Document

EX-99.1 2 vuhi2021doc.htm EX-99.1 Document

Exhibit 99.1

VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED FINANCIAL STATEMENTS

For the year ended December 31, 2021

Contents


			Page Number
Audited Financial Statements
Definitions			1
Independent Auditor's Report			3
Consolidated Balance Sheets			5-6
Consolidated Statements of Income			7
Consolidated Statements of Cash Flows			8
Consolidated Statements of Common Shareholder's Equity			9
Notes to the Consolidated Financial Statements			10-39



DEFINITIONS
ACE			Affordable Clean Energy
AFUDC			Allowance for funds used during construction
AMA			Asset Management Agreement
ARO			Asset Retirement Obligation
ARP			Alternative Revenue Program
ASC			Accounting Standards Codification
ASU			Accounting Standard Update
BTA			Build Transfer Agreement
Capital Dynamics			Capital Dynamics, Inc., a Delaware corporation
CCR			Coal Combustion Residuals
CECA			Clean Energy Cost Adjustment
CERC			CERC Corp., together with its subsidiaries
COVID-19			Novel coronavirus disease 2019, and any mutations or variants thereof, and related global outbreak that was subsequently declared a pandemic by the World Health Organization
CODM			Chief Operating Decision Maker who is the Company's President
CPCN			Certificate of Public Convenience and Necessity
CPP			Clean Power Plan
CSIA			Compliance and System Improvement Adjustment
DRR			Distribution Replacement Rider
DSMA			Demand Side Management Adjustment
ECA			Environmental Cost Adjustment
EEFC			Energy Efficiency Funding Component
EEFR			Energy Efficiency Funding Rider
EPA			Environmental Protection Agency
FASB			Financial Accounting Standards Board
February 2021 Winter Storm Event			The extreme and unprecedented winter weather event in February 2021 resulting in electricity generation supply shortages, including in Texas, and natural gas supply shortages and increased wholesale prices of natural gas in the United States, primarily due to prolonged freezing temperatures.
FERC			Federal Energy Regulation Commission
GAAP			Generally Accepted Accounting Principles
GHG			Greenhouse gases
IDEM			Indiana Department of Environmental Management
Infrastructure Services			Provided underground pipeline construction and repair services through VISCO and its wholly-owned subsidiaries, Miller Pipeline, LLC and Minnesota Limited, LLC
IURC			Indiana Utility Regulatory Commission
LIBOR			London Interbank Offered Rate
MGP			Manufactured gas plant
MISO			Midcontinent Independent System Operator
MW			megawatts
NYMEX			New York Mercantile Exchange
Posey Solar			Posey Solar, LLC, a Delaware limited liability company
PowerTeam Services			PowerTeam Services, LLC, a Delaware limited liability company, now known as Artera Services, LLC
PPA			Power purchase agreement
PRP			Potentially responsible parties
PUCO			Public Utilities Commission of Ohio
ROU			Right of use
Scope 1 emissions			Direct source of emissions from a company’s operations
Scope 2 emissions			Indirect source of emissions from a company’s energy usage
Scope 3 emissions			Indirect source of emissions from a company’s end-users
SERP			Supplemental Executive Retirement Plan
SRC			Sales Reconciliation Component
TCJA			Tax Cuts and Jobs Acts
TDSIC			Transmission, Distribution and Storage System Improvement Charge
Tenaska			Tenaska Wind Holdings, LLC
TSCR			Tax Savings Credit Rider
VISCO			Vectren Infrastructure Services Corporation, previously a wholly-owned subsidiary of Vectren, and which was sold pursuant to the Securities Purchase Agreement, dated as of February 3 2020, by and among VUSI, PowerTeam Services and, solely for purposes of Section 10.17 of the Securities Purchase Agreement, Vectren
VRP			Voluntary Remediation Program
VUSI			Vectren Utility Services, Inc., a wholly-owned subsidiary of Vectren

INDEPENDENT AUDITOR'S REPORT

To the Director of Vectren Utility Holdings, Inc.

Opinion

We have audited the consolidated financial statements of Vectren Utility Holdings, Inc. and subsidiaries (the "Company") (a wholly owned subsidiary of Vectren Corporation), which comprise the consolidated balance sheets as of December 31, 2021 and 2020, and the related consolidated statements of income, cash flows, and common shareholder’s equity, for each of the three years in the period ended December 31, 2021, and the related notes to the consolidated financial statements (collectively referred to as the "financial statements").

In our opinion, the accompanying financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021, in accordance with accounting principles generally accepted in the United States of America.

Basis for Opinion

We conducted our audits in accordance with auditing standards generally accepted in the United States of America (GAAS). Our responsibilities under those standards are further described in the Auditor’s Responsibilities for the Audit of the Financial Statements section of our report. We are required to be independent of the Company and to meet our other ethical responsibilities, in accordance with the relevant ethical requirements relating to our audits. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Responsibilities of Management for the Financial Statements

Management is responsible for the preparation and fair presentation of the financial statements in accordance with accounting principles generally accepted in the United States of America, and for the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free from material misstatement, whether due to fraud or error.

In preparing the financial statements, management is required to evaluate whether there are conditions or events, considered in the aggregate, that raise substantial doubt about the Company’s ability to continue as a going concern for one year after the date that the financial statements are issued.

Auditor’s Responsibilities for the Audit of the Financial Statements

Our objectives are to obtain reasonable assurance about whether the financial statements as a whole are free from material misstatement, whether due to fraud or error, and to issue an auditor’s report that includes our opinion. Reasonable assurance is a high level of assurance but is not absolute assurance and therefore is not a guarantee that an audit conducted in accordance with GAAS will always detect a material misstatement when it exists. The risk of not detecting a material misstatement resulting from fraud is higher than for one resulting from error, as fraud may involve collusion, forgery, intentional omissions, misrepresentations, or the override of internal control. Misstatements are considered material if there is a substantial likelihood that, individually or in the aggregate, they would influence the judgment made by a reasonable user based on the financial statements.

In performing an audit in accordance with GAAS, we:

• Exercise professional judgment and maintain professional skepticism throughout the audit.

• Identify and assess the risks of material misstatement of the financial statements, whether due to fraud or error, and design and perform audit procedures responsive to those risks. Such procedures include examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements.

• Obtain an understanding of internal control relevant to the audit in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control. Accordingly, no such opinion is expressed.

• Evaluate the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluate the overall presentation of the financial statements.

• Conclude whether, in our judgment, there are conditions or events, considered in the aggregate, that raise substantial doubt about the Company’s ability to continue as a going concern for a reasonable period of time.

We are required to communicate with those charged with governance regarding, among other matters, the planned scope and timing of the audit, significant audit findings, and certain internal control-related matters that we identified during the audit.

/s/ DELOITTE & TOUCHE LLP

Indianapolis, Indiana

March 16, 2022

VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS


	December 31, 2021		December 31, 2020
	(in millions)
ASSETS
Current Assets:
Cash and cash equivalents	$	7	$	8
Accounts receivable - less allowance for credit losses of $4 and $6, respectively	149		127

Accrued unbilled revenues - less allowance for credit losses of $1 and $1, respectively	116		97
Inventories	104		121
Regulatory assets	106		3
Prepaid expenses and other current assets	58		41
Total current assets	540		397


Property, Plant and Equipment, net	6,045		5,613
Other Assets:

Other investments	—		17
Goodwill	205		205
Regulatory assets	581		518
Other non-current assets	82		72
Total other assets	868		812
Total Assets	$	7,453	$	6,822

The accompanying notes are an integral part of these consolidated financial statements.

VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS


	December 31, 2021		December 31, 2020
LIABILITIES AND SHAREHOLDER'S EQUITY	(in millions)
Current Liabilities:
Accounts payable	$	218	$	188
Accounts payable - affiliated companies	40		88

Accrued liabilities	203		129

Current maturities of long-term debt	5		55

Total current liabilities	466		460
Other Liabilities:
Deferred income taxes	672		646
Regulatory liabilities	1,020		970
Other non-current liabilities	302		256
Total other liabilities	1,994		1,872
Long-term Debt:
Long-term debt - net of current maturities	1,111		858
Long-term debt - affiliated companies	1,343		1,343
Total long-term debt, net	2,454		2,201
Commitment and Contingencies (Note 8)
Shareholder's Equity:
Common stock (no par value)	1,218		1,163
Retained earnings	1,321		1,126

Total shareholder's equity	2,539		2,289
Total Liabilities and Shareholder's Equity	$	7,453	$	6,822

The accompanying notes are an integral part of these consolidated financial statements.

VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME


	Year Ended December 31,
	2021		2020		2019
	(in millions)
Revenues:
Gas utility revenues	$	1,087	$	868	$	863
Electric utility revenues	629		554		570

Total	1,716		1,422		1,433
Expenses:
Utility natural gas	425		241		280
Fuel and purchased power	186		147		166
Operation and maintenance	389		376		429
Depreciation and amortization	299		286		269
Taxes other than income taxes	77		74		67
Total	1,376		1,124		1,211
Operating Income	340		298		222
Other Income (Expense):
Interest expense	(80)		(82)		(87)
Other income, net	23		20		22
Income Before Income Taxes	283		236		157
Income taxes	48		48		9
Net Income	$	235	$	188	$	148

The accompanying notes are an integral part of these consolidated financial statements.

VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Year Ended December 31,
	2021		2020		2019
	(in millions)
Cash Flows from Operating Activities:
Net income	$	235	$	188	$	148
Adjustments to reconcile net income to cash from operating activities:
Depreciation & amortization	299		286		269
Deferred income taxes & investment tax credits	36		88		33
Expense portion of pension & postretirement benefit cost	7		12		14
Changes in working capital accounts:
Accounts receivable & accrued unbilled revenue	(41)		(39)		14
Inventories	17		(9)		(20)
Net regulatory assets and liabilities	(89)		(81)		(63)
Accounts payable	(57)		93		9
Employer contributions to pension & postretirement plans	(2)		(3)		(17)
Other current assets and liabilities	53		(7)		7
Other assets and other liabilities	(58)		(4)		(83)
Other operating activities, net	16		13		12
Net cash provided by operating activities	416		537		323
Cash Flows from Investing Activities:
Capital expenditures, excluding AFUDC equity	(632)		(677)		(584)
Sale of investments	—		—		34
Purchase of investments	—		—		(38)
Proceeds from company-owned life insurance	—		2		20
Other-net	(3)		2		—
Net cash used in investing activities	(635)		(673)		(568)
Cash Flows from Financing Activities:

Proceeds from long-term debt - affiliated companies	—		650		693
Retirement of long-term debt	(55)		(400)		(568)

Net change in commercial paper	258		(176)		102
Capital contribution from parent	55		130		54
Dividends to parent	(40)		(71)		(48)
Net cash provided by financing activities	218		133		233
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	(1)		(3)		(12)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	8		11		23
Cash, Cash Equivalents and Restricted Cash at End of Period	$	7	$	8	$	11

The accompanying notes are an integral part of these consolidated financial statements

VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER'S EQUITY


	Common Stock		Retained Earnings		Total
	(in millions)
Balance at January 1, 2019	$	979	$	909	$	1,888
Net income			148		148

Common stock:
Additional capital contribution	54				54
Dividends			(48)		(48)

Balance at December 31, 2019	1,033		1,009		2,042
Net income			188		188

Common stock:
Additional capital contribution	130				130
Dividends			(71)		(71)

Balance at December 31, 2020	1,163		1,126		2,289
Net income			235		235

Common stock:
Additional capital contribution	55				55
Dividends			(40)		(40)

Balance at December 31, 2021	$	1,218	$	1,321	$	2,539

The accompanying notes are an integral part of these consolidated financial statements.

VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(1) Organization and Nature of Operations

Vectren Utility Holdings, Inc. (collectively with its subsidiaries Utility Holdings, VUHI or the Company), an Indiana corporation, was formed on March 31, 2000, to serve as the intermediate holding company for Vectren Corporation’s (Vectren) three operating public utilities: Indiana Gas Company, Inc. (CenterPoint Energy Indiana North or CEI North), Southern Indiana Gas and Electric Company (CenterPoint Energy Indiana South or CEI South), and Vectren Energy Delivery of Ohio, Inc. (CenterPoint Energy Ohio or CEOH). The Company also has other assets that provide information technology and other services to the three utilities. Vectren, a wholly owned subsidiary of CenterPoint Energy, Inc. (collectively with its subsidiaries, CenterPoint Energy) and an Indiana corporation, is an energy holding company headquartered in Evansville, Indiana, and was organized on June 10, 1999. Both Vectren and the Company are holding companies as defined by the Energy Policy Act of 2005 (Energy Act).

As of December 31, 2021, CEI North provided energy delivery services to 633,975 natural gas customers located in central and southern Indiana. CEI South provided energy delivery services to 150,382 electric customers and 114,671 gas customers located near Evansville in southwestern Indiana. CEI South also owns and operates electric generation assets to serve its electric customers and optimizes those assets in the wholesale power market. As of December 31, 2021, CEOH provided energy delivery services to 329,722 natural gas customers located near Dayton in west-central Ohio.

Merger with CenterPoint Energy. On February 1, 2019 (Merger Date), pursuant to the Merger Agreement, Vectren consummated the previously announced merger with CenterPoint Energy and was acquired for approximately $6 billion in cash (the Merger). Each share of Vectren common stock issued and outstanding immediately prior to the closing was canceled and converted into the right to receive $72.00 in cash per share, without interest. At the closing, each stock unit payable in Vectren common stock or whose value was determined with reference to the value of Vectren common stock, whether vested or unvested, was canceled with cash consideration paid in accordance with the terms of the Merger Agreement. These amounts did not include a stub period cash dividend of $0.41145 per share, which was declared, with CenterPoint Energy consent, by Vectren's board of directors on January 16, 2019, and paid to Vectren stockholders as of the Merger Date.

Pursuant to the Merger Agreement and immediately subsequent to the close of the Merger, Vectren cash settled all outstanding share-based awards issued prior to the Merger Date by Vectren to its employees. As a result, VUHI recorded an incremental cost of $26 million in Operation and maintenance expenses on its Consolidated Statements of Income during the year ended December 31, 2019 for its share of allocated costs.

Subsequent to the close of the Merger, VUHI recognized severance totaling $41 million to employees terminated in 2019, inclusive of change of control severance payments to executives of Vectren under existing agreements, and which is included in Operation and maintenance expenses on its Consolidated Statements of Income during the year ended December 31, 2019.

In connection with the Merger, VUHI made offers to prepay certain outstanding guaranteed senior notes as required pursuant to certain note purchase agreements previously entered into by VUHI. See Note 7 for further details.

(2) Summary of Significant Accounting Policies

(a) Principles of Consolidation

The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries, after appropriate elimination of intercompany transactions.

(b) Use of Estimates

In applying accounting policies, the Company makes judgments, assumptions, and estimates that affect the amounts reported in these consolidated financial statements and related footnotes. Examples of transactions for which estimation techniques are used include valuing deferred tax obligations, unbilled revenue, uncollectible accounts, regulatory assets and liabilities, asset retirement obligations, and derivatives and other financial instruments. Estimates also impact the depreciation of property, plant and equipment and the testing of goodwill and other assets for impairment. Recorded estimates are revised when better information becomes available or when actual amounts can be determined. Actual results could differ from current estimates.

Highly liquid investments with an original maturity of three months or less at the date of purchase are considered cash equivalents. Cash and cash equivalents are stated at cost plus accrued interest to approximate fair value.

(d) Accounts Receivables and Allowance for Credit Losses

Accounts receivable are recorded at the invoiced amount and do not bear interest. Management reviews historical write-offs, current available information, and reasonable and supportable forecasts to estimate and establish allowance for credit losses. Account balances are charged off against the allowance when management determines it is probable the receivable will not be recovered. See Note 5 for further information about regulatory deferrals of bad debt expense related to COVID-19.

(e) Inventories

In most circumstances, the Company’s inventory components are recorded using an average cost method; however, natural gas in storage at the Company’s Indiana utilities is recorded using the Last In – First Out (LIFO) method. Inventory related to the Company’s regulated operations is valued at historical cost consistent with ratemaking treatment. Materials and supplies are recorded as inventory when purchased and subsequently charged to expense or capitalized to plant when installed.

Inventories consist of the following:


	December 31,
	2021		2020
	(in millions)
Gas in storage – at LIFO cost	$	45	$	37
Materials & supplies	45		39
Coal & oil for electric generation - at average cost	14		44
Other	—		1
Total inventories	$	104	$	121

Based on the average cost of gas purchased during December 2021, the cost of replacing inventories carried at LIFO cost exceeded carrying value at December 31, 2021 by $8 million. Based on the average cost of gas purchased during December 2020, the cost of replacing inventories carried at LIFO cost was less than the carrying value at December 31, 2020 by $8 million.

Due to CEOH’s exit of the merchant function, CEOH does not hold a balance in natural gas inventory as it does not sell natural gas directly to customers. In addition, no storage facilities are owned by CEOH.

(f) Long-lived Assets and Goodwill

The Company records property, plant and equipment at historical cost and expenses repair and maintenance costs as incurred.

The Company periodically evaluates long-lived assets, including property, plant and equipment, when events or changes in circumstances indicate that the carrying value of these assets may not be recoverable. For rate regulated businesses, recoverability of long-lived assets is assessed by determining if a capital disallowance from a regulator is probable through monitoring the outcome of rate cases and other proceedings. No long-lived asset impairments were recorded in 2021, 2020 or 2019.

The Company performs goodwill impairment tests at least annually and evaluates goodwill when events or changes in circumstances indicate that its carrying value may not be recoverable. The Company recognizes a goodwill impairment by the amount a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill within that reporting unit. The Company includes deferred tax assets and liabilities within its reporting unit’s carrying value for the purposes of annual and interim impairment tests, regardless of whether the estimated fair value reflects the disposition of such assets and liabilities. Goodwill is reported in the Company's Natural Gas reporting segment.

The Company performed the annual goodwill impairment tests in the third quarter of 2021 and determined that no goodwill impairment charge was required.

(g) Depreciation and Amortization Expense

The Company computes depreciation and amortization using the straight-line method based on economic lives or regulatory-mandated recovery periods. Amortization expense includes amortization of certain regulatory assets.

The Company’s portion of jointly owned property, plant and equipment, along with that plant’s related operating expenses, is presented in these financial statements in proportion to the ownership percentage.

(h) Capitalization of AFUDC

The Company capitalizes AFUDC as a component of projects under construction and amortizes it over the assets’ estimated useful lives once the assets are placed in service. AFUDC represents the composite interest cost of borrowed funds and a reasonable return on the equity funds used for construction as the Company applies the guidance for accounting for regulated operations. Although AFUDC increases both property, plant and equipment and earnings, it is realized in cash when the assets are included in rates.


	Year Ended December 31,
	2021		2020		2019
	(in millions)
AFUDC - borrowed funds (1)	$	19	$	16	$	26
AFUDC - equity funds (1)	5		8		4

(1)Included in Other income, net on the Company’s Consolidated Statements of Consolidated Income.

(i) Regulation

Retail public utility operations affecting Indiana customers are subject to regulation by the IURC, and retail public utility operations affecting Ohio customers are subject to regulation by the PUCO. CEI South is subject to FERC regulation as an electric public utility. The Company’s accounting policies give recognition to the ratemaking and accounting practices authorized by these agencies.

(j) Refundable or Recoverable Gas Costs and Cost of Fuel and Purchased Power

All metered gas rates in Indiana contain a gas cost adjustment clause that allows the Company to charge for changes in the cost of purchased gas. Metered electric rates contain a fuel adjustment clause that allows for adjustment in charges for electric energy to reflect changes in the cost of fuel. The net energy cost of purchased power, subject to a variable benchmark based on NYMEX natural gas prices, is also recovered through regulatory proceedings. The Company records any under-or-over-

recovery resulting from gas and fuel adjustment clauses each month in revenues. A corresponding regulatory asset or liability is recorded until the under-or-over-recovery is billed or refunded to utility customers. The cost of gas sold is charged to operating expense as delivered to customers, and the cost of fuel and purchased power for electric generation is charged to operating expense when consumed.

(k) Regulatory Assets and Liabilities

The Company applies the guidance for accounting for regulated operations within its Electric reportable segment and Natural Gas reportable segment. The Company's rate-regulated subsidiaries may collect revenues subject to refund pending final determination in rate proceedings. In connection with such revenues, estimated rate refund liabilities are recorded which reflect management’s current judgment of the ultimate outcomes of the proceedings.

The Company's rate-regulated businesses recognize removal costs as a component of depreciation expense in accordance with regulatory treatment. In addition, a portion of the amount of removal costs collected from customers that relate to AROs has been reflected as an asset retirement liability in accordance with accounting guidance for AROs.

(l) Asset Retirement Obligations

A portion of removal costs related to interim retirements of gas utility pipeline and electric utility poles, and reclamation activities meet the definition of an ARO. The Company records the fair value of a liability for a legal ARO in the period in which it is incurred. When the liability is initially recorded, the Company capitalizes a cost by increasing the carrying amount of the related long-lived asset. The liability is accreted, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, the Company settles the obligation for its recorded amount or incurs a gain or loss. To the extent regulation is involved, regulatory assets and liabilities result when accretion and amortization is adjusted to match rates established by regulators and any gain or loss is subject to deferral.

(m) Derivative Instruments

The Company is exposed to various market risks. These risks arise from transactions entered into in the normal course of business. The Company, from time to time, utilizes derivative instruments such as physical forward contracts, to mitigate the impact of changes in commodity prices on operating results and cash flows. Such derivatives are recognized in the Company’s Consolidated Balance Sheet at their fair value unless the Company elects the normal purchase and sales exemption for qualified physical transactions. A derivative may be designated as a normal purchase or normal sale if the intent is to physically receive or deliver the product for use or sale in the normal course of business.

(n) Environmental Costs

The Company expenses or capitalizes environmental expenditures, as appropriate, depending on their future economic benefit. The Company expenses amounts that relate to an existing condition caused by past operations that do not have future economic benefit. The Company records undiscounted liabilities related to these future costs when environmental assessments and/or remediation activities are probable and the costs can be reasonably estimated.

(o) Income Taxes

On February 1, 2019, Vectren became a wholly-owned subsidiary of CenterPoint Energy and became included in CenterPoint Energy's consolidated federal income tax return. Vectren and certain subsidiaries are also included in various unitary or consolidated state income tax returns with CenterPoint Energy. In other state jurisdictions, Vectren and certain subsidiaries continue to file separate state tax returns. The Company calculates the provision for income taxes and income tax liabilities for each jurisdiction using a separate return method.

The Company uses the asset and liability method of accounting for deferred income taxes. Deferred income tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. A valuation allowance is established against deferred tax assets for which management believes realization is not considered to be more likely than not. The Company recognizes interest and penalties as a component of income tax expense (benefit), as applicable, in their respective Consolidated Statements of Income.

To the extent certain excess deferred income taxes of the Company’s rate-regulated subsidiaries may be recoverable or payable through future rates, regulatory assets and liabilities have been recorded, respectively.

Investment tax credits are deferred and amortized to income over the approximate lives of the related property.

(p) Revenue Policy

Revenue is recognized when obligations under the terms of a contract with the customer are satisfied. Revenue is measured as the amount of consideration the Company expects to receive in exchange for transferring goods or providing services. The satisfaction of performance obligation occurs when the transfer of goods and services occur, which may be at a point in time or over time, resulting in revenue being recognized over the course of the underlying contract or at a single point in time based upon the delivery of services to customers.

