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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d)

of the Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): March 19, 2020

CENTERPOINT ENERGY, INC.

(Exact name of registrant as specified in its charter)

_______________________________



Texas		1-31447			74-0694415
(State or other jurisdiction		(Commission File Number)			(IRS Employer
of incorporation)					Identification No.)

1111 Louisiana
Houston	Texas		77002
(Address of principal executive offices)			(Zip Code)

Registrant’s telephone number, including area code:			(713)	207-1111

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below):

☐Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

☐Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

☐Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

☐Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))



Securities registered pursuant to Section 12(b) of the Act:
Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common Stock, $0.01 par value	CNP	The New York Stock Exchange
Common Stock, $0.01 par value	CNP	Chicago Stock Exchange, Inc.
Depositary Shares for 1/20 of 7.00% Series B Mandatory Convertible Preferred Stock, $0.01 par value	CNP/PB	The New York Stock Exchange

Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (§230.405) or Rule 12b-2 of the Securities Exchange Act of 1934 (§240.12b-2).

Emerging Growth Company ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

Item 7.01 Regulation FD Disclosure.

Included herein is financial information related to Vectren Utility Holdings, Inc. (“VUHI”) and Southern Indiana Gas & Electric Company (“SIGECO”). SIGECO is a wholly-owned subsidiary of VUHI. VUHI is a wholly-owned subsidiary of Vectren Corporation (“Vectren”), which in turn, is a wholly-owned subsidiary of CenterPoint Energy, Inc. (“CenterPoint Energy”).

Exhibits 99.1 and 99.2 to this Current Report on Form 8-K includes audited financial statements for the years ended December 31, 2019 and 2018, for VUHI and SIGECO, respectively. These financial statements are not intended to comply with Regulation S-X or Regulation S-K.

Each of Exhibits 99.1 and 99.2 is furnished, not filed, pursuant to Item 7.01. Accordingly, none of the information will be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), or otherwise subject to the liability of that section, as amended, and the information in Exhibits 99.1 and 99.2 will not be incorporated by reference into any registration statement filed by CenterPoint Energy under the Securities Act of 1933, as amended, unless specifically identified as being incorporated by reference.

Item 9.01 Financial Statements and Exhibits.

Each of Exhibits 99.1 and 99.2 is furnished, not filed, pursuant to Item 7.01. Accordingly, none of the information will be deemed “filed” for purposes of Section 18 of the Exchange Act, or otherwise subject to the liability of that section, as amended, and the information in Exhibits 99.1 and 99.2 will not be incorporated by reference into any registration statement filed by CenterPoint Energy under the Securities Act of 1933, as amended, unless specifically identified as being incorporated by reference.

(d) Exhibits.



EXHIBIT NUMBER	EXHIBIT DESCRIPTION
99.1	Reporting Package of Vectren Utility Holdings, Inc.
99.2	Reporting Package of Southern Indiana Gas & Electric Company
104	Cover Page Interactive Data File - the cover page XBRL tags are embedded within the Inline XBRL document

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.



	CENTERPOINT ENERGY, INC.

Date: March 19, 2020	By:	/s/ Kristie L. Colvin
		Kristie L. Colvin
		Senior Vice President and Chief Accounting Officer

Document

VECTREN UTILITY HOLDINGS INC. AND SUBSIDIARY COMPANIES

CONSOLIDATED FINANCIAL STATEMENTS

For the year ended December 31, 2019

Contents



	Page Number
Audited Financial Statements
Independent Auditors' Report	1
Consolidated Balance Sheets	2-3
Consolidated Statements of Income	4
Consolidated Statements of Cash Flows	5
Consolidated Statements of Common Shareholders' Equity	6
Notes to the Consolidated Financial Statements	7-44



DEFINITIONS
AFUDC: allowance for funds used during construction	FASB: Financial Accounting Standards Board
ARO: Asset Retirement Obligation	FERC: Federal Energy Regulatory Commission
ASC: Accounting Standards Codification	IDEM: Indiana Department of Environmental Management
ASU: Accounting Standard Update	IURC: Indiana Utility Regulatory Commission
CECA: Clean Energy Cost Adjustment	MISO: Midcontinent Independent System Operator
CSIA: Compliance and System Improvement Adjustment	MW: megawatts
DRR: Distribution Replacement Rider	PUCO: Public Utilities Commission of Ohio
DSMA: Demand Side Management Adjustment	SERP: Supplemental Executive Retirement Plan
ECA: Environmental Cost Adjustment	SRC: Sales Reconciliation Component
EEFC: Energy Efficiency Funding Component	TCJA: Tax Cuts and Jobs Acts
EEFR: Energy Efficiency Funding Rider	TDSIC: Transmission, Distribution and Storage System Improvement Charge
EPA: Environmental Protection Agency	TSCR: Tax Savings Credit RIDER

INDEPENDENT AUDITORS’ REPORT

To the Director of Vectren Utility Holdings, Inc.

