costs to comply with federal mandates.	April 2021



Columbia of Pennsylvania	DSIC-Q4 2020(2)	$	0.8	$	25.0	9/20-11/20	Eligible project costs including piping, couplings, gas service lines, excess flow valves, risers, meter bars, meters, and other related capitalized cost, to improve the distribution system.	January 2021



Columbia of Virginia	SAVE - 2021	$	5.2	$	46.4	1/21-12/21	Replacement projects that (1) enhance system safety or reliability, or (2) reduce, or potentially reduce, greenhouse gas emissions.	January 2021



Columbia of Kentucky	SMRP - 2021(3)	$	5.8	$	50.0	1/21-12/21	Replacement of mains and inclusion of system safety investments.	Q2 2021




Columbia of Maryland	STRIDE - 2021	$	1.3	$	16.9	1/21-12/21	Pipeline upgrades designed to improve public safety or infrastructure reliability.	January 2021




NIPSCO - Electric	TDSIC - 7(4)	$	11.3	$	122.3	7/19-7/20	New or replacement projects undertaken for the purpose of safety, reliability, system modernization or economic development.	February 2021







NIPSCO - Electric	FMCA - 13(5)(6)	$	(1.2)	$	—	9/19-2/20	Project costs to comply with federal mandates.	August 2020


(in millions)	Total		2021		2022		2023		2024		2025		After
Long-term debt (1)	$	9,135.0	$	—	$	30.0	$	—	$	—	$	1,260.0	$	7,845.0
Interest payments on long-term debt	6,046.3		336.3		335.7		334.1		334.1		334.1		4,372.0
Finance leases(2)	264.7		32.7		32.2		28.8		20.8		16.1		134.1
Operating leases(3)	48.0		11.7		5.2		4.7		4.5		3.7		18.2
Energy commodity contracts	42.1		42.1		—		—		—		—		—
Service obligations:
Pipeline service obligations(4)	1,495.6		468.7		422.5		256.0		150.5		56.2		141.7
IT service obligations	240.3		74.9		74.0		38.1		30.5		22.8		—
Other service obligations(5)	12.6		12.6		—		—		—		—		—
Other liabilities(6)	116.9		26.0		0.8		90.1		—		—		—
Total contractual obligations	$	17,401.5	$	1,005.0	$	900.4	$	751.8	$	540.4	$	1,692.9	$	12,511.0



			þ☑			ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)



			¨☐			TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)


Year Ended December 31, (in millions)	2020			2019			2018			2020 vs. 2019		2019 vs. 2018
Operating Revenues	$	3,140.1		$	3,522.8		$	3,419.5		$	(382.7)	$	103.3
Operating Expenses
Cost of energy	794.2			1,067.6			1,259.3			(273.4)		(191.7)
Operation and maintenance	1,138.0			935.7			1,908.1			202.3		(972.4)
Depreciation and amortization	363.1			403.2			301.0			(40.1)		102.2
Impairment of intangible assets	—			209.7			—			(209.7)		209.7
Loss on sale of fixed assets and impairments, net	412.4			0.1			0.2			412.3		(0.1)
Other taxes	233.3			231.1			205.0			2.2		26.1
Total Operating Expenses	2,941.0			2,847.4			3,673.6			93.6		(826.2)
Operating Income (Loss)	$	199.1		$	675.4		$	(254.1)		$	(476.3)	$	929.5
Revenues
Residential	$	2,110.6		$	2,317.2		$	2,248.3		$	(206.6)	$	68.9
Commercial	679.7			775.1			753.7			(95.4)		21.4
Industrial	213.8			245.8			228.6			(32.0)		17.2
Off-System	41.0			77.7			92.4			(36.7)		(14.7)
Other	95.0			107.0			96.5			(12.0)		10.5
Total	$	3,140.1		$	3,522.8		$	3,419.5		$	(382.7)	$	103.3
Sales and Transportation (MMDth)
Residential	249.5			274.9			280.3			(25.4)		(5.4)
Commercial	170.5			189.6			187.6			(19.1)		2.0
Industrial	538.1			542.5			555.7			(4.4)		(13.2)
Off-System	23.3			32.9			30.0			(9.6)		2.9
Other	0.3			0.3			—			—		0.3
Total	981.7			1,040.2			1,053.6			(58.5)		(13.4)
Heating Degree Days	5,097			5,375			5,562			(278)		(187)
Normal Heating Degree Days	5,485			5,452			5,610			33		(158)
% Warmer than Normal	(7)		%	(1)		%	(2)		%
Gas Distribution Customers
Residential	2,954,478			3,221,178			3,194,662			(266,700)		26,516
Commercial	253,184			282,778			281,517			(29,594)		1,261
Industrial	4,968			5,982			5,833			(1,014)		149
Other	3			3			3			—		—
Total	3,212,633			3,509,941			3,482,015			(297,308)		27,926