(q) MISO Transactions

With the IURC’s approval, the Company is a member of the MISO, a FERC approved regional transmission organization. The MISO serves the electrical transmission needs of much of the Midcontinent region and maintains operational control over the Company’s electric transmission facilities as well as other utilities in the region. The Company is an active participant in the MISO energy markets, bidding its owned generation into the Day Ahead and Real Time markets and procuring power for its retail customers at Locational Marginal Pricing (LMP) as determined by the MISO market.

MISO-related purchase and sale transactions are recorded using settlement information provided by the MISO. These purchase and sale transactions are accounted for on at least a net hourly position, meaning net purchases within that interval are recorded on the Company's Consolidated Statements of Income in Utility natural gas, Fuel and purchased power, and net sales within that interval are recorded on the Company's Consolidated Statements of Income in Utility revenues. On occasion, prior period transactions are resettled outside the routine process due to a change in the MISO’s tariff or a material interpretation thereof. Expenses associated with resettlements are recorded once the resettlement is probable and the resettlement amount can be estimated. Revenues associated with resettlements are recognized when the amount is determinable and collectability is reasonably assured.

The Company also receives transmission revenue that results from other members’ use of the Company’s transmission system. These revenues are also included in Electric utility reportable segment revenues. Generally, these transmission revenues along with costs charged by the MISO are considered components of base rates and any variance from that included in base rates is recovered from / refunded to retail customers through tracking mechanisms.

(r) Excise & Utility Receipts Taxes

Excise taxes and a portion of utility receipts taxes are included in rates charged to customers. Accordingly, the Company records these taxes received as a component of utility revenues, which totaled $33 million in 2021, $30 million in 2020, and $30 million in 2019. Expense associated with excise and utility receipts taxes are recorded as a component of Taxes other than income taxes on the Consolidated Statements of Income.

(s) Fair Value Measurements

Certain assets and liabilities are valued and disclosed at fair value. Nonfinancial assets and liabilities include the initial measurement of an asset retirement obligation or the use of fair value in goodwill and long-lived assets impairment tests. FASB guidance provides the framework for measuring fair value. That framework provides a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). The three levels of the fair value hierarchy are described as follows:


Level 1			Inputs to the valuation methodology are unadjusted quoted prices for identical assets or liabilities in active markets that the Company has the ability to access.
Level 2			Inputs to the valuation methodology include · quoted prices for similar assets or liabilities in active markets; · quoted prices for identical or similar assets or liabilities in inactive markets; · inputs other than quoted prices that are observable for the asset or liability; · inputs that are derived principally from or corroborated by observable market data by correlation or other means. If the asset or liability has a specified (contractual) term, the Level 2 input must be observable for substantially the full term of the asset or liability.
Level 3			Inputs to the valuation methodology are unobservable and significant to the fair value measurement.

The asset or liability’s fair value measurement level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement. Valuation techniques used maximize the use of observable inputs and minimize the use of unobservable inputs.

(3) Revenue Recognition

In accordance with ASC 606, revenue is recognized when a customer obtains control of promised goods or services. The amount of revenue recognized reflects the consideration to which the Company expects to be entitled to receive in exchange for these goods or services.

The Company determines that disaggregating revenue into certain categories achieves the disclosure objective to depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. These material revenue generating categories, as disclosed in Note 12, include: Natural Gas and Electric.

The Company provides commodity service to customers at rates, charges, and terms and conditions included in tariffs approved by regulators. The Company’s utilities bill customers monthly and have the right to consideration from customers in an amount that corresponds directly with the performance obligation satisfied to date. The performance obligation is satisfied and revenue is recognized upon the delivery of services to customers. The Company records revenues for services and goods delivered but not billed at the end of an accounting period in Accrued unbilled revenues, derived from estimated unbilled consumption and tariff rates or in a regulatory asset, as applicable. The Company's revenues are also adjusted for the effects of regulation including tracked operating expenses, infrastructure replacement mechanisms, decoupling mechanisms, and lost margin recovery. Decoupling and lost margin recovery mechanisms are considered ARPs, which are excluded from the scope of ASC 606. Customers are billed monthly and payment terms, set by the regulator, require payment within a month of billing. The Company's revenues are not subject to significant returns, refunds, or warranty obligations.

In the following table, the Company's revenue is disaggregated by reportable segment and major source.


	Year Ended December 31, 2021
	Electric		Natural Gas		Total
	(in millions)
Revenue from contracts	$	609	$	1,071	$	1,680
Other (1)	20		16		36
Total Revenues	$	629	$	1,087	$	1,716

	Year Ended December 31, 2020
	Electric		Natural Gas		Total
	(in millions)
Revenue from contracts	$	529	$	869	$	1,398
Other (1)	25		(1)		24
Total Revenues	$	554	$	868	$	1,422


	Year Ended December 31, 2019
	Electric		Natural Gas		Total
	(in millions)
Revenue from contracts	$	548	$	856	$	1,404
Other (1)	22		7		29
Total Revenues	$	570	$	863	$	1,433

(1)Primarily consists of income from ARPs. ARPs are contracts between the utility and its regulators, not between the utility and a customer. The Company recognizes ARP revenue as other revenues when the regulator-specified conditions for recognition have been met. Upon recovery of ARP revenue through incorporation in rates charged for utility service to customers, ARP revenue is reversed and recorded as revenue from contracts with customers. The recognition of ARP revenues and the reversal of ARP revenues upon recovery through rates charged for utility service may not occur in the same period.

Revenues from Contracts with Customers

Contract Balances. The Company does not have any material contract balances (right to consideration for services already provided or obligations to provide services in the future for consideration already received). Substantially all the Company's accounts receivable results from contracts with customers.

The opening and closing balances of the Company's accounts receivable and other accrued unbilled revenue are as follows:


	Accounts Receivable		Other Accrued Unbilled Revenues
	(in millions)
Opening balance as of December 31, 2020	$	127	$	97
Closing balance as of December 31, 2021	149		116
Increase	$	22	$	19

Allowance for Credit Losses and Bad Debt Expense

The Company segregates financial assets that fall under the scope of Topic 326, primarily trade receivables due in one year or less, into portfolio segments based on shared risk characteristics, such as geographical location and regulatory environment, for evaluation of expected credit losses. Historical and current information, such as average write-offs, are applied to each portfolio segment to estimate the allowance for losses on uncollectible receivables. Additionally, the allowance for losses on uncollectible receivables is adjusted for reasonable and supportable forecasts of future economic conditions, which can include changing weather, commodity prices, regulations, and macroeconomic factors, among others. For a discussion of regulatory deferrals related to COVID-19, see Note 5.

The table below summarizes the Company's bad debt expense amounts for 2021, 2020 and 2019, net of regulatory deferrals, including those related to COVID-19:


	Year Ended December 31,
	2021		2020		2019
	(in millions)
Bad debt expense	$	2	$	6	$	5

(4) Property, Plant and Equipment

(a) Property, Plant and Equipment

Property, plant and equipment includes the following:


		December 31, 2021						December 31, 2020
	Weighted Average Useful Lives	Property, Plant and Equipment, Gross		Accumulated Depreciation and Amortization		Property, Plant and Equipment, Net		Property, Plant and Equipment, Gross		Accumulated Depreciation and Amortization		Property, Plant and Equipment, Net
	(in years)	(in millions)
Electric transmission and distribution	35	$	1,857	$	1,018	$	839	$	1,631	$	855	$	776
Electric generation	26	2,013		750		1,263		1,922		754		1,168
Natural gas distribution	31	5,744		1,887		3,857		5,094		1,627		3,467
Other property	3	126		40		86		509		307		202
Total		$	9,740	$	3,695	$	6,045	$	9,156	$	3,543	$	5,613

(b) Depreciation and Amortization

The following table presents depreciation and amortization expense:


	Year Ended December 31,
	2021		2020		2019
	(in millions)
Depreciation	$	292	$	282	$	265
Amortization of regulatory assets	6		3		3
Other amortization	1		1		1
Total	$	299	$	286	$	269

The Company recorded AROs relating to the closure of the ash ponds at A.B. Brown and F.B. Culley and to treated wood poles for electric distribution, distribution transformers containing PCB (also known as Polychlorinated Biphenyl), and underground fuel storage tanks. The Company also recorded AROs relating to gas pipelines abandoned in place. The estimates of future liabilities were developed using historical information, and where available, quoted prices from outside contractors.

A reconciliation of the changes in the ARO liability recorded in Other non-current liabilities in the Company’s Consolidated Balance Sheet is as follows:


	December 31, 2021		December 31, 2020
	(in millions)
Beginning balance	$	160	$	160
Accretion expense (1)	7		4

Revisions in estimates (2)	28		(4)
Ending balance	$	195	$	160

(1)Reflected in Regulatory assets on the Company’s Consolidated Balance Sheets.

(2)In 2021, the Company reflected an increase in its ARO liability, which is primarily attributable to establishing an ARO for a new solar generation field, which went into service in 2021, and a revision to the ARO for Culley East ash pond for a new closure methodology and cash flows.

(5) Regulatory Assets & Liabilities

The following is a list of regulatory assets and liabilities reflected on the Company’s Consolidated Balance Sheets as of December 31, 2021 and 2020.


	December 31,
	2021		2020
	(in millions)
Regulatory Assets:
Future amounts recoverable from ratepayers related to:

Net deferred income taxes	$	10	$	9
Asset retirement obligations and other	37		48
Total future amounts recoverable from ratepayers	47		57
Amounts deferred for future recovery related to:

Extraordinary gas costs (1)	74		—
Indiana cost recovery riders	52		24
Ohio cost recovery riders	51		51
Gas recovery costs (1)	32		3
Total amounts deferred for future recovery	209		78
Amounts currently recovered in customer rates related to:


Indiana authorized trackers	78		79
Ohio authorized trackers	68		39
Indiana authorized cost deferrals	161		137
Ohio authorized cost deferrals	100		94
Loss on reacquired debt and hedging costs	24		37


Total amounts recovered in customer rates	431		386
Total Regulatory Assets	$	687	$	521
Total Current Regulatory Assets	$	106	$	3
Total Non-current Regulatory Assets	$	581	$	518
Regulatory Liabilities:
Regulatory liabilities related to TCJA	$	354	$	386
Estimated removal costs	623		584
Other regulatory liabilities	43		—
Total Regulatory Liabilities	$	1,020	$	970

(1)Included in current regulatory assets on the Company’s Consolidated Balance Sheets.

Of the $431 million currently being recovered in customer rates, $93 million related to Ohio deferrals is earning a return. The weighted average recovery period of regulatory assets currently being recovered in base rates, not earning a return, which totals $193 million, is 30 years. Regulatory assets not earning a return with perpetual or undeterminable lives have been excluded from the weighted average recovery period calculation. The remainder of the regulatory assets are being recovered timely through periodic recovery mechanisms. The Company has rate orders for all deferred costs not yet in rates and therefore believes future recovery is probable.

Regulatory assets for asset retirement obligations, see Notes 4 and 10 for further discussion, are primarily a result of costs incurred for expected retirement activity for the Company's ash ponds beyond what has been recovered in rates. The Company believes the recovery of these assets are probable as the Company reached a settlement agreement with the intervening parties whereby the costs would be recovered as requested in the petition filed with the IURC on August 14, 2019. On May 13, 2020, the IURC approved the settlement agreement in full. On October 28, 2020, the IURC approved the Company's ECA proceeding, which included the initiation of recovery of the federally mandated project costs.

The deferred tax related regulatory liability is primarily the revaluation of deferred taxes at the reduced federal corporate tax rate that was enacted on December 22, 2017. These regulatory liabilities are being refunded to customers over time following regulatory commission approval.

