Published: 2021-11-03 00:00:00 ET

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Our accompanying Condensed Consolidated Financial Statements (unaudited) reflect all normal recurring adjustments that are necessary, in the opinion of management, to present fairly the results of operations in accordance with GAAP in the United States of America. The accompanying financial statements include the accounts of us, our majority-owned subsidiaries, and VIEs of which we are the primary beneficiary after the elimination of all intercompany accounts and transactions.

The accompanying financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2020. Income for interim periods may not be indicative of results for the calendar year due to weather variations and other factors.

The Condensed Consolidated Financial Statements (unaudited) have been prepared pursuant to the rules and regulations of the SEC. Certain information and note disclosures normally included in annual financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to those rules and regulations, although we believe that the disclosures made in this Quarterly Report on Form 10-Q are adequate to make the information herein not misleading.

Recently Issued Accounting Pronouncements

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

In March 2020, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting and in January 2021, the FASB issued ASU 2021-01, Reference Rate Reform (Topic 848): Scope. These pronouncements provide 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. These pronouncements are effective upon issuance on March 12, 2020, and will apply through December 31, 2022. We have evaluated the temporary expedients and options available under this guidance and identified the financial instruments to which the expedients could be applied, if deemed necessary. As of September 30, 2021, we have not applied any expedients and options available under this ASU.

In August 2020, the FASB issued ASU 2020-06, Debt with Conversion and Other Options (Subtopic 470-20) and Derivative and Hedging - Contracts in Entity's Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity's Own Equity. This pronouncement simplifies the accounting for certain financial instruments with characteristics of liabilities and equity, including convertible instruments and contracts on an entity's own equity. Specifically, the ASU "simplifies accounting for convertible instruments by removing major separation models required under current GAAP." In addition, the ASU "removes certain settlement conditions that are required for equity contracts to qualify for it" and "simplifies the diluted earnings per share (EPS) calculations in certain areas." This pronouncement is effective for the annual period beginning after December 15, 2021, and interim periods within those fiscal years. This accounting pronouncement will impact the denominator in the calculation of diluted EPS for our Equity Units. Beginning Q1 2022, we will be required to assume share settlement of the remaining purchase contract liability balance when applying the if-converted method. Moreover, we will also be required to utilize the average share price for the period instead of the end of period price. We will adopt this ASU on its effective date.

Recently Adopted Accounting Pronouncements

In December 2019, the FASB issued ASU 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes. This pronouncement simplifies the accounting for income taxes by eliminating certain exceptions to the general principles in ASC 740, income taxes. It also improves consistency of application for other areas of the guidance by clarifying and amending existing guidance. We adopted the amendments of this pronouncement as of January 1, 2021 with no material impact to the Condensed Consolidated Financial Statements (unaudited).

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for residential, commercial and industrial customers in Ohio, Pennsylvania, Virginia, Kentucky, Maryland, and Indiana. The Electric Operations segment provides electric service in 20 counties in the northern part of Indiana.

The tables below reconcile revenue disaggregation by customer class to segment revenue, as well as to revenues reflected on the Condensed Statements of Consolidated Income (Loss) (unaudited) for the three and nine months ended September 30, 2021 and September 30, 2020:

Three Months Ended September 30, 2021 (in millions)			Gas Distribution Operations						Electric Operations						Corporate and Other(2)						Total
Customer Revenues(1)
Residential			$	304.3					$	178.7					$	—					$	483.0
Commercial			99.2						151.6						—						250.8
Industrial			41.0						125.7						—						166.7
Off-system			14.5						—						—						14.5
Miscellaneous			4.6						(1.0)						0.2						3.8
Total Customer Revenues			$	463.6					$	455.0					$	0.2					$	918.8
Other Revenues			8.7						23.9						8.0						40.6
Total Operating Revenues			$	472.3					$	478.9					$	8.2					$	959.4

(1)Customer revenue amounts exclude intersegment revenues. See Note 18, "Business Segment Information," for discussion of intersegment revenues.

(2)Other revenues related to the Transition Services Agreement entered into in connection with the sale of the Massachusetts Business.

Three Months Ended September 30, 2020 (in millions)			Gas Distribution Operations						Electric Operations						Corporate and Other						Total
Customer Revenues(1)
Residential			$	306.9					$	164.8					$	—					$	471.7
Commercial			91.8						132.3						—						224.1
Industrial			42.8						102.7						—						145.5
Off-system			6.0						—						—						6.0
Miscellaneous			6.8						7.2						0.2						14.2
Total Customer Revenues			$	454.3					$	407.0					$	0.2					$	861.5
Other Revenues			15.8						25.2						—						41.0
Total Operating Revenues			$	470.1					$	432.2					$	0.2					$	902.5

(1)Customer revenue amounts exclude intersegment revenues. See Note 18, "Business Segment Information," for discussion of intersegment revenues.

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Nine Months Ended September 30, 2021 (in millions)			Gas Distribution Operations						Electric Operations						Corporate and Other(2)						Total
Customer Revenues(1)
Residential			$	1,456.5					$	439.8					$	—					$	1,896.3
Commercial			496.0						404.4						—						900.4
Industrial			142.9						367.7						—						510.6
Off-system			46.0						—						—						46.0
Miscellaneous			19.2						4.6						0.6						24.4
Total Customer Revenues			$	2,160.6					$	1,216.5					$	0.6					$	3,377.7
Other Revenues			21.8						68.4						23.1						113.3
Total Operating Revenues			$	2,182.4					$	1,284.9					$	23.7					$	3,491.0
(1)Customer revenue amounts exclude intersegment revenues. See Note 18, "Business Segment Information," for discussion of intersegment revenues. (2)Other revenues related to the Transition Services Agreement entered into in connection with the sale of the Massachusetts Business.
Nine Months Ended September 30, 2020 (in millions)			Gas Distribution Operations						Electric Operations						Corporate and Other						Total
Customer Revenues(1)
Residential			$	1,518.1					$	411.5					$	—					$	1,929.6
Commercial			483.9						365.4						—						849.3
Industrial			165.6						301.1						—						466.7
Off-system			32.7						—						—						32.7
Miscellaneous			24.6						16.6						0.6						41.8
Total Customer Revenues			$	2,224.9					$	1,094.6					$	0.6					$	3,320.1
Other Revenues			79.5						71.1						—						150.6
Total Operating Revenues			$	2,304.4					$	1,165.7					$	0.6					$	3,470.7
(1)Customer revenue amounts exclude intersegment revenues. See Note 18, "Business Segment Information," for discussion of intersegment revenues.

Customer Accounts Receivable. Accounts receivable on our Condensed Consolidated Balance Sheets (unaudited) includes both billed and unbilled amounts, as well as certain amounts that are not related to customer revenues. Unbilled amounts of accounts receivable relate to a portion of a customer’s consumption of gas or electricity from the date of the last cycle billing through the last day of the month (balance sheet date). Factors taken into consideration when estimating unbilled revenue include historical usage, customer rates and weather. A significant portion of our operations are subject to seasonal fluctuations in sales. During the heating season, primarily from November through March, revenues and receivables from gas sales are more significant than in other months. The opening and closing balances of customer receivables for the nine months ended September 30, 2021 are presented in the table below. We had no significant contract assets or liabilities during the period. Additionally, we have not incurred any significant costs to obtain or fulfill contracts.

(in millions)			Customer Accounts Receivable, Billed (less reserve)						Customer Accounts Receivable, Unbilled (less reserve)
Balance as of December 31, 2020			$	400.0					$	327.2
Balance as of September 30, 2021			272.7						204.5

Utility revenues are billed to customers monthly on a cycle basis. We expect that substantially all customer accounts receivable will be collected following customer billing, as this revenue consists primarily of periodic, 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. It is probable that substantially all of the consideration to which we are entitled from customers will be collected upon satisfaction of performance obligations.

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Allowance for Credit Losses. To evaluate for expected credit losses, customer account receivables are pooled based on similar risk characteristics, such as customer type, geography, payment terms, and related macro-economic risks. Expected credit losses are established using a model that considers historical collections experience, current information, and reasonable and supportable forecasts. Internal and external inputs are used in our credit model including, but not limited to, energy consumption trends, revenue projections, actual charge-offs data, recoveries data, shut-offs, and final bill data. We continuously evaluate available information relevant to assessing collectability of current and future receivables. We evaluate creditworthiness of specific customers periodically or following 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 relevant amount. We also monitor other circumstances that could affect our overall expected credit losses including, but not limited to, creditworthiness of overall population in service territories, adverse conditions impacting an industry sector, and current economic conditions.

