Published: 2022-02-23 00:00:00 ET

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A.       Company Structure and Principles of Consolidation. We are an energy holding company incorporated in Delaware and headquartered in Merrillville, Indiana. Our subsidiaries are fully regulated natural gas and electric utility companies serving approximately 3.7 million customers in six states. We generate substantially all of our operating income through these rate-regulated businesses. The consolidated 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.

B.       Use of Estimates. The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

C.       Cash, Cash Equivalents and Restricted Cash. We consider all highly liquid investments with original maturities of three months or less to be cash equivalents. We report amounts deposited in brokerage accounts for margin requirements as restricted cash. In addition, we have amounts deposited in trusts to satisfy requirements for the provision of various property, liability, workers compensation, and long-term disability insurance, which is classified as restricted cash on the Consolidated Balance Sheets and disclosed with cash and cash equivalents on the Statements of Consolidated Cash Flows.

D. Accounts Receivable and Unbilled Revenue. Accounts receivable on the Consolidated Balance Sheets includes both billed and unbilled amounts. Unbilled amounts of accounts receivable relate to a portion of a customer’s consumption of gas or electricity from the last cycle billing date through the last day of the month (balance sheet date). Factors taken into consideration when estimating unbilled revenue include historical usage, customer rates, weather and reasonable and supportable forecasts. Accounts receivable fluctuates from year to year depending in large part on weather impacts and price volatility. Our accounts receivable on the Consolidated Balance Sheets include unbilled revenue, less reserves. The reserve for uncollectible receivables is our best estimate of the amount of probable credit losses in the existing accounts receivable. We determined the reserve based on historical experience and in consideration of current market conditions. Account balances are charged against the allowance when it is anticipated the receivable will not be recovered. Refer to Note 3, "Revenue Recognition," for additional information on customer-related accounts receivable, including amounts related to unbilled revenues.

E.        Investments in Debt Securities. Our investments in debt securities are carried at fair value and are designated as available-for-sale. These investments are included within “Available-for-sale debt securities” on the Consolidated Balance Sheets. Unrealized gains and losses, net of deferred income taxes, are recorded to accumulated other comprehensive income or loss. At each reporting period these investments are qualitatively and quantitatively assessed to determine whether a decline in fair value below the amortized cost basis has resulted from a credit loss or other factors. Impairments related to credit loss are recorded through an allowance for credit losses. Impairments that are not related to credit losses are included in other comprehensive income and are reflected in the Statements of Consolidated Income (Loss). No material impairment charges were recorded for the years ended December 31, 2021, 2020 or 2019. Refer to Note 18, "Fair Value," for additional information.

F.        Basis of Accounting for Rate-Regulated Subsidiaries. Rate-regulated subsidiaries account for and report assets and liabilities consistent with the economic effect of the way in which regulators establish rates, if the rates established are designed to recover the costs of providing the regulated service and it is probable that such rates can be charged and collected. Certain expenses and credits subject to utility regulation or rate determination normally reflected in income are deferred on the Consolidated Balance Sheets and are later recognized in income as the related amounts are included in customer rates and recovered from or refunded to customers.

We continually evaluate whether or not our operations are within the scope of ASC 980 and rate regulations. As part of that analysis, we evaluate probability of recovery for our regulatory assets. In management’s opinion, our regulated subsidiaries will be subject to regulatory accounting for the foreseeable future. Refer to Note 9, "Regulatory Matters," for additional information.

G.       Plant and Other Property and Related Depreciation and Maintenance. Property, plant and equipment (principally utility plant) is stated at cost. Our rate-regulated subsidiaries record depreciation using composite rates on a straight-line basis over the remaining service lives of the electric, gas and common properties, as approved by the appropriate regulators.

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Non-utility property includes renewable generation assets owned by joint ventures of which we are the primary beneficiary and is generally depreciated on a straight-line basis over the life of the associated assets. Refer to Note 6, "Property, Plant and Equipment," for additional information related to depreciation expense.

For rate-regulated companies, AFUDC is capitalized on all classes of property except organization costs, land, autos, office equipment, tools and other general property purchases. The allowance is applied to construction costs for that period of time between the date of the expenditure and the date on which such project is placed in service. Our pre-tax rate for AFUDC was 3.3% in 2021, 2.6% in 2020 and 3.0% in 2019.

Generally, our subsidiaries follow the practice of charging maintenance and repairs, including the cost of removal of minor items of property, to expense as incurred. When our subsidiaries retire regulated property, plant and equipment, original cost plus the cost of retirement, less salvage value, is charged to accumulated depreciation. However, when it becomes probable a regulated asset will be retired substantially in advance of its original expected useful life or is abandoned, the cost of the asset and the corresponding accumulated depreciation is recognized as a separate asset. If the asset is still in operation, the gross amounts are classified as "Non-Utility and Other " as described in Note 6, "Property, Plant and Equipment." If the asset is no longer operating but still subject to recovery, the net amount is classified in "Regulatory assets" on the Consolidated Balance Sheets. If we are able to recover a full return of and on investment, the carrying value of the asset is based on historical cost. If we are not able to recover a full return on investment, a loss on impairment is recognized to the extent the net book value of the asset exceeds the present value of future revenues discounted at the incremental borrowing rate.

When our subsidiaries sell entire regulated operating units, or retire or sell nonregulated properties, the original cost and accumulated depreciation and amortization balances are removed from "Net Property, Plant and Equipment" on the Consolidated Balance Sheets. Any gain or loss is recorded in earnings, unless otherwise required by the applicable regulatory body. Refer to Note 6, "Property, Plant and Equipment," for further information.

External and internal costs associated with on-premise computer software developed for internal use are capitalized. Capitalization of such costs commences upon the completion of the preliminary stage of each project. Once the installed software is ready for its intended use, such capitalized costs are amortized on a straight-line basis generally over a period of five years. External and internal up-front implementation costs associated with cloud computing arrangements that are service contracts are deferred on the Consolidated Balance Sheets. Once the installed software is ready for its intended use, such deferred costs are amortized on a straight-line basis to "Operation and maintenance," over the minimum term of the contract plus contractually-provided renewal periods that are reasonable expected to be exercised.

H.        Goodwill and Other Intangible Assets. Substantially all of our goodwill relates to the excess of cost over the fair value of the net assets acquired in the Columbia acquisition on November 1, 2000. We test our goodwill for impairment annually as of May 1, or more frequently if events and circumstances indicate that goodwill might be impaired. Fair value of our reporting units is determined using a combination of income and market approaches. See Note 7, "Goodwill and Other Intangible Assets," for additional information.

I.         Accounts Receivable Transfer Program. Certain of our subsidiaries have agreements with third parties to transfer certain accounts receivable without recourse. These transfers of accounts receivable are accounted for as secured borrowings. The entire gross receivables balance remains on the December 31, 2021 and 2020 Consolidated Balance Sheets. When amounts are securitized, the short-term debt is recorded in the amount of proceeds received from the transferees involved in the transactions. Refer to Note 16, "Short Term Borrowings," for further information.

J.        Gas Cost and Fuel Adjustment Clause. Our regulated subsidiaries defer most differences between gas and fuel purchase costs and the recovery of such costs in revenues and adjust future billings for such deferrals on a basis consistent with applicable state-approved tariff provisions. These deferred balances are recorded as "Regulatory assets" or "Regulatory liabilities," as appropriate, on the Consolidated Balance Sheets. Refer to Note 9, "Regulatory Matters," for additional information.

K.        Inventory. Both the LIFO inventory methodology and the weighted average cost methodology are used to value natural gas in storage, as approved by regulators for all of our regulated subsidiaries. Inventory valued using LIFO was $44.9 million and $42.3 million at December 31, 2021 and 2020, respectively. Based on the average cost of gas using the LIFO method, the estimated replacement cost of gas in storage was less than the stated LIFO cost by $13.6 million and $19.6 million at December 31, 2021 and 2020, respectively. As all LIFO inventory costs are collected from customers through our rate-

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regulated subsidiaries, no inventory impairment has been recorded. Gas inventory valued using the weighted average cost methodology was $282.4 million at December 31, 2021 and $148.8 million at December 31, 2020.

Electric production fuel is valued using the weighted average cost inventory methodology, as approved by NIPSCO's regulator.

Materials and supplies are valued using the weighted average cost inventory methodology.

L.        Accounting for Exchange and Balancing Arrangements of Natural Gas. Our Gas Distribution Operations segment enters into balancing and exchange arrangements of natural gas as part of its operations and off-system sales programs. We record a receivable or payable for any of our respective cumulative gas imbalances, as well as for any gas inventory borrowed or lent under a Gas Distribution Operations exchange agreement. Exchange gas is valued based on individual regulatory jurisdiction requirements (for example, historical spot rate, spot at the beginning of the month). These receivables and payables are recorded as “Exchange gas receivable” or “Exchange gas payable” on our Consolidated Balance Sheets, as appropriate.

M.         Accounting for Risk Management Activities. We account for our derivatives and hedging activities in accordance with ASC 815. We recognize all derivatives as either assets or liabilities on the Consolidated Balance Sheets at fair value, unless such contracts are exempted as a normal purchase normal sale under the provisions of the standard. The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and resulting designation.

We do not offset the fair value amounts recognized for any of our derivative instruments against the fair value amounts recognized for the right to reclaim cash collateral or obligation to return cash collateral for derivative instruments executed with the same counterparty under a master netting arrangement. See Note 10, "Risk Management Activities," for additional information.

N.        Income Taxes and Investment Tax Credits. We record income taxes to recognize full interperiod tax allocations. Under the asset and liability method, deferred income taxes are provided for the tax consequences of temporary differences by applying enacted statutory tax rates applicable to future years to differences between the financial statement carrying amount and the tax basis of existing assets and liabilities. Investment tax credits associated with regulated operations are deferred and amortized as a reduction to income tax expense over the estimated useful lives of the related properties.

To the extent certain deferred income taxes of the regulated companies are recoverable or payable through future rates, regulatory assets and liabilities have been established. Regulatory assets for income taxes are primarily attributable to property-related tax timing differences for which deferred taxes had not been provided in the past, when regulators did not recognize such taxes as costs in the rate-making process. Regulatory liabilities for income taxes are primarily attributable to the regulated companies’ obligation to refund to ratepayers deferred income taxes provided at rates higher than the current Federal income tax rate. Such property-related amounts are credited to ratepayers using either the average rate assumption method or the reverse South Georgia method. Non property-related amounts are credited to ratepayers consistent with state utility commission direction.

Pursuant to the Internal Revenue Code and relevant state taxing authorities, we and our subsidiaries file consolidated income tax returns for federal and certain state jurisdictions. We and our subsidiaries are parties to a tax sharing agreement. Income taxes recorded by each party represent amounts that would be owed had the party been separately subject to tax.

O.       Pension Remeasurement. We utilize a third-party actuary for the purpose of performing actuarial valuations of our defined benefit plans. Annually, as of December 31, we perform a remeasurement for our pension plans. Quarterly, we monitor for significant events, and if a significant event is identified, we perform a qualitative and quantitative assessment to determine if the resulting remeasurement would materially impact the NiSource financial statements. If material, an interim remeasurement is performed. We had one such interim remeasurement in the first quarter of 2021. See Note 12, "Pension and Other Postretirement Benefits," for additional information.

P. Environmental Expenditures. We accrue for costs associated with environmental remediation obligations, including expenditures related to asset retirement obligations and cost of removal, when the incurrence of such costs is probable and the amounts can be reasonably estimated, regardless of when the expenditures are actually made. The undiscounted estimated future expenditures are based on currently enacted laws and regulations, existing technology and estimated site-specific costs where assumptions may be made about the nature and extent of site contamination, the extent of cleanup efforts, costs of alternative cleanup methods and other variables. The liability is adjusted as further information is discovered or circumstances change. The accruals for estimated environmental expenditures are recorded on the Consolidated Balance Sheets in “Other accruals” for short-term portions of these liabilities and “Other noncurrent liabilities” for the respective long-term portions of

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these liabilities. Rate-regulated subsidiaries applying regulatory accounting establish regulatory assets on the Consolidated Balance Sheets to the extent that future recovery of environmental remediation costs is probable through the regulatory process. Refer to Note 8, "Asset Retirement Obligations," and Note 19, "Other Commitments and Contingencies," for further information.

Q.        Excise Taxes. As an agent for some state and local governments, we invoice and collect certain excise taxes levied by state and local governments on customers and record these amounts as liabilities payable to the applicable taxing jurisdiction. Such balances are presented within "Other accruals" on the Consolidated Balance Sheets. These types of taxes collected from customers, comprised largely of sales taxes, are presented on a net basis affecting neither revenues nor cost of sales. We account for excise taxes for which we are liable by recording a liability for the expected tax with a corresponding charge to “Other taxes” expense on the Statements of Consolidated Income (Loss).

R.        Accrued Insurance Liabilities. We accrue for insurance costs related to workers compensation, automobile, property, general and employment practices liabilities based on the most probable value of each claim. In general, claim values are determined by professional, licensed loss adjusters who consider the facts of the claim, anticipated indemnification and legal expenses, and respective state rules. Claims are reviewed by us at least quarterly and an adjustment is made to the accrual based on the most current information.

S.        VIEs and Allocation of Earnings. We fund a significant portion of our renewable generation assets through joint ventures with tax equity partners. We consolidate these joint ventures in accordance with ASC 810 as they are VIEs in which we hold a variable interest, and we control decisions that are significant to the joint ventures' ongoing operations and economic results (i.e., we are the primary beneficiary).

These joint ventures are subject to profit sharing arrangements in which the allocation of the joint ventures' cash distributions and tax benefits to members is based on factors other than members' relative ownership percentages. As such, we utilize the HLBV method to allocate proceeds to each partner at the balance sheet date based on the liquidation provisions of the related joint venture's operating agreement and adjusts the amount of the VIE's net income attributable to us and the noncontrolling tax equity member during the period.

In each reporting period, the application of HLBV to our consolidated VIEs results in a difference between the amount of profit from the consolidated joint ventures and the amount included in regulated rates. As discussed above in "F. Basis of Accounting for Rate-Regulated Subsidiaries," we are subject to the accounting and reporting requirements of ASC 980. In accordance with these principles, we recognize a regulatory liability or asset for amounts representing the timing difference between the profit earned from the joint ventures and the amount included in regulated rates to recover our approved investments in consolidated joint ventures. The amounts recorded in income will ultimately reflect the amount allowed in regulated rates to recover our investments over the useful life of the projects. The offset to the regulatory liability or asset associated with our renewable investments included in regulated rates is recorded in "Depreciation expense" on the Statements of Consolidated Income (Loss).