February 2021 Winter Storm Event

In February 2021, certain of the Company's jurisdictions experienced an extreme and unprecedented winter weather event that resulted in prolonged freezing temperatures, which impacted their businesses. The February 2021 Winter Storm Event impacted wholesale prices of the Company’s natural gas purchases and their ability to serve customers in their service territories, including due to the reduction in available natural gas capacity and impacts to the Company’s natural gas supply portfolio activities, and the effects of weather on their systems and their ability to transport natural gas, among other things. The overall natural gas market, including the markets from which the Company sourced a significant portion of its natural gas for their operations, experienced significant impacts caused by the February 2021 Winter Storm Event, resulting in extraordinary increases in the price of natural gas purchased by the Company.

The Company deferred under-recovered natural gas cost as regulatory assets under existing recovery mechanisms. As of December 31, 2021, the Company has recorded current regulatory assets of $74 million associated with the February 2021 Winter Storm Event through the gas cost recovery mechanism.

Amounts for the under recovery of natural gas costs are reflected in regulatory assets on the Company’s Consolidated Balance Sheets. Recovery of natural gas costs within the regulatory assets are probable and are subject to customary regulatory prudence reviews in all jurisdictions that may impact the amounts ultimately recovered. The Company has begun recovery of natural gas costs attributable to the February 2021 Winter Storm Event.

COVID-19 Regulatory Matters

Governors, public utility commissions and other authorities in the states in which the Company operate have issued a number of different orders related to the COVID-19 pandemic, including orders addressing customer non-payment and disconnection. Although the disconnect moratoriums have expired in the Company’s service territories, it continues to support those customers who may need payment assistance, arrangements or extensions.

The IURC and PUCO have either (1) issued orders to record a regulatory asset for incremental bad debt expenses related to COVID-19, including costs associated with the suspension of disconnections and payment plans or (2) provided authority to recover bad debt expense through an existing tracking mechanism. The IURC issued an order in October 2021 for CEI South and November 2021 approving settlements in each of their recent base rate cases which included recovery of the applicable regulatory asset. The Company has recorded estimated incremental uncollectible receivables to the associated regulatory asset of $2 million and $3 million, as of December 31, 2021 and 2020, respectively.

The IURC and PUCO have authorized utilities to employ deferred accounting authority for certain COVID-19 related costs which ensure the safety and health of customers, employees, and contractors, that would not have been incurred in the normal course of business.

(6) Transactions with Other Vectren Companies and Affiliates

Vectren Infrastructure Services Corporation (VISCO)

On April 9, 2020, Vectren closed on a transaction to sell its Infrastructure Services business which provided underground pipeline construction and repair services. VISCO’s customers included the Company's utilities and fees incurred by the Company totaled:


	Year Ended December 31,
	2020(1)		2019
	(in millions)
Pipeline construction and repair services (2)	$	55	$	150

(1)Represents charges for the period, January 1, 2020 until the closing of the sale of VISCO.

(2)Amounts owed to VISCO are included in Accounts payable - affiliated companies.

Support Services & Purchases

Affiliates of CenterPoint Energy and Vectren provide corporate and general and administrative services to the Company and allocates certain costs to the Company. These services are billed to the Company at actual cost, either directly or as an allocation using various allocators, including number of employees, number of customers and/or the level of payroll, revenue contribution and capital expenditures. Affiliates of CenterPoint Energy provide other miscellaneous services, including geographic services and other management support. These services are billed at actual cost, and the charges are not necessarily indicative of what would have been incurred had CenterPoint Energy's subsidiaries not been affiliates. Amounts owed for support services and purchases as of December 31, 2021 and 2020 are included in Accounts payable - affiliated companies.

Additionally, CenterPoint Energy, through an energy service subsidiary divested in June 2020, sold natural gas to the Company's Electric reportable segment for use in electric generation activities. Contracts for natural gas were executed in a competitive bidding process and are reflective of what would have been incurred had CenterPoint Energy not been an affiliate.


	Year Ended December 31,
	2021		2020		2019
	(in millions)
Affiliate natural gas expense (1)	$	—	$	1	$	1
Corporate allocations (2)	111		51		92

(1)Amounts charged for natural gas are included primarily in Utility natural gas until the closing of the sale of CenterPoint Energy's energy service subsidiary.

(2)The allocated costs in 2021, 2020 and 2019 also include allocations from CenterPoint Energy for corporate service charges. Amounts charged for corporate allocations are reflected primarily in Operation and maintenance expense. The increased allocated costs in 2021 primarily related to a technology project. The allocated costs in 2019 include $22 million of severance and $26 million of stock-based compensation as a result of the Merger with CenterPoint Energy.

Retirement Plans & Other Postretirement Benefits

As of December 31, 2021, Vectren maintains three closed qualified defined benefit pension plans, a nonqualified SERP, and a postretirement benefit plan. Vectren's defined benefit pension plans and postretirement benefit plan, which cover the Company’s eligible full-time regular employees, are primarily noncontributory. The postretirement benefit plan includes health care and life insurance benefits which are a combination of self-insured and fully insured programs. Vectren's current and former employees comprise the vast majority of the participants and retirees covered by these plans. Effective in 2021, certain participants of the Vectren Non-Bargaining Retirement Plan and all liabilities and assets associated with the accrued benefits of such participants were transferred to and became participants of the CenterPoint Energy pension plan.

Vectren satisfies the future funding requirements for its funded plans and the payment of benefits for unfunded plans from general corporate assets and, as necessary, relies on the Company to support the funding of these obligations. However, the Company has no contractual funding obligation to the plans. The Company did not make a contribution in 2021 or 2020 to the Company's parents' deferred benefit and pension plans. The Company contributed $2 million and $3 million in 2021 and 2020, respectively, to Vectren's SERP and post retirement benefit plans. The combined funded status of Vectren's pension plans was approximately 100 percent and 92 percent, respectively, as of December 31, 2021 and 2020. The combined funded status of CenterPoint Energy's, excluding Vectren, defined benefit pension plans was approximately 92 percent as of December 31, 2021.

Vectren allocates retirement plan and other postretirement benefit plan periodic cost calculated pursuant to GAAP to its subsidiaries, which is also how the Company’s rate regulated utilities recover retirement plan periodic costs through base rates. Periodic costs are charged to the Company following a labor cost allocation methodology and results in retirement costs being allocated to both operating expense and capital projects. For the years ended December 31, 2021, 2020, and 2019, costs totaling $6 million, $10 million and $16 million, respectively, were charged to the Company from CenterPoint Energy.

Any difference between the Company's funding requirements to Vectren and allocated periodic costs is recognized by the Company as an intercompany asset or liability. The allocation methodology to determine the intercompany funding requirements from the subsidiaries to Vectren is consistent with FASB guidance related to "multiemployer" benefit accounting. Neither plan assets nor plan obligations as calculated pursuant to GAAP by Vectren are allocated to individual subsidiaries.

As of December 31, 2021 and 2020, the Company has $41 million, and $46 million, respectively, representing defined benefit funding by the Company to Vectren that is yet to be reflected in costs. As of December 31, 2021 and 2020, the Company has $35 million and $37 million, respectively, included in Other non-current liabilities representing costs related to other postretirement benefits charged to the Company that is yet to be funded to Vectren. The Company's labor allocation methodology is used to compute the Company's funding of the defined benefit retirement and other postretirement plans to the Company's parent, which is consistent with the regulatory ratemaking processes of the Company's subsidiaries.

Share-Based Incentive Plans & Deferred Compensation Plans

Subsequent to the February 1, 2019 completion of the Merger, and pursuant to the Merger Agreement, all the share-based awards of Vectren have been settled and a majority of its deferred compensation liabilities have been settled. As of December 31, 2021, the Company does not have share-based compensation plans separate from Vectren or CenterPoint Energy.

As of December 31, 2021 most active employees of the deferred compensation plans were transferred out of VUHI and into other CenterPoint Energy companies. As of December 31, 2021 and 2020, less than $1 million and $5 million, respectively, is included in Other non-current liabilities and represents deferred compensation obligations that are yet to be funded in the plan.

Cash Management Arrangements

The Company participates in the centralized cash management program with affiliates of Vectren and has long-term borrowing arrangements with CenterPoint Energy. See Note 7 for further information regarding intercompany borrowing arrangements.

Income Taxes

The Company does not file federal or state income tax returns separate from those filed by its parent, Vectren or CenterPoint Energy. As of February 2, 2019, the Company's parent is included in CenterPoint Energy's consolidated U.S. federal income tax return. Vectren and/or certain of its subsidiaries file income tax returns in various states. Pursuant to a tax sharing agreement and for financial reporting purposes, Vectren subsidiaries record income taxes on a separate company basis. The Company's allocated share of tax effects resulting from it being a part of this consolidated tax group are recorded at the parent company level. Current taxes payable/receivable are settled with the Company's parent in cash quarterly and after filing the consolidated federal and state income tax returns.

Deferred income taxes are provided for temporary differences between the tax basis (adjusted for related unrecognized tax benefits, if any) of an asset or liability and its reported amount in the financial statements. Deferred tax assets and liabilities are computed based on the currently-enacted statutory income tax rates that are expected to be applicable when the temporary differences are scheduled to reverse. The Company’s rate-regulated utilities recognize regulatory liabilities for deferred taxes provided in excess of the current statutory tax rate and regulatory assets for deferred taxes provided at rates less than the current statutory tax rate. Such tax-related regulatory assets and liabilities are reported at the revenue requirement level and amortized to income as the related temporary differences reverse, generally over the lives of the related properties. A valuation allowance is recorded to reduce the carrying amounts of deferred tax assets unless it is more likely than not that the deferred tax assets will be realized.

Tax benefits associated with income tax positions taken, or expected to be taken, in a tax return are recorded only when the more-likely-than-not recognition threshold is satisfied and measured at the largest amount of benefit that is greater than 50 percent likely of being realized upon settlement. The Company reports interest and penalties associated with unrecognized tax benefits within Income taxes in the Consolidated Statements of Income and reports tax liabilities related to unrecognized tax benefits as part of Other non-current liabilities.

Investment tax credits (ITCs) are deferred and amortized to income over the approximate lives of the related property. Production tax credits (PTCs) are recognized as energy is generated and sold based on a per kilowatt hour rate prescribed in applicable federal and state statutes.

The Company's gas and electric utilities currently recover corporate income tax expense in approved rates charged to customers. The IURC and the PUCO both issued orders which initiated proceedings to investigate the impact of the Tax Cuts and Jobs Act (TCJA) on utility companies and customers within each state. In addition, both Commissions have ordered each utility to establish regulatory liabilities to record all estimated impacts of tax reform starting January 1, 2018. As of

December 31, 2021 and 2020, the Company has $354 million and $386 million, respectively, in liabilities associated with excess deferred income taxes.

In Indiana, the IURC approved a reduction to the Company’s current rates and charges, effective June 1, 2018, to capture the immediate impact of the lower corporate federal income tax rate. The refund of excess deferred taxes and regulatory liabilities commenced in November 2018 for the Company’s Indiana electric customers and in January 2019 for the Company’s Indiana gas customers.

In Ohio, a rate reduction to the Company's current rates and charges was effective upon the Company receiving approval of new base rates effective on September 1, 2019. In January 2019, the Company filed an application with PUCO in compliance with its October 2018 order requiring utilities to file for a request to adjust rates to reflect the impact of the TCJA, requesting authority to implement a Tax Credit and Savings Rider (TCSR) to flow back to customers the tax benefits realized under the TCJA, including the refund of excess deferred taxes and regulatory liabilities. An order was received July 1, 2020; however, it did not resolve Component D of the TCJA case. As of December 31, 2021, the Company still awaits a ruling on this portion.