At each reporting period, we record expected credit losses to an allowance for credit losses account. When deemed to be uncollectible, customer accounts are written-off. A rollforward of our allowance for credit losses as of September 30, 2021 and December 31, 2020 are presented in the table below:

(in millions)			Gas Distribution Operations						Electric Operations						Corporate and Other						Total
Balance as of January 1, 2021			$	41.8					$	9.7					$	0.8					$	52.3
Current period provisions			7.7						(0.6)						—						7.1
Write-offs charged against allowance			(34.7)						(6.2)						—						(40.9)
Recoveries of amounts previously written off			9.4						0.4						—						9.8
Balance as of September 30, 2021			$	24.2					$	3.3					$	0.8					$	28.3

(in millions)			Gas Distribution Operations						Electric Operations						Corporate and Other						Total
Balance as of January 1, 2020			$	9.1					$	3.1					$	0.8					$	13.0
Current period provisions			45.3						9.3						—						54.6
Write-offs charged against allowance			(26.7)						(3.0)						—						(29.7)
Recoveries of amounts previously written off			14.1						0.3						—						14.4
Balance as of December 31, 2020			$	41.8					$	9.7					$	0.8					$	52.3

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 recovered in rates. At the balance sheet date, in addition to our evaluation of the allowance for credit losses discussed above, 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. We also considered the on-time bill payment promotion and robust customer marketing strategy for energy assistance programs that we have implemented. Based upon this evaluation, we have concluded that the allowance for credit losses as of September 30, 2021 adequately reflected the collection risk and net realizable value for our receivables. We have now resumed our common credit mitigation practices in all jurisdictions as all moratoriums have expired (see Note 7, "Regulatory Matters," for additional information on regulatory moratoriums and regulatory assets).

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The calculations of basic and diluted EPS are based on the weighted average number of shares of common stock and potential common stock outstanding during the period. For the purposes of determining diluted EPS, the effects of the purchase contracts included within the Equity Units were included in the calculation of potential common stock outstanding for the three and nine months ended September 30, 2021 using the if-converted method under US GAAP. This method assumes conversion at the beginning of the reporting period, or at time of issuance, if later. For the purchase contracts, the number of shares of our common stock that would be issuable at the end of each reporting period will be reflected in the denominator of our diluted EPS calculation. If the stock price falls below the initial reference price of $24.51, the number of shares of our common stock used in calculating diluted EPS will be the maximum number of shares per the contract as described in Note 5, "Equity." Conversely, if the stock price is above the initial reference price of $24.51, a variable number of shares of our common stock will be used in calculating diluted EPS. A numerator adjustment was reflected in the calculation of diluted EPS for interest expense incurred in 2021, net of tax, related to the purchase contracts.

The Series C Mandatory Convertible Preferred Stock included within the Equity Units represent contingently convertible securities as the conversion is contingent on a successful remarketing as described in Note 5, "Equity." Contingently convertible shares where conversion is not tied to a market price trigger are excluded from the calculation of diluted EPS until such time as the contingency has been resolved under the if-converted method. As of September 30, 2021, the contingency was not resolved and thus no shares were reflected in the denominator in the calculation of diluted EPS for the three and nine months ended September 30, 2021.

Diluted EPS also includes the incremental effects of the various long-term incentive compensation plans and the open ATM forward agreements during the period under the treasury stock method when the impact would be dilutive. Refer to Note 5, "Equity," for more information on our ATM forward agreements.

For the three and nine months ended September 30, 2020, we had a net loss on the Condensed Statements of Consolidated Income (Loss) (unaudited) during the period, and any potentially dilutive shares would have had an anti-dilutive impact on EPS. The following table presents the calculation of our basic and diluted EPS:

			Three Months Ended September 30,												Nine Months Ended  September 30,
(in millions, except per share amounts)			2021						2020						2021						2020
Numerator:
Net Income (Loss) Available to Common Shareholders - Basic			$	49.4					$	(186.7)					$	377.6					$	(143.4)
Dilutive effect of Equity Units			0.6						—						1.0						—
Net Income (Loss) Available to Common Shareholders - Diluted			$	50.0					$	(186.7)					$	378.6					$	(143.4)
Denominator:
Average common shares outstanding - Basic			393.2						383.8						392.9						383.5
Dilutive potential common shares:
Equity Units			35.2						—						21.3						—
Shares contingently issuable under employee stock plans			0.9						—						0.7						—
Shares restricted under employee stock plans			0.3						—						0.3						—
Forward Agreements			0.7						—						0.6						—
Average Common Shares - Diluted			430.3						383.8						415.8						383.5
Earnings per common share:
Basic			$	0.13					$	(0.49)					$	0.96					$	(0.37)
Diluted			$	0.12					$	(0.49)					$	0.91					$	(0.37)

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ATM Program and Forward Sale Agreements. On February 22, 2021, we entered into six separate equity distribution agreements pursuant to which we are able to sell up to an aggregate of $750.0 million of our common stock.

On February 23, 2021, under the ATM program, we executed a forward sale agreement, which allows us to issue a fixed number of shares at a price to be settled in the future. From February 24, 2021 to March 17, 2021, the forward purchaser under our forward sale agreement borrowed 6,672,740 shares from third parties, which the forward purchaser sold, through its affiliated agent, at a weighted average price of $22.48 per share. We may settle the forward sale agreement in shares, cash, or net shares by December 15, 2021. Had we settled all the shares under the forward sale agreement at September 30, 2021, we would have received approximately $145.0 million, based on a net price of $21.73 per share.

On June 1, 2021, under the ATM program, we executed a forward sale agreement, which allows us to issue a fixed number of shares at a price to be settled in the future. From June 1, 2021 to June 11, 2021, the forward purchaser under our forward sale agreement borrowed 5,852,475 shares from third parties, which the forward purchaser sold, through its affiliated agent, at a weighted average price of $25.63 per share. We may settle the forward sale agreement in shares, cash, or net shares by December 15, 2021. Had we settled all the shares under the forward sale agreement at September 30, 2021, we would have received approximately $146.9 million, based on a net price of $25.10 per share.

On August 9, 2021, under the ATM program, we executed a forward sale agreement, which allows us to issue a fixed number of shares at a price to be settled in the future. From August 9, 2021 to September 1, 2021, the forward purchaser under our forward sale agreement borrowed 5,941,598 shares from third parties, which the forward purchaser sold, through its affiliated agent, at a weighted average price of $25.25 per share. We may settle the forward sale agreement in shares, cash, or net shares by December 15, 2022. Had we settled all the shares under the forward sale agreement at September 30, 2021, we would have received approximately $148.4 million, based on a net price of $24.97 per share.

As of September 30, 2021, the ATM program (including the impacts of the forward sale agreements discussed above) had approximately $300.0 million of equity available for issuance. The program expires on December 31, 2023.

Preferred Stock. As of September 30, 2021, we had 20,000,000 shares of preferred stock authorized for issuance, of which 1,302,500 shares of preferred stock in the aggregate for all series were outstanding. The following table displays preferred dividends declared for the period by outstanding series of shares:

									Three Months Ended September 30,												Nine Months Ended  September 30,												September 30,						December 31,
									2021						2020						2021						2020						2021						2020
(in millions except shares and per share amounts)			Liquidation Preference Per Share			Shares			Dividends Declared Per Share																								Outstanding
5.650% Series A			$	1,000.00		400,000			28.25						28.25						56.50						56.50						$	393.9					$	393.9
6.500% Series B			$	25,000.00		20,000			406.25						406.25						1,625.00						1,625.00						$	486.1					$	486.1
Series C(1)			$	1,000.00		862,500			—						—						—						—						$	839.8					$	—

(1)The Series C Mandatory Convertible Preferred Stock initially will not bear any dividends.

In addition, 20,000 shares of Series B–1 Preferred Stock, par value $0.01 per share, were outstanding as of September 30, 2021. Holders of Series B–1 Preferred Stock are not entitled to receive dividend payments and have no conversion rights. The Series B–1 Preferred Stock is paired with the Series B Preferred Stock and may not be transferred, redeemed or repurchased except in connection with the simultaneous transfer, redemption or repurchase of the underlying Series B Preferred Stock.