Recently Issued Accounting Pronouncements

We are currently evaluating the impact of certain ASUs on our Consolidated Financial Statements and Notes to Consolidated Financial Statements, 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 December 31, 2021, we have not applied any expedients and options available under these ASUs.

In November 2021, the FASB issued ASU 2021-10, Government Assistance (Topic 832): Disclosures by Business Entities about Government Assistance. This pronouncement requires business entities to provide certain disclosures when they have received government assistance and use a grant or contribution accounting model by analogy to other accounting guidance. This

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pronouncement is applicable for financial statements issued for annual periods beginning after December 15, 2021. We are currently evaluating the impact of adoption, if any, on the Notes to Consolidated Financial Statements.

Recently Adopted Accounting Pronouncements

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." Finally, this ASU "eliminates the cash conversion and beneficial conversion feature models that require an issuer of certain convertible debt and preferred stock to separately account for embedded conversion features as a component of equity." 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 payment 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 have adopted this ASU on its effective date.

Customer Revenues. Substantially all of our revenues are tariff-based. Under ASC 606, the recipients of our utility service meet the definition of a customer, while the operating company tariffs represent an agreement that meets the definition of a contract, which creates enforceable rights and obligations. Customers in certain of our jurisdictions participate in programs that allow for a fixed payment each month regardless of usage. Payments received that exceed the value of gas or electricity actually delivered are recorded as a liability and presented in "Customer Deposits and Credits" on the Consolidated Balance Sheets. Amounts in this account are reduced and revenue is recorded when customer usage exceeds payments received.

We have identified our performance obligations created under tariff-based sales as 1) the commodity (natural gas or electricity, which includes generation and capacity) and 2) delivery. These commodities are sold and / or delivered to and generally consumed by customers simultaneously, leading to satisfaction of our performance obligations over time as gas or electricity is delivered to customers. Due to the at-will nature of utility customers, performance obligations are limited to the services requested and received to date. Once complete, we generally maintain no additional performance obligations.

Transaction prices for each performance obligation are generally prescribed by each operating company’s respective tariff. Rates include provisions to adjust billings for fluctuations in fuel and purchased power costs and cost of natural gas. Revenues are adjusted for differences between actual costs, subject to reconciliation, and the amounts billed in current rates. Under or over recovered revenues related to these cost recovery mechanisms are included in "Regulatory Assets" or "Regulatory Liabilities" on the Consolidated Balance Sheets and are recovered from or returned to customers through adjustments to tariff rates. As we provide and deliver service to customers, revenue is recognized based on the transaction price allocated to each performance obligation. Distribution revenues are generally considered daily or "at-will" contracts as customers may cancel their service at any time (subject to notification requirements), and revenue generally represents the amount we are entitled to bill customers.

In addition to tariff-based sales, our Gas Distribution Operations segment enters into balancing and exchange arrangements of natural gas as part of our operations and off-system sales programs. Performance obligations for these types of sales include transportation and storage of natural gas and can be satisfied at a point in time or over a period of time, depending on the specific transaction. For those transactions that span a period of time, we record a receivable or payable for any cumulative gas imbalances, as well as for any gas inventory borrowed or lent under a Gas Distributions Operations exchange agreement.

Revenue Disaggregation and Reconciliation. We disaggregate revenue from contracts with customers based upon reportable segment as well as by customer class. The Gas Distribution Operations segment provides natural gas service and transportation 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.

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The tables below reconcile revenue disaggregation by customer class to segment revenue as well as to revenues reflected on the Statements of Consolidated Income (Loss):

Year Ended December 31, 2021 (in millions)			Gas Distribution Operations						Electric Operations						Corporate and Other(2)						Total
Customer Revenues(1)
Residential			$	2,109.4					$	567.9					$	—					$	2,677.3
Commercial			722.4						534.9						—						1,257.3
Industrial			195.7						493.4						—						689.1
Off-system			71.3						—						—						71.3
Miscellaneous			27.3						8.2						0.8						36.3
Total Customer Revenues			$	3,126.1					$	1,604.4					$	0.8					$	4,731.3
Other Revenues			45.1						91.9						31.3						168.3
Total Operating Revenues			$	3,171.2					$	1,696.3					$	32.1					$	4,899.6

(1)Customer revenue amounts exclude intersegment revenues. See Note 23, "Segments of Business," 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.

Year Ended December 31, 2020 (in millions)			Gas Distribution Operations						Electric Operations						Corporate and Other(2)						Total
Customer Revenues(1)
Residential			$	2,075.0					$	527.8					$	—					$	2,602.8
Commercial			670.5						480.3						—						1,150.8
Industrial			212.8						412.1						—						624.9
Off-system			41.0						—						—						41.0
Miscellaneous			32.7						20.2						0.8						53.7
Total Customer Revenues			$	3,032.0					$	1,440.4					$	0.8					$	4,473.2
Other Revenues			96.1						95.5						16.9						208.5
Total Operating Revenues			$	3,128.1					$	1,535.9					$	17.7					$	4,681.7

(1)Customer revenue amounts exclude intersegment revenues. See Note 23, "Segments of Business," 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.

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

(1)Customer revenue amounts exclude intersegment revenues. See Note 23, "Segments of Business," for discussion of intersegment revenues.

Other Revenues. As permitted by accounting principles generally accepted in the United States, regulated utilities have the ability to earn certain types of revenue that are outside the scope of ASC 606. These revenues primarily represent revenue earned under alternative revenue programs. Alternative revenue programs represent regulator-approved mechanisms that allow for the adjustment of billings and revenue for certain approved programs. We maintain a variety of these programs, including demand side management initiatives that recover costs associated with the implementation of energy efficiency programs, as

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well as normalization programs that adjust revenues for the effects of weather or other external factors. Additionally, we maintain certain programs with future test periods that operate similarly to FERC formula rate programs and allow for recovery of costs incurred to replace aging infrastructure. When the criteria to recognize alternative revenue have been met, we establish a regulatory asset and present revenue from alternative revenue programs on the Statements of Consolidated Income (Loss) as “Other revenues.” When amounts previously recognized under alternative revenue accounting guidance are billed, we reduce the regulatory asset and record a customer account receivable.

Customer Accounts Receivable. Accounts receivable on our Consolidated Balance Sheets includes both billed and unbilled amounts, as well as certain amounts that are not related to customer revenues. Unbilled amounts of accounts receivable relate to a portion of a customer’s consumption of gas or electricity from the date of the last cycle billing through the last day of the month (balance sheet date). Factors taken into consideration when estimating unbilled revenue include historical usage, customer rates and weather. 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 year ended December 31, 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 December 31, 2021			459.6						337.0

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.

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, customer delinquencies, 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.

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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 December 31, 2021 and December 31, 2020, are presented in the tables 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			5.8						1.4						—						7.2
Write-offs charged against allowance			(46.7)						(7.7)						—						(54.4)
Recoveries of amounts previously written off			18.0						0.4						—						18.4
Balance as of December 31, 2021			$	18.9					$	3.8					$	0.8					$	23.5

(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 December 31, 2021 adequately reflected the collection risk and net realizable value of our receivables. We have now resumed our common credit mitigation practices in all jurisdictions as these moratoriums have expired (see Note 9, "Regulatory Matters," for additional information on regulatory moratoriums and regulatory assets).

A VIE is an entity in which the controlling interest is determined through means other than a majority voting interest. Refer to Note 1-S, "VIEs and Allocation of Earnings," for information on our accounting policy for the VIEs.

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

Members of the respective joint ventures are NIPSCO (who is the managing member) and tax equity partners. 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 respective joint venture. NIPSCO has an obligation to purchase, through a PPA at established market rates, 100% of the electricity generated by the joint ventures.

Rosewater

Rosewater owns and operates 102 MW of nameplate capacity wind generation assets. NIPSCO and the tax equity partner made cash contributions in December 2020 and March 2021 per the equity capital contribution agreement. NIPSCO also assumed an obligation to the developer of the wind generation assets representing the remaining economic interest, which comes due in 2023. From the contributed funds, Rosewater paid $7.4 million and $85.3 million to the developer of the wind generation assets

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as of December 31, 2021 and 2020, respectively. 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.

Indiana Crossroads Wind

Indiana Crossroads Wind owns and operates 302 MW of nameplate capacity wind generation assets. NIPSCO and the tax equity partner made cash contributions in December 2021 per the equity capital contribution agreement. NIPSCO also assumed an obligation to the developer of the wind generation assets representing the remaining economic interest, which comes due in 2023. From the contributed funds, Indiana Crossroads Wind paid $233.0 million and zero to the developer of the wind generation assets as of December 31, 2021 and 2020, respectively. 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 Indiana Crossroads Wind.

The following table displays the Noncontrolling interest in consolidated subsidiaries included in the Consolidated Balance Sheets:

(in millions)			December 31, 2021						December 31, 2020
Rosewater			$	88.2					$	85.6
Indiana Crossroads Wind			237.4						—
Total			$	325.6					$	85.6

The following table displays the Net income (loss) attributable to noncontrolling interest included in the Statements of Consolidated Income (Loss) for the years ended December 31:

(in millions)			2021						2020						2019
Rosewater			$	(4.2)					$	3.4					$	—
Indiana Crossroads Wind			8.1						—						—
Total			$	3.9					$	3.4					$	—

The following table displays the contributions associated with each VIE:

(in millions)			December 31, 2021												December 31, 2020
			Rosewater						Indiana Crossroads Wind						Rosewater						Indiana Crossroads Wind
NIPSCO Cash Contribution			$	0.1					$	2.7					$	0.7					$	—
Tax Equity Partner Cash Contribution			7.5						237.6						86.1						—
NIPSCO's Obligation to Developer(1)			6.0						271.5						69.7						—
Total Contributions			$	13.6					$	511.8					$	156.5					$	—

(1)Included in "Other noncurrent liabilities" in the Consolidated Balance Sheets

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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.

Our Consolidated Balance Sheets included the following assets and liabilities associated with VIEs.

(in millions)			December 31, 2021												December 31, 2020
			Rosewater						Indiana Crossroads Wind						Rosewater						Indiana Crossroads Wind
Net Property, Plant and Equipment			$	170.1					$	525.8					$	175.6					$	—
Current assets			6.2						8.1						1.7						—
Total assets(1)			176.3						533.9						177.3						—
Current liabilities			2.5						7.5						15.3						—
Asset retirement obligations			5.7						14.8						5.5						—
Other noncurrent liabilities			—						—						0.1						—
Total liabilities			$	8.2					$	22.3					$	20.9					$	—

(1)The assets of Rosewater and Indiana Crossroads represent assets of a consolidated VIE that can be used only to settle obligations of the respective consolidated VIE. The creditors of the liabilities of Rosewater and Indiana Crossroads do not have recourse to the general credit of the primary beneficiary.

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 shares underlying the purchase contracts included within the Equity Units were included in the calculation of potential common stock outstanding for the year ended December 31, 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, subject to anti-dilution adjustments, 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 13, "Equity." Conversely, if the stock price is above the initial reference price of $24.51, subject to anti-dilution adjustments, 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 shares underlying the Series C Mandatory Convertible Preferred Stock included within the Equity Units are contingently convertible as the conversion is contingent on a successful remarketing as described in Note 13, "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 December 31, 2021, the contingency was not resolved and thus no shares were reflected in the denominator in the calculation of diluted EPS for the year ended December 31, 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 13, "Equity," for more information on our ATM forward agreements.

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For the year ended December 31, 2020, we had a net loss on the Statements of Consolidated Income (Loss) 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:

Year Ended December 31, (in millions, except per share amounts)			2021						2020						2019
Numerator:
Net Income (Loss) Available to Common Shareholders - Basic			$	529.8					$	(72.7)					$	328.0
Dilutive effect of Equity Units			1.6						—						—
Net Income (Loss) Available to Common Shareholders - Diluted			$	531.4					$	(72.7)					$	328.0
Denominator:
Average common shares outstanding - Basic			393.6						384.3						374.6
Dilutive potential common shares:
Equity Units			22.0						—						—
Shares contingently issuable under employee stock plans			0.8						—						0.9
Shares restricted under employee stock plans			0.3						—						0.2
ATM Forward agreements			0.6						—						0.3
Average Common Shares - Diluted			417.3						384.3						376.0
Earnings per common share:
Basic			$	1.35					$	(0.19)					$	0.88
Diluted			$	1.27					$	(0.19)					$	0.87

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

At December 31, (in millions)			2021						2020
Property, Plant and Equipment
Gas Distribution Utility(1)			$	15,240.6					$	14,010.2
Electric Utility(1)			6,754.9						6,478.0
Corporate			217.8						197.3
Construction Work in Process			808.0						572.6
Renewable Generation Assets(2)			702.4						175.7
Non-Utility and Other(3)			1,447.6						2,746.1
Total Property, Plant and Equipment			$	25,171.3					$	24,179.9
Accumulated Depreciation and Amortization
Gas Distribution Utility(1)			$	(3,490.2)					$	(3,292.9)
Electric Utility(1)			(2,433.1)						(2,305.0)
Corporate			(132.2)						(109.3)
Renewable Generation Assets(2)			(6.5)						(0.1)
Non-Utility and Other(3)			(1,227.5)						(1,853.1)
Total Accumulated Depreciation and Amortization			$	(7,289.5)					$	(7,560.4)
Net Property, Plant and Equipment			$	17,881.8					$	16,619.5

(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 joint ventures between NIPSCO and unrelated tax equity partners, 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, 2020 includes net book value of four coal units totaling $903.8 million related to R.M. Schahfer Generating Station. Two of the four units were subsequently retired in 2021 and reclassified to current and long-term Regulatory Assets. Depreciation expense for the remaining net book value continues to be recorded at the composite depreciation rate approved by the IURC. As of December 31, 2021, Non-Utility and Other includes a net book value of $201.5 million related to the units not yet retired.

On October 1, 2021, NIPSCO retired R.M. Schahfer Generating Station Units 14 and 15. The net book value of the retired units was reclassified from "Net Property, Plant and Equipment," to current and long-term ''Regulatory Assets.'' The estimated net book value of R.M. Schahfer Generating Station's coal Units 14 and 15 and other associated plant retired was approximately $600.0 million. See Note 9, "Regulatory Matters," for additional details regarding the recovery of the regulatory assets associated with retired generating stations.