Year Ended December 31, (dollars in millions)	2018			2017			2016			2018 vs. 2017			2017 vs. 2016
Net Revenues
Operating revenues	$	3,419.5		$	3,102.1		$	2,830.6		$	317.4		$	271.5
Less: Cost of sales (excluding depreciation and amortization)	1,259.3			1,005.0			895.4			254.3			109.6
Net Revenues	2,160.2			2,097.1			1,935.2			63.1			161.9
Operating Expenses
Operation and maintenance	1,908.1			1,090.8			941.5			817.3			149.3
Depreciation and amortization	301.0			269.3			252.9			31.7			16.4
Loss on sale of assets and impairments, net	0.2			2.8			—			(2.6		)	2.8
Other taxes	205.0			184.1			171.1			20.9			13.0
Total Operating Expenses	2,414.3			1,547.0			1,365.5			867.3			181.5
Operating Income (Loss)	$	(254.1	)	$	550.1		$	569.7		$	(804.2	)	$	(19.6	)
Revenues
Residential	$	2,248.3		$	2,029.4		$	1,823.4		$	218.9		$	206.0
Commercial	753.7			669.4			588.1			84.3			81.3
Industrial	228.6			217.5			194.3			11.1			23.2
Off-System	92.4			111.8			94.4			(19.4		)	17.4
Other	96.5			74.0			130.4			22.5			(56.4		)
Total	$	3,419.5		$	3,102.1		$	2,830.6		$	317.4		$	271.5
Sales and Transportation (MMDth)
Residential	280.3			247.1			248.9			33.2			(1.8		)
Commercial	187.6			169.3			165.6			18.3			3.7
Industrial	555.7			517.5			517.7			38.2			(0.2		)
Off-System	30.0			39.0			39.6			(9.0		)	(0.6		)
Other	—			0.3			(0.1		)	(0.3		)	0.4
Total	1,053.6			973.2			971.7			80.4			1.5
Heating Degree Days	5,562			4,927			5,148			635			(221		)
Normal Heating Degree Days	5,610			5,610			5,642			—			(32		)
% Warmer than Normal	(1		)%	(12		)%	(9		)%
Gas Distribution Customers
Residential	3,194,662			3,168,516			3,141,736			26,146			26,780
Commercial	281,563			280,362			279,556			1,201			806
Industrial	6,038			6,228			6,240			(190		)	(12		)
Other	3			4			—			(1		)	4
Total	3,482,266			3,455,110			3,427,532			27,156			27,578



	Impact on December 31, 2018 Projected Benefit Obligation Increase/(Decrease)
Change in Assumptions (in millions)	Pension Benefits			Other Postretirement Benefits
+50 basis points change in discount rate	$	(79.6	)	$	(23.6	)
-50 basis points change in discount rate	86.2			25.8
+50 basis points change in health care trend rates				12.5
-50 basis points change in health care trend rates				(11.0		)

	Impact on 2018 Expense Increase/(Decrease)⁽¹⁾
Change in Assumptions (in millions)	Pension Benefits			Other Postretirement Benefits
+50 basis points change in discount rate	$	(3.3	)	$	(0.7	)
-50 basis points change in discount rate	2.8			0.8
+50 basis points change in expected long-term rate of return on plan assets	(10.3		)	(1.3		)
-50 basis points change in expected long-term rate of return on plan assets	10.3			1.3
+50 basis points change in health care trend rates				0.6
-50 basis points change in health care trend rates				(0.5		)