As of September 30, 2021 and 2020, Series A Preferred Stock had $6.7 million of cumulative preferred dividends in arrears, or $16.63 per share, and Series B Preferred Stock had $1.4 million of cumulative preferred dividends in arrears, or $72.23 per share.

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Equity Units. On April 19, 2021, we completed the sale of 8.625 million Equity Units, initially consisting of Corporate Units, each with a stated amount of $100. The offering generated net proceeds of $835.5 million, after underwriting and issuance expenses. Each Corporate Unit consists of a forward contract to purchase shares of our common stock in the future and a 1/10th, or 10%, undivided beneficial ownership interest in one share of Series C Mandatory Convertible Preferred Stock, par value $0.01 per share, with a liquidation preference of $1,000 per share.

The purchase contract obligates holders to purchase shares of our common stock on December 1, 2023, subject to early settlement in certain situations. The purchase price paid under the purchase contract is $100 and the number of shares to be purchased will be determined under a settlement rate formula based on the volume-weighted average share price of our common stock near the settlement date, subject to a maximum settlement rate. The Series C Mandatory Convertible Preferred Stock will initially be pledged upon issuance as collateral to secure the purchase of common stock under the related purchase contracts.

We will pay quarterly contract adjustment payments at the rate of 7.75% per year on the stated amount of $100 per Equity Unit. The contract adjustment payments are payable in cash, shares of our common stock or a combination thereof, at our election. We have the right to defer the payment of contract adjustment payments until no later than the purchase contract settlement date. If we exercise our option to defer the payment of contract adjustment payments, then until the deferred contract adjustment payments have been paid, we will not declare or pay any dividends on, or make any distributions on, or redeem, purchase or acquire, or make a liquidation payment with respect to, any shares of our capital stock; make any payment of principal of, or interest or premium, if any, on, or repay, repurchase or redeem any of our debt securities that rank on parity with, or junior to, the contract adjustment payments; or make any guarantee payments under any guarantee by us of securities of any of our subsidiaries if our guarantee ranks on parity with, or junior to, the contract adjustment payments.

The Series C Mandatory Convertible Preferred Stock initially will not bear any dividends and the liquidation preference of the mandatory convertible preferred stock will not accrete. The Series C Mandatory Convertible Preferred Stock is expected to be remarketed prior to December 1, 2023. Following a successful remarketing, dividends may become payable on the Series C Mandatory Convertible Preferred Stock and/or the minimum conversion rate of the Series C Mandatory Convertible Preferred Stock may be increased. Each share of Series C Mandatory Convertible Preferred Stock, unless previously converted, will automatically convert based on a conversion rate on the mandatory conversion date, which is expected to be on or about March 1, 2024. The conversion rate will be determined based on the volume-weighted average share price of our common stock near the conversion date, subject to a minimum and maximum conversion rate. If no successful remarketing of the Series C Mandatory Convertible Preferred Stock has previously occurred, effective as of December 1, 2023, the conversion rate will be zero, no shares of our common stock will be delivered upon automatic conversion and each share of Series C Mandatory Convertible Preferred Stock will be automatically transferred to us on the mandatory conversion date without any payment of cash or shares of our common stock thereon. In the event of such a remarketing failure, any shares of Series C Mandatory Convertible Preferred Stock held as part of Corporate Units will be automatically delivered to us on December 1, 2023 in full satisfaction of the relevant holder's obligation under the related purchase contracts.

We recorded the initial present value of the purchase contract payments as a liability with a corresponding reduction to additional-paid-in-capital. The current portion of this liability is included in "Other accruals," and the noncurrent portion is included in "Other noncurrent liabilities" on the Condensed Consolidated Balance Sheets (unaudited). Purchase contract payments are recorded against this liability. Accretion of the stock purchase contract liability is recorded as interest expense. Refer to Note 4, "Earnings Per Share," for additional information regarding our application of diluted EPS to the purchase contracts and the Series C Mandatory Convertible Preferred Stock. Under the terms of the Equity Units, assuming no anti-dilution or other adjustments, the maximum number of shares of common stock we will issue under the purchase contracts is 35.2 million and maximum number of shares of common stock we will issue under the Series C Mandatory Convertible Preferred Stock is 35.2 million.

Selected information about the Equity Units is presented below:

(in millions except contract rate)			Issuance Date			Units Issued			Total Net Proceeds(1)			Purchase Contract Annual Rate			Purchase Contract Liability(2)
Equity Units			April 19, 2021			8.625			$	835.5		7.75		%	$	168.8

(1)Issuance costs of $27.0 million were recorded on a relative fair value basis as a reduction to preferred stock of $22.5 million and a reduction to the purchase contract liability of $4.5 million.

(2)Cash payments of $16.7 million and $24.5 million were made during the three and nine months ended September 30, 2021. The purchase contract liability was $145.4 million at September 30, 2021.

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In 2020, MISO approved NIPSCO's plan to retire the R.M. Schahfer Generating Station Units 14, 15, 17 and 18 in 2023. The December 2019 NIPSCO electric rate case order included approval to create a regulatory asset upon the retirement of the R.M. Schahfer Generating Station. The order allows for the recovery of, and on, the net book value of the station by the end of 2032. On March 11, 2021, NIPSCO submitted separate Attachment Y Notices for Units 14 and 15 seeking a suspension date of October 1, 2021 for both coal fired units at R.M. Schahfer Generating Station. On May 28, 2021, NIPSCO received approval from MISO to suspend and retire these two units on October 1, 2021. The remaining two units are still scheduled to be retired in 2023.

In connection with MISO's approvals of NIPSCO's planned retirement of the R.M. Schahfer Generating Station, we recorded plant retirement-related charges of zero and $4.6 million for the three and nine months ended September 30, 2020, respectively, comprised of write downs of certain capital projects that have been cancelled and materials and supplies inventory balances deemed obsolete due to the planned retirement. As a result of the accelerated retirements of Units 14 and 15, we recorded severance charges and wrote down additional obsolete inventory. These charges totaled $3.6 million and $12.2 million for the three and nine months ended September 30, 2021, respectively. These charges are presented within "Operation and maintenance" on the Condensed Statements of Consolidated Income (Loss). At retirement, the net book value of each retired unit will be reclassified from "Net Property, Plant and Equipment," to current and long-term ''Regulatory Assets.'' The total net book value of R.M. Schahfer Generating Station's four coal units and other associated plant estimated to be retired was $831.8 million at September 30, 2021. Refer to Note 19, "Subsequent Event," for additional information.

On April 28, 2021, in response to a Motion filed by certain parties in NIPSCO's quarterly FAC proceeding, the IURC created a sub-docket proceeding in order to receive additional information related to the retirements of Units 14 and 15 on October 1, 2021 and any resulting cost impacts to customers.

COVID-19 Regulatory Filings

In response to COVID-19, we received approvals or directives from the regulatory commissions in the states in which we operate. The ongoing impacts of these approvals or directives are described in the table below:

Jurisdiction			Moratorium in Place?			Regulatory Asset balance as of September 30, 2021 (in millions)			Regulatory Asset balance as of December 31, 2020 (in millions)			Deferred COVID-19 Costs
Columbia of Ohio			No			$	2.1		$	2.0		Incremental operation and maintenance expenses
NIPSCO			No			$	2.2		$	9.2		Incremental bad debt expense and the costs to implement the requirements of the COVID-19 related order
Columbia of Pennsylvania			No			$	6.5		$	5.4		Incremental bad debt expense incurred from March 13, 2020 through December 31, 2021, above levels currently in rates
Columbia of Virginia			No			$	1.4		$	—		Incremental incurred costs (including incremental bad debt expense), subject to an earnings test review
Columbia of Maryland			No			$	0.9		$	0.7		Incremental 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 received in connection with the pandemic

The Pennsylvania PUC adopted an order on March 11, 2021, and subsequently reaffirmed their stance in a June 23, 2021 order, which lifted its prior pandemic-related moratorium on service terminations for non-payments of utility bills beginning April 1, 2021. Pursuant to that order, Pennsylvania utilities are required to offer payment plans on billing arrearages, with the length of such payment plans depending on a customer's income level. Pursuant to a subsequent order, Pennsylvania utilities were no longer required to offer these extended pandemic-related payment arrangements to customers in arrears as of October 1, 2021.