The weighted average depreciation provisions for utility plant, as a percentage of the original cost, for the periods ended December 31, 2021, 2020 and 2019 were as follows:

			2021						2020						2019
Electric Operations(1)			3.4		%				3.4		%				2.8		%
Gas Distribution Operations			2.2		%				2.3		%				2.5		%

(1)Increased rate beginning in 2020 primarily attributable to higher depreciation rates from the recent rate case proceeding.

We recognized depreciation expense of $672.1 million, $655.6 million and $612.2 million for the years ended 2021, 2020 and 2019, respectively. The 2021 depreciation expense amount includes a $5.3 million credit related to the regulatory deferral of income (loss) associated with our joint ventures, which is not included in current rates. See Note 9, "Regulatory Matters," for additional details.

Amortization of on-premise Software Costs. We amortized $49.4 million, $56.7 million and $55.5 million in 2021, 2020 and 2019, respectively, related to software recorded as intangible assets. Our unamortized software balance was $181.8 million and $136.4 million at December 31, 2021 and 2020, respectively.

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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. Our goodwill balance was $1,485.9 million as of December 31, 2021 and 2020. All our goodwill has been allocated to our Gas Distribution Operations segment.

For our annual goodwill impairment analysis performed as of May 1, 2021, we completed a qualitative "step 0" assessment and determined that it was more likely than not that the estimated fair value of the reporting unit substantially exceeded the related carrying value of our reporting unit. For this test, we assessed various assumptions, events and circumstances that would have affected the estimated fair value of the reporting units as compared to their baseline May 1, 2020 "step 1" fair value measurement.

Columbia of Massachusetts was not considered to be a reporting unit for May 1, 2020 fair value measurement as the goodwill balance had been reduced to zero as of December 31, 2019. During the fourth quarter of 2019, in connection with the preparation of the year-end financial statements, we assessed the matters related to the then proposed sale of the Massachusetts Business and determined a new impairment analysis was required for our Columbia of Massachusetts reporting unit. 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 2019 year-end impairment analysis indicated that the fair value of the Columbia of Massachusetts reporting unit was below its carrying value. As a result, we reduced the Columbia of Massachusetts reporting unit goodwill balance to zero and recognized a goodwill impairment charge totaling $204.8 million, which was non-deductible for tax purposes.

Intangible and Other Long-Lived Assets Impairment. Prior to December 31, 2019, our intangible assets, apart from goodwill, consisted of franchise rights identified as part of the purchase price allocations associated with the acquisition in February 1999 of Columbia of Massachusetts.

During the fourth quarter of 2019, in connection with the preparation of the year-end financial statements, we assessed the changes in circumstances that occurred during the quarter to determine if it was more likely than not that the fair value of our long-lived assets (including franchise rights) were below their carrying amount. 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 zero, which resulted in an impairment charge totaling $209.7 million recorded in the Gas Distribution Operations segment during the year ended December 31, 2019.

As of December 31, 2021 and 2020, the carrying amount of the franchise rights was zero. We recorded zero amortization expense in 2021 and 2020 and $11.0 million in 2019 related to our franchise rights intangible asset.

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Changes in our liability for asset retirement obligations for the years 2021 and 2020 are presented in the table below:

(in millions)			2021						2020
Beginning Balance			$	495.6					$	416.9
Accretion recorded as a regulatory asset/liability			16.0						17.3
Additions			23.2						5.5
Settlements			(11.2)						(13.9)
Change in estimated cash flows			(11.2)						86.0			(1)
Other			—						(16.2)			(2)
Ending Balance			$	512.4					$	495.6

(1)The change in estimated cash flows for 2020 is primarily attributed to revisions to the estimated costs associated with refining the CCR compliance plan, changes in estimated costs for electric generating stations and the changes in estimated costs for retirement of gas mains. See Note 19-E, "Environmental Matters," for additional information on CCRs.

(2)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.

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 when the rates established are designed to recover the costs of providing the regulated service and it is probable that such rates 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.

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Regulatory assets were comprised of the following items: 

At December 31, (in millions)			2021						2020
Regulatory Assets
Unrecognized pension and other postretirement benefit costs (see Note 12)			$	512.1					$	583.3
Deferred pension and other postretirement benefit costs (see Note 12)			74.8						72.4
Environmental costs (see Note 19-E)			45.8						56.6
Regulatory effects of accounting for income taxes (see Note 1-N and Note 11)			194.8						194.5
Under-recovered gas and fuel costs (see Note 1-J)			73.6						8.0
Depreciation			177.5						192.6
Post-in-service carrying charges			237.9						228.6
Safety activity costs			171.9						146.0
DSM programs			39.2						37.8
Retired coal generating stations			803.9						204.7
Losses on commodity price risk programs (See Note 10)			9.6						54.7
Deferred property taxes			65.1						62.9
Renewable energy investments (See Note 1-S and Note 4)			18.5						—
Other			67.5						88.4
Total Regulatory Assets			$	2,492.2					$	1,930.5
Less: Current Portion			206.2						135.7
Total Noncurrent Regulatory Assets			$	2,286.0					$	1,794.8

Regulatory liabilities were comprised of the following items: 

At December 31, (in millions)			2021						2020
Regulatory Liabilities
Over-recovered gas and fuel costs (see Note 1-J)			$	5.4					$	47.8
Cost of removal (see Note 8)			749.5						775.2
Regulatory effects of accounting for income taxes (see Note 1-N and Note 11)			1,040.8						1,105.1
Deferred pension and other postretirement benefit costs (see Note 12)			75.9						69.5
Gains on commodity price risk programs (See Note 10)			34.2						14.0
Other			74.2						53.9
Total Regulatory Liabilities			$	1,980.0					$	2,065.5
Less: Current Portion			137.4						161.3
Total Noncurrent Regulatory Liabilities			$	1,842.6					$	1,904.2

Regulatory assets, including under-recovered gas and fuel costs and depreciation, of approximately $1,207.0 million and $1,260.6 million as of December 31, 2021 and 2020, respectively, are not earning a return on investment. These costs are recovered over a remaining life, the longest of which is 48 years.

Assets:

Unrecognized pension and other postretirement benefit costs. Represents the 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 by certain subsidiaries that will ultimately be recovered through base rates.

Deferred pension and other postretirement benefit costs. Primarily relates to the difference between defined benefit plan expense recorded by certain subsidiaries due to regulatory orders and the corresponding expense that would otherwise be recorded in accordance with GAAP. The majority of these amounts are driven by Columbia of Ohio. The timeframe for the

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recovery of these costs are expected to be addressed in our base rate case, and the costs are expected to be collected through future base rates, revenue riders or tracking mechanisms.

Environmental costs. Includes certain recoverable costs related to gas plant sites, disposal sites or other sites onto which material may have migrated, the recovery of which is to be addressed in future base rates, billing riders or tracking 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.

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. The majority of this balance is driven by Columbia of Ohio's IRP and CEP deferrals. Recovery of these amounts is approved annually through the related riders.

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. The majority of this balance is driven by Columbia of Ohio's IRP and CEP deferrals.

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.

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

Retired coal generating stations. Represents the net book value of Units 7 and 8 of Bailly Generating Station that was retired during 2018 and the net book value of Units 14 and 15 of R.M. Schahfer Generating Station retired in 2021. These amounts are currently being amortized at a rate consistent with their inclusion in customer rates. The December 2019 NIPSCO electric rate case order allows for the recovery of, and on, the net book value of the stations by the end of 2032 and implements a revenue credit for the retired units. The credit is based on the difference between the net book value of Units 14 and 15 upon retirement and the last base rate case proceeding. The credit will be reset when new base rates are determined. See Note 6, "Property, Plant and Equipment," for further details.

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.

Deferred 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.

Renewable energy investments. Represents the regulatory deferral of certain amounts representing the timing difference between the profit earned from the joint ventures and the amount included in regulated rates to recover our approved investments in consolidated joint ventures. These amounts will be collected through base rates over the life of the renewable generating assets to which they relate. Refer to Note 1-S, "VIEs and Allocation of Earnings," for additional information. Renewable energy formation and developer costs are also included in this regulatory asset.

 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 collected through depreciation rates for future costs to be incurred.

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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. Balance includes excess deferred taxes recorded upon implementation of the TCJA in December 2017, net of amounts amortized through 2021.

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

Gains on commodity price risk programs. Represents the unrealized gains 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 passed back to customers through their inclusion in customer rates.

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 December 31, 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			$	5.2		$	5.4		Incremental bad debt expense incurred from March 13, 2020 through December 29, 2021, above levels currently in rates
Columbia of Virginia			No			$	1.5		$	—		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.On December 16, 2021, CPA received a final order approving its 2021 base rate case, which includes a provision to discontinue the deferral of COVID-19 uncollectible accounts as of December 29, 2021 and begin recovery of amounts deferred as of 12/31/2020 over a five year period beginning on January 1, 2022.

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 connection with the Maryland Relief Act and the order issued by the PSC of Maryland on June 15, 2021, Columbia of Maryland received approximately $0.8 million of assistance that was applied to customer accounts in August 2021. 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.

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We are exposed to certain risks 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, 2021												December 31, 2020
(in millions)			Assets						Liabilities						Assets						Liabilities
Current(1)
Derivatives designated as hedging instruments			$	—					$	136.4					$	—					$	70.9
Derivatives not designated as hedging instruments			10.6						0.4						10.4						7.3
Total			$	10.6					$	136.8					$	10.4					$	78.2
Noncurrent(2)
Derivatives designated as hedging instruments			$	—					$	—					$	—					$	99.5
Derivatives not designated as hedging instruments			13.8						7.4						2.8						45.1
Total			$	13.8					$	7.4					$	2.8					$	144.6

(1) Presented in "Prepayments and other" and "Other accruals", respectively, on the Consolidated Balance Sheets.

(2) Presented in "Deferred charges and other" and "Other noncurrent liabilities", respectively, on the Consolidated Balance Sheets.

Derivatives Not Designated as Hedging Instruments

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. At December 31, 2021, we had 124.5 MMDth of net energy derivative volumes outstanding related to our natural gas hedges.

NIPSCO has received IURC approval to lock in a fixed price for its natural gas customers using long-term forward purchase instruments and is limited to 20% of NIPSCO’s average annual GCA purchase volume. As of December 31, 2021, the remaining terms of these instruments range from one to six years.

All 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 and FAC mechanisms, respectively. These instruments are not designated as accounting hedges. Refer to Note 9, "Regulatory Matters," for additional information.

Derivatives Designated as Hedging Instruments

Interest rate risk management. As of December 31, 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 associated with forecasted debt issuances. These interest rate swaps are designated as cash flow hedges.

Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheets were:

(in millions)

AOCI(1)

Amounts Expected to be Reclassified to Earnings During the Next 12 Months(1)

Maximum Term

Interest Rate

$

25.4

0.8

371 months

(1) All amounts are net of tax.

The actual amounts reclassified from Accumulated Other Comprehensive Income (Loss) to Net Income can differ from the estimate above due to market price changes.

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The gains and losses related to these swaps are recorded to AOCI. Upon issuance, we amortize the gains and losses over the life of the debt associated with these swaps as we recognize interest expense. These amounts are immaterial in 2021, 2020 and 2019 and are recorded in "Interest expense, net" on the Statements of Consolidated Income (Loss).

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).

There were no amounts excluded from effectiveness testing for derivatives in cash flow hedging relationships at December 31, 2021, 2020 and 2019.

Our derivative instruments measured at fair value as of December 31, 2021 and 2020 do not contain any credit-risk-related contingent features. Cash flows for derivative financial instruments are generally classified in cash flows from operating activities.

Income Tax Expense. The components of income tax expense (benefit) were as follows: 

Year Ended December 31, (in millions)			2021						2020						2019
Income Taxes
Current
Federal			$	(0.1)					$	0.2					$	—
State			6.0						11.7						5.2
Total Current			5.9						11.9						5.2
Deferred
Federal			99.2						(0.4)						110.7
State			13.8						(27.4)						9.0
Total Deferred			113.0						(27.8)						119.7
Deferred Investment Credits			(1.1)						(1.2)						(1.4)
Income Taxes			$	117.8					$	(17.1)					$	123.5

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Statutory Rate Reconciliation. The following table represents a reconciliation of income tax expense at the statutory federal income tax rate to the actual income tax expense from continuing operations:

Year Ended December 31, (in millions)			2021												2020												2019
Book income (loss) before income taxes			$	706.6											$	(31.3)											$	506.6
Tax expense (benefit) at statutory federal income tax rate			148.3						21.0		%				(6.6)						21.0		%				106.5						21.0		%
Increases (reductions) in taxes resulting from:
State income taxes, net of federal income tax benefit			14.1						2.0						(11.7)						37.4						10.1						2.0
Amortization of regulatory liabilities			(39.1)						(5.5)						(38.4)						122.7						(29.4)						(5.8)
Goodwill impairment			—						—						—						—						43.0						8.5
Fines and penalties			—						—						11.8						(37.7)						11.5						2.3
Charitable contribution carryover			—						—						—						—						(2.5)						(0.5)
State regulatory proceedings			—						—						—						—						(9.5)						(1.9)
Employee stock ownership plan dividends and other compensation			(1.2)						(0.2)						(1.3)						4.2						(2.0)						(0.4)
Deferred taxes on TCJA regulatory liability divested			—						—						23.3						(74.5)						—						—
Tax accrual adjustments			(0.1)						—						8.9						(28.4)						—						—
Federal tax credits			(2.1)						(0.3)						(2.5)						8.0						—						—
Other adjustments			(2.1)						(0.3)						(0.6)						1.9						(4.2)						(0.8)
Income Taxes			$	117.8					16.7		%				$	(17.1)					54.6		%				$	123.5					24.4		%

The difference in tax expense year-over-year has a relative impact on the effective tax rate proportional to pretax income or loss. The 37.9% decrease in effective tax rate in 2021 versus 2020 was primarily the result of higher pre-tax income, state jurisdictional mix of pre-tax income in 2021 tax effected at statutory tax rates and increased amortization of excess deferred federal income taxes in 2021 compared to 2020. These items were offset by decreased deferred tax expense recognized on the sale of Columbia of Massachusetts' regulatory liability in 2020, established due to TCJA in 2017, that would have otherwise been recognized over the amortization period, 2020 non-deductible penalties and valuation allowance related to Columbia of Massachusetts and 2020 one-time tax accrual adjustments.

The 30.2% increase in effective tax rate in 2020 versus 2019 was primarily the result of lower pre-tax income, state jurisdictional mix of pre-tax loss in 2020 tax effected at statutory tax rates and increased amortization of excess deferred federal income taxes in 2020 compared to 2019. These items were offset by increased deferred tax expense recognized on the sale of Columbia of Massachusetts' regulatory liability, established due to TCJA in 2017, that would have otherwise been recognized over the amortization period, non-deductible penalties and non-cash impairment of goodwill related to Columbia of Massachusetts in 2019 (see Note 7, "Goodwill and Other Intangible Assets" for additional information), and one-time tax accrual adjustments.