	Impact on December 31, 2020 Projected Benefit Obligation Increase/(Decrease)
Change in Assumptions (in millions)	Pension Benefits		Other Postretirement Benefits
+50 basis points change in discount rate	$	(88.7)	$	(29.8)
-50 basis points change in discount rate	96.5		32.7



	Impact on 2020 Expense Increase/(Decrease)(1)
Change in Assumptions (in millions)	Pension Benefits		Other Postretirement Benefits
+50 basis points change in discount rate	$	(2.0)	$	(0.8)
-50 basis points change in discount rate	1.6		0.9
+50 basis points change in expected long-term rate of return on plan assets	(9.8)		(1.3)
-50 basis points change in expected long-term rate of return on plan assets	9.8		1.3


Year Ended December 31, (in millions, net of taxes)	2020		2019		2018
Net Income (Loss)	$	(14.2)	$	383.1	$	(50.6)
Other comprehensive income (loss):
Net unrealized gain (loss) on available-for-sale securities(1)	2.7		5.7		(2.6)
Net unrealized gain (loss) on cash flow hedges(2)	(70.7)		(64.2)		22.7
Unrecognized pension and OPEB benefit (costs)(3)	3.9		3.1		(4.4)
Total other comprehensive income (loss)	(64.1)		(55.4)		15.7
Total Comprehensive Income (Loss)	$	(78.3)	$	327.7	$	(34.9)


(in millions)	December 31, 2020		December 31, 2019
ASSETS
Property, Plant and Equipment
Plant	$	24,179.9	$	24,541.9
Accumulated depreciation and amortization	(7,560.4)		(7,629.7)


Net Property, Plant and Equipment(1)	16,619.5		16,912.2
Investments and Other Assets
Unconsolidated affiliates	0		1.3
Available-for-sale debt securities (amortized cost of $163.9 and $150.1, allowance for credit losses of $0.5 and $0, respectively)	170.9		154.2
Other investments	81.1		74.7
Total Investments and Other Assets	252.0		230.2
Current Assets
Cash and cash equivalents	116.5		139.3
Restricted cash	9.1		9.1
Accounts receivable	843.6		876.1

Allowance for credit losses	(52.3)		(19.2)
Accounts receivable, net	791.3		856.9
Gas inventory	191.2		250.9

Materials and supplies, at average cost	141.5		120.2
Electric production fuel, at average cost	68.4		53.6

Exchange gas receivable	34.1		48.5

Regulatory assets	135.7		225.7
Deferred property taxes	85.6		79.5

Prepayments and other	86.0		70.2
Total Current Assets(1)	1,659.4		1,853.9
Other Assets

Regulatory assets	1,794.8		2,013.9
Goodwill	1,485.9		1,485.9



Deferred charges and other	228.9		163.7
Total Other Assets	3,509.6		3,663.5
Total Assets	$	22,040.5	$	22,659.8



(in millions)	December 31, 2018			December 31, 2017
ASSETS
Property, Plant and Equipment
Utility plant	$	22,780.8		$	21,026.6
Accumulated depreciation and amortization	(7,257.9		)	(6,953.6		)
Net utility plant	15,522.9			14,073.0
Other property, at cost, less accumulated depreciation	19.6			286.5
Net Property, Plant and Equipment	15,542.5			14,359.5
Investments and Other Assets
Unconsolidated affiliates	2.1			5.5
Other investments	204.0			204.1
Total Investments and Other Assets	206.1			209.6
Current Assets
Cash and cash equivalents	112.8			29.0
Restricted cash	8.3			9.4
Accounts receivable (less reserve of $21.1 and $18.3, respectively)	1,058.5			898.9
Gas inventory	286.8			285.1
Materials and supplies, at average cost	101.0			105.9
Electric production fuel, at average cost	34.7			80.1
Exchange gas receivable	88.4			45.8
Regulatory assets	235.4			176.3
Prepayments and other	129.5			132.8
Total Current Assets	2,055.4			1,763.3
Other Assets
Regulatory assets	2,002.1			1,624.9
Goodwill	1,690.7			1,690.7
Intangible assets, net	220.7			231.7
Deferred charges and other	86.5			82.0
Total Other Assets	4,000.0			3,629.3
Total Assets	$	21,804.0		$	19,961.7