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For Columbia of Virginia, the moratorium on non-residential disconnections ended on October 6, 2020, and the moratorium on residential disconnections and late payment fees ended on August 30, 2021. Legislative and regulatory requirements extending COVID-19 payment plans between 6 and 24 months remain in place.

In conjunction with the order issued by the PSC of Maryland on June 15, 2021, all termination moratoriums will be lifted the later of November 1, 2021 or 30 days after the Maryland Relief Act funds have been applied to customer accounts. Columbia of Maryland received approximately $0.8 million of assistance that were applied to customer accounts in August 2021 in accordance with the terms of the order. As such, all termination moratoriums were lifted and normal collections procedures resumed on November 1, 2021.

Unless otherwise noted above, all other pandemic-related regulatory actions have expired or been lifted.

We are exposed to certain risks relating to our ongoing business operations, namely commodity price risk and interest rate risk. We recognize that the prudent and selective use of derivatives may help to lower our cost of debt capital, manage our interest rate exposure and limit volatility in the price of natural gas.

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

(in millions)			September 30, 2021						December 31, 2020
Risk Management Assets - Current(1)
Interest rate risk programs			$	—					$	—
Commodity price risk programs			27.9						10.4
Total			$	27.9					$	10.4
Risk Management Assets - Noncurrent(2)
Interest rate risk programs			$	—					$	—
Commodity price risk programs			18.8						2.8
Total			$	18.8					$	2.8
Risk Management Liabilities - Current(3)
Interest rate risk programs			$	46.6					$	70.9
Commodity price risk programs			0.4						7.3
Total			$	47.0					$	78.2
Risk Management Liabilities - Noncurrent(4)
Interest rate risk programs			$	68.8					$	99.5
Commodity price risk programs			6.9						45.1
Total			$	75.7					$	144.6

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

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

(3)Presented in "Other accruals" on the Condensed Consolidated Balance Sheets (unaudited).

(4)Presented in "Other noncurrent liabilities" on the Condensed Consolidated Balance Sheets (unaudited).

Commodity Price Risk Management

We, along with our utility customers, are exposed to variability in cash flows associated with natural gas purchases and volatility in natural gas prices. We purchase natural gas for sale and delivery to our retail, commercial and industrial customers, and for most customers the variability in the market price of gas is passed through in their rates. Some of our utility subsidiaries offer programs to certain customers whereby variability in the market price of gas is assumed by the respective utility. The objective of our commodity price risk programs is to mitigate the gas cost variability, for us or on behalf of our customers, associated with natural gas purchases or sales by economically hedging the various gas cost components using a combination of futures, options, forwards or other derivative contracts.

NIPSCO received IURC approval to lock in a fixed price for its natural gas customers using long-term forward purchase instruments. The term of these instruments may range from five to 10 years and is limited to 20% of NIPSCO’s average annual

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GCA purchase volume. Gains and losses on these derivative contracts are deferred as regulatory liabilities or assets and are remitted to or collected from customers through NIPSCO’s quarterly GCA mechanism. These instruments are not designated as accounting hedges.

Interest Rate Risk Management

As of September 30, 2021, 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 between 2022 and 2024. These interest rate swaps are designated as cash flow hedges. The gains and losses related to these swaps are recorded to AOCI and 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 Condensed Statements of Consolidated Income (Loss) (unaudited).

There were no amounts excluded from effectiveness testing for derivatives in cash flow hedging relationships at September 30, 2021 and December 31, 2020.

Our derivative instruments measured at fair value as of September 30, 2021 and December 31, 2020 do not contain any credit-risk-related contingent features.

 

A.    Fair Value Measurements

Recurring Fair Value Measurements

The following tables present financial assets and liabilities measured and recorded at fair value on our Condensed Consolidated Balance Sheets (unaudited) on a recurring basis and their level within the fair value hierarchy as of September 30, 2021 and December 31, 2020:

Recurring Fair Value Measurements September 30, 2021 (in millions)			Quoted Prices in Active Markets for Identical Assets (Level 1)						Significant Other Observable Inputs (Level 2)						Significant Unobservable Inputs (Level 3)						Balance as of September 30, 2021
Assets
Risk management assets			$	—					$	46.7					$	—					$	46.7
Available-for-sale debt securities			—						168.9						—						168.9
Total			$	—					$	215.6					$	—					$	215.6
Liabilities
Risk management liabilities			$	—					$	122.7					$	—					$	122.7
Total			$	—					$	122.7					$	—					$	122.7

Recurring Fair Value Measurements December 31, 2020 (in millions)			Quoted Prices in Active Markets for Identical Assets (Level 1)						Significant Other Observable Inputs (Level 2)						Significant Unobservable Inputs (Level 3)						Balance as of December 31, 2020
Assets
Risk management assets			$	—					$	13.2					$	—					$	13.2
Available-for-sale debt securities			—						170.9						—						170.9
Total			$	—					$	184.1					$	—					$	184.1
Liabilities
Risk management liabilities			$	—					$	222.8					$	—					$	222.8
Total			$	—					$	222.8					$	—					$	222.8

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Risk Management Assets and Liabilities. Risk management assets and liabilities include interest rate swaps, exchange-traded NYMEX futures and NYMEX options and non-exchange-based forward purchase contracts.

Level 1- When utilized, exchange-traded derivative contracts are based on unadjusted quoted prices in active markets and are classified within Level 1. These financial assets and liabilities are secured with cash on deposit with the exchange; therefore, nonperformance risk has not been incorporated into these valuations. These financial assets and liabilities are deemed to be cleared and settled daily by NYMEX as the related cash collateral is posted with the exchange. As a result of this exchange rule, NYMEX derivatives are considered to have no fair value at the balance sheet date for financial reporting purposes, and are presented in Level 1 net of posted cash; however, the derivatives remain outstanding and are subject to future commodity price fluctuations until they are settled in accordance with their contractual terms.

Level 2- Certain non-exchange-traded derivatives are valued using broker or over-the-counter, on-line exchanges. In such cases, these non-exchange-traded derivatives are classified within Level 2. Non-exchange-based derivative instruments include swaps, forwards, and options. In certain instances, these instruments may utilize models to measure fair value. We use a similar model to value similar instruments. Valuation models utilize various inputs that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, other observable inputs for the asset or liability and market-corroborated inputs, (i.e., inputs derived principally from or corroborated by observable market data by correlation or other means). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized within Level 2.

Level 3- Certain derivatives trade in less active markets with a lower availability of pricing information and models may be utilized in the valuation. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized within Level 3.

Credit risk is considered in the fair value calculation of derivative instruments that are not exchange-traded. Credit exposures are adjusted to reflect collateral agreements which reduce exposures. As of September 30, 2021 and December 31, 2020, there were no material transfers between fair value hierarchies. Additionally, there were no changes in the method or significant assumptions used to estimate the fair value of our financial instruments.

Credit risk is considered in the fair value calculation of each of our forward-starting interest rate swaps, as described in Note 8, "Risk Management Activities." As they are based on observable data and valuations of similar instruments, the hedges are categorized within Level 2 of the fair value hierarchy. There was no exchange of premium at the initial date of the swaps, and we can settle the contracts at any time.

NIPSCO has entered into long-term forward natural gas purchase instruments to lock in a fixed price for its natural gas customers. We value these contracts using a pricing model that incorporates market-based information when available, as these instruments trade less frequently and are classified within Level 2 of the fair value hierarchy. For additional information, see Note 8, “Risk Management Activities.”

Available-for-Sale Debt Securities. Available-for-sale debt securities are investments pledged as collateral for trust accounts related to our wholly owned insurance company. We value U.S. Treasury, corporate debt and mortgage-backed securities using a matrix pricing model that incorporates market-based information. These securities trade less frequently and are classified within Level 2.