The components of income tax expense and amortization of investment tax credits follow:


	Year Ended December 31,
	2021		2020		2019
	(in millions)
Current:
Federal	$	7	$	(32)	$	3
State	5		(7)		(4)
Total current taxes	12		(39)		(1)
Deferred:
Federal	(1)		63		9
State	12		25		2
Total deferred taxes	11		88		11
Investment tax credit amortization	(1)		(1)		(1)
Investment tax credit deferred	26		—		—
Total income tax expense	$	48	$	48	$	9

A reconciliation of the federal statutory rate to the effective income tax rate follows:


	Year Ended December 31,
	2021		2020		2019
Statutory rate	21	%	21	%	21	%
Regulatory liability amortization settled through rates	(7)		(7)		(11)
State and local taxes-net of federal benefit	5		2		3
All other - net	(2)		4		(7)
Effective tax rate	17	%	20	%	6	%

Significant components of the net deferred tax liability follow:


	December 31,
	2021		2020
	(in millions)
Non-current deferred tax assets:
Net operating loss & other carryforwards	$	23	$	—
Regulatory liabilities settled through future rates	82		86
Total deferred tax assets	105		86
Non-current deferred tax liabilities:
Depreciation & cost recovery timing differences	664		646
Regulatory assets recoverable through future rates	9		10

Employee benefit obligations	4		4

Deferred fuel costs	54		26
Other – net	46		46
Total deferred tax liabilities	777		732
Net non-current deferred tax liability	$	672	$	646

As of December 31, 2021, the Company had a $23 million investment tax credit carryforward that will expire in 2041. Investment tax credits of $28 million and $3 million are included in Other non-current liabilities as of December 31, 2021 and 2020, respectively.

Uncertain Tax Positions

Unrecognized tax benefits for all periods presented were not material to the Company. The net liability on the Consolidated Balance Sheet for unrecognized tax benefits inclusive of interest and penalties totaled $1 million and $1 million, respectively, at December 31, 2021 and 2020.

The Company's parent and certain of its subsidiaries file income tax returns in the U.S. federal jurisdiction and various states. The Internal Revenue Service (IRS) is currently auditing Vectren's U.S. federal income 2014-2019 tax returns. The State of Indiana, Vectren's primary state tax jurisdiction, has concluded examinations of Vectren's consolidated state income tax returns for tax years through 2017 with no adjustments. The statutes of limitations for assessment of Indiana income tax have expired with respect to tax years through 2016 except to the extent of refunds claimed on amended tax returns. Tax years through 2018 have been audited and settled with the IRS for CenterPoint Energy. For the 2019-2021 tax years, CenterPoint Energy and its subsidiaries are participants in the IRS’s Compliance Assurance Process.

(7) Borrowing Arrangements

Long-Term Debt

Long-term senior unsecured obligations and first mortgage bonds outstanding by subsidiary follow:


	December 31,
	2021		2020
	(in millions)
VUHI
Fixed Rate Affiliate Debt
2023, 3.72%	$	93	$	93
2025, 1.21%	300		300
2028, 3.20%	45		45
2030, 1.72%	175		175
2032, 3.26%	100		100
2035, 3.90%	25		25
2043, 4.25%	70		70
2045, 4.36%	95		95
2047, 3.93%	100		100
2049, 3.42%	125		125


	December 31,
	2021		2020
2050, 3.92%	175		175
2055, 4.51%	40		40
Fixed Rate Senior Unsecured Notes


2021, 4.67%	—		55
2023, 3.72%	57		57
2026, 5.02%	60		60


2035, 6.10%	75		75

2041, 5.99%	35		35
2042, 5.00%	100		100
2043, 4.25%	10		10
2045, 4.36%	40		40


Variable Rate Term Loans

Commercial Paper backed by long-term facility	350		92
Total VUHI	2,070		1,867
CEI South
First Mortgage Bonds
2022, 2013 Series C, current adjustable rate .83%, tax-exempt	5		5
2024, 2013 Series D, current adjustable rate .83%, tax-exempt	23		23
2025, 2014 Series B, current adjustable rate .83%, tax-exempt	41		41
2029, 1999 Series, 6.72%	80		80
2037, 2013 Series E, current adjustable rate .83%, tax-exempt	22		22
2038, 2013 Series A, current adjustable rate .83%, tax-exempt	22		22
2043, 2013 Series B, current adjustable rate .83%, tax-exempt	40		40
2044, 2014 Series A, 4.00%, tax-exempt	22		22
2055, 2015 Series Mt. Vernon, .875%, tax-exempt	15		23
2055, 2015 Series Warrick County, .875%, tax-exempt	23		15
Total CEI South	293		293
CEI North
Fixed Rate Senior Unsecured Notes
2025, Series E, 6.53%	10		10
2027, Series E, 6.42%	5		5
2027, Series E, 6.68%	1		1
2027, Series F, 6.34%	20		20
2028, Series F, 6.36%	10		10
2028, Series F, 6.55%	20		20
2029, Series G, 7.08%	30		30
Total CEI North	96		96
Total long-term debt payable - affiliated companies	1,343		1,343
Total long-term debt payable to third parties	1,116		913
Total long-term debt outstanding	2,459		2,256
Current maturities of long-term debt	(5)		(55)




Total long-term debt, net of current maturities	$	2,454	$	2,201

Credit Facilities. On February 4, 2021, VUHI replaced its existing revolving credit facility with a new amended and restated credit facility. The size of the facility remains unchanged and remains guaranteed by CEI South, CEI North and CEOH. The credit facility contains provisions relating to the replacement of LIBOR. The Company had the following revolving credit facility as of December 31, 2021:

Execution Date

Company

Size of Facility

Draw Rate of LIBOR plus (1)

Financial Covenant Limit on Debt for Borrowed Money to Capital Ratio

Debt for Borrowed Money to Capital Ratio as of December 31, 2021 (2)

Termination Date

(in millions)

February 4, 2021

Utility Holdings (3)

400

1.250%

65%

48.9%

February 4, 2024

(1) Based on credit ratings.

(2)As defined in the revolving credit facility agreement.

(3)This credit facility was issued by VUHI, is guaranteed by CEI South, CEI North and CEOH and includes a $20 million letter of credit sublimit. This credit facility backstops, VUHI's commercial paper program.

There were no borrowings outstanding under the revolving credit facility as of December 31, 2021.

Mandatory Tenders. Certain series of CEI South bonds, aggregating $186 million are subject to mandatory tenders prior to the bond's final maturities. In 2020, $38 million of such bonds was tendered and remarketed and $148 million of such bonds are subject to being tendered in 2023.

Future Long-Term Debt Sinking Fund Requirements and Maturities. As of December 31, 2021, CEI South had approximately $293 million aggregate principal amount of first mortgage bonds outstanding. Generally, all of CEI South's real and tangible property is subject to the lien of CEI South's mortgage indenture. CEI South may issue additional bonds under its mortgage indenture up to 60% of currently unfunded property additions. As of December 31, 2021, approximately $1.4 billion of additional first mortgage bonds could be issued on this basis. However, CEI South is also limited in its ability to issue additional bonds under its mortgage indenture due to certain provisions in its parent’s, VUHI, debt agreements.

Maturities. As of December 31, 2021, maturities of affiliate long-term debt, and third party debt, including commercial paper backed by the VUHI credit facility that expires in July 2024, were as follows:


	Affiliate Debt		Third Party Debt		Total Debt
	(in millions)
2022	$	—	$	5	$	5
2023	93		57		150
2024	—		373		373
2025	300		51		351
2026	—		60		60
2027 and thereafter	950		570		1,520

Debt Guarantees. The Company's outstanding long-term and commercial paper borrowing arrangements are jointly and severally guaranteed by CEI South, CEI North, and CEOH. The Company’s third-party long-term debt, including current portions, outstanding as of December 31, 2021, was $1,116 million.

Covenants. Both long-term and short-term borrowing arrangements contain customary default provisions; restrictions on liens, sale-leaseback transactions, mergers or consolidations, and sales of assets; and restrictions on leverage, among other restrictions. Multiple debt agreements contain a covenant that the ratio of consolidated total debt to consolidated total capitalization will not exceed 65 percent. As of December 31, 2021, the Company was in compliance with all debt covenants.

(8) Commitments and Contingencies

(a) Purchase Obligations

Commitments include minimum purchase obligations related to the Company's Natural Gas reportable segment and Electric reportable segment. A purchase obligation is defined as an agreement to purchase goods or services that is enforceable and legally binding on the Company and that specifies all significant terms, including: fixed or minimum quantities to be purchased; fixed, minimum or variable price provisions; and the approximate timing of the transaction. Contracts with minimum payment provisions have various quantity requirements and durations and are not classified as non-trading derivative assets and liabilities in the Company's Consolidated Balance Sheets as of December 31, 2021 and 2020. These contracts meet an exception as “normal purchases contracts” or do not meet the definition of a derivative. Natural gas and coal supply commitments also include transportation contracts that do not meet the definition of a derivative.

On February 9, 2021, CEI South entered into a BTA with a subsidiary of Capital Dynamics. Pursuant to the BTA, Capital Dynamics, with its partner Tenaska, will build a 300 MW solar array in Posey County, Indiana through a special purpose entity, Posey Solar. Upon completion of construction, currently projected to be at the end of 2023, and subject to IURC approval, which was received on October 27, 2021, CEI South will acquire Posey Solar and its solar array assets for a fixed purchase price. Due to rising cost for the project, caused in part by supply chain disruptions and the rising cost of commodities, Capital Dynamics is planning to downsize the project to approximately 200 MWs to remain viable. CEI South collaboratively agreed to the scope change and is currently working through contract negotiations, contingent on further IURC review and approval.

As of December 31, 2021, minimum purchase obligations were approximately:


	Natural Gas and Coal Supply		Other (1)
	(in millions)
2022	$	238	$	53
2023	191		490
2024	131		70
2025	112		30
2026	78		30
2027 and beyond	305		165

(1)VUHI’s undiscounted minimum payment obligations related to PPAs with commitments ranging from 15 to 25 years and its purchase commitment under its BTA in Posey County, Indiana at the original contracted amount, prior to any renegotiation, are included above. The remaining undiscounted payment obligations relate primarily to technology hardware and software agreements.

Excluded from the table above are estimates for cash outlays from other PPAs through CEI South that do not have minimum thresholds but do require payment when energy is generated by the provider. Costs arising from certain of these commitments are pass-through costs, generally collected dollar-for-dollar from retail customers through regulator-approved cost recovery mechanisms.

(b) AMAs

The Company entered into a third-party AMA beginning in April 2021 through March 2024 associated with its utility distribution service in Indiana. Pursuant to the provisions of the agreement, the Company either sells natural gas to the asset manager and agrees to repurchase an equivalent amount of natural gas throughout the year at the same cost, or simply purchases its full natural gas requirements at each delivery point from the asset manager. Generally, AMAs are contracts between the Company and an asset manager that are intended to transfer the working capital obligation and maximize the utilization of the assets. In these agreements, the Company agrees to release transportation and storage capacity to other parties to manage natural gas storage, supply and delivery arrangements for the Company and to use the released capacity for other purposes when it is not needed for the Company. The Company may receive compensation from the asset manager through payments made over the life of the AMAs. The Company has an obligation to purchase their winter storage requirements that have been released to the asset manager under these AMAs.

Environmental Matters

MGP Sites. The Company and its predecessors operated manufactured gas plants in the past. The Company has accrued estimated costs for investigation, remediation, and ground water monitoring that it expects to incur to fulfill its respective obligations using assumptions based on actual costs incurred, the timing of expected future payments and inflation factors, among others. While the Company has recorded all costs which it presently is obligated to incur in connection with activities at these sites, it is possible that future events may require remedial activities which are not presently foreseen, and those costs may not be subject to PRP or insurance recovery.