(in millions, except share amounts)	December 31, 2018			December 31, 2017			(in millions, except share amounts)	December 31, 2020		December 31, 2019
CAPITALIZATION AND LIABILITIES							CAPITALIZATION AND LIABILITIES
Capitalization							Capitalization
Stockholders’ Equity							Stockholders’ Equity
Common stock - $0.01 par value, 400,000,000 shares authorized; 372,363,656 and 337,015,806 shares outstanding, respectively	$	3.8		$	3.4
Preferred stock - $0.01 par value, 20,000,000 shares authorized; 420,000 shares outstanding	880.0			—
Common stock - $0.01 par value, 600,000,000 shares authorized; 391,760,051 and 382,135,680 shares outstanding, respectively							Common stock - $0.01 par value, 600,000,000 shares authorized; 391,760,051 and 382,135,680 shares outstanding, respectively	$	3.9	$	3.8
Preferred stock - $0.01 par value, 20,000,000 shares authorized; 440,000 shares outstanding							Preferred stock - $0.01 par value, 20,000,000 shares authorized; 440,000 shares outstanding	880.0		880.0
Treasury stock	(99.9		)	(95.9		)	Treasury stock	(99.9)		(99.9)
Additional paid-in capital	6,403.5			5,529.1			Additional paid-in capital	6,890.1		6,666.2
Retained deficit	(1,399.3		)	(1,073.1		)	Retained deficit	(1,765.2)		(1,370.8)
Accumulated other comprehensive loss	(37.2		)	(43.4		)	Accumulated other comprehensive loss	(156.7)		(92.6)
Total NiSource Stockholders' Equity							Total NiSource Stockholders' Equity	5,752.2		5,986.7
Noncontrolling interest in consolidated subsidiaries							Noncontrolling interest in consolidated subsidiaries	85.6		0
Total Stockholders’ Equity	5,750.9			4,320.1			Total Stockholders’ Equity	5,837.8		5,986.7
Long-term debt, excluding amounts due within one year	7,105.4			7,512.2			Long-term debt, excluding amounts due within one year	9,219.8		7,856.2
Total Capitalization	12,856.3			11,832.3			Total Capitalization	15,057.6		13,842.9
Current Liabilities							Current Liabilities
Current portion of long-term debt	50.0			284.3			Current portion of long-term debt	23.3		13.4
Short-term borrowings	1,977.2			1,205.7			Short-term borrowings	503.0		1,773.2
Accounts payable	883.8			625.6			Accounts payable	589.0		666.0

Customer deposits and credits	238.9			262.6			Customer deposits and credits	243.3		256.4
Taxes accrued	222.7			208.1			Taxes accrued	244.1		231.6
Interest accrued	90.7			112.3			Interest accrued	104.7		99.4
Risk management liabilities	5.0			43.2			Risk management liabilities	78.2		12.6

Exchange gas payable	85.5			59.6			Exchange gas payable	48.5		59.7

Regulatory liabilities	140.9			58.7			Regulatory liabilities	161.3		160.2
Legal and environmental	18.9			32.1

Accrued compensation and employee benefits	149.7			195.4			Accrued compensation and employee benefits	141.8		156.3
Claims accrued	114.7			12.5			Claims accrued	28.6		165.4
Other accruals	58.8			78.3			Other accruals	113.6		151.6
Total Current Liabilities	4,036.8			3,178.4			Total Current Liabilities	2,279.4		3,745.8
Other Liabilities							Other Liabilities
Risk management liabilities	46.7			28.5			Risk management liabilities	144.6		134.0
Deferred income taxes	1,330.5			1,292.9			Deferred income taxes	1,470.6		1,485.3
Deferred investment tax credits	11.2			12.4

Accrued insurance liabilities	84.4			80.1			Accrued insurance liabilities	84.8		81.5
Accrued liability for postretirement and postemployment benefits	389.1			337.1			Accrued liability for postretirement and postemployment benefits	336.1		373.2