At each reporting date, we quantitatively and qualitatively assess available-for-sale debt securities for impairment. For securities in a loss position that we intend to hold, we perform an analysis to determine whether the unrealized loss is related to credit factors. The analysis focuses on a variety of factors that include, but are not limited to, downgrade on ratings of the security, defaults in the current reporting period or projected defaults in the future, the security's yield spread over treasuries, and other relevant market data. If the unrealized loss is not related to credit factors, it is included in other comprehensive income. If the unrealized loss is related to credit factors, the loss is recognized as credit loss expense in earnings during the period, with an offsetting entry to the allowance for credit losses. The amount of the credit loss recorded to the allowance account is limited by the amount at which the security's fair value is less than its amortized cost basis. If the credit losses in the allowance for credit losses are deemed uncollectible, the allowance on the uncollectible portion is charged off, with an offsetting entry to the carrying value of the security. Subsequent improvements to the estimated credit losses of available-for-sale debt securities are recognized immediately in earnings. As of September 30, 2021 and December 31, 2020, we recorded $0.2 million and $0.5 million, respectively, as an allowance for credit losses on available-for-sale debt securities as a result of

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the analysis described above. Continuous credit monitoring and portfolio credit balancing mitigates our risk of credit losses on our available-for-sale debt securities.

The amortized cost, gross unrealized gains and losses, allowance for credit losses, and fair value of available-for-sale securities at September 30, 2021 and December 31, 2020 were: 

September 30, 2021 (in millions)			Amortized Cost						Gross Unrealized Gains						Gross Unrealized Losses(1)						Allowance for Credit Losses						Fair Value
Available-for-sale debt securities
U.S. Treasury debt securities			$	45.7					$	0.2					$	(0.2)					$	—					$	45.7
Corporate/Other debt securities			118.9						5.0						(0.5)						(0.2)						123.2
Total			$	164.6					$	5.2					$	(0.7)					$	(0.2)					$	168.9
December 31, 2020 (in millions)			Amortized Cost						Gross Unrealized Gains						Gross Unrealized Losses(2)						Allowance for Credit Losses						Fair Value
Available-for-sale debt securities
U.S. Treasury debt securities			$	33.7					$	0.3					$	—					$	—					$	34.0
Corporate/Other debt securities			130.2						7.7						(0.5)						(0.5)						136.9
Total			$	163.9					$	8.0					$	(0.5)					$	(0.5)					$	170.9

(1)Fair value of U.S. Treasury debt securities and Corporate/Other debt securities in an unrealized loss position without an allowance for credit losses is $28.4 million and $25.8 million, respectively, at September 30, 2021.

(2)Fair value of U.S. Treasury debt securities and Corporate/Other debt securities in an unrealized loss position without an allowance for credit losses is zero and $13.2 million, respectively, at December 31, 2020.

Realized gains and losses on available-for-sale securities were immaterial for the three and nine months ended September 30, 2021 and 2020.

The cost of maturities sold is based upon specific identification. At September 30, 2021, approximately $12.6 million of U.S. Treasury debt securities and approximately $1.4 million of Corporate/Other debt securities have maturities of less than a year.

There are no material items in the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis as of September 30, 2021 and December 31, 2020.

Non-recurring Fair Value Measurements

We measure the fair value of certain assets, including goodwill, on a non-recurring basis, typically annually or when events or changes in circumstances indicate that the carrying amount of the assets may not be recoverable.

In March 2021, we reached an agreement with Eversource regarding the final purchase price, including net working capital adjustments to the October 9, 2020 purchase price of our Massachusetts Business. The working capital amounts were measured at fair value, less costs to sell.

B.    Other Fair Value Disclosures for Financial Instruments. The carrying amount of cash and cash equivalents, restricted cash, customer deposits and short-term borrowings is a reasonable estimate of fair value due to their liquid or short-term nature.

The following method and assumptions were used to estimate the fair value of each class of financial instruments.

Purchase Contract Liability. At April 19, 2021, we recorded the purchase contract liability at fair value using a discounted cash flow method and observable, market-corroborated inputs. This value is a reasonable estimate of fair value at September 30, 2021, and has been categorized within Level 2 of the fair value hierarchy. Refer to Note 5, ''Equity'' for additional information.

Long-term Debt. Our long-term borrowings are recorded at historical amounts. The fair value of outstanding long-term debt is estimated based on the quoted market prices for the same or similar securities. Certain premium costs associated with the early settlement of long-term debt are not taken into consideration in determining fair value. These fair value measurements are

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classified within Level 2 of the fair value hierarchy. As of September 30, 2021, there was no change in the method or significant assumptions used to estimate the fair value of long-term debt.

The carrying amount and estimated fair values of these financial instruments were as follows: 

(in millions)			Carrying Amount as of September 30, 2021						Estimated Fair Value as of September 30, 2021						Carrying Amount as of Dec. 31, 2020						Estimated Fair Value as of Dec. 31, 2020
Long-term debt (including current portion)			$	9,243.9					$	10,558.1					$	9,243.1					$	11,034.2

Our interim effective tax rates reflect the estimated annual effective tax rates for 2021 and 2020, adjusted for tax expense associated with certain discrete items. The effective tax rates for the three months ended September 30, 2021 and 2020 were 19.2% and 27.3%, respectively. The effective tax rates for the nine months ended September 30, 2021 and 2020 were 17.9% and 42.0%, respectively. These effective tax rates differ from the federal statutory tax rate of 21% primarily due to increased amortization of excess deferred federal income tax liabilities, as specified in the TCJA, tax credits, state income taxes and other permanent book-to-tax differences. These adjustments have a relative impact on the effective tax rate proportionally to pretax income or loss.

The decrease in the three month effective tax rate of 8.1% in 2021 compared to 2020 is primarily attributed to discrete items in 2020 related to the pre-tax book loss recorded for the classification as held for sale of the Massachusetts Business and loss on early extinguishment of long-term debt tax effected at statutory tax rates.

The decrease in the nine month effective tax rate of 24.1% in 2021 compared to 2020 is primarily attributed to discrete items in 2020 related to the pre-tax book loss recorded for the classification as held for sale of the Massachusetts Business and loss on early extinguishment of long-term debt tax effected at statutory tax rates.

There were no material changes recorded in 2021 to our uncertain tax positions recorded as of December 31, 2020.

We provide defined contribution plans and noncontributory defined benefit retirement plans that cover certain of our employees. Benefits under the defined benefit retirement plans reflect the employees’ compensation, years of service and age at retirement. Additionally, we provide health care and life insurance benefits for certain retired employees. The majority of employees may become eligible for these benefits if they reach retirement age while working for us. The expected cost of such benefits is accrued during the employees’ years of service. We determined that, for certain rate-regulated subsidiaries, the future recovery of postretirement benefit costs is probable, and we record regulatory assets and liabilities for amounts that would otherwise have been recorded to expense or accumulated other comprehensive loss. Current rates of rate-regulated companies include postretirement benefit costs, including amortization of the regulatory assets and liabilities that arose prior to inclusion of these costs in rates. For most plans, cash contributions are remitted to grantor trusts.

For the nine months ended September 30, 2021, we contributed $3.3 million to our pension plans and $15.0 million to our OPEB plans.

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The following table provides the components of the plans’ actuarially determined net periodic benefit cost for the three and nine months ended September 30, 2021 and 2020:

			Pension Benefits												OPEB
Three Months Ended September 30, (in millions)			2021						2020						2021						2020
Components of Net Periodic Benefit (Income) Cost(1)
Service cost			$	7.5					$	8.1					$	1.5					$	1.7
Interest cost			7.9						13.1						2.5						3.8
Expected return on assets			(25.2)						(28.3)						(3.8)						(3.6)
Amortization of prior service credit			—						0.2						(0.6)						(0.4)
Recognized actuarial loss			5.5						8.6						1.2						1.2
Settlement loss			2.9						8.0						—						—
Total Net Periodic Benefit (Income) Cost			$	(1.4)					$	9.7					$	0.8					$	2.7

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

			Pension Benefits												OPEB
Nine Months Ended September 30, (in millions)			2021						2020						2021						2020
Components of Net Periodic Benefit (Income) Cost(1)
Service cost			$	22.6					$	24.1					$	4.5					$	4.9
Interest cost			23.5						40.1						7.5						11.6
Expected return on assets			(76.3)						(85.1)						(11.4)						(10.8)
Amortization of prior service credit			—						0.6						(1.8)						(1.4)
Recognized actuarial loss			16.3						26.0						3.6						3.8
Settlement loss			9.5						8.0						—						—
Total Net Periodic Benefit (Income) Cost			$	(4.4)					$	13.7					$	2.4					$	8.1

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

During the first quarter of 2021, one of our qualified pension plans met the requirement for settlement accounting. A settlement charge of $3.3 million was recorded during the first quarter of 2021. As a result of the settlement, the pension plan was remeasured, resulting in a decrease to the net pension asset of $5.8 million, a net increase to regulatory assets of $2.1 million, and a net debit to accumulated other comprehensive loss of $0.4 million. Net periodic pension benefit cost for 2021 increased by $4.0 million as a result of the interim remeasurement.