Indiana MGPs. In CEI North's service territory, the existence, location and certain general characteristics of 26 gas manufacturing and storage sites have been identified for which the Company may have some remedial responsibility. A remedial investigation/feasibility study was completed at one of the sites under an agreed upon order between CEI North and the IDEM, and a Record of Decision was issued by the IDEM in January 2000. The remaining sites have been submitted to the IDEM’s VRP. The Company has also identified its involvement in 5 manufactured gas plant sites in CEI South’s service territory, all of which are currently enrolled in the IDEM’s VRP. The Company is currently conducting some level of remedial activities, including groundwater monitoring at certain sites.

Total costs that may be incurred in connection with addressing these sites cannot be determined at this time. The estimated accrued costs are limited to the Company's share of the remediation efforts and are therefore net of exposures of other PRPs. The estimated range of possible remediation costs for the sites for which the Company believes it may have responsibility was based on remediation continuing for the minimum time frame given in the table below.


			December 31, 2021
			VUHI
			(in millions, except years)
Amount accrued for remediation			5
Minimum estimated remediation costs			3
Maximum estimated remediation costs			22
Minimum years of remediation			5
Maximum years of remediation			20

The cost estimates are based on studies of a site or industry average costs for remediation of sites of similar size. The actual remediation costs will depend on the number of sites to be remediated, the participation of other PRPs, if any, and the remediation methods used.

The Company does not expect the ultimate outcome of these matters to have a material adverse effect on the financial condition, results of operations or cash flows.

CCR Rule. In April 2015, the EPA finalized its CCR Rule, which regulates ash as non-hazardous material under the RCRA. The final rule allows beneficial reuse of ash, and the majority of the ash generated by CEI South’s generating plants will continue to be reused. In July 2018, the EPA released its final CCR Rule Phase I Reconsideration which extended the deadline to October 31, 2020 for ceasing placement of ash in ponds that exceed groundwater protections standards or that fail to meet location restrictions. In August 2019, the EPA proposed additional “Part A” amendments to its CCR Rule with respect to beneficial reuse of ash and other materials. Further “Part B” amendments, which related to alternate liners for CCR surface impoundments and the surface impoundment closure process, were published in March 2020. The Part A amendments were finalized in August 2020 and extended the deadline to cease placement of ash in ponds to April 11, 2021, discussed further below. The EPA published the final Part B amendments in November 2020. The Part A amendments do not restrict CEI South’s current beneficial reuse of its fly ash. The Company evaluated the Part B amendments to determine potential impacts and determined that the Part B amendments did not have an impact on its current plans. Shortly after taking office in January 2021, President Biden signed an executive order requiring agencies to review environmental actions taken by the Trump administration, including the CCR Rule Phase I Reconsideration, the Part A amendments, and the Part B amendments; the EPA has completed its review of the Phase I Reconsideration, Part A amendments, and Part B amendments and determined that the most environmentally protective course is to implement the rules.

CEI South has three ash ponds, two at the F.B. Culley facility (Culley East and Culley West) and one at the A.B. Brown facility. Under the existing CCR Rule, CEI South is required to perform integrity assessments, including ground water monitoring, at its F.B. Culley and A.B. Brown generating stations. The ground water studies are necessary to determine the remaining service life of the ponds and whether a pond must be retrofitted with liners or closed in place. CEI South’s Warrick generating unit is not included in the scope of the CCR Rule as this unit has historically been part of a larger generating station that predominantly serves an adjacent industrial facility. Preliminary groundwater monitoring indicates potential groundwater impacts very close to CEI South’s ash impoundments, and further analysis is ongoing. The CCR Rule required companies to complete location restriction determinations by October 18, 2018. CEI South completed its evaluation and determined that one F.B. Culley pond (Culley East) and the A.B. Brown pond fail the aquifer placement location restriction. As a result of this failure, CEI South was required to cease disposal of new ash in the ponds and commence closure of the ponds by April 11, 2021, unless approved for an extension. CenterPoint Energy has applied for the extensions available under the CCR Rule that would allow CEI South to continue to use the ponds through October 15, 2023. The EPA is still reviewing industry extension requests, including the Company’s extension request. Companies can continue to operate ponds pending completion of the EPA’s evaluation of the requests for extension. If the EPA denies a full extension request, that denial may result in increased and potentially significant operational costs in connection with the accelerated implementation of an alternative ash disposal system or may adversely impact CEI South’s future operations. Failure to comply with a cease waste receipt could also result in an enforcement proceeding, resulting in the imposition of fines and penalties. On April 24, 2019, CEI South received an order from the IURC approving recovery in rates of costs associated with the closure of the Culley West pond, which has already completed closure activities. On August 14, 2019, CEI South filed its petition with the IURC for recovery of costs associated with the closure of the A.B. Brown ash pond, which would include costs associated with the excavation and recycling of ponded ash. This petition was subsequently approved by the IURC on May 13, 2020. On October 28, 2020, the IURC approved CEI South’s ECA proceeding, which included the initiation of recovery of the federally mandated project costs.

CEI South continues to refine site specific estimates of closure costs for its ten-acre Culley East pond. In July 2018, CEI South filed a Complaint for Damages and Declaratory Relief against its insurers seeking reimbursement of defense, investigation and pond closure costs incurred to comply with the CCR Rule, and has since reached confidential settlement agreements with its insurers. The proceeds of these settlements will offset costs that have been and will be incurred to close the ponds.

As of December 31, 2021, the Company has recorded an approximate $90 million ARO, which represents the discounted value of future cash flow estimates to close the ponds at A.B. Brown and F.B. Culley. This estimate is subject to change due to the contractual arrangements; continued assessments of the ash, closure methods, and the timing of closure; implications of CEI South’s generation transition plan; changing environmental regulations; and proceeds received from the settlements in the aforementioned insurance proceeding. In addition to these removal costs, CEI South also anticipates equipment purchases of between $60 million and $80 million to complete the A.B. Brown closure project.

Clean Water Act Permitting of Groundwater Discharges. In April 2021, the U.S. Supreme Court issued an opinion providing that indirect discharges via groundwater or other non-point sources are subject to permitting and liability under the Clean Water Act when they are the functional equivalent of a direct discharge. The Company is evaluating the extent to which this decision will affect Clean Water Act permitting requirements and/or liability for their operations.

Other Environmental. From time to time, the Company identifies the presence of environmental contaminants during operations or on property where predecessors have conducted operations. Other such sites involving contaminants may be identified in the future. The Company has and expects to continue to remediate any identified sites consistent with state and federal legal obligations. From time to time, the Company has received notices, and may receive notices in the future, from regulatory authorities or others regarding status as a PRP in connection with sites found to require remediation due to the presence of environmental contaminants. In addition, the Company has been, or may be, named from time to time as defendants in litigation related to such sites. Although the ultimate outcome of such matters cannot be predicted at this time, the Company does not expect these matters, either individually or in the aggregate, to have a material adverse effect on their financial condition, results of operations or cash flows.

Other Proceedings

The Company is involved in other legal, environmental, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies regarding matters arising in the ordinary course of business. From time to time, the Company is also defendant in legal proceedings with respect to claims brought by various plaintiffs against broad groups of participants in the energy industry. Some of these proceedings involve substantial amounts. The Company regularly analyzes current information and, as necessary, provides accruals for probable and reasonably estimable liabilities on the eventual

disposition of these matters. The Company does not expect the disposition of these matters to have a material adverse effect on the Company's financial condition, results of operations or cash flows.

(9) Regulatory Matters

COVID-19 Regulatory Matters

For information about COVID-19 regulatory matters, see Note 5 to the consolidated financial statements.

February 2021 Winter Storm Event

The table below presents the incremental natural gas costs included in regulatory assets as of December 31, 2021 as a result of the February 2021 Winter Storm Event and the Company's requested recovery status as of March 2022.

State

Recovery Status

Legislative Activity

Incremental Gas Cost in Regulatory Assets (in millions)


CEI North	IURC issued order August 25, 2021. Recovery began September 2021 with 50% of the February 2021 variance recovered evenly over the 12‐month period September 2021 to August 2022, with the remainder of the variance recovered through a volumetric per‐therm allocation over the same 12-month period.	None.	$	63
CEI South	IURC issued order July 28, 2021. Recovery began August 2021 with 50% of the February 2021 variance recovered evenly over the 12‐month period August 2021 to July 2022, with the remainder of the variance recovered through a volumetric per‐therm allocation over the same 12-month period.	None.	11
		Total	$	74

CEI South CPCN

On February 9, 2021, CEI South entered into a BTA with a subsidiary of Capital Dynamics. Under the agreement, Capital Dynamics, with its partner Tenaska, contracted to build a 300 MW solar array in Posey County, Indiana through a special purpose entity, Posey Solar. Upon completion of construction, which is projected to be at the end of 2023, CEI South will acquire Posey Solar and its solar array assets for a fixed purchase price. On February 23, 2021, CEI South filed a CPCN with the IURC seeking approval to purchase the project. CEI South also sought approval for a 100 MW solar PPA with Clenera LLC in Warrick County, Indiana. The request accounted for increased cost of debt related to this PPA, which provides equivalent equity return to offset imputed debt during the 25 year life of the PPA. A hearing was conducted on June 21, 2021. On October 27, 2021, the IURC issued an order approving the CPCN, authorizing CEI South to purchase the Posey solar project through a BTA and approved recovery of costs via a levelized rate over the anticipated 35-year life. The IURC also approved the Warrick County solar PPA but denied the request to preemptively offset imputed debt in the PPA cost. The Posey solar project is expected to be in service by 2023. Due to rising cost for the project, caused in part by supply chain issues in the energy industry and the rising costs of commodities, we, along with Capital Dynamics, recently announced plans to downsize the project to approximately 200 MW. CEI South collaboratively agreed to the scope change and is currently working through contract negotiations, contingent on further IURC review and approval.

On June 17, 2021 CEI South filed a CPCN with the IURC seeking approval to construct two natural gas combustion turbines to replace portions of its existing coal-fired generation fleet. CEI South has also requested depreciation expense and post in-service carrying costs to be deferred in a regulatory asset until the date Indiana South’s base rates include a return on and recovery of depreciation expense on the facility. A hearing was conducted on January 26 through 28, 2022. The estimated $334 million turbine facility would be constructed at the current site of the A.B. Brown power plant in Posey County, Indiana and would provide a combined output of 460 MW. Construction of the turbines will begin following receipt of necessary regulatory approvals by the IURC and FERC, which are anticipated in the second half of 2022 and first quarter 2023, respectively. The turbines are targeted to be operational in first quarter of 2025. Subject to IURC approval, recovery of the proposed natural gas combustion turbines and regulatory asset will be requested in the next CEI South rate case expected in 2023.

On August 25, 2021, CEI South filed with the IURC seeking approval to purchase 185 MW of solar power, under a 15-year PPA, from Oriden LLC, which is developing a solar project in Vermillion County, Indiana, and 150 MW of solar power,

under a 20-year PPA, from Origis Energy USA Inc., which is developing a solar project in Knox County, Indiana. Subject to necessary approvals, both solar arrays are expected to be in service by 2023.

CEI South Securitization of Planned Generation Retirements

The State of Indiana has enacted legislation, Senate Bill 386, that would enable the Company to request approval from the IURC to securitize the remaining book value and removal costs associated with generating facilities to be retired in the next twenty-four months. The Governor of Indiana signed the legislation on April 19, 2021. The Company intends to seek securitization in the future associated with planned retirements of coal generation facilities in 2022.