Regulatory liabilities	2,519.1			2,736.9			Regulatory liabilities	1,904.2		2,352.0
Asset retirement obligations	352.0			268.7			Asset retirement obligations	477.1		416.9

Other noncurrent liabilities	177.9			194.4			Other noncurrent liabilities	286.1		228.2
Total Other Liabilities	4,910.9			4,951.0			Total Other Liabilities	4,703.5		5,071.1
Commitments and Contingencies (Refer to Note 18, "Other Commitments and Contingencies")	—			—
Commitments and Contingencies (Refer to Note 20, "Other Commitments and Contingencies")							Commitments and Contingencies (Refer to Note 20, "Other Commitments and Contingencies")
Total Capitalization and Liabilities	$	21,804.0		$	19,961.7		Total Capitalization and Liabilities	$	22,040.5	$	22,659.8



(in millions)	Common Stock		Treasury Stock			Additional Paid-In Capital		Retained Deficit			Accumulated Other Comprehensive Loss			Total
Balance as of January 1, 2016	$	3.2	$	(79.3	)	$	5,078.0	$	(1,123.3	)	$	(35.1	)	$	3,843.5
Comprehensive Income:
Net Income	—		—			—		331.5			—			331.5
Other comprehensive income, net of tax	—		—			—		—			10.0			10.0
Common stock dividends ($0.64 per share)	—		—			—		(205.7		)	—			(205.7		)
Treasury stock acquired	—		(9.4		)	—		—			—			(9.4		)
Cumulative effect of change in accounting principle⁽¹⁾	—		—			—		25.3			—			25.3
Stock issuances:
Common stock	0.1		—			—		—			—			0.1
Employee stock purchase plan	—		—			4.7		—			—			4.7
Long-term incentive plan	—		—			20.9		—			—			20.9
401(k) and profit sharing	—		—			41.4		—			—			41.4
Dividend reinvestment plan	—		—			8.9		—			—			8.9
Balance as of December 31, 2016	$	3.3	$	(88.7	)	$	5,153.9	$	(972.2	)	$	(25.1	)	$	4,071.2
Comprehensive Loss:
Net Income	—		—			—		128.5			—			128.5
Other comprehensive loss, net of tax	—		—			—		—			(18.3		)	(18.3		)
Common stock dividends ($0.70 per share)	—		—			—		(229.4		)	—			(229.4		)
Treasury stock acquired	—		(7.2		)	—		—			—			(7.2		)
Stock issuances:
Employee stock purchase plan	—		—			5.0		—			—			5.0
Long-term incentive plan	—		—			14.9		—			—			14.9
401(k) and profit sharing	—		—			34.3		—			—			34.3
Dividend reinvestment plan	—		—			6.4		—			—			6.4
ATM Program	0.1		—			314.6		—			—			314.7
Balance as of December 31, 2017	$	3.4	$	(95.9	)	$	5,529.1	$	(1,073.1	)	$	(43.4	)	$	4,320.1


(in millions)	Common Stock		Preferred Stock(1)		Treasury Stock		Additional Paid-In Capital		Retained Deficit		Accumulated Other Comprehensive Loss		Noncontrolling Interest in Consolidated Subsidiaries		Total
Balance as of January 1, 2018	$	3.4	$	0	$	(95.9)	$	5,529.1	$	(1,073.1)	$	(43.4)	$	0	$	4,320.1
Comprehensive Loss:
Net Loss	0		0		0		0		(50.6)		0		0		(50.6)
Other comprehensive income, net of tax	0		0		0		0		0		15.7		0		15.7

Dividends
Common stock ($0.78 per share)	0		0		0		0		(273.5)		0		0		(273.5)
Preferred stock ($28.88 per share)	0		0		0		0		(11.6)		0		0		(11.6)
Treasury stock acquired	0		0		(4.0)		0		0		0		0		(4.0)
Cumulative effect of change in accounting principle	—		—		—		—		9.5		(9.5)		—		—
Stock issuances:
Common stock - private placement	0.3		0		0		599.3		0		0		0		599.6
Preferred stock	0		880.0		0		0		0		0		0		880.0
Employee stock purchase plan	0		0		0		5.5		0		0		0		5.5
Long-term incentive plan	0		0		0		15.4		0		0		0		15.4
401(k) and profit sharing	0		0		0		21.8		0		0		0		21.8