During the second and third quarters of 2021, the requirements for settlement accounting were also met, resulting in settlement charges of $3.3 million and $2.9 million recorded for the three months ended June 30, 2021 and September 30, 2021, respectively.

The following table provides the key assumptions that were used to calculate the pension benefit obligation and the net periodic benefit cost at the interim remeasurement date for the plan that triggered settlement accounting:

			February 28, 2021
Weighted-average Assumption to Determine Benefit Obligation
Discount rate			2.57		%
Weighted-average Assumptions to Determine Net Periodic Benefit Costs for the period ended
Discount rate - service cost			2.81		%
Discount rate - interest cost			1.57		%
Expected return on assets			4.80		%

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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 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.

We control decisions that are significant to Rosewater's ongoing operations and economic results. Therefore, we have concluded that we are the primary beneficiary of Rosewater and have consolidated Rosewater.

We have applied the HLBV method of attributing income and loss to the noncontrolling interest held by the tax equity partner. HLBV accounting was applied as the allocation of Rosewater's economic results to members differs 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 period to reflect the change in our associated book value.

In March 2021, in exchange for additional respective membership interests in Rosewater, NIPSCO contributed $0.1 million in cash, and the tax equity partner contributed $7.5 million in cash, the second of two contractual cash contributions for each partner, per the equity capital contribution agreement. NIPSCO also assumed an additional obligation of $6.0 million to the developer, which comes due in 2023 and is included in "Other noncurrent liabilities" in the Condensed Consolidated Balance Sheets (unaudited). From the contributed funds, Rosewater paid $7.4 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. With asset construction now complete, NIPSCO and the tax equity partner have made total cash contributions of $0.8 million and $93.6 million, respectively, and NIPSCO has assumed an obligation to the developer of $75.7 million, totaling contributions of $170.1 million for both partners. We did not provide any financial or other support during the year that was not previously contractually required, nor do we expect to provide such support in the future.

At September 30, 2021 and December 31, 2020, $168.0 million and $156.4 million, respectively, in net assets (as detailed in the table below) related to Rosewater and the non-controlling interest attributable to the unrelated tax equity partner of $89.2 million and $85.6 million, respectively, were included in the Condensed Consolidated Balance Sheets (unaudited). Amounts allocated to the tax equity partner were $1.0 million and zero for the three months ended September 30, 2021 and 2020, respectively, and $3.4 million and zero for the nine months ended September 30, 2021 and 2020, respectively. These amounts are included in "Net loss attributable to non-controlling interest" on the Condensed Statements of Consolidated Income (Loss) (unaudited).

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Our Condensed Consolidated Balance Sheets (unaudited) included the following assets and liabilities associated with Rosewater:

(in millions)			September 30, 2021						December 31, 2020
Net Property, Plant and Equipment			$	171.6					$	175.6
Current assets			5.3						1.7
Total assets(1)			$	176.9					$	177.3
Current liabilities			$	3.1					$	15.3
Asset retirement obligations			5.7						5.5
Other noncurrent liabilities			0.1						0.1
Total liabilities			$	8.9					$	20.9

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

We generate short-term borrowings through several sources, described in further detail below.

Revolving Credit Facility. We maintain a revolving credit facility to fund ongoing working capital requirements, including the provision of liquidity support for our commercial paper program, provide for issuance of letters of credit and also for general corporate purposes. Our revolving credit facility has a program limit of $1.85 billion and is comprised of a syndicate of banks led by Barclays. We had no outstanding borrowings under this facility as of September 30, 2021 and December 31, 2020.

Commercial Paper Program. Our commercial paper program has a program limit of up to $1.5 billion with a dealer group comprised of Barclays, Citigroup, Credit Suisse and Wells Fargo. We had $380.0 million and $503.0 million of commercial paper outstanding with weighted-average interest rates of 0.17% and 0.27% as of September 30, 2021 and December 31, 2020, respectively.

Accounts Receivable Transfer Programs. Columbia of Ohio, NIPSCO and Columbia of Pennsylvania each maintain a receivables agreement whereby they may transfer their customer accounts receivables to third-party financial institutions through wholly owned and consolidated special purpose entities. The three agreements expire between May 2022 and October 2022 and may be further extended if mutually agreed to by the parties thereto.

All receivables transferred to third parties are valued at face value, which approximates fair value due to their short-term nature. The amount of the undivided percentage ownership interest in the accounts receivables transferred is determined in part by required loss reserves under the agreements.

Transfers of accounts receivable are accounted for as secured borrowings resulting in the recognition of short-term borrowings on the Condensed Consolidated Balance Sheets (unaudited). As of September 30, 2021, the maximum amount of debt that could be recognized related to our accounts receivable programs is $205.0 million.

We had no short-term borrowings related to the securitization transactions as of September 30, 2021 and December 31, 2020.

For the nine months ended September 30, 2021 and 2020, zero and $122.0 million, respectively, were recorded as cash flows used for financing activities related to the change in short-term borrowings due to securitization transactions. For the accounts receivable transfer programs, we pay used facility fees for amounts borrowed, unused commitment fees for amounts not borrowed, and upfront renewal fees. Fees associated with the securitization transactions were $0.3 million and $0.6 million for the three months ended September 30, 2021 and 2020, respectively, and $1.1 million and $2.1 million for the nine months

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ended September 30, 2021 and 2020, respectively. Columbia of Ohio, NIPSCO and Columbia of Pennsylvania remain responsible for collecting on the receivables securitized, and the receivables cannot be transferred to another party.

Items listed above are presented net in the Condensed Statements of Consolidated Cash Flows (unaudited) as their maturities are less than 90 days.

A. Guarantees and Indemnities. We and certain of our subsidiaries enter into various agreements providing financial or performance assurance to third parties on behalf of certain subsidiaries as a part of normal business. Such agreements include guarantees and stand-by letters of credit. These agreements are entered into primarily to support or enhance the creditworthiness otherwise attributed to a subsidiary on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish the subsidiaries' intended commercial purposes. As of September 30, 2021 and December 31, 2020, we had issued stand-by letters of credit of $14.1 million and $15.2 million, respectively.

We provide guarantees related to our future performance under BTAs for our renewable generation projects. At September 30, 2021, our guarantees for multiple BTAs totaled $574.4 million. In October 2021, the amount of the guarantees increased to $774.4 million in accordance with the Fairbanks BTA. The amount of each guaranty will fluctuate upon the completion of the various steps outlined in each BTA. See ''- E. Other Matters - Generation Transition,'' below for more information.

 B. Legal Proceedings. On September 13, 2018, a series of fires and explosions occurred in Lawrence, Andover and North Andover, Massachusetts related to the delivery of natural gas by Columbia of Massachusetts (the "Greater Lawrence Incident").

We have been subject to inquiries and investigations by government authorities and regulatory agencies regarding the Greater Lawrence Incident. On February 26, 2020, the Company and Columbia of Massachusetts entered into agreements with the U.S. Attorney’s Office for the District of Massachusetts to resolve the U.S. Attorney’s Office’s investigation relating to the Greater Lawrence Incident, as described below. The Company and Columbia of Massachusetts entered into an agreement with the Massachusetts Attorney General’s Office (among other parties) to resolve the Massachusetts DPU and the Massachusetts Attorney General’s Office investigations, that was approved by the Massachusetts DPU on October 7, 2020 as part of the sale of the Massachusetts Business to Eversource.

U.S. Department of Justice Investigation. On February 26, 2020, the Company and Columbia of Massachusetts entered into agreements with the U.S. Attorney’s Office to resolve the U.S. Attorney’s Office’s investigation relating to the Greater Lawrence Incident. Columbia of Massachusetts agreed to plead guilty in the United States District Court for the District of Massachusetts (the ''Court'') to violating the Natural Gas Pipeline Safety Act (the ''Plea Agreement''), and the Company entered into a Deferred Prosecution Agreement (the ''DPA'').