Subsidiary Restructuring

In July 2021, CEI North and CEI South filed petitions with the IURC for the approval of a new financial services agreement and the confirmation of CEI North’s financing authority, and final orders were issued by the IURC on December 28, 2021. CEOH filed a similar application with the PUCO in September 2021 and the PUCO issued an order on January 26, 2022 adopting recommendations by PUCO staff. CenterPoint Energy is evaluating the transfer of Indiana North and CEOH from VUHI to CERC in order to better align its organizational structure with management and financial reporting. Both the IURC and PUCO have approved the transaction. As a part of the restructuring, VUHI may approach certain of its debt holders with an offer to exchange existing VUHI debt for CERC debt. The orders allow the reissuance of existing debt of Indiana North and CEOH to CERC, to continue to amortize existing issuance expenses and discounts, and to treat any potential exchange fees as discounts to be amortized over the life of the debt. If CenterPoint Energy moves forward with the restructuring, including any VUHI debt exchanges, it is expected to be completed in 2022.

CEI South Base Rate Case

On October 30, 2020, and as subsequently amended, CEI South filed its base rate case with the IURC seeking approval for a revenue increase of approximately $29 million. This rate case filing is required under Indiana TDSIC statutory requirements before the completion of Indiana South’s capital expenditure program, approved in 2014 for investments starting in 2014 through 2020. The revenue increase is based upon a requested ROE of 10.15% and an overall after-tax rate of return of 5.99% on total rate base of approximately $469 million. Indiana South has utilized a projected test year, reflecting its 2021 budget as the basis for the revenue increase requested and proposes to implement rates in two phases. On April 23, 2021, a Stipulation and Settlement Agreement was filed resolving all issues in the case. The settlement recommended a revenue increase of $21 million based on a 9.7% ROE and an overall after-tax rate of return of 5.78% on total rate base of approximately $469 million. A settlement hearing was held on June 24, 2021. On October 6, 2021, the IURC issued an order approving the settlement. Phase one rates, reflecting actual plant-in-service and cost of capital through June 2021, became effective in October 2021 and phase two rates, reflecting actual plant-in-service and cost of capital through December 2021 with certain adjustments, will become effective in March 2022.

CEI North Base Rate Case

On December 18, 2020, CEI North filed its base rate case with the IURC seeking approval for a revenue increase of approximately $21 million. This rate case filing is required under Indiana TDSIC statutory requirements before the completion of CEI North’s capital expenditure program, approved in 2014 for investments starting in 2014 through 2020. The revenue increase is based upon a requested ROE of 10.15% and an overall after-tax rate of return of 6.32% on total rate base of approximately $1,611 million. Indiana North has utilized a projected test year, reflecting its 2021 budget as the basis for the revenue increase requested and proposes to implement rates in two phases. On June 25, 2021, a Stipulation and Settlement Agreement was filed resolving all issues in the case. The settlement recommended a revenue decrease of $6 million based on a 9.8% ROE and an overall after-tax rate of return of 6.16% on total rate base of approximately $1,611 million. A settlement hearing was held August 6, 2021. On November 17, 2021, the IURC issued an order approving the settlement. Phase one rates, reflecting actual plant-in-service and cost of capital through June 2021, became effective in November 2021 and phase two rates, reflecting actual plant-in-service and cost of capital through December 2021 with certain adjustments, will become effective in March 2022.

Rate Change Applications

The Company is routinely involved in rate change applications before state regulatory authorities. Those applications include general rate cases, where the entire cost of service of the utility is assessed and reset. In addition, the Company is periodically involved in proceedings to adjust its capital tracking mechanisms in Indiana (CSIA for gas and TDSIC, ECA and CECA for Electric) and Ohio (DRR), its decoupling mechanism in Indiana (SRC for gas), and its energy efficiency cost

trackers in Indiana (EEFC for gas and DSMA for electric) and Ohio (EEFR). The table below reflects significant applications pending or completed since the Company’s consolidated 2020 financial statements were furnished to the the SEC on Current Report 8-K dated March 26, 2021.

Mechanism

Annual Increase (Decrease) (1) (in millions)

Filing Date

Effective Date

Approval Date

Additional Information

CEI South - Gas (IURC)

CSIA

(1)

April
2021

July
2021

Represents an increase of $11 million to rate base (investment period July 2020 through December 2020), which reflects a $(1 million) annual decrease in current revenues. 80% of revenue requirement is included in requested rate increase and 20% is deferred until the next rate case, which was filed in December 2020. The mechanism also includes refunds associated with the TCJA, resulting in no change to the previous credit provided, and a change in the total (over)/under-recovery variance of less than $1 million annually.

Rate Case

October 2020

October 2021

See discussion above under CEI South Base Rate Case.

CEI North - Gas (IURC)

CSIA

April
2021

July
2021

Represents an increase of $37 million to rate base (investment period July 2020 through December 2020), which reflects a $5 million annual increase in current revenues. 80% of revenue requirement is included in requested rate increase and 20% is deferred until the next rate case, which was filed in December 2020. The mechanism also includes refunds associated with the TCJA, resulting in no change to the previous credit provided, and a change in the total (over)/under-recovery variance of $6 million annually.

Rate Case

December 2020

November 2021

See discussion above under CEI North Base Rate Case.

CEOH (PUCO)

DRR

April
2021

September 2021

Represents an increase of $71 million to rate base for investments made in 2020, which reflects a $9 million annual increase in current revenues. A change in (over)/under-recovery variance of $5 million annually is also included in rates.

Mechanism

Annual Increase (Decrease) (1) (in millions)

Filing Date

Effective Date

Approval Date

Additional Information

CEI South - Electric (IURC)

TDSIC (1)

February 2022

TBD

Requested an increase of $42 million to rate base, which reflects a $3 million annual increase in current revenues. 80% of the revenue requirement is included in requested rate increase and 20% is deferred until next rate case. The mechanism also includes a change in (over)/under-recovery variance of less than $1 million.

CECA (1)

(2)

February 2022

TBD

Requested a decrease of less than $1 million to rate base, which reflects a $3 million annual decrease in current revenues. The mechanism also includes a change in (over)/under-recovery variance of less than $1 million. This mechanism includes a non-traditional rate making approach related to a 50 MW universal solar array placed in service in January 2021.

TDSIC

August 2021

November 2021

Requested an increase of $35 million to rate base, which reflects a $3 million annual increase in current revenues. 80% of the revenue requirement is included in requested rate increase and 20% is deferred until next rate case. The mechanism also includes a change in (over)/under-recovery variance of less than $1 million.

ECA

May
2021

September 2021

Requested an increase of $39 million to rate base, which reflects a $2 million annual increase in current revenues. 80% of the revenue requirement is included in requested rate increase and 20% is deferred until next rate case. The mechanism also included a change in (over)/under-recovery variance of less than $1 million annually.

TDSIC

February 2021

May
2021

Requested an increase of $28 million to rate base, which reflects a $3 million annual increase in current revenues. 80% of the revenue requirement is included in requested rate increase and 20% is deferred until next rate case. The mechanism also includes a change in (over)/under-recovery variance of less than $1 million.

CECA

February 2021

June
2021

May
2021

Reflects an $8 million annual increase in current revenues through a non-traditional rate making approach related to a 50 MW universal solar array placed in service in January 2021.

(1)Represents proposed increases (decreases) when effective date and/or approval date is not yet determined. Approved rates could differ materially from proposed rates.

(10) Environmental and Sustainability Matters

Global Climate Change

There is increasing attention being paid in the United States and worldwide to the issue of climate change. As a result, from time to time, regulatory agencies have considered the modification of existing laws or regulations or the adoption of new laws or regulations addressing the emissions of GHG on the state, federal, or international level. On August 3, 2015, the EPA released its CPP rule, which required a 32% reduction in carbon emissions from 2005 levels. The final rule was published in the Federal Register on October 23, 2015, and that action was immediately followed by litigation ultimately resulting in the U.S. Supreme Court staying implementation of the rule. On July 8, 2019, the EPA published the ACE rule, which (i) repealed the CPP rule; (ii) replaced the CPP rule with a program that requires states to implement a program of energy efficiency improvement targets for individual coal-fired electric generating units; and (iii) amended the implementing regulations for Section 111(d) of the Clean Air Act. On January 19, 2021, the majority of the ACE rule — including the CPP repeal, CPP replacement, and the timing-related portions of the Section 111(d) implementing rule — was struck down by the U.S. Court of

Appeals for the D.C. Circuit and on October 29, 2021, the U.S. Supreme Court agreed to consider four petitions filed by various coal interests and a coalition of 19 states that seek review of the lower court’s decision vacating the ACE rule. The Company is currently unable to predict what a replacement rule for either the ACE rule or CPP would require.

The Biden administration recommitted the United States to the Paris Agreement, which can be expected to drive a renewed regulatory push to require further GHG emission reductions from the energy sector and proceeded to lead negotiations at the global climate conference in Glasgow, Scotland. On April 22, 2021, President Biden announced new goals of 50% reduction of economy-wide GHG emissions, and 100% carbon-free electricity by 2035, which formed the basis of the United States' commitments announced in Glasgow. In September 2021, CenterPoint Energy announced its new net zero emissions goals for both Scope 1 and Scope 2 emissions by 2035 as well as a goal to reduce Scope 3 emissions by 20% to 30% by 2035. The Company’s revenues, operating costs and capital requirements could be adversely affected as a result of any regulatory action that would require installation of new control technologies or a modification of its operations or would have the effect of reducing the consumption of natural gas. In addition, the EPA has indicated that it intends to implement new regulations targeting reductions in methane emissions, which are likely to increase costs related to production, transmission and storage of natural gas. Incentives to conserve energy or to use energy sources other than natural gas could result in a decrease in demand for the Company’s services. Further, certain local government bodies have introduced or are considering requirements and/or incentives to reduce energy consumption by certain specified dates. These initiatives could have a significant impact on the Company and its operations, and this impact could increase if other cities and jurisdictions in its service area enact similar initiatives. Further, our third party suppliers, vendors and partners may also be impacted by climate change laws and regulations, which could impact the Company’s business by, among other things, causing permitting and construction delays, project cancellations or increased project costs passed on to the Company. Conversely, regulatory actions that effectively promote the consumption of natural gas because of its lower emissions characteristics would be expected to benefit the Company. At this time, however, the Company cannot quantify the magnitude of the impacts from possible new regulatory actions related to GHG emissions, either positive or negative, on the Company’s business.

Climate Change Trends and Uncertainties

As a result of increased awareness regarding climate change, coupled with adverse economic conditions, availability of alternative energy sources, including private solar, microturbines, fuel cells, energy-efficient buildings and energy storage devices, and new regulations restricting emissions, including potential regulations of methane emissions, some consumers and companies may use less energy, meet their own energy needs through alternative energy sources or avoid expansions of their facilities, including natural gas facilities, resulting in less demand for the Company's services. As these technologies become a more cost-competitive option over time, whether through cost effectiveness or government incentives and subsidies, certain customers may choose to meet their own energy needs and subsequently decrease usage of the Company's systems and services, which may result in, among other things, CEI South's generating facilities becoming less competitive and economical. Further, evolving investor sentiment related to the use of fossil fuels and initiatives to restrict continued production of fossil fuels have had significant impacts on the Company's electric generation and natural gas businesses. For example, because CEI South’s current generating facilities substantially rely on coal for their operations, certain financial institutions choose not to participate in the Company's financing arrangements. Conversely, demand for the Company's services may increase as a result of customer changes in response to climate change. For example, as the utilization of electric vehicles increases, demand for electricity may increase, resulting in increased usage of the Company's systems and services. Any negative opinions with respect to the Company's environmental practices or its ability to meet the challenges posed by climate change formed by regulators, customers, legislators or other stakeholders could harm its reputation.

To address these developments, the Company announced its new net zero emissions goals for both Scope 1 and Scope 2 emissions by 2035. In June of 2020, CEI South identified a preferred generation resource in its most recent IRP submitted to the IURC that aligns with its new net zero emission goals and includes the replacement of 730 MW of coal-fired generation facilities with a significant portion comprised of renewables, including solar and wind, supported by dispatchable natural gas combustion turbines, including a pipeline to serve such natural gas generation, as well as storage. The Company believes its planned investments in renewable energy generation and corresponding planned reduction in its GHG emissions as part of its newly adopted net zero emissions goals support global efforts to reduce the impacts of climate change.