ATM Program	0.1		0		0		232.4		0		0		0		232.5
Balance as of December 31, 2018	$	3.8	$	880.0	$	(99.9)	$	6,403.5	$	(1,399.3)	$	(37.2)	$	0	$	5,750.9
Comprehensive Income:
Net Income	0		0		0		0		383.1		0		0		383.1
Other comprehensive loss, net of tax	0		0		0		0		0		(55.4)		0		(55.4)
Dividends
Common stock ($0.80 per share)	0		0		0		0		(298.5)		0		0		(298.5)
Preferred stock (See Note 13)	0		0		0		0		(56.1)		0		0		(56.1)


Stock issuances:


Employee stock purchase plan	0		0		0		5.6		0		0		0		5.6
Long-term incentive plan	0		0		0		10.4		0		0		0		10.4
401(k) and profit sharing	0		0		0		17.6		0		0		0		17.6

ATM Program	0		0		0		229.1		0		0		0		229.1
Balance as of December 31, 2019	$	3.8	$	880.0	$	(99.9)	$	6,666.2	$	(1,370.8)	$	(92.6)	$	0	$	5,986.7
Comprehensive Loss:
Net Income (Loss)	0		0		0		0		(17.6)		0		3.4		(14.2)
Other comprehensive loss, net of tax	0		0		0		0		0		(64.1)		0		(64.1)
Dividends:
Common stock ($0.84 per share)	0		0		0		0		(321.7)		0		0		(321.7)
Preferred stock (See Note 13)	0		0		0		0		(55.1)		0		0		(55.1)


Contribution from noncontrolling interest	0		0		0		0		0		0		82.2		82.2

Stock issuances:


Employee stock purchase plan	0		0		0		5.7		0		0		0		5.7
Long-term incentive plan	0		0		0		8.4		0		0		0		8.4
401(k) and profit sharing	0		0		0		13.4		0		0		0		13.4
ATM program	0.1		0		0		196.4		0		0		0		196.5
Balance as of December 31, 2020	$	3.9	$	880.0	$	(99.9)	$	6,890.1	$	(1,765.2)	$	(156.7)	$	85.6	$	5,837.8



	Preferred	Common
(in thousands)	Shares	Shares	Treasury		Outstanding
Balance as of January 1, 2016	—	322,181	(3,071	)	319,110
Treasury stock acquired			(433	)	(433	)
Issued:
Employee stock purchase plan	—	201	—		201
Long-term incentive plan	—	2,103	—		2,103
401(k) and profit sharing plan	—	1,793	—		1,793
Dividend reinvestment plan	—	386	—		386
Balance as of December 31, 2016	—	326,664	(3,504	)	323,160
Treasury stock acquired			(293	)	(293	)
Issued:
Employee stock purchase plan	—	207	—		207
Long-term incentive plan	—	351	—		351
401(k) and profit sharing plan	—	1,396	—		1,396
Dividend reinvestment plan	—	264	—		264
ATM Program	—	11,931	—		11,931
Balance as of December 31, 2017	—	340,813	(3,797	)	337,016
Treasury stock acquired			(166	)	(166	)
Issued:
Common stock - private placement⁽¹⁾	—	24,964	—		24,964
Preferred stock⁽¹⁾	420
Employee stock purchase plan	—	223	—		223
Long-term incentive plan	—	561	—		561
401(k) and profit sharing plan	—	882	—		882
ATM program	—	8,883	—		8,883
Balance as of December 31, 2018	420	376,326	(3,963	)	372,363


1.	1. Nature of Operations and Summary of Significant Accounting Policies


	Twelve Months Ended December 31,
(in millions)	2020	2019	2018
Pretax Income (Loss)	($422.3)	$36.8	($835.6)