On March 9, 2020, Columbia of Massachusetts entered its guilty plea pursuant to the Plea Agreement. The Court sentenced Columbia of Massachusetts on June 23, 2020, in accordance with the terms of the Plea Agreement (as modified). On June 23, 2021, the Court terminated Columbia of Massachusetts' period of probation under the Plea Agreement, which marked the completion of all terms of the Plea Agreement.

Under the DPA, the U.S. Attorney’s Office agreed to defer prosecution of the Company in connection with the Greater Lawrence Incident for a three-year period (which three-year period may be extended for twelve (12) months upon the U.S. Attorney’s Office’s determination of a breach of the DPA) subject to certain obligations of the Company, including, but not limited to, the Company's agreement, as to each of the Company’s subsidiaries involved in the distribution of gas through pipeline facilities in Massachusetts, Indiana, Ohio, Pennsylvania, Maryland, Kentucky and Virginia, to implement and adhere to each of the recommendations from the NTSB stemming from the Greater Lawrence Incident. Pursuant to the DPA, if the Company complies with all of its obligations under the DPA, the U.S. Attorney’s Office will not file any criminal charges against the Company related to the Greater Lawrence Incident.

Private Actions. Various lawsuits, including several purported class action lawsuits, have been filed by various affected residents or businesses in Massachusetts state courts against the Company and/or Columbia of Massachusetts in connection with the Greater Lawrence Incident.

On July 26, 2019, the Company, Columbia of Massachusetts and NiSource Corporate Services Company, a subsidiary of the Company, entered into a term sheet with the class action plaintiffs under which they agreed to settle the class action claims in connection with the Greater Lawrence Incident. Columbia of Massachusetts agreed to pay $143 million into a settlement fund to compensate the settlement class and the settlement class agreed to release Columbia of Massachusetts and affiliates from all

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claims arising out of or related to the Greater Lawrence Incident. The following claims are not covered under the proposed settlement because they are not part of the consolidated class action: (1) physical bodily injury and wrongful death; (2) insurance subrogation, whether equitable, contractual or otherwise; and (3) claims arising out of appliances that are subject to the Massachusetts DPU orders. Emotional distress and similar claims are covered under the proposed settlement unless they are secondary to a physical bodily injury. The settlement class is defined under the term sheet as all persons and businesses in the three municipalities of Lawrence, Andover and North Andover, Massachusetts, subject to certain limited exceptions. The Court granted final approval of the settlement on March 12, 2020.

With respect to claims not included in the consolidated class action, many of the asserted wrongful death and bodily injury claims have settled, and we continue to discuss potential settlements with remaining claimants. The outcomes and impacts of such private actions are uncertain at this time.

Shareholder Derivative Lawsuit. On April 28, 2020, a shareholder derivative lawsuit was filed by the City of Detroit Police and Fire Retirement System in the United States District Court for the District of Delaware against certain of the Company’s current and former directors, alleging state-law claims for breaches of fiduciary duty with respect to the pipeline safety management systems relating to the distribution of natural gas prior to the Greater Lawrence Incident and also including federal-law claims related to our proxy statement disclosures regarding our safety systems. The remedies sought included damages for the alleged breaches of fiduciary duty, corporate governance reforms, and restitution of any unjust enrichment. The defendants filed a motion to dismiss the lawsuit, and oral argument was held on March 2, 2021. On March 9, 2021, the district court granted the defendants’ motion to dismiss. It dismissed the federal-law claims with prejudice for failure to state a claim on which relief can be granted and declined to exercise jurisdiction over the state-law claims, which were dismissed without prejudice.

Following the dismissal of the federal court action, on April 29, 2021, the same plaintiff filed a shareholder derivative lawsuit in the Delaware Court of Chancery against certain of our current and former directors. The new complaint alleged a single count for breach of fiduciary duty, and no longer alleged disclosure violations or breaches of federal securities laws. The complaint related to substantially the same matters as those alleged in the dismissed federal derivative complaint. The remedies sought included damages for the alleged breaches of fiduciary duty, corporate governance reforms, and restitution of compensation by the individual defendants. On May 19, 2021, the defendants filed a motion to dismiss the lawsuit, and on July 2, 2021, they filed their opening brief in support of the motion. On August 26, 2021, rather than respond to the defendants’ motion to dismiss and opening brief, the plaintiff filed an amended complaint. Like the original complaint in the Delaware Court of Chancery, the amended complaint alleges a single count for breach of fiduciary duty, based on substantially similar allegations, and seeks substantially similar remedies. On September 10, 2021, the defendants filed a motion to dismiss. On October 13, 2021, the defendants filed their opening brief in support of the motion. The plaintiff's opposition to the motion is due on December 3, 2021, and the defendants' reply brief is due on January 10, 2022. Because of the preliminary nature of this lawsuit, we are not able to estimate a loss or range of loss, if any, that may be incurred in connection with this matter at this time.

Other Claims and Proceedings. We are also party to certain other claims, regulatory and legal proceedings arising in the ordinary course of business in each state in which we have operations, none of which we believe to be individually material at this time.

Due to the inherent uncertainty of litigation, there can be no assurance that the outcome or resolution of any particular claim, proceeding or investigation would not have a material adverse effect on our results of operations, financial position or liquidity. Certain matters in connection with the Greater Lawrence Incident, for example, have had or may have a material impact as described above. If one or more other matters were decided against us, the effects could be material to our results of operations in the period in which we would be required to record or adjust the related liability and could also be material to our cash flows in the periods that we would be required to pay such liability.

C. Other Greater Lawrence Incident Matters. In connection with the Greater Lawrence Incident, Columbia of Massachusetts, in cooperation with the Massachusetts Governor’s office, replaced the entire affected pipeline system. We invested approximately $258 million of capital spend for the pipeline replacement; this work was completed in 2019. We maintain property insurance for gas pipelines and other applicable property. Columbia of Massachusetts has filed a proof of loss with its property insurer for the pipeline replacement. In January 2020, we filed a lawsuit against the property insurer, seeking payment of our property claim. On October 27, 2021, NiSource and the property insurer filed cross motions for summary judgment, each asking the court to determine whether there was coverage under the policy. We do not expect these motions to

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be fully briefed and ruled upon until at least the first quarter of 2022. We are currently unable to predict the timing or amount of any insurance recovery under the property policy.

D. Environmental Matters. Our operations are subject to environmental statutes and regulations related to air quality, water quality, hazardous waste and solid waste. We believe that we are in substantial compliance with the environmental regulations currently applicable to our operations.

It is management's continued intent to address environmental issues in cooperation with regulatory authorities in such a manner as to achieve mutually acceptable compliance plans. However, there can be no assurance that fines and penalties will not be incurred. Management expects a majority of environmental assessment and remediation costs to be recoverable through rates for certain of our companies.

As of September 30, 2021 and December 31, 2020, we had recorded a liability of $92.3 million and $92.6 million, respectively, to cover environmental remediation at various sites. This liability is included in "Other accruals" and "Other noncurrent liabilities" in the Condensed Consolidated Balance Sheets (unaudited). We recognize costs associated with environmental remediation obligations when the incurrence of such costs is probable and the amounts can be reasonably estimated. The original estimates for remediation activities may differ materially from the amount ultimately expended. The actual future expenditures depend on many factors, including laws and regulations, the nature and extent of impact and the method of remediation. These expenditures are not currently estimable at some sites. We periodically adjust our liability as information is collected and estimates become more refined.

CERCLA. Our subsidiaries are potentially responsible parties at waste disposal sites under the CERCLA and similar state laws. Under CERCLA, each potentially responsible party can be held jointly, severally and strictly liable for the remediation costs as the EPA, or state, can allow the parties to pay for remedial action or perform remedial action themselves and request reimbursement from the potentially responsible parties. Our affiliates have retained CERCLA environmental liabilities, including remediation liabilities, associated with certain current and former operations. At this time, NIPSCO cannot estimate the full cost of remediating properties that have not yet been investigated, but it is possible that the future costs could be material to the Condensed Consolidated Financial Statements (unaudited).