We have audited the accompanying consolidated financial statements of Vectren Utility Holdings, Inc. and its subsidiaries (the "Company")(a wholly owned subsidiary of Vectren Corporation), which comprise the consolidated balance sheets as of December 31, 2019 and 2018, and the related consolidated statements of income, comprehensive income, cash flows and common shareholder’s equity for each of the three years in the period ended December 31, 2019, and the related notes to the consolidated financial statements.

Management's Responsibility for the Consolidated Financial Statements

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

Auditors' Responsibility

Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the Company's preparation and fair presentation of the consolidated financial statements 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, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Vectren Utility Holdings, Inc. and its subsidiaries as of December 31, 2019 and 2018, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2019, in accordance with accounting principles generally accepted in the United States of America.

/s/ DELOITTE & TOUCHE LLP

Indianapolis, Indiana

March 12, 2020

VECTREN UTILITY HOLDINGS. INC. AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(In millions)



	At December 31,
	2019		2018
ASSETS
Current Assets
Cash & cash equivalents	$	10.9	$	22.5
Accounts receivable - less reserves of $4.8 & $3.7, respectively	103.4		112.9
Accrued unbilled revenues	87.2		99.3
Inventories	112.2		92.0
Recoverable fuel & natural gas costs	2.4		6.9
Prepayments & other current assets	26.9		34.4
Total current assets	343.0		368.0
Utility Plant
Original cost	8,065.7		7,528.4
Less: accumulated depreciation & amortization	3,052.4		2,891.7
Net utility plant	5,013.3		4,636.7
Investments in unconsolidated affiliates	0.2		0.2
Other investments	15.8		26.5
Nonutility plant - net	181.7		201.8
Goodwill	205.0		205.0
Regulatory assets	466.7		375.0
Other assets	77.3		60.8
TOTAL ASSETS	$	6,303.0	$	5,874.0

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

VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(In millions)



	At December 31,
	2019		2018
LIABILITIES & SHAREHOLDER'S EQUITY
Current Liabilities
Accounts payable	$	154.6	$	174.5
Affiliated payables to CenterPoint Energy, Inc.	4.0		—
Payables to other Vectren companies	33.0		27.6
Accrued liabilities	142.1		180.7
Short-term borrowings	—		166.6
Current maturities of long-term debt	400.0		—
Total current liabilities	733.7		549.4
Long-term debt - net of current maturities	1,088.9		1,779.8
Long-term debt payable to CenterPoint Energy, Inc.	693.0		—
Total long-term debt	1,781.9		1,779.8
Deferred Credits & Other Liabilities
Deferred income taxes	530.6		489.0
Regulatory liabilities	966.3		941.2
Deferred credits & other liabilities	248.6		227.4
Total deferred credits & other liabilities	1,745.5		1,657.6
Commitments & Contingencies (Notes 8-10)
Common Shareholder's Equity
Common stock (no par value)	1,033.4		979.2
Retained earnings	1,008.5		908.0
Total common shareholder's equity	2,041.9		1,887.2
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY	$	6,303.0	$	5,874.0

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

VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF INCOME

(In millions)



	Year Ended December 31,
	2019		2018		2017
OPERATING REVENUES
Gas utility	$	862.4	$	857.8	$	812.7
Electric utility	570.2		582.5		569.6
Other	0.4		0.3		0.3
Total operating revenues	1,433.0		1,440.6		1,382.6
OPERATING EXPENSES
Cost of gas sold	279.8		316.7		271.5
Cost of fuel & purchased power	165.9		186.2		171.8
Other operating	428.8		355.0		369.3
Depreciation & amortization	269.0		250.1		234.5
Taxes other than income taxes	67.7		63.9		55.9
Total operating expenses	1,211.2		1,171.9		1,103.0
OPERATING INCOME	221.8		268.7		279.6
Other income - net	21.7		36.0		29.5
Interest expense	87.0		81.4		72.6
INCOME BEFORE INCOME TAXES	156.5		223.3		236.5
Income taxes	8.5		32.7		60.7
NET INCOME	$	148.0	$	190.6	$	175.8

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

VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)