Standard	Description	Effective Date	Effect on the financial statements or other significant matters
ASU 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Statement	This pronouncement provides temporary optional expedients and exceptions for applying GAAP principles to contract modifications and hedging relationships to ease the financial reporting burdens of the expected market transition from LIBOR and other interbank offered rates to alternative reference rates.	Upon issuance on March 12, 2020, and will apply though December 31, 2022.	We continue to evaluate the temporary expedients and options available under this guidance, and the effects of these pronouncements on our Consolidated Financial Statements and Notes to Consolidated Financial Statements. We are currently identifying and evaluating contracts that may be impacted. As of December 31, 2020, we have not applied any expedients and options available under this ASU.
ASU 2021-01, Reference Rate Reform (Topic 848): Scope


Standard			Adoption
ASU 2019-04, Codification Improvements to Topic 326, Financial Instruments-Credit Losses, Topic 815, Derivatives and Hedging, and Topic 825, Financial Instruments			In June 2016, the FASB issued ASU 2016-13, Measurement of Credit Losses on Financial Instruments (ASC 326). ASC 326 revised the GAAP guidance on the impairment of most financial assets and certain other instruments that are not measured at fair value through net income. ASC 326 introduces the current expected credit loss (CECL) model that is based on expected losses for instruments measured at amortized cost rather than incurred losses. It also requires entities to record an allowance 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 debt securities will be recognized immediately in earnings, instead of over-time as they would under historic guidance. In 2019, the FASB issued ASU 2019-04, Codification Improvements to Topic 326, Financial Instruments-Credit Losses, Topic 815, Derivative and Hedging, and Topic 825, Financial Instruments. This pronouncement clarified and improved certain areas of guidance related to the recently issued standards on credit losses, hedging, and recognition and measurement. We adopted ASC 326 effective January 1, 2020, using a modified retrospective method. Adoption of this standard did not have material impact on our Consolidated Financial Statements. No adjustments were made to the January 1, 2020 opening balances as a result of this adoption. As required under the modified retrospective method of adoption, results for the reporting periods beginning after January 1, 2020 are presented under ASC 326, while prior period amounts are not adjusted. See Note 3, "Revenue Recognition," and Note 18, "Fair Value," for our discussion of the implementing these standards.
ASU 2016-13, Financial Instruments-Credit Losses (Topic 326)
ASU 2018-14, Compensation—Retirement Benefits—Defined Benefit Plans—General (Subtopic 715-20): Disclosure Framework—Changes to the Disclosure Requirements for Defined Benefit Plans			~~The~~Issued in August 2018, the pronouncement modifies the disclosure requirements for defined benefit pension ~~and~~or other postretirement benefit plans. The guidance removes disclosures that are no longer considered cost beneficial, clarifies the specific requirements of disclosures and adds disclosure requirements identified as relevant. The modifications affect annual period disclosures for fiscal years ending after December 15, 2020, and ~~must be~~are applied on a retrospective basis to all periods presented. These disclosure requirements are reflected in the Note 12, "Pension and Postretirement Benefits."
ASU 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes			~~Annual periods ending after December 15, 2020. Early adoption is permitted.~~	This pronouncement simplifies the accounting for income taxes by eliminating certain exceptions to the general principles in ASC 740, income taxes. It also improves consistency of application for other areas of the guidance by clarifying and amending existing guidance. We ~~are currently evaluating~~adopted the ~~effects~~amendments of this pronouncement ~~on our Notes~~as of January 1, 2021 with no material impact to the Consolidated Financial Statements. ~~We tentatively expect to adopt this ASU on its effective date.~~
~~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 also have recorded balances for trade receivables that fall within the scope of the standard. We are currently evaluating the impact of adoption, if any, on our Consolidated Financial Statements and Notes to Consolidated Financial Statements.