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Net Deferred Income Tax Liability Components. Deferred income taxes result from temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities. The principal components of our net deferred tax liability were as follows: 

At December 31, (in millions)			2021						2020
Deferred tax liabilities
Accelerated depreciation and other property differences			$	2,454.4					$	2,339.3
Other regulatory assets			308.6						331.8
Total Deferred Tax Liabilities			2,763.0						2,671.1
Deferred tax assets
Other regulatory liabilities and deferred investment tax credits (including TCJA)			284.7						287.8
Pension and other postretirement/postemployment benefits			104.8						118.1
Net operating loss carryforward and AMT credit carryforward			545.9						608.5
Environmental liabilities			22.2						22.6
Other accrued liabilities			42.1						41.5
Other, net			111.7						128.4
Total Deferred Tax Assets			1,111.4						1,206.9
Valuation Allowance			(7.8)						(6.4)
Net Deferred Tax Assets			1,103.6						1,200.5
Net Deferred Tax Liabilities			$	1,659.4					$	1,470.6

At December 31, 2021, we have federal net operating loss carryforwards of $464.4 million (tax effected). The federal net operating loss carryforwards are available to offset taxable income and will begin to expire in 2036. We believe it is more likely than not that we will realize the benefit from the federal net operating loss carryforwards.

We also have $73.7 million (tax effected, net of federal benefit) of state net operating loss carryforwards. Depending on the jurisdiction in which the state net operating loss was generated, the carryforwards will begin to expire in 2028.

We believe it is more likely than not that a portion of the benefit from certain state NOL carryforwards will not be realized. In recognition of this risk, we have provided a valuation allowance of $7.8 million (net) on the deferred tax assets related to sale of Massachusetts Business assets reflected in the state net operating loss carryforward presented above.

Unrecognized Tax Benefits. A reconciliation of the beginning and ending amounts of unrecognized tax benefits is as follows:

At December 31, 2021, (in millions)			2021						2020						2019
Opening Balance			$	21.7					$	23.2					$	1.2
Gross decreases - tax positions in prior period			—						(1.5)						(0.6)
Gross increases - current period tax positions			—						—						22.6
Ending Balance			$	21.7					$	21.7					$	23.2
Offset for net operating loss carryforwards			(21.7)						(21.7)						(22.6)
Balance, Less Net Operating Loss Carryforwards			$	—					$	—					$	0.6

We present accrued interest on unrecognized tax benefits, accrued interest on other income tax liabilities and tax penalties in "Income Taxes" on our Statements of Consolidated Income (Loss). Interest expense recorded on unrecognized tax benefits and other income tax liabilities was immaterial for all periods presented. There were no accruals for penalties recorded in the Statements of Consolidated Income (Loss) for the years ended December 31, 2021, 2020 and 2019, and there were no balances for accrued penalties recorded on the Consolidated Balance Sheets as of December 31, 2021 and 2020.

We are subject to income taxation in the United States and various state jurisdictions, primarily Indiana, Pennsylvania, Kentucky, Massachusetts, Maryland and Virginia.

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We participate in the IRS CAP, which provides the opportunity to resolve tax matters with the IRS before filing each year's consolidated federal income tax return. As of December 31, 2021, tax years through 2020 have been audited and are effectively closed to further assessment. The audit of tax year 2021 under the CAP program is expected to be completed in 2022.

The statute of limitations in each of the state jurisdictions in which we operate remains open between 3-4 years from the date the state income tax returns are filed. As of December 31, 2021, there were no state income tax audits in progress that would have a material impact on the consolidated financial statements.

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

Our Pension and Other Postretirement Benefit Plans’ Asset Management. The Board has delegated oversight of the pension and other postretirement benefit plans’ assets to the NiSource Benefits Committee (“the Committee”). The Committee has adopted investment policy statements for the pension and other postretirement benefit plans’ assets. For the pension plans, we employ a liability-driven investing strategy. A total return approach is utilized for the other postretirement benefit plans’ assets. A mix of diversified investments are used to maximize the long-term return of plan assets and hedge the liabilities at a prudent level of risk. The investment portfolio includes U.S. and non-U.S. equities, real estate, long-term and intermediate-term fixed income and alternative investments. Risk tolerance is established through careful consideration of plan liabilities, funded status, and asset class volatility. Investment risk is measured and monitored on an ongoing basis through quarterly investment portfolio reviews, annual liability measurements, and periodic asset/liability studies.

In determining the expected long-term rate of return on plan assets, historical markets are studied, relationships between equities and fixed income are analyzed and current market factors, such as inflation and interest rates are evaluated with consideration of diversification and rebalancing. Our expected long-term rate of return on assets is based on assumptions regarding target asset allocations and corresponding long-term capital market assumptions for each asset class. The pension plans’ investment policy calls for a gradual reduction in the allocation of return-seeking assets (equities, real estate and private equity) and a corresponding increase in the allocation of liability-hedging assets (fixed income) as the funded status of the plans’ increase.

As of December 31, 2021 and December 31, 2020, the acceptable minimum and maximum ranges established by the policy for the pension and other postretirement benefit plans are as follows:

December 31, 2021			Defined Benefit Pension Plan												Postretirement Benefit Plan
Asset Category			Minimum						Maximum						Minimum						Maximum
Domestic Equities			7%						27%						0%						55%
International Equities			3%						13%						0%						25%
Fixed Income			69%						81%						20%						100%
Real Estate			0%						3%						0%						0%
Private Equity			0%						3%						0%						0%
Short-Term Investments			0%						10%						0%						10%

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December 31, 2020			Defined Benefit Pension Plan												Postretirement Benefit Plan
Asset Category			Minimum						Maximum						Minimum						Maximum
Domestic Equities			12%						32%						0%						55%
International Equities			6%						16%						0%						25%
Fixed Income			59%						71%						20%						100%
Real Estate			0%						7%						0%						0%
Private Equity			0%						5%						0%						0%
Short-Term Investments			0%						10%						0%						10%

The actual Pension Plan and Postretirement Plan Asset Mix at December 31, 2021 and December 31, 2020 are as follows:

			Defined Benefit Pension Assets(1)						December 31, 2021						Postretirement Benefit Plan Assets						December 31, 2021
Asset Class (in millions)			Asset Value						% of Total Assets						Asset Value						% of Total Assets
Domestic Equities			$	324.3					16.4		%				$	118.6					40.4		%
International Equities			150.9						7.6		%				50.5						17.2		%
Fixed Income			1,382.3						69.7		%				118.8						40.4		%
Real Estate			37.2						1.9		%				—						—
Cash/Other			87.0						4.4		%				5.8						2.0		%
Total			$	1,981.7					100.0		%				$	293.7					100.0		%
			Defined Benefit Pension Assets(1)						December 31, 2020						Postretirement Benefit Plan Assets						December 31, 2020
Asset Class (in millions)			Asset Value						% of Total Assets						Asset Value						% of Total Assets
Domestic Equities			$	446.3					21.0		%				$	108.8					38.0		%
International Equities			230.1						10.9		%				48.2						16.8		%
Fixed Income			1,291.2						61.0		%				122.0						42.6		%
Real Estate			52.9						2.5		%				—						—
Cash/Other			97.2						4.6		%				7.4						2.6		%
Total			$	2,117.7					100.0		%				$	286.4					100.0		%

(1)Total includes accrued dividends and pending traders with brokers.

The categorization of investments into the asset classes in the tables above are based on definitions established by the Committee.

Fair Value Measurements. The following table sets forth, by level within the fair value hierarchy, the pension and other postretirement benefits investment assets at fair value as of December 31, 2021 and 2020. Assets are classified in their entirety based on the observability of inputs used in determining the fair value measurement. There were no investment assets in the pension and other postretirement benefits trusts classified within Level 3 for the years ended December 31, 2021 and 2020.

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We use the following valuation techniques to determine fair value. For the year ended December 31, 2021, there were no significant changes to valuation techniques to determine the fair value of our pension and other postretirement benefits' assets.

Level 1 Measurements

Most common and preferred stocks are traded in active markets on national and international securities exchanges and are valued at closing prices on the last business day of each period presented. Cash is stated at cost, which approximates fair value, with the exception of cash held in foreign currencies which fluctuates with changes in the exchange rates. Short-term bills and notes are priced based on quoted market values.

Level 2 Measurements

Most U.S. Government Agency obligations, mortgage/asset-backed securities, and corporate fixed income securities are generally valued by benchmarking model-derived prices to quoted market prices and trade data for identical or comparable securities. To the extent that quoted prices are not available, fair value is determined based on a valuation model that includes inputs such as interest rate yield curves and credit spreads. Securities traded in markets that are not considered active are valued based on quoted market prices, broker or dealer quotations, or alternative pricing sources with reasonable levels of price transparency. Other fixed income includes futures and options which are priced on bid valuation or settlement pricing.

Level 3 Measurements

Investments with unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets and liabilities are classified as level 3 investments.

Not Classified

Commingled funds, private equity limited partnerships and real estate partnerships are not classified within the fair value hierarchy. Instead, these assets are measured at estimated fair value using the net asset value per share of the investments. Commingled funds' underlying assets are principally marketable equity and fixed income securities. Units held in commingled funds are valued at the unit value as reported by the investment managers. Private equity and real estate funds invest in natural resources, commercial real estate and distressed real estate. The fair value of these investments is determined by reference to the funds’ underlying assets.

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Fair Value Measurements at December 31, 2021: 

(in millions)			December 31, 2021						Quoted Prices in  Active Markets for  Identical Assets (Level 1)						Significant Other Observable Inputs (Level 2)						Significant Unobservable Inputs  (Level 3)
Pension plan assets:
Cash			$	10.3					$	9.7					$	0.6					$	—
Equity securities
International equities			0.5						0.5						—						—
Fixed income securities
Government			387.3						—						387.3						—
Corporate			645.9						—						645.9						—
Mutual Funds
U.S. multi-strategy			128.4						128.4						—						—
International equities			38.7						38.7						—						—
Private equity limited partnerships(3)
U.S. multi-strategy(1)			10.9						—						—						—
International multi-strategy(2)			4.5						—						—						—
Distressed opportunities			0.1						—						—						—
Real estate(3)			37.2						—						—						—
Commingled funds(3)
Short-term money markets			55.0						—						—						—
U.S. equities			195.9						—						—						—
International equities			111.7						—						—						—
Fixed income			349.1						—						—						—
Pension plan assets subtotal			1,975.5						177.3						1,033.8						—
Other postretirement benefit plan assets:
Mutual funds
U.S. multi-strategy			103.8						103.8						—						—
International equities			24.4						24.4						—						—
Fixed income			118.5						118.5						—						—
Commingled funds(3)
Short-term money markets			5.8						—						—						—
U.S. equities			14.8						—						—						—
International equities			26.1						—						—						—
Other postretirement benefit plan assets subtotal			293.4						246.7						—						—
Due to brokers, net(4)			(1.8)						—						(1.8)						—
Receivables/payables			0.3						—						0.3						—
Accrued income/dividends			8.0						8.0						—						—
Total pension and other postretirement benefit plan assets			$	2,275.4					$	432.0					$	1,032.3					$	—

(1)This class includes limited partnerships/fund of funds that invest in a diverse portfolio of private equity strategies, including buy-outs, venture capital, growth capital, special situations and secondary markets, primarily inside the United States. 

(2)This class includes limited partnerships/fund of funds that invest a in diverse portfolio of private equity strategies, including buy-outs, venture capital, growth capital, special situations and secondary markets, primarily outside the United States.

(3)This class of investments is measured at fair value using the net asset value per share and has not been classified in the fair value hierarchy.

(4)This class represents pending trades with brokers.

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The table below sets forth a summary of unfunded commitments, redemption frequency and redemption notice periods for certain investments that are measured at fair value using the net asset value per share for the year ended December 31, 2021:

(in millions)			Fair Value						Unfunded Commitments						Redemption Frequency						Redemption Notice Period
Commingled Funds
Short-term money markets			$	60.8					$	—					Daily						1 day
U.S. equities			210.7						—						Daily						1 day - 5 days
International equities			137.8						—						Monthly						10 days-30 days
Fixed income			349.1						—						Daily						3 days
Private Equity and Real Estate Limited Partnerships(1)			20.4						12.1						N/A						N/A
Total			$	778.8					$	12.1

(1)Private equity and real estate limited partnerships typically call capital over a 3-5 year period and pay out distributions as the underlying investments are liquidated. The typical expected life of these limited partnerships is 0-15 years, and these investments typically cannot be redeemed prior to liquidation.

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Fair Value Measurements at December 31, 2020: 

(in millions)			December 31, 2020						Quoted Prices in Active Markets for Identical Assets (Level 1)						Significant Other Observable Inputs (Level 2)						Significant Unobservable Inputs  (Level 3)
Pension plan assets:
Cash			$	11.9					$	11.9					$	—					$	—
Equity securities
U.S. equities			2.4						2.4						—						—
Fixed income securities
Government			243.4						—						243.4						—
Corporate			692.6						—						692.6						—
Mutual Funds
U.S. multi-strategy			161.3						161.3						—						—
International equities			55.4						55.4						—						—
Fixed income			0.1						0.1						—						—
Private equity limited partnerships(3)
U.S. multi-strategy(1)			10.9						—						—						—
International multi-strategy(2)			6.6						—						—						—
Distressed opportunities			0.3						—						—						—
Real Estate			52.9						—						—						—
Commingled funds(3)
Short-term money markets			78.8						—						—						—
U.S. equities			279.7						—						—						—
International equities			176.8						—						—						—
Fixed income			337.6						—						—						—
Pension plan assets subtotal			2,110.7						231.1						936.0						—
Other postretirement benefit plan assets:
Mutual funds
U.S. multi-strategy			94.8						94.8						—						—
International equities			24.1						24.1						—						—
Fixed income			121.8						121.8						—						—
Commingled funds(3)
Short-term money markets			7.6						—						—						—
U.S. equities			14.0						—						—						—
International equities			24.1						—						—						—
Other postretirement benefit plan assets subtotal			286.4						240.7						—						—
Due to brokers, net(4)			(1.6)						—						(1.6)						—
Accrued income/dividends			8.6						8.6						—						—
Total pension and other postretirement benefit plan assets			$	2,404.1					$	480.4					$	934.4					$	—

(1)This class includes limited partnerships/fund of funds that invest in a diverse portfolio of private equity strategies, including buy-outs, venture capital, growth capital, special situations and secondary markets, primarily inside the United States. 