MGP. We maintain a program to identify and investigate former MGP sites where Gas Distribution Operations subsidiaries or predecessors may have liability. The program has identified 54 such sites where liability is probable. Remedial actions at many of these sites are being overseen by state or federal environmental agencies through consent agreements or voluntary remediation agreements.

We utilize a probabilistic model to estimate our future remediation costs related to MGP sites. The model was prepared with the assistance of a third party and incorporates our experience and general industry experience with remediating MGP sites. We complete an annual refresh of the model in the second quarter of each fiscal year. No material changes to the estimated future remediation costs were noted as a result of the refresh completed as of June 30, 2021. Our total estimated liability related to the facilities subject to remediation was $86.3 million and $85.0 million at September 30, 2021 and December 31, 2020, respectively. The liability represents our best estimate of the probable cost to remediate the MGP sites. We believe that it is reasonably possible that remediation costs could vary by as much as $17 million in addition to the costs noted above. Remediation costs are estimated based on the best available information, applicable remediation standards at the balance sheet date and experience with similar facilities.

CCRs. We are in compliance with the EPA's final rule for the regulation of CCRs. The CCR rule also resulted in revisions to previously recorded legal obligations associated with the retirement of certain NIPSCO facilities. The actual asset retirement costs related to the CCR rule may vary substantially from the estimates used to record the increased asset retirement obligation due to the uncertainty about the requirements that will be established by environmental authorities, compliance strategies that will be used and the preliminary nature of available data used to estimate costs. As allowed by the rule, NIPSCO will continue to collect data over time to determine the specific compliance solutions and associated costs and, as a result, the actual costs may vary. NIPSCO will also continue to work with the EPA and the Indiana Department of Environmental Management to obtain administrative approvals associated with the CCR rule. In the event that the approvals are not obtained, future operations could be impacted. We believe the possibility of such an outcome is remote.

E. Other Matters.

Generation Transition. NIPSCO has executed several PPAs to purchase 100% of the output from renewable generation facilities at a fixed price per MWh. Each facility supplying the energy will have an associated nameplate capacity, and

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payments under the PPAs will not begin until the associated generation facility is constructed by the owner/seller. NIPSCO has also executed several BTAs with developers to construct renewable generation facilities. NIPSCO's purchase obligation under each respective BTA is dependent on satisfactory approval of the BTA by the IURC, successful execution by NIPSCO of an agreement with a tax equity partner and timely completion of construction. NIPSCO has received IURC approval for all of its BTAs and PPAs. NIPSCO and the tax equity partner are obligated to make cash contributions to the joint venture that acquires the project at the date construction is substantially complete. Once the tax equity partner has earned its 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 joint venture.

Employee Separation Benefits. In the third quarter of 2020, we launched a program to evaluate our organizational structure under the auspices of NiSource Next, which has continued into 2021. We recognized the majority of the related severance expense in 2020 when employees accepted severance offers, absent a retention period. For employees that had a retention period, expense was recognized over the remaining service period. The total severance expense for employees is approximately $42 million, with substantially all of it incurred and paid to date.

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The following tables display the components of Accumulated Other Comprehensive Loss:

(in millions)			Gains and Losses on Securities(1)						Gains and Losses on Cash Flow Hedges(1)						Pension and OPEB Items(1)						Accumulated Other Comprehensive Loss(1)
Balance as of July 1, 2021			$	4.4					$	(113.1)					$	(14.9)					$	(123.6)
Other comprehensive income (loss) before reclassifications			(0.6)						6.5						—						5.9
Amounts reclassified from accumulated other comprehensive loss			(0.2)						0.1						0.4						0.3
Net current-period other comprehensive income (loss)			(0.8)						6.6						0.4						6.2
Balance as of September 30, 2021			$	3.6					$	(106.5)					$	(14.5)					$	(117.4)
(1)All amounts are net of tax. Amounts in parentheses indicate debits.
(in millions)			Gains and Losses on Securities(1)						Gains and Losses on Cash Flow Hedges(1)						Pension and OPEB Items(1)						Accumulated Other Comprehensive Loss(1)
Balance as of January 1, 2021			$	6.0					$	(147.9)					$	(14.8)					$	(156.7)
Other comprehensive income (loss) before reclassifications			(2.0)						41.3						(1.3)						38.0
Amounts reclassified from accumulated other comprehensive loss			(0.4)						0.1						1.6						1.3
Net current-period other comprehensive income (loss)			(2.4)						41.4						0.3						39.3
Balance as of September 30, 2021			$	3.6					$	(106.5)					$	(14.5)					$	(117.4)

(1)All amounts are net of tax. Amounts in parentheses indicate debits.

(in millions)			Gains and Losses on Securities(1)						Gains and Losses on Cash Flow Hedges(1)						Pension and OPEB Items(1)						Accumulated Other Comprehensive Loss(1)
Balance as of July 1, 2020			$	3.6					$	(207.8)					$	(17.7)					$	(221.9)
Other comprehensive income before reclassifications			1.2						26.0						1.0						28.2
Amounts reclassified from accumulated other comprehensive loss			0.2						—						(0.1)						0.1
Net current-period other comprehensive income			1.4						26.0						0.9						28.3
Balance as of September 30, 2020			$	5.0					$	(181.8)					$	(16.8)					$	(193.6)
(1)All amounts are net of tax. Amounts in parentheses indicate debits.
(in millions)			Gains and Losses on Securities(1)						Gains and Losses on Cash Flow Hedges(1)						Pension and OPEB Items(1)						Accumulated Other Comprehensive Loss(1)
Balance as of January 1, 2020			$	3.3					$	(77.2)					$	(18.7)					$	(92.6)
Other comprehensive income (loss) before reclassifications			2.0						(104.6)						1.4						(101.2)
Amounts reclassified from accumulated other comprehensive loss			(0.3)						—						0.5						0.2
Net current-period other comprehensive income (loss)			1.7						(104.6)						1.9						(101.0)
Balance as of September 30, 2020			$	5.0					$	(181.8)					$	(16.8)					$	(193.6)

(1)All amounts are net of tax. Amounts in parentheses indicate debits.

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The following table displays the components of Other, Net included on the Condensed Statements of Consolidated Income (Loss) (unaudited):

			Three Months Ended September 30,												Nine Months Ended  September 30,
(in millions)			2021						2020						2021						2020
Interest income			$	1.1					$	1.3					$	2.7					$	4.4
AFUDC equity			3.5						1.8						8.4						4.9
Pension and other postretirement non-service benefit			9.3						0.6						26.4						6.4
Sale of emission reduction credits			—						4.6						—						4.6
Miscellaneous			0.4						(0.3)						(0.3)						(0.4)
Total Other, net			$	14.3					$	8.0					$	37.2					$	19.9

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The following table provides information about our business segments. We use operating income as our primary measurement for each of the reported segments and make decisions on finance, dividends and taxes at the corporate level on a consolidated basis. Segment revenues include intersegment sales to affiliated subsidiaries, which are eliminated in consolidation. Affiliated sales are recognized on the basis of prevailing market, regulated prices or at levels provided for under contractual agreements. Operating income is derived from revenues and expenses directly associated with each segment.

			Three Months Ended September 30,												Nine Months Ended  September 30,
(in millions)			2021						2020						2021						2020
Operating Revenues
Gas Distribution Operations
Unaffiliated			$	472.3					$	470.1					$	2,182.4					$	2,304.4
Intersegment			3.0						3.0						9.1						9.0
Total			475.3						473.1						2,191.5						2,313.4
Electric Operations
Unaffiliated			478.9						432.2						1,284.9						1,165.7
Intersegment			0.2						0.1						0.6						0.5
Total			479.1						432.3						1,285.5						1,166.2
Corporate and Other
Unaffiliated			8.2						0.2						23.7						0.6
Intersegment			108.6						120.5						329.9						327.9
Total			116.8						120.7						353.6						328.5
Eliminations			(111.8)						(123.6)						(339.6)						(337.4)
Consolidated Operating Revenues			$	959.4					$	902.5					$	3,491.0					$	3,470.7
Operating Income (Loss)
Gas Distribution Operations			$	11.0					$	(42.2)					$	419.1					$	38.0
Electric Operations			140.4						130.0						307.9						295.4
Corporate and Other			(4.3)						5.0						(4.5)						(0.7)
Consolidated Operating Income			$	147.1					$	92.8					$	722.5					$	332.7

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