~~Standard~~	~~Adoption~~
~~ASU 2018-15,~~ ~~Intangibles—Goodwill and Other— Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract~~	In August 2018, the FASB issued this ASU, which amends current guidance to align the accounting for costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing costs associated with developing or obtaining internal-use software. We elected to early adopt the ASU on a prospective basis, effective October 1, 2018. As a result of adopting this ASU, we will defer onto the Consolidated Balance Sheets up-front implementation costs of cloud computing arrangements if they would have been capitalized in a similar on-premise software solution.
~~ASU 2018-02,~~ ~~Income Statement—Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income~~	We adopted this ASU effective March 31, 2018. Upon adoption, $9.5 million of tax effects that were stranded in accumulated other comprehensive income (loss) as a result of the implementation of the TCJA were reclassified to retained deficit. This change is reflected on our Statements of Consolidated Stockholders' Equity.
~~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 Consolidated Financial Statements or Notes to Consolidated Financial Statements.~~
~~ASU 2018-11, Leases (Topic 842): Targeted Improvements~~	We adopted the provisions of ASC 842 beginning on January 1, 2019, using the transition method provided in ASU 2018-11, which was applied to all existing leases at that date. As such, results for reporting periods beginning after January 1, 2019 will be presented under ASC 842, while prior period amounts will continue to be reported in accordance with ASC 840. To ease the process of implementing ASC 842, we elected a number of practical expedients, including the "practical expedient package" described in ASC 842-10-65-1 and the provisions of ASU 2018-01, which allows us to not evaluate existing land easements under ASC 842. We elected the short-term lease recognition exemption for all leases that qualify. As such, for those leases with terms less than 12 months, we will not recognize ROU assets or lease liabilities. Further, ASC 842 provides lessees the option of electing an accounting policy, by class of underlying asset, in which the lessee may choose not to separate nonlease components from lease components. We elected this practical expedient for our leases of fleet vehicles and railcars. We also elected to use a practical expedient that allows the use of hindsight in determining lease terms when evaluating leases that existed at the implementation date. We are the lessee for substantially all of our current leasing activity. Upon adopting ASC 842 we began recognizing right-of-use assets and liabilities associated with operating leases (other than short term operating leases) on our Consolidated Balance Sheets resulting in an increase in assets and liabilities of approximately $60 million. The adoption of ASC 842 did not have a material impact to our results of operations or cash flows. We have implemented key system functionality and internal controls to facilitate the preparation of financial information upon adoption. Our SEC filings will include expanded disclosures to comply with the provisions of ASC 842 beginning with our quarterly report on Form 10-Q for the first quarter of 2019.
~~ASU 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842~~
~~ASU 2016-02, Leases (Topic 842)~~



~~Standard~~	~~Adoption~~
~~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)~~



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	)



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	)



Year Ended December 31, 2018 (in millions)	Gas Distribution Operations		Electric Operations		Corporate and Other		Total
Customer Revenues⁽¹⁾
Residential	$	2,250.0	$	494.7	$	—	$	2,744.7
Commercial	751.9		492.7		—		1,244.6
Industrial	228.0		613.6		—		841.6
Off-system	92.4		—		—		92.4
Miscellaneous	49.7		17.4		0.7		67.8
Total Customer Revenues	$	3,372.0	$	1,618.4	$	0.7	$	4,991.1
Other Revenues	34.4		89.0		—		123.4
Total Operating Revenues	$	3,406.4	$	1,707.4	$	0.7	$	5,114.5


Year Ended December 31, 2019 (in millions)	Gas Distribution Operations		Electric Operations		Corporate and Other		Total
Customer Revenues(1)
Residential	$	2,309.0	$	481.6	$	0	$	2,790.6
Commercial	771.3		486.6		0		1,257.9
Industrial	245.2		607.7		0		852.9
Off-system	77.7		0		0		77.7
Miscellaneous	52.0		21.5		0.8		74.3
Total Customer Revenues	$	3,455.2	$	1,597.4	$	0.8	$	5,053.4
Other Revenues	54.5		101.0		0		155.5
Total Operating Revenues	$	3,509.7	$	1,698.4	$	0.8	$	5,208.9


Reconciliation of Unrecognized Tax Benefits (in millions)	2020		2019		2018
Unrecognized Tax Benefits - Opening Balance	$	23.2	$	1.2	$	1.4

Gross decreases - tax positions in prior period	(1.5)		(0.6)		(0.4)
Gross increases - current period tax positions	0		22.6		0.2
Unrecognized Tax Benefits - Ending Balance	$	21.7	$	23.2	$	1.2

Offset for net operating loss carryforwards	(21.7)		(22.6)		0
Balance - Less Net Operating Loss Carryforwards	$	0	$	0.6	$	1.2