(2)This class includes limited partnerships/fund of funds that invest in diverse portfolio of private equity strategies, including buy-outs, venture capital, growth capital, special situations and secondary markets, primarily outside the United States.

(3)This class of investments is measured at fair value using the net asset value per share and has not been classified in the fair value hierarchy.

(4)This class represents pending trades with brokers.

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The table below sets forth a summary of unfunded commitments, redemption frequency and redemption notice periods for certain investments that are measured at fair value using the net asset value per share for the year ended December 31, 2020:

(in millions)			Fair Value						Unfunded Commitments						Redemption Frequency						Redemption Notice Period
Commingled Funds
Short-term money markets			$	86.4					$	—					Daily						1 day
U.S. equities			293.7						—						Monthly						1 day -5 days
International equities			200.9						—						Monthly						10 days - 30 days
Fixed income			337.6						—						Daily						3 days
Private Equity and Real Estate Limited Partnerships(1)			22.7						12.1						N/A						N/A
Total			$	941.3					$	12.1

(1)Private equity and real estate limited partnerships typically call capital over a 3-5 year period and pay out distributions as the underlying investments are liquidated. The typical expected life of these limited partnerships is 0-15 years, and these investments typically cannot be redeemed prior to liquidation.

 

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Our Pension and Other Postretirement Benefit Plans’ Funded Status and Related Disclosure. The following table provides a reconciliation of the plans’ funded status and amounts reflected in our Consolidated Balance Sheets at December 31 based on a December 31 measurement date:

			Pension Benefits												Other Postretirement Benefits
(in millions)			2021						2020						2021						2020
Change in projected benefit obligation(1)
Benefit obligation at beginning of year			$	2,058.4					$	2,130.5					$	590.8					$	576.5
Service cost			30.2						32.0						6.2						6.6
Interest cost			31.4						51.6						9.9						15.4
Plan participants’ contributions			—						—						4.2						4.1
Plan amendments			—						—						0.1						—
Actuarial (gain) loss(2)			(68.7)						140.1						(14.8)						24.8
Benefits paid			(198.9)						(174.5)						(40.6)						(37.0)
Estimated benefits paid by incurred subsidy			—						—						0.4						0.4
Spinoff to Eversource			—						(121.3)						—						—
Projected benefit obligation at end of year			$	1,852.4					$	2,058.4					$	556.2					$	590.8
Change in plan assets
Fair value of plan assets at beginning of year			$	2,117.7					$	2,080.9					$	286.4					$	261.4
Actual return on plan assets			58.9						329.9						23.9						36.3
Employer contributions			4.0						2.9						19.8						21.6
Plan participants’ contributions			—						—						4.2						4.1
Benefits paid			(198.9)						(174.6)						(40.6)						(37.0)
Spinoff to Eversource			—						(121.4)						—						—
Fair value of plan assets at end of year			$	1,981.7					$	2,117.7					$	293.7					$	286.4
Funded Status at end of year			$	129.3					$	59.3					$	(262.5)					$	(304.4)
Amounts recognized in the statement of financial position consist of:
Noncurrent assets			159.3						91.4						—						—
Current liabilities			(2.8)						(2.9)						(1.0)						(0.9)
Noncurrent liabilities			(27.2)						(29.2)						(261.5)						(303.5)
Net amount recognized at end of year(3)			$	129.3					$	59.3					$	(262.5)					$	(304.4)
Amounts recognized in accumulated other comprehensive income or regulatory asset/liability(4)
Unrecognized prior service credit			$	0.3					$	0.3					$	(7.8)					$	(10.1)
Unrecognized actuarial loss			438.0						497.2						88.5						116.4
Net amount recognized at end of year			$	438.3					$	497.5					$	80.7					$	106.3

(1)The change in benefit obligation for Pension Benefits represents the change in Projected Benefit Obligation while the change in benefit obligation for Other Postretirement Benefits represents the change in accumulated postretirement benefit obligation.

(2)The pension actuarial gain was primarily driven by the increase in discount rate. The postretirement benefit gain was also primarily driven by an increase in discount rates.

(3)We recognize our Consolidated Balance Sheets underfunded and overfunded status of our various defined benefit postretirement plans, measured as the difference between the fair value of the plan assets and the benefit obligation.

(4)We determined that for certain rate-regulated subsidiaries the future recovery of pension and other postretirement benefits costs is probable. These rate-regulated subsidiaries recorded regulatory assets and liabilities of $512.1 million and zero, respectively, as of December 31, 2021, and $583.3 million and zero, respectively, as of December 31, 2020 that would otherwise have been recorded to accumulated other comprehensive loss.

Our accumulated benefit obligation for our pension plans was $1,834.4 million and $2,036.8 million as of December 31, 2021 and 2020, respectively. The accumulated benefit obligation at each date is the actuarial present value of benefits attributed by the pension benefit formula to employee service rendered prior to that date and based on current and past compensation levels. The accumulated benefit obligation differs from the projected benefit obligation disclosed in the table above in that it includes no assumptions about future compensation levels. 

We are required to reflect the funded status of our pension and postretirement benefit plans on the Consolidated Balance Sheet. The funded status of the plans is measured as the difference between the plan assets' fair value and the projected benefit obligation. We present the noncurrent aggregate of all underfunded plans within "Accrued liability for postretirement and

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postemployment benefits." The portion of the amount by which the actuarial present value of benefits included in the projected benefit obligation exceeds the fair value of plan assets, payable in the next 12 months, is reflected in "Accrued compensation and other benefits." We present the aggregate of all overfunded plans within "Deferred charges and other."

Information for pension plans with a projected benefit obligation in excess of plan assets:

			December 31,
			2021						2020
Accumulated Benefit Obligation			$	30.0					$	32.1
Funded Status
Projected Benefit Obligation			30.0						32.1
Fair Value of Plan Assets			—						—
Funded Status of Underfunded Pension Plans at End of Year(1)			$	(30.0)					$	(32.1)

(1)As of December 31, 2021 and 2020, only our nonqualified plans were underfunded. These plans have no assets as they are not funded until benefits are paid.

Information for pension plans with plan assets in excess of the projected benefit obligation:

			December 31,
			2021						2020
Accumulated Benefit Obligation			$	1,804.3					$	2,004.7
Funded Status
Projected Benefit Obligation			1,822.4						2,026.3
Fair Value of Plan Assets			1,981.7						2,117.7
Funded Status of Overfunded Pension Plans at End of Year			$	159.3					$	91.4

Our pension plans were overfunded, in aggregate, by $129.3 million at December 31, 2021 compared to being overfunded by $59.3 million at December 31, 2020. The improvement in the funded status was due primarily to favorable asset returns. We contributed $4.0 million and $2.9 million to our pension plans in 2021 and 2020, respectively.

Our other postretirement benefit plans were underfunded by $262.5 million at December 31, 2021 compared to being underfunded by $304.4 million at December 31, 2020. The improvement in funded status was primarily due to employer contributions and increased discount rates. We contributed $19.8 million and $21.6 million to our other postretirement benefit plans in 2021 and 2020, respectively.

In 2021 and 2020, some of our qualified pension plans paid lump sum payouts in excess of the respective plan's service cost plus interest cost, thereby meeting the requirement for settlement accounting. We recorded settlement charges of $11.4 million and $10.5 million in 2021 and 2020, respectively. Net periodic pension benefit cost for 2021 was increased by $4.0 million as a result of the interim remeasurement.

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The following table provides the key assumptions that were used to calculate the pension and other postretirement benefits obligations for our various plans as of December 31:

			Pension Benefits												Other Postretirement  Benefits
			2021						2020						2021						2020
Weighted-average assumptions to Determine Benefit Obligation
Discount Rate			2.76		%				2.38		%				2.85		%				2.49		%
Rate of Compensation Increases			4.00		%				4.00		%				—						—
Interest Crediting Rates			4.00		%				4.00		%				—						—
Health Care Trend Rates
Trend for Next Year			—						—						6.20		%				6.69		%
Ultimate Trend			—						—						4.50		%				4.50		%
Year Ultimate Trend Reached			—						—						2030						2029

We expect to make contributions of approximately $2.8 million to our pension plans and approximately $21.5 million to our postretirement medical and life plans in 2022.

The following table provides benefits expected to be paid in each of the next five fiscal years, and in the aggregate for the five fiscal years thereafter. The expected benefits are estimated based on the same assumptions used to measure our benefit obligation at the end of the year and include benefits attributable to the estimated future service of employees:

(in millions)			Pension Benefits						Other Postretirement Benefits						Federal Subsidy Receipts
Year(s)
2022			$	157.3					$	38.1					$	0.4
2023			150.4						37.4						0.4
2024			145.6						36.9						0.3
2025			143.1						36.5						0.3
2026			135.7						35.8						0.3
2027-2031			598.9						168.7						1.1

The following table provides the components of the plans’ actuarially determined net periodic benefits cost for each of the three years ended December 31, 2021, 2020 and 2019:

			Pension Benefits																		Other Postretirement Benefits
(in millions)			2021						2020						2019						2021						2020						2019
Components of Net Periodic Benefit (Income) Cost(1)
Service cost			$	30.2					$	32.0					$	29.2					$	6.2					$	6.6					$	5.1
Interest cost			31.4						51.6						72.3						9.9						15.4						19.2
Expected return on assets			(101.6)						(111.6)						(108.8)						(15.3)						(14.4)						(13.1)
Amortization of prior service cost (credit)			0.1						0.7						0.2						(2.2)						(2.1)						(3.2)
Recognized actuarial loss			21.7						33.8						45.2						4.6						4.9						2.0
Settlement/curtailment loss			11.4						10.5						9.5						—						1.5						—
Total Net Periodic Benefits (Income) Cost			$	(6.8)					$	17.0					$	47.6					$	3.2					$	11.9					$	10.0

(1)Service cost is presented in "Operation and maintenance" on the Statements of Consolidated Income (Loss). Non-service cost components are presented within "Other, net."

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The following table provides the key assumptions that were used to calculate the net periodic benefits cost for our various plans:

			Pension Benefits																		Other Postretirement Benefits
			2021						2020						2019						2021						2020						2019
Weighted-average Assumptions to Determine Net Periodic Benefit Cost
Discount rate - service cost			2.81		%				3.39		%				4.48		%				3.00		%				3.52		%				4.59		%
Discount rate - interest cost			1.57		%				2.65		%				3.84		%				1.73		%				2.76		%				3.94		%
Expected Long-Term Rate of Return on Plan Assets			5.20		%				5.70		%				6.10		%				5.50		%				5.67		%				5.83		%
Rate of Compensation Increases			4.00		%				4.00		%				4.00		%				—						—						—
Interest Crediting Rates			4.00		%				4.00		%				4.00		%				—						—						—

We assumed a 5.20% and 5.50% rate of return on pension and other postretirement plan assets, respectively, for our calculation of 2021 pension benefits cost. These rates were primarily based on asset mix and historical rates of return and were adjusted in 2021 due to anticipated changes in asset allocation and projected market returns.

The following table provides other changes in plan assets and projected benefit obligations recognized in other comprehensive income or regulatory asset or liability:

			Pension Benefits												Other Postretirement Benefits
(in millions)			2021						2020						2021						2020
Other Changes in Plan Assets and Projected Benefit Obligations  Recognized in Other Comprehensive Income or Regulatory Asset  or Liability
Net prior service cost			$	—					$	—					$	0.1					$	—
Net actuarial loss (gain)			(26.0)						(78.2)						(23.3)						2.9
Settlements/curtailments			(11.4)						(10.5)						—						(1.5)
Less: amortization of prior service cost			(0.1)						(0.7)						2.2						2.1
Less: amortization of net actuarial loss			(21.7)						(33.8)						(4.6)						(4.9)
Less: gain attributable to spinoff to Eversource			—						(33.1)						—						—
Less: prior service cost attributable to spinoff to Eversource			—						(2.0)						—						—
Total Recognized in Other Comprehensive Income or Regulatory  Asset or  Liability			$	(59.2)					$	(158.3)					$	(25.6)					$	(1.4)
Amount Recognized in Net Periodic Benefits Cost and Other  Comprehensive Income or Regulatory Asset or Liability			$	(66.0)					$	(141.3)					$	(22.4)					$	10.5

Holders of shares of our common stock are entitled to receive dividends when, as and if declared by the Board out of funds legally available. The policy of the Board has been to declare cash dividends on a quarterly basis payable on or about the 20th day of February, May, August and November. We have certain debt covenants that could potentially limit the amount of dividends we could pay in order to maintain compliance with these covenants. Refer to Note 15, "Long-Term Debt," for more information. As of December 31, 2021, these covenants did not restrict the amount of dividends that were available to be paid.

Dividends paid to preferred shareholders vary based on the series of preferred stock owned. Holders of our shares of common stock are subject to the prior dividend rights of holders of our preferred stock or the depositary shares representing such preferred stock outstanding, and if full dividends have not been declared and paid on all outstanding shares of preferred stock in any dividend period, no dividend may be declared or paid or set aside for payment on our common stock.

Common and preferred stock activity for 2021, 2020 and 2019 is described further below.

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ATM Program and Forward Sale Agreements. On November 1, 2018, we entered into five separate equity distribution agreements pursuant to which we were able to sell up to an aggregate of $500.0 million of our common stock. Four of these agreements were then amended on August 1, 2019 and one was terminated, pursuant to which we were able to sell up to an aggregate of $434.4 million of our common stock. These equity distribution agreements impacting fiscal years 2020 and 2019 expired on December 31, 2020.

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 allowed 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. On December 14, 2021, the forward sale agreement was settled for $21.48 per share, resulting in $143.3 million of net proceeds.

On June 1, 2021, under the ATM program, we executed a forward sale agreement, which allowed 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. On December 13, 2021, the forward sale agreement was settled for $24.85 per share, resulting in $145.4 million of net proceeds.

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 December 31, 2021, we would have received approximately $146.8 million, based on a net price of $24.71 per share.

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

The following table summarizes our activity under the ATM program.