To the extent climate changes result in warmer temperatures in the Company’s service territories, financial results from its business could be adversely impacted. For example, the Company could be adversely affected through lower natural gas sales. Another possible result of climate change is more frequent and more severe weather events, such as hurricanes, tornadoes and flooding, including such storms as the February 2021 Winter Storm Event. To the extent adverse weather conditions affect the Company’s suppliers, results from their natural gas business may suffer. When the Company cannot deliver natural gas to customers, or customers cannot receive services, the Company’s financial results can be impacted by lost revenues, and it

generally must seek approval from regulators to recover restoration costs. To the extent the Company is unable to recover those costs, or if higher rates resulting from recovery of such costs result in reduced demand for services, the Company’s future financial results may be adversely impacted. Further, as the intensity and frequency of significant weather events continues, it may impact the Company’s ability to secure cost-efficient insurance.

Effluent Limitation Guidelines (ELG)

In 2015, the EPA finalized revisions to the existing steam electric wastewater discharge standards which set more stringent wastewater discharge limits and effectively prohibited further wet disposal of coal ash in ash ponds. These new standards are applied at the time of permit renewal and an affected facility must comply with the wastewater discharge limitations no later than December 31, 2023, and the prohibition of wet sluicing of bottom ash no later than December 31, 2025. In February 2019, the IURC approved CEI South’s ELG compliance plan for its F.B. Culley Generating Station, and CEI South is currently finalizing its ELG compliance plan for the remainder of its affected units as part of its ongoing IRP process.

Cooling Water Intake Structures

Section 316 of the federal Clean Water Act requires steam electric generating facilities use “best technology available” to minimize adverse environmental impacts on a body of water. In May 2014, the EPA finalized a regulation requiring installation of “best technology available” to mitigate impingement and entrainment of aquatic species in cooling water intake structures. CEI South is currently completing the required ecological studies and anticipates timely compliance in 2022-2023.

(11) Fair Value Measurements

Certain methods and assumptions must be used to estimate the fair value of financial instruments. The fair value of the Company's long-term debt was estimated based on the quoted market prices for the same or similar issues or on the current rates offered to the Company for instruments with similar characteristics. Because of the maturity dates and variable interest rates of short-term borrowings and cash & cash equivalents, those carrying amounts approximate fair value. Because of the inherent difficulty of estimating interest rate and other market risks, the methods used to estimate fair value may not always be indicative of actual realizable value, and different methodologies could produce different fair value estimates at the reporting date. The carrying values and estimated fair values using primarily Level 2 assumptions of the Company's other financial instruments follow:


	December 31,
	2021				2020
	Carrying Amount		Est. Fair Value		Carrying Amount		Est. Fair Value
	(in millions)
Long-term debt payable to third parties, including Commercial Paper	$	1,116	$	1,234	$	913	$	1,070
Long-term debt payable to CenterPoint Energy	1,343		1,416		1,343		1,499

Cash and cash equivalents	7		7		8		8
Natural gas purchase instrument assets (1)	14		14		—		—
Natural gas purchase instrument liabilities (2)	—		—		10		10
Interest rate swap liabilities (2) (3)	14		14		20		20

(1)Presented in Prepaid expenses and other current assets and Other non-current assets on the Consolidated Balance Sheets.

(2) Presented in Accrued liabilities and Other non-current liabilities on the Consolidated Balance Sheets.

(3) The interest rate swaps contain provisions that require the Company to maintain an investment grade credit rating on its long-term unsecured unsubordinated debt from S&P and Moody’s. If the Company’s debt were to fall below investment grade, it would be in violation of these provisions, and the counterparties to the interest rate swaps could request immediate payment. The aggregate fair value of all derivative instruments with credit-risk-related contingent features that are in a liability position on December 31, 2021, is approximately $14 million for which the Company has posted collateral of $7 million in the normal course of business. If the credit-risk-related contingent features underlying these agreements were triggered on December 31, 2021, the Company would be required to post an additional

$7 million of collateral to its counterparties. The maximum collateral required if further escalating collateral is triggered would equal the net liability position.

Under current regulatory treatment, call premiums on reacquisition of utility-related long-term debt are generally recovered in customer rates over the life of the refunding issue. Accordingly, any reacquisition of this debt would not be expected to have a material effect on the Company's results of operations.

The Company’s Indiana gas utilities entered into four five-year forward purchase arrangements to hedge the variable price of natural gas for a portion of the Company’s gas supply. These arrangements, approved by the IURC, replaced normal purchase or normal sale long-term physical fixed-price purchases. The Company values these contracts using a pricing model that incorporates market-based information, and are classified within Level 2 of the fair value hierarchy. Gains and losses on these derivative contracts are deferred as regulatory liabilities or assets and are refunded to or collected from customers through the Company’s respective gas cost recovery mechanisms.

(12) Segment Reporting

The Company’s determination of reportable segments considers the strategic operating units under which its CODM manages sales, allocates resources and assesses performance of various products and services to wholesale or retail customers in differing regulatory environments. The Company's CODM views net income as the measure of profit or loss for the reportable segments. In 2021, VUHI transferred certain assets previously recorded in Other Operations directly into the reportable segments that received the benefits of such assets, and prior year amounts were reclassified.

As of December 31, 2021, reportable segments are as follows:

•The Natural Gas segment provides natural gas distribution and transportation services to nearly two-thirds of Indiana and to west central Ohio.

•The Electric segment provides electric generation, transmission and distribution services primarily to southwestern Indiana, and includes the Company’s power generating and wholesale power operations. Regulated operations supply natural gas and/or electricity to over one million customers.

Other operations provides information technology and other support services to the operating segments, owns shared company assets that are charged to the operating segments, as well as unallocated corporate expenses such as Merger-related costs, advertising and certain charitable contributions, among other activities, that benefit the Company’s other operating segments.

Information related to the Company’s business segments is summarized below:


	Revenues from External Customers		Depreciation and Amortization		Net Income (Loss)
	(in millions)
For the year ended December 31, 2021:
Natural Gas	$	1,087	$	180	$	146
Electric	629		116		91
Other Operations	—		3		(2)
Eliminations	—		—		—
Total	$	1,716	$	299	$	235
For the year ended December 31, 2020:
Natural Gas	$	868	$	175	$	120
Electric	554		111		73
Other Operations	—		—		(5)
Eliminations	—		—		—
Total	$	1,422	$	286	$	188


	Revenues from External Customers		Depreciation and Amortization		Net Income (Loss)
	(in millions)
For the year ended December 31, 2019:
Natural Gas	$	863	$	162	$	73
Electric	570		107		58
Other Operations	—		—		17
Eliminations	—		—		—
Total	$	1,433	$	269	$	148


	Year Ended December 31,
	2021		2020		2019
	(in millions)
Capital Expenditures
Natural Gas	$	417	$	365	$	348
Electric	210		260		204
Other Operations	48		49		6
Non-cash costs and changes in accruals	(43)		3		26
Total capital expenditures	$	632	$	677	$	584


	December 31,
	2021		2020
	(in millions)
Assets
Natural Gas	$	4,919	$	4,402
Electric	2,428		2,278
Other Operations, net of eliminations	106		142
Total assets	$	7,453	$	6,822

(13) Additional Balance Sheet and Operational Information

Prepaid expenses and other current assets in the Consolidated Balance Sheets consist of the following:


	December 31,
	2021		2020
	(in millions)
Prepaid gas delivery service	$	31	$	16
Prepaid taxes	2		17
Other prepayments & current assets	25		8
Total prepayments & other current assets	$	58	$	41

Other investments in the Consolidated Balance Sheets consist of the following:


	December 31,
	2021		2020
	(in millions)
Cash surrender value of life insurance policies	$	—	$	17


Total other investments	$	—	$	17

Accrued liabilities in the Consolidated Balance Sheets consist of the following:


	December 31,
	2021		2020
	(in millions)
Refunds to customers & customer deposits	$	40	$	40
Accrued taxes	100		51
Accrued interest	12		12
Accrued salaries & other	56		26
Total accrued liabilities	$	208	$	129

Supplemental Cash Flow Information:


	Year Ended December 31,
	2021		2020		2019
	(in millions)
Cash Payments/Receipts:
Interest	$	87	$	79	$	85
Income tax refunds	(19)		(25)		(2)
Non-cash transactions:
Accounts payable related to capital expenditures	39		8		17

(14) Impact of Recently Issued Accounting Standards

Management believes that other recently adopted standards and recently issued standards that are not yet effective will not have a material impact on the Company's financial position, results of operations or cash flows upon adoption.

(15) Leases

An arrangement is determined to be a lease at inception based on whether the Company has the right to control the use of an identified asset. ROU assets represent the Company's right to use the underlying asset for the lease term and lease liabilities represent the Company's obligation to make lease payments arising from the lease. ROU assets and liabilities are recognized at the lease commencement date based on the present value of lease payments over the lease term, including payments at commencement that depend on an index or rate. Most leases in which the Company are the lessee do not have a readily determinable implicit rate, so an incremental borrowing rate, based on the information available at the lease commencement dates, utilized to determine the present value of lease payments. When a secured borrowing rate is not readily available, unsecured borrowing rates are adjusted for the effects of collateral to determine the incremental borrowing rate. Lease expense and lease income are recognized on a straight-line basis over the lease term for operating leases.

The Company has lease agreements with lease and non-lease components and have elected the practical expedient to combine lease and non-lease components for certain classes of leases, such as office buildings. For classes of leases in which lease and non-lease components are not combined, consideration is allocated between components based on the stand-alone prices.

The Company's lease agreements do not contain any material residual value guarantees, material restrictions or material covenants. There are no material lease transactions with related parties. Because risk is minimal, the Company does not take any significant actions to manage risk associated with the residual value of their leased assets.

The Company's lease agreements are primarily equipment and real property leases, including land and office facility leases. The Company's lease terms may include options to extend or terminate a lease when it is reasonably certain that those options will be exercised. The Company has elected an accounting policy that exempts leases with terms of one year or less from the recognition requirements of ASC 842.

The components of lease cost, included in Other Operating expense on the Company's Statements of Consolidated Income, are as follows:


	Year Ended December 31,
	2021		2020
	(in millions)
Operating lease cost	$	1	$	1
Short-term lease cost	1		2

Total lease cost	$	2	$	3

Supplemental balance sheet information related to leases is as follows:


	December 31,
	2021			2020
	(in millions, except lease term and discount rate)
Assets:
Operating ROU assets (1)	$	2		$	3
Total leased assets	$	2		$	3
Liabilities:
Current operating lease liability (2)	$	1		$	1
Non-current operating lease liability (3)	1			2
Total lease liabilities	$	2		$	3

Weighted-average remaining lease term (in years) - operating leases	10			5
Weighted-average discount rate - operating leases	2.85		%	2.68		%

(1)Reported within Other assets in the Consolidated Balance Sheet

(2)Reported within Current other liabilities in the Consolidated Balance Sheet

(3)Reported within Other liabilities in the Consolidated Balance Sheet

As of December 31, 2021, maturities of operating lease liabilities were as follows:


	(in millions)
2022	$	1
2023	1
2024	—
2025	—
2026	—
2027 and beyond	1
Total lease payments	3
Less: Interest	1
Present value of lease liabilities	$	2

Other information related to leases is as follows:


	Year Ended
	December 31, 2021
	(in millions)
Operating cash flows from operating leases included in the measurement of lease liabilities	$	1

(16) Subsequent Events

Management performs a review of subsequent events for any events occurring after the balance sheet date but prior to the date the financial statements are issued. The Company's management has performed a review of subsequent events through March 16, 2022, the date the financial statements were issued.