Year Ending December 31,			2021						2020						2019
Number of shares issued			12,525,215						8,459,430						8,422,498
Average price per share			$	23.95					$	23.60					$	27.75
Proceeds, net of fees (in millions)			$	288.1					$	196.5					$	229.1

Preferred Stock. On June 11, 2018, we completed the sale of 400,000 shares of 5.650% Series A Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Stock (the "Series A Preferred Stock") at a price of $1,000 per share. The transaction resulted in $400.0 million of gross proceeds or $393.9 million of net proceeds, after deducting commissions and sale expenses. The Series A Preferred Stock was issued in a private placement pursuant to SEC Rule 144A. On December 13, 2018, we filed a registration statement with the SEC enabling holders to exchange their unregistered shares of Series A Preferred Stock for publicly registered shares with substantially identical terms.

Dividends on the Series A Preferred Stock accrue and are cumulative from the date the shares of Series A Preferred Stock were originally issued to, but not including, June 15, 2023 at a rate of 5.650% per annum of the $1,000 liquidation preference per share. On and after June 15, 2023, dividends on the Series A Preferred Stock will accumulate for each five year period at a percentage of the $1,000 liquidation preference equal to the five-year U.S. Treasury Rate plus (i) in respect of each five year period commencing on or after June 15, 2023 but before June 15, 2043, a spread of 2.843% (the “Initial Margin”), and (ii) in respect of each five year period commencing on or after June 15, 2043, the Initial Margin plus 1.000%. The Series A Preferred Stock may be redeemed by us at our option on June 15, 2023, or on each date falling on the fifth anniversary thereafter, or in connection with a ratings event (as defined in the Certificate of Designation of the Series A Preferred Stock).

As of December 31, 2021 and 2020, Series A Preferred Stock had $1.0 million of cumulative preferred dividends in arrears, or $2.51 per share.

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Holders of Series A Preferred Stock generally have no voting rights, except for limited voting rights with respect to (i) potential amendments to our certificate of incorporation that would have a material adverse effect on the existing preferences, rights, powers or duties of the Series A Preferred Stock, (ii) the creation or issuance of any security ranking on a parity with the Series A Preferred Stock if the cumulative dividends payable on then outstanding Series A Preferred Stock are in arrears, or (iii) the creation or issuance of any security ranking senior to the Series A Preferred Stock. The Series A Preferred Stock does not have a stated maturity and is not subject to mandatory redemption or any sinking fund. The Series A Preferred Stock will remain outstanding indefinitely unless repurchased or redeemed by us. Any such redemption would be effected only out of funds legally available for such purposes and will be subject to compliance with the provisions of our outstanding indebtedness.

On December 5, 2018, we completed the sale of 20,000,000 depositary shares with an aggregate liquidation preference of $500,000,000 under the Company’s registration statement on Form S-3. Each depositary share represents 1/1,000th ownership interest in a share of our 6.500% Series B Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Stock, liquidation preference $25,000 per share (equivalent to $25 per depositary share) (the “Series B Preferred Stock"). The transaction resulted in $500.0 million of gross proceeds or $486.1 million of net proceeds, after deducting commissions and sale expenses.

Dividends on the Series B Preferred Stock accrue and are cumulative from the date the shares of Series B Preferred Stock were originally issued to, but not including, March 15, 2024 at a rate of 6.500% per annum of the $25,000 liquidation preference per share. On and after March 15, 2024, dividends on the Series B Preferred Stock will accumulate for each five year period at a percentage of the $25,000 liquidation preference equal to the five-year U.S. Treasury Rate plus (i) in respect of each five year period commencing on or after March 15, 2024 but before March 15, 2044, a spread of 3.632% (the “Initial Margin”), and (ii) in respect of each five year period commencing on or after March 15, 2044, the Initial Margin plus 1.000%. The Series B Preferred Stock may be redeemed by us at our option on March 15, 2024, or on each date falling on the fifth anniversary thereafter, or in connection with a ratings event (as defined in the Certificate of Designation of the Series B Preferred Stock).

As of December 31, 2021 and 2020, Series B Preferred Stock had $1.4 million of cumulative preferred dividends in arrears, or $72.23 per share.

In addition, 20,000 shares of Series B–1 Preferred Stock, par value $0.01 per share, were outstanding as of December 31, 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.

Holders of Series B Preferred Stock generally have no voting rights, except for limited voting rights with respect to (i) potential amendments to our certificate of incorporation that would have a material adverse effect on the existing preferences, rights, powers or duties of the Series B Preferred Stock, (ii) the creation or issuance of any security ranking on a parity with the Series B Preferred Stock if the cumulative dividends payable on then outstanding Series B Preferred Stock are in arrears, or (iii) the creation or issuance of any security ranking senior to the Series B Preferred Stock. In addition, if and whenever dividends on any shares of Series B Preferred Stock shall not have been declared and paid for at least six dividend periods, whether or not consecutive, the number of directors then constituting our Board of Directors shall automatically be increased by two until all accumulated and unpaid dividends on the Series B Preferred Stock shall have been paid in full, and the holders of Series B-1 Preferred Stock, voting as a class together with the holders of any outstanding securities ranking on a parity with the Series B-1 Preferred Stock and having like voting rights that are exercisable at the time and entitled to vote thereon, shall be entitled to elect the two additional directors. The Series B Preferred Stock does not have a stated maturity and is not subject to mandatory redemption or any sinking fund. The Series B Preferred Stock will remain outstanding indefinitely unless repurchased or redeemed by us. Any such redemption would be effected only out of funds legally available for such purposes and will be subject to compliance with the provisions of our outstanding indebtedness.

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The following table summarizes preferred stock by outstanding series of shares:

									Year ended December 31,									December 31,						December 31,
									2021			2020			2019			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			$	56.50		$	56.50		$	56.50		$	393.9					$	393.9
6.500% Series B			$	25,000.00		20,000			$	1,625.00		$	1,625.00		$	1,674.65		$	486.1					$	486.1
Series C(1)			$	1,000.00		862,500			—			—			—			$	666.5					$	—

(1) The Series C Mandatory Convertible Preferred Stock initially will not bear any dividends. We recorded the initial present value of the purchase contract payments as a liability with a corresponding reduction to preferred stock.

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.

The Series C Mandatory Convertible Preferred Stock and forward purchase contracts are legally detachable and separately exercisable, however, due to the economic linkage between the forward purchase contract and the Series C Mandatory Convertible Preferred Stock, we have concluded that the ability to separate the Corporate Units is non-substantive. Accordingly, we are accounting for the Corporate Units as a single unit of account. We recorded the initial present value of the purchase contract payments as a liability with a corresponding reduction to preferred stock. The current portion of this liability

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is included in "Other accruals," and the noncurrent portion is included in "Other noncurrent liabilities" on the Consolidated Balance Sheets. Purchase contract payments are recorded against this liability. Accretion of the stock purchase contract liability is recorded as interest expense. Refer to Note 5, "Earnings Per Share," for additional information regarding our application of diluted EPS to the shares underlying purchase contracts and the Series C Mandatory Convertible Preferred Stock as part of the Equity Units. Under the terms of the Equity Units, assuming no anti-dilution or other adjustments such as a fundamental change, 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 $41.2 million and zero were made during the years ended December 31, 2021 and December 31, 2020, respectively. The purchase contract liability was $129.4 million at December 31, 2021.

Noncontrolling Interest in Consolidated Subsidiaries. As of December 31, 2021 and 2020, NIPSCO and tax equity partners have completed their cash contributions into the Indiana Crossroads Wind and Rosewater joint ventures. Earnings, tax attributes and cash flows are allocated to both NIPSCO and the respective tax equity partners in varying percentages by category and over the life of the partnership. The tax equity partner's contributions, net of these allocations, is represented as a noncontrolling interest within total equity on the Consolidated Balance Sheets. Refer to Note 4, "Variable Interest Entities," for more information.

Prior to May 19, 2020 we issued share-based compensation to employees and non-employee directors under the NiSource Inc. 2010 Omnibus Plan ("2010 Omnibus Plan"), which was most recently approved by stockholders at the Annual Meeting of Stockholders held on May 12, 2015. The 2010 Omnibus Plan provided for awards to employees and non-employee directors of incentive and nonqualified stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance units, cash-based awards and other stock-based awards and superseded the Director Stock Incentive Plan (“Director Plan”) with respect to grants made after the effective date of the 2010 Omnibus Plan.

The stockholders approved and adopted the NiSource Inc. 2020 Omnibus Incentive Plan ("2020 Omnibus Plan") at the Annual Meeting of Stockholders held on May 19, 2020. The 2020 Omnibus Plan provides for awards to employees and non-employee directors of incentive and nonqualified stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance units, cash-based awards and other stock-based awards and supersedes the 2010 Omnibus Plan with respect to grants made after the effective date of the 2020 Omnibus Plan.

The 2020 Omnibus Plan provides that the number of shares of common stock of NiSource available for awards is 10,000,000 plus the number of shares subject to outstanding awards that expire or terminate for any reason that were granted under the 2020 Omnibus Plan, the 2010 Omnibus Plan or any other equity plan under which awards were outstanding as of May 19, 2020. At December 31, 2021, there were 9,081,947 shares available for future awards under the 2020 Omnibus Plan.

We recognized stock-based employee compensation expense of $16.7 million, $13.5 million and $16.3 million, during 2021, 2020 and 2019, respectively, as well as related tax benefits of $4.0 million, $3.3 million and $4.0 million, respectively. We recognized related excess tax expense from the distribution of vested share-based employee compensation of $0.4 million in 2020, and excess tax benefits of $0.4 million and $0.8 million in 2021 and 2019, respectively.

As of December 31, 2021, the total remaining unrecognized compensation cost related to non-vested awards amounted to $25.1 million, which will be amortized over the weighted-average remaining requisite service period of 1.8 years.

Restricted Stock Units and Restricted Stock. We granted 285,755, 235,100, and 166,031 restricted stock units and shares of restricted stock to employees, subject to service conditions in 2021, 2020, and 2019, respectively. The total grant date fair value of the restricted stock units and shares of restricted stock during 2021, 2020, and 2019, respectively, was $5.7 million, $6.1 million, and $4.1 million based on the average market price of our common stock at the date of each grant less the present value

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of any dividends not received during the vesting period, which will be expensed over the vesting period which is generally three years. As of December 31, 2021, 274,796, 198,303, and 99,055 non-vested restricted stock units and shares of restricted stock granted in 2021, 2020, and 2019, respectively, were outstanding.

If an employee terminates employment before the service conditions lapse under the 2019, 2020 or 2021 awards due to (1) retirement or disability (as defined in the award agreement), or (2) death, the service conditions will lapse on the date of such termination with respect to a pro rata portion of the restricted stock units and shares of restricted stock based upon the percentage of the service period satisfied between the grant date and the date of the termination of employment. In the event of a change in control (as defined in the award agreement), all unvested shares of restricted stock and restricted stock units awarded will immediately vest upon termination of employment occurring in connection with a change in control. Termination due to any other reason will result in all unvested shares of restricted stock and restricted stock units awarded being forfeited effective on the employee’s date of termination.

A summary of our restricted stock unit award transactions for the year ended December 31, 2021 is as follows:

(shares)			Restricted Stock Units						Weighted Average Award Date Fair  Value Per Unit ($)
Non-vested at December 31, 2020			478,227						24.51
Granted			285,755						19.83
Forfeited			(36,697)						23.72
Vested			(155,131)						22.66
Non-vested at December 31, 2021			572,154						22.72

Employee Performance Shares. We granted 973,885 performance shares subject to service, performance and/or market-based vesting conditions in 2021. In regards to 390,941 performance shares granted, the performance conditions are based on the achievement of relative total shareholder return. The number of shares that are eligible to vest based on the Company's relative total shareholder return performance will be adjusted based on a performance magnifier related to safety. In regards to remaining 582,944 performance shares granted, the performance conditions are based on the achievement of one non-GAAP financial measure and/or achievement of relative total shareholder return. The number of shares that are eligible to vest based on these performance conditions will be adjusted based on performance of the magnifier framework for 2021 awards, outlined below.

The financial measure is cumulative net operating earnings per share ("NOEPS"), which we define as income from continuing operations adjusted for certain items. Relative total shareholder return, a market-based vesting condition, which we define as the annualized growth in dividends and share price of a share of our common stock (calculated using a 20 trading day average of our closing price over the performance period, approximately) compared to the total shareholder return of a predetermined peer group of companies. A relative shareholder return result within the first quartile will result in an increase to the NOEPS shares of 25%, while a relative shareholder return result within the fourth quartile will result in a decrease of 25%. A Monte Carlo analysis was used to value the portion of these awards dependent on the market-based vesting condition. The grant date fair value of the NOEPS shares is based on the closing stock price of our common stock at the date of each grant, which will be expensed over the requisite service period of three years. See table below for further details on these awards.

For the 2021 awards, the magnifier framework consists of three areas of focus including safety, environment, and diversity, equity and inclusion ("DE&I"), representing 20%, 10% and 10%, respectively.

We granted 528,729 and 552,389 performance shares subject to service, performance and market-based vesting conditions in 2020 and 2019, respectively. The performance conditions are based on the achievement of one non-GAAP financial measure, relative total shareholder return and additional operational measures as outlined below.

The financial measure is cumulative net operating earnings per share ("NOEPS"), which we define as income from continuing operations adjusted for certain items. The number of cumulative NOEPS shares determined using this measure shall be increased or decreased based on our relative total shareholder return, a market-based vesting condition, which we define as the annualized growth in dividends and share price of a share of our common stock (calculated using a 20 trading day average of our closing price over the performance period, approximately) compared to the total shareholder return of a predetermined peer

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group of companies. A relative shareholder return result within the first quartile will result in an increase to the NOEPS shares of 25%, while a relative shareholder return result within the fourth quartile will result in a decrease of 25%. A Monte Carlo analysis was used to value the portion of these awards dependent on the market-based vesting condition. The grant date fair value of the NOEPS shares is based on the average market price of our common stock at the date of each grant less the present value of dividends not received during the vesting period, which will be expensed over the requisite service period of three years. See table below for further details on these awards.

If a threshold level of cumulative NOEPS financial performance is achieved, additional operational measures, which we refer to as the customer value framework and which consists of equally weighted areas of focus, apply. Each area of focus represents an equal portion of the customer value framework shares, and the targets for all areas of focus must be met for the customer value framework shares to vest at 100%. The grant date fair value of the customer value framework shares is based on the average market price of our common stock on the grant date of each award less the present value of dividends not received during the vesting period, which will be expensed over the requisite service period of three years for those customer value framework shares that are granted. See table below for further details on these awards.

For the 2020 awards, the customer value framework consists of four equally weighted areas of focus including safety, customer satisfaction, culture and environmental, each representing 25% of the customer value framework shares. For the 2019 awards, the customer value framework consists of five equally weighted areas of focus including financial and all those noted for the 2020 awards, each representing 20% of the customer value framework shares.

The following table presents details of the performance awards described above.

Award Year			Service Conditions Lapse date			Performance Period			Award Conditions						Shares outstanding at 12/31/2021 (shares)			Grant Date Fair Value (in millions)
2021			02/28/24			01/01/2021- 12/31/2023			Non-GAAP Financial Measure						278,328			$	6.5
									Relative Total Shareholder Return						278,328			$	6.7
									Relative Total Shareholder Return						124,200			$	3.2
			02/28/23			01/01/2021- 12/31/2022			Relative Total Shareholder Return						252,082			$	4.8
2020			02/28/23			01/01/2020- 12/31/2022			Non-GAAP Financial Measure						349,686			$	11.7
									Operational Measures						80,696			$	2.6
2019			02/28/22			01/01/2019- 12/31/2021			Non-GAAP Financial Measure						353,302			$	11.7
									Operational Measures						81,528			$	2.5

A summary of our performance award transactions for the year ended December 31, 2021 is as follows:

(shares)			Performance Awards						Weighted Average Grant Date Fair  Value Per Unit ($)
Non-vested at December 31, 2020			1,384,336						25.09
Granted			973,885						21.76
Forfeited			(133,695)						25.25
Vested			(426,375)						22.09
Non-vested at December 31, 2021			1,798,151						23.78

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Non-employee Director Awards. As of May 19, 2020, awards to non-employee directors may be made only under the 2020 Omnibus Plan. Currently, restricted stock units are granted annually to non-employee directors, subject to a non-employee director’s election to defer receipt of such restricted stock unit award. The non-employee director’s annual award of restricted stock units vest on the first anniversary of the grant date subject to special pro-rata vesting rules in the event of retirement or disability (as defined in the award agreement), or death. The vested restricted stock units are payable as soon as practicable following vesting except as otherwise provided pursuant to the non-employee director’s deferral election. Certain restricted stock units remain outstanding from the 2010 Omnibus Plan and the Director Plan. All such awards are fully vested and shall be distributed to the directors upon their separation from the Board.

As of December 31, 2021, 252,673 restricted stock units are outstanding to non-employee directors under either the 2020 Omnibus Plan, the 2010 Omnibus Plan or the Director Plan. Of this amount, 66,273 restricted stock units are unvested and expected to vest.

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Our long-term debt as of December 31, 2021 and 2020 is as follows:

Long-term debt type			Maturity as of December 31, 2021			Weighted average interest rate (%)						Outstanding balance as of December 31, (in millions)
												2021						2020
Senior notes:
NiSource			August 2025			0.95		%				1,250.0						1,250.0
NiSource			May 2027			3.49		%				1,000.0						1,000.0
NiSource			December 2027			6.78		%				3.0						3.0
NiSource			September 2029			2.95		%				750.0						750.0
NiSource			May 2030			3.60		%				1,000.0						1,000.0
NiSource			February 2031			1.70		%				750.0						750.0
NiSource			December 2040			6.25		%				152.6						152.6
NiSource			June 2041			5.95		%				347.4						347.4
NiSource			February 2042			5.80		%				250.0						250.0
NiSource			February 2043			5.25		%				500.0						500.0
NiSource			February 2044			4.80		%				750.0						750.0
NiSource			February 2045			5.65		%				500.0						500.0
NiSource			May 2047			4.38		%				1,000.0						1,000.0
NiSource			March 2048			3.95		%				750.0						750.0
Total senior notes												$	9,003.0					$	9,003.0
Medium term notes:
NiSource			April 2022 to May 2027			7.99		%				$	49.0					$	49.0
NIPSCO			August 2022 to August 2027			7.61		%				68.0						68.0
Columbia of Massachusetts			December 2025 to February 2028			6.37		%				15.0						15.0
Total medium term notes												$	132.0					$	132.0
Finance leases:
NiSource Corporate Services			March 2022 to December 2025			1.73		%				51.4						49.4
NIPSCO			December 2027 to January 2033			1.86		%				18.7						16.0
Columbia of Ohio			December 2025 to March 2044			6.15		%				87.8						91.2
Columbia of Virginia			July 2029 to November 2039			6.28		%				17.7						18.4
Columbia of Kentucky			May 2027			3.79		%				0.2						0.3
Columbia of Pennsylvania			August 2027 to May 2035			6.35		%				9.8						19.7
Total finance leases												185.6						195.0
Unamortized issuance costs and discounts												$	(79.1)					$	(86.9)
Total Long-Term Debt												$	9,241.5					$	9,243.1

There was no long-term debt activity during 2021. Details of our 2020 long-term debt related activity are summarized below:

•On April 13, 2020, we completed the issuance and sale of $1.0 billion of 3.60% senior unsecured notes maturing in 2030, which resulted in approximately $987.8 million of net proceeds after deducting commissions and expenses.

•On August 18, 2020, we completed the issuance and sale of $1.25 billion of 0.95% senior unsecured notes maturing in 2025 and $750.0 million of 1.70% senior unsecured notes maturing in 2031, which resulted in approximately $1,980.4 million of net proceeds after deducting commissions and expenses.

•In August 2020, we executed tender offers for $969.3 million of outstanding notes consisting of a combination of our 4.45% notes due 2021, 2.65% notes due 2022, 3.85% notes due 2023, 3.65% notes due 2023, 6.25% notes due 2040, and 5.95% notes due 2041. In August and September 2020, we redeemed $609.3 million of outstanding notes representing the remainder of our 4.45% notes due 2021, 2.65% notes due 2022, 3.85% notes due 2023, and 3.65% notes due 2023 and all of our 5.89% notes due 2025. In conjunction with the debt retired, we recorded a $231.8 million loss on early extinguishment of long-term debt, primarily attributable to early redemption premiums.

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•In September 2020, Columbia of Massachusetts redeemed $25.0 million of its outstanding 6.26% notes due 2028. In conjunction with the debt retired, Columbia of Massachusetts recorded an $11.7 million loss on early extinguishment of long-term debt, primarily attributable to early redemption premiums. Under the terms of the Asset Purchase Agreement, Columbia of Massachusetts’ net working capital at the closing of the sale of the Massachusetts Business was increased by 50% of the debt extinguishment costs, which was approximately $5.3 million.

See Note 19-A, "Contractual Obligations," for the outstanding long-term debt maturities at December 31, 2021.

Unamortized debt expense, premium and discount on long-term debt applicable to outstanding bonds are being amortized over the life of such bonds.

We are subject to a financial covenant under our revolving credit facility which requires us to maintain a debt to capitalization ratio that does not exceed 70%. As of December 31, 2021, the ratio was 57.4%.

We are also subject to certain other non-financial covenants under the revolving credit facility. Such covenants include a limitation on the creation or existence of new liens on our assets, generally exempting liens on utility assets, purchase money security interests, preexisting security interests and an additional subset of assets equal to $200 million. An asset sale covenant generally restricts the sale, conveyance, lease, transfer or other disposition of our assets to those dispositions that are for a price not materially less than fair market of such assets, that would not materially impair our ability to perform obligations under the revolving credit facility, and that together with all other such dispositions, would not have a material adverse effect. The covenant also restricts dispositions to no more than 15% of our consolidated total assets on December 31, 2020. The revolving credit facility also includes a cross-default provision, which triggers an event of default under the credit facility in the event of an uncured payment default relating to any indebtedness of us or any of our subsidiaries in a principal amount of $75.0 million or more.

Our indentures generally do not contain any financial maintenance covenants. However, our indentures are generally subject to cross-default provisions ranging from uncured payment defaults of $5 million to $50 million, and limitations on the incurrence of liens on our assets, generally exempting liens on utility assets, purchase money security interests, preexisting security interests and an additional subset of assets capped at 10% of our consolidated net tangible assets.

We generate short-term borrowings from our revolving credit facility, commercial paper program, and accounts receivable transfer programs. Each of these borrowing sources is described further 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. On February 18, 2022, we extended the termination date of our revolving credit facility to February 18, 2027. At December 31, 2021 and 2020, we had no outstanding borrowings under this facility.

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 $560.0 million and $503.0 million of commercial paper outstanding with weighted-average interest rates of 0.24% and 0.27% as of December 31, 2021 and 2020, respectively.

Accounts Receivable Transfer Programs. Columbia of Ohio, NIPSCO and Columbia of Pennsylvania each maintain a receivables agreement whereby they transfer their customer accounts receivables to third party financial institutions through wholly-owned and consolidated special purpose entities. The three agreements expire between May 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 Consolidated Balance Sheets. As of December 31, 2021, the maximum amount of debt that could be recognized related to our accounts receivable programs is $270.0 million.

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

For the years ended December 31, 2021 and 2020, zero and $353.2 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 $1.4 million, $2.6 million, and $2.6 million for the years ended December 31, 2021, 2020 and 2019, 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 Statements of Consolidated Cash Flows as their maturities are less than 90 days.

Lease Descriptions. We are the lessee for substantially all of our leasing activity, which includes operating and finance leases for corporate and field offices, railcars, fleet vehicles and certain IT assets. Our corporate and field office leases have remaining lease terms between 1 and 22 years with options to renew the leases for up to 25 years. We lease railcars to transport coal to and from our electric generation facilities in Indiana. Our railcars are specifically identified in the lease agreement, which have a remaining lease term of 1 year with options to renew for 1 year. Our fleet vehicles include trucks, trailers and equipment that have been customized specifically for use in the utility industry. We lease fleet vehicles on 1 year terms, after which we have the option to extend on a month-to-month basis or terminate with written notice. ROU assets and liabilities on our Consolidated Balance Sheets do not include obligations for possible fleet vehicle lease renewals beyond the initial lease term. While we have the ability to renew these leases beyond the initial term, we are not reasonably certain to do so. We lease the majority of our IT assets under 4 year lease terms. Ownership of leased IT assets is transferred to us at the end of the lease term.

We have not provided material residual value guarantees for our leases, nor do our leases contain material restrictions or covenants. Lease contracts containing renewal and termination options are mostly exercisable at our sole discretion. Certain of our real estate and railcar leases include renewal periods in the measurement of the lease obligation if we have deemed the renewals reasonably certain to be exercised.

With respect to service contracts involving the use of assets, if we have the right to direct the use of the asset and obtain substantially all economic benefits from the use of an asset, we account for the service contract as a lease. Unless specifically provided to us by the lessor, we utilize NiSource's collateralized incremental borrowing rate commensurate to the lease term as the discount rate for all of our leases. ASC 842 permits a lessee, by class of underlying asset, not to separate nonlease components from lease components. Our policy is to apply this expedient for our leases of fleet vehicles, IT assets and railcars when calculating their respective lease liabilities.

Lease costs for the years ended December 31, 2021 and December 31, 2020 are presented in the table below. These costs include both amounts recognized in expense and amounts capitalized as part of the cost of another asset. Income statement presentation for these costs (when ultimately recognized on the income statement) is also included:

Year Ended December 31, (in millions)			Income Statement Classification			2021						2020
Finance lease cost
Amortization of right-of-use assets			Depreciation and amortization			$	28.8					$	23.4
Interest on lease liabilities			Interest expense, net			9.4						11.1
Total finance lease cost						38.2						34.5
Operating lease cost			Operation and maintenance			15.6						20.3
Total lease cost						$	53.8					$	54.8

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Our right-of-use assets and liabilities are presented in the following lines on the Consolidated Balance Sheets:

At December 31, (in millions)			Balance Sheet Classification			2021						2020
Assets
Finance leases			Net Property, Plant and Equipment			$	165.7					$	176.8
Operating leases			Deferred charges and other			33.8						39.9
Total leased assets						199.5						216.7
Liabilities
Current
Finance leases			Current portion of long-term debt			28.1						23.3
Operating leases			Other accruals			6.7						10.3
Noncurrent
Finance leases			Long-term debt, excluding amounts due within one year			157.5						171.7
Operating leases			Other noncurrent liabilities			27.9						29.9
Total lease liabilities						$	220.2					$	235.2

Other pertinent information related to leases was as follows:

Year Ended December 31, (in millions)			2021						2020
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows used for finance leases			$	9.4					$	11.1
Operating cash flows used for operating leases			15.4						20.2
Financing cash flows used for finance leases			25.7						18.4
Right-of-use assets obtained in exchange for lease obligations
Finance leases			22.4						59.3
Operating leases			$	6.0					$	10.9

			December 31, 2021						December 31, 2020
Weighted-average remaining lease term (years)
Finance leases			10.6						11.2
Operating leases			8.5						8.0
Weighted-average discount rate
Finance leases			5.0		%				5.1		%
Operating leases			3.7		%				4.0		%

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Maturities of our lease liabilities as of December 31, 2021 were as follows:

As of December 31, 2021, (in millions)			Total			Finance Leases			Operating Leases
2022			$	45.1		$	37.2		$	7.9
2023			38.5			33.6			4.9
2024			30.2			25.6			4.6
2025			23.2			19.2			4.0
2026			19.6			15.8			3.8
Thereafter			129.1			112.9			16.2
Total lease payments			285.7			244.3			41.4
Less: Imputed interest			(65.5)			(58.7)			(6.8)
Total			220.2			185.6			34.6
Reported as of December 31, 2021
Short-term lease liabilities			34.8			28.1			6.7
Long-term lease liabilities			185.4			157.5			27.9
Total lease liabilities			$	220.2		$	185.6		$	34.6

There were no leases signed but not yet commenced as of December 31, 2021.

A.Fair Value Measurements

Recurring Fair Value Measurements

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

 

Recurring Fair Value Measurements December 31, 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 December 31, 2021
Assets
Risk management assets			$	—					$	24.4					$	—					$	24.4
Available-for-sale debt securities			—						171.8						—						171.8
Total			$	—					$	196.2					$	—					$	196.2
Liabilities
Risk management liabilities			$	—					$	144.2					$	—					$	144.2
Total			$	—					$	144.2					$	—					$	144.2

 

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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

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 that reduce exposures. As of December 31, 2021 and 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 10, "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 10, “Risk Management Activities.”

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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.

Our available-for-sale debt securities impairments are recognized periodically using an allowance approach. At each reporting date, we utilize a quantitative and qualitative review process to assess the impairment of available-for-sale debt securities at the individual security level. For securities in a loss position, we evaluate our intent to sell or whether it is more-likely-than-not that we will be required to sell the security prior to the recovery of its amortized cost. If either criteria is met, the loss is recognized in earnings immediately, with the offsetting entry to the carrying value of the security. If both criteria are not met, 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 certain amounts recorded in the allowance for credit losses are deemed uncollectible, the allowance on the uncollectible portion will be 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 will be recognized immediately in earnings. As of December 31, 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 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 December 31, 2021 and 2020 were: 

December 31, 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			$	52.8					$	0.1					$	(0.4)					$	—					$	52.5
Corporate/Other debt securities			116.5						3.7						(0.7)						(0.2)						119.3
Total			$	169.3					$	3.8					$	(1.1)					$	(0.2)					$	171.8
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 $36.2 and $35.4 million, respectively, at December 31, 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 year-ended December 31, 2021 and 2020.

The cost of maturities sold is based upon specific identification. At December 31, 2021, approximately $8.2 million of U.S. Treasury debt securities and approximately $3.8 million of Corporate/Other debt securities have maturities of less than a year.

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

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Non-recurring Fair Value Measurements

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

The sale of the Massachusetts Business occurred on October 9, 2020, and the assets and liabilities of the Massachusetts Business were measured at fair value, less costs to sell.

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.

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 estimate was made at April 19, 2021, and will not be remeasured at each subsequent balance sheet date. It has been categorized within Level 2 of the fair value hierarchy. Refer to Note 13, ''Equity'' for additional information.

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

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

Long-term debt. The fair value of outstanding long-term debt is estimated based on the quoted market prices for the same or similar securities. Certain premium costs associated with the early settlement of long-term debt are not taken into consideration in determining fair value. These fair value measurements are classified within Level 2 of the fair value hierarchy. For the years ended December 31, 2021 and 2020, there was no change in the method or significant assumptions used to estimate the fair value of long-term debt.

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

At December 31, (in millions)			Carrying Amount 2021						Estimated Fair Value 2021						Carrying Amount 2020						Estimated Fair Value 2020
Long-term debt (including current portion)			$	9,241.5					$	10,415.7					$	9,243.1					$	11,034.2

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A.        Contractual Obligations. We have certain contractual obligations requiring payments at specified periods. The obligations include long-term debt, lease obligations, energy commodity contracts and obligations for various services including pipeline capacity and outsourcing of IT services. The total contractual obligations in existence at December 31, 2021 and their maturities were:

(in millions)			Total						2022						2023						2024						2025						2026						After
Long-term debt (1)			$	9,135.0					$	30.0					$	—					$	—					$	1,260.0					$	—					$	7,845.0
Interest payments on long-term debt			5,710.0						335.7						334.1						334.1						334.1						321.6						4,050.4
Finance leases(2)			244.3						37.2						33.6						25.6						19.2						15.8						112.9
Operating leases(3)			41.4						7.9						4.9						4.6						4.0						3.8						16.2
Energy commodity contracts			68.6						60.4						8.2						—						—						—						—
Service obligations:
Pipeline service obligations			1,605.0						610.5						366.0						241.0						136.1						98.7						152.7
IT service obligations			180.1						69.5						44.8						35.7						27.6						2.5						—
Other liabilities(4)			553.0						95.6						457.4						—						—						—						—
Total contractual obligations			$	17,537.4					$	1,246.8					$	1,249.0					$	641.0					$	1,781.0					$	442.4					$	12,177.2

(1) Long-term debt balance excludes unamortized issuance costs and discounts of $79.1 million.

(2) Finance lease payments shown above are inclusive of interest totaling $58.7 million.

(3) Operating lease payments shown above are inclusive of interest totaling $6.8 million. Operating lease balances do not include obligations for possible fleet vehicle lease renewals beyond the initial lease term. While we have the ability to renew these leases beyond the initial term, we are not reasonably certain to do so as they are renewed month-to-month after the first year. If we were to continue the fleet vehicle leases outstanding at December 31, 2021, payments would be $33.3 million in 2022, $30.2 million in 2023, $27.2 million in 2024, $24.0 million in 2025, $17.0 million in 2026 and $16.1 million thereafter.

(4)Other liabilities shown above are inclusive of the Rosewater and Indiana Crossroads Developer payments due in 2023 and Equity Unit purchase contract liability payments to be made in 2022 and 2023.

Purchase and Service Obligations. We have entered into various purchase and service agreements whereby we are contractually obligated to make certain minimum payments in future periods. Our purchase obligations are for the purchase of physical quantities of natural gas, electricity and coal. Our service agreements encompass a broad range of business support and maintenance functions which are generally described below.

Our subsidiaries have entered into various energy commodity contracts to purchase physical quantities of natural gas, electricity and coal. These amounts represent the minimum quantity of these commodities we are obligated to purchase at both fixed and variable prices. To the extent contractual purchase prices are variable, obligations disclosed in the table above are valued at market prices as of December 31, 2021.

NIPSCO has power purchase arrangements representing a total of 500 MW of wind power, with contracts expiring between 2024 and 2040. No minimum quantities are specified within these agreements due to the variability of electricity generation from wind, so no amounts related to these contracts are included in the table above. Upon early termination of one of these agreements by NIPSCO for any reason (other than material breach by the counterparties), NIPSCO may be required to pay a termination charge that could be material depending on the events giving rise to termination and the timing of the termination.

We have pipeline service agreements that provide for pipeline capacity, transportation and storage services. These agreements, which have expiration dates ranging from 2022 to 2038, require us to pay fixed monthly charges.

NIPSCO has contracts with three major rail operators providing for coal transportation services for which there are certain minimum payments. These service contracts extend for various periods through 2028.

We have executed agreements with multiple IT service providers. The agreements extend for various periods through 2027.

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B.        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 part of normal business. Such agreements include guarantees and stand-by letters of credit. These agreements are entered into primarily to support or enhance the creditworthiness otherwise attributed to a subsidiary on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish the subsidiaries’ intended commercial purposes. At December 31, 2021 and 2020, we had issued stand-by letters of credit of $18.9 million and $15.2 million, respectively, for the benefit of third parties.

We provide guarantees related to our future performance under BTAs for our renewable generation projects. At December 31, 2021 and 2020, our guarantees for multiple BTAs totaled $288.9 million and $40.7 million, respectively. In February 2022, the amount of the guarantees increased to $485.2 million in accordance with the Fairbanks and Cavalry BTAs. The amount of each guaranty will decrease upon the substantial completion of the construction of the facilities. See “- F. Other Matters - Generation Transition,” below for more information.

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

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, were 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 March 12, 2020, the Court granted final approval of the settlement of the consolidated class action. 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

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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. Briefing on the defendants' motion to dismiss was completed on January 10, 2022, and oral argument on the defendants' motion to dismiss took place on February 3, 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 resolution of any particular claim, proceeding or investigation would not have a material adverse effect on our results of operations, financial position or liquidity. 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.

D.        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. After the cross motions for summary judgment were fully briefed, we reached an agreement in principle to settle the coverage dispute for a portion of the above invested amount. We expect that the agreement will be finalized, a settlement payment by the insurer to NiSource will be made, and the case will be dismissed by the end of the first quarter of 2022.

E.        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 and asset retirement costs, further described below, to be recoverable through rates. See Note 9, "Regulatory Matters," for additional detail.

As of December 31, 2021 and 2020, we had recorded a liability of $91.1 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 Consolidated Balance Sheets. 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

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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. See Note 8, "Asset Retirement Obligations," for a discussion of all obligations, including those discussed below.

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 Consolidated Financial Statements.

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 $85.1 million and $85.0 million at December 31, 2021 and 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 cannot estimate the likelihood that the agencies will deny approvals or the financial impact on us if these approvals are not obtained.

F.         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 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 BTAs 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 the employees accepted severance offers, absent a retention period. For employees that have a retention period, expense will be 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 table displays the activity of Accumulated Other Comprehensive Loss, net of tax:

(in millions)			Gains and Losses on Securities(1)						Gains and Losses on Cash Flow Hedges(1)						Pension and OPEB Items(1)						Accumulated Other Comprehensive Loss(1)
Balance as of January 1, 2019			$	(2.4)					$	(13.0)					$	(21.8)					$	(37.2)
Other comprehensive income (loss) before reclassifications			6.1						(64.3)						2.3						(55.9)
Amounts reclassified from accumulated other comprehensive loss			(0.4)						0.1						0.8						0.5
Net current-period other comprehensive income (loss)			5.7						(64.2)						3.1						(55.4)
Balance as of December 31, 2019			$	3.3					$	(77.2)					$	(18.7)					$	(92.6)
Other comprehensive income (loss) before reclassifications			3.3						(70.8)						2.9						(64.6)
Amounts reclassified from accumulated other comprehensive loss			(0.6)						0.1						1.0						0.5
Net current-period other comprehensive income (loss)			2.7						(70.7)						3.9						(64.1)
Balance as of December 31, 2020			$	6.0					$	(147.9)					$	(14.8)					$	(156.7)
Other comprehensive income (loss) before reclassifications			(3.5)						25.3						6.6						28.4
Amounts reclassified from accumulated other comprehensive loss			(0.4)						0.1						1.8						1.5
Net current-period other comprehensive income (loss)			(3.9)						25.4						8.4						29.9
Balance as of December 31, 2021			$	2.1					$	(122.5)					$	(6.4)					$	(126.8)

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

Year Ended December 31, (in millions)			2021						2020						2019
Interest income			$	4.0					$	5.5					$	7.7
AFUDC equity			13.1						9.9						8.0
Charitable contributions			(11.5)						(1.5)						(5.1)
Pension and other postretirement non-service cost(1)			35.5						9.3						(16.5)
Sale of emission reduction credits			—						4.6						—
Miscellaneous			(0.3)						4.3						0.7
Total Other, net			$	40.8					$	32.1					$	(5.2)

(1) See Note 12, "Pension and Other Postretirement Benefits" for additional information.

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At December 31, 2021, our operations are divided into two primary reportable segments, the Gas Distribution Operations and the Electric Operations segments. The remainder of our operations, which are not significant enough on a stand-alone basis to warrant treatment as an operating segment, are presented as "Corporate and Other" and primarily are comprised of interest expense on holding company debt, and unallocated corporate costs and activities. Refer to Note 3, "Revenue Recognition," for additional information on our segments and their sources of revenues. The following table provides information about our reportable segments. We use operating income as our primary measurement for each of the reported segments and make decisions on finance, dividends and taxes at the corporate level on a consolidated basis. Segment revenues include intersegment sales to affiliated subsidiaries, which are eliminated in consolidation. Affiliated sales are recognized on the basis of prevailing market, regulated prices or at levels provided for under contractual agreements. Operating income is derived from revenues and expenses directly associated with each segment.

Year Ended December 31, (in millions)			2021						2020						2019
Operating Revenues
Gas Distribution Operations
Unaffiliated			$	3,171.2					$	3,128.1					$	3,509.7
Intersegment			12.3						12.1						13.1
Total			3,183.5						3,140.2						3,522.8
Electric Operations
Unaffiliated			1,696.3						1,535.9						1,698.4
Intersegment			0.8						0.7						0.8
Total			1,697.1						1,536.6						1,699.2
Corporate and Other
Unaffiliated			32.1						17.7						0.8
Intersegment			460.3						449.8						468.1
Total			492.4						467.5						468.9
Eliminations			(473.4)						(462.6)						(482.0)
Consolidated Operating Revenues			$	4,899.6					$	4,681.7					$	5,208.9

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Year Ended December 31, (in millions)			2021						2020						2019
Operating Income (Loss)
Gas Distribution Operations(1)			$	617.5					$	199.1					$	675.4
Electric Operations			387.8						348.8						406.8
Corporate and Other(2)			1.6						2.9						(191.5)
Consolidated Operating Income			$	1,006.9					$	550.8					$	890.7
Depreciation and Amortization
Gas Distribution Operations			$	383.0					$	363.1					$	403.2
Electric Operations			329.4						321.3						277.3
Corporate and Other			36.0						41.5						36.9
Consolidated Depreciation and Amortization			$	748.4					$	725.9					$	717.4
Assets
Gas Distribution Operations			$	15,153.7					$	13,433.0					$	14,224.5
Electric Operations			7,178.9						6,443.1						6,027.6
Corporate and Other			1,824.3						2,164.4						2,407.7
Consolidated Assets			$	24,156.9					$	22,040.5					$	22,659.8
Capital Expenditures(3)
Gas Distribution Operations			$	1,406.4					$	1,266.9					$	1,380.3
Electric Operations			517.4						422.8						468.9
Corporate and Other			16.6						31.1						18.6
Consolidated Capital Expenditures			$	1,940.4					$	1,720.8					$	1,867.8

(1)In 2020, Gas Distribution Operations reflects the loss of $412.4 million on the sale of the Massachusetts Business.

(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."

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

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The following table provides additional information regarding our Consolidated Statements of Cash Flows for the years ended December 31, 2021, 2020 and 2019:

Year Ended December 31, (in millions)			2021						2020						2019
Supplemental Disclosures of Cash Flow Information
Non-cash transactions:
Capital expenditures included in current liabilities			$	245.7					$	170.4					$	223.6
Assets acquired under a finance lease			22.4						59.3						26.4
Assets acquired under an operating lease			6.0						10.9						13.4
Reclassification of other property to regulatory assets(1)			607.6						—						—
Assets recorded for asset retirement obligations(2)			12.0						91.5						54.6
Obligation to developer at formation of joint venture(3)			277.5						69.7						—
Purchase contract liability, net of fees and payments(4)			129.4						—						—
Schedule of interest and income taxes paid:
Cash paid for interest on long-term debt, net of interest capitalized amounts			$	322.4					$	349.0					$	349.7
Cash paid for interest on finance leases			9.4						11.1						11.3
Cash paid for income taxes, net of refunds(5)			5.4						(1.0)						10.8

(1)See Note 9, "Regulatory Matters," for additional information.

(2)See Note 8, "Asset Retirement Obligations," for additional information.

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

(4)Refer to Note 13, "Equity," for additional information.

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

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NISOURCE INC.

SCHEDULE II – VALUATION AND QUALIFYING ACCOUNTS

Twelve months ended December 31, 2021
									Additions
($ in millions)			Balance Jan. 1, 2021						Charged to Costs and Expenses						Charged to Other Account (1)									Deductions for Purposes for which Reserves were Created						Balance Dec. 31, 2021
Reserves Deducted in Consolidated Balance Sheet from Assets to Which They Apply:
Reserve for accounts receivable			$	52.3					$	18.3					$	6.4								$	53.5					$	23.5
Reserve for deferred charges and other			—						—						2.3									—						2.3
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						—						—									3.0						—
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						—						—									—						3.0

(1) Charged to Other Accounts reflects the deferral of bad debt expense to a regulatory asset or the movement of the reserve between short term and long term..

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