	Year Ended December 31,
	2019			2018			2017
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	148.0		$	190.6		$	175.8
Adjustments to reconcile net income to cash from operating activities:
Depreciation & amortization	269.0			250.1			234.5
Deferred income taxes & investment tax credits	33.4			20.7			45.9
Provision for uncollectible accounts	7.2			6.5			5.7
Expense portion of pension & postretirement benefit cost	14.3			4.2			3.5
Other non-cash items - net	4.5			3.5			2.0
Changes in working capital accounts:
Accounts receivable & accrued unbilled revenue	14.3			14.5			(27.0		)
Inventories	(20.2		)	25.5			1.5
Recoverable/refundable fuel & natural gas costs	5.7			12.3			10.7
Prepayments & other current assets	7.1			(1.7		)	5.1
Account payable	9.2			(59.7		)	26.2
Accrued liabilities	(30.5		)	26.7			13.9
Employer contributions to pension & postretirement plans	(17.1		)	(8.4		)	—
Changes in noncurrent assets	(50.9		)	(36.9		)	(66.0		)
Changes in noncurrent liabilities	(70.6		)	(24.5		)	15.0
Net cash from operating activities	323.4			423.4			446.8
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from:
Long-term debt, net of issuance costs	—			299.3			198.5
Long-term debt from CenterPoint Energy, Inc.	693.0			—			—
Capital contribution from parent	54.2			101.7			46.3
Requirements for:
Dividends to parent	(47.5		)	(127.9		)	(123.3		)
Retirement of long-term debt	(568.0		)	(100.0		)	—
Net change in commercial paper and short-term borrowings to third parties	101.6			(12.9		)	(14.9		)
Net cash from financing activities	233.3			160.2			106.6
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from:
Sale of Company-owned life insurance	20.2			—			2.7
Sale of investments	34.4			—			—
Requirements for:
Capital expenditures, excluding AFUDC equity	(584.4		)	(570.9		)	(554.2		)
Purchase of investments	(38.5		)	—			(1.5		)
Net cash from investing activities	(568.3		)	(570.9		)	(553.0		)
Net change in cash & cash equivalents	(11.6		)	12.7			0.4
Cash & cash equivalents at beginning of period	22.5			9.8			9.4
Cash & cash equivalents at end of period	$	10.9		$	22.5		$	9.8

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

VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER’S EQUITY

(In millions)



	Common Stock		Retained Earnings			Total
Balance at January 1, 2017	$	831.2	$	792.8		$	1,624.0
Net income			175.8			175.8
Common stock:
Additional capital contribution	46.3					46.3
Dividends			(123.3		)	(123.3		)
Balance at December 31, 2017	877.5		845.3			1,722.8
Net income			190.6			190.6
Common stock:
Additional capital contribution	101.7					101.7
Dividends			(127.9		)	(127.9		)
Balance at December 31, 2018	979.2		908.0			1,887.2
Net income			148.0			148.0
Common stock:
Additional capital contribution	54.2					54.2
Dividends			(47.5		)	(47.5		)
Balance at December 31, 2019	$	1,033.4	$	1,008.5		$	2,041.9

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

VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

1. Organization and Nature of Operations

Vectren Utility Holdings, Inc. (the Company, Utility Holdings or VUHI), an Indiana corporation, was formed on March 31, 2000, to serve as the intermediate holding company for Vectren Corporation’s (Vectren or the Company's parent) three operating public utilities: Indiana Gas Company, Inc. (Indiana Gas or Vectren Energy Delivery of Indiana - North), Southern Indiana Gas and Electric Company (SIGECO or Vectren Energy Delivery of Indiana - South), and Vectren Energy Delivery of Ohio, Inc. (VEDO). Herein, 'the Company' may also refer to Indiana Gas Company, Inc., Southern Indiana Gas and Electric Company, Inc. and/or Vectren Energy Delivery of Ohio, Inc. 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. (CenterPoint) 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).

At December 31, 2019, Indiana Gas provided energy delivery services to 615,854 natural gas customers located in central and southern Indiana. SIGECO provided energy delivery services to 147,942 electric customers and 113,193 gas customers located near Evansville in southwestern Indiana. SIGECO also owns and operates electric generation assets to serve its electric customers and optimizes those assets in the wholesale power market. Indiana Gas and SIGECO generally do business as Vectren Energy Delivery of Indiana. VEDO provided energy delivery services to 324,848 natural gas customers located near Dayton in west-central Ohio.

Merger with CenterPoint Energy, Inc.

On February 1, 2019, pursuant to the Merger Agreement, Vectren consummated the previously announced Merger with CenterPoint and was acquired for approximately $6 billion in cash. 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 consent, by Vectren's board of directors on January 16, 2019, and paid to Vectren stockholders as of the record date of February 1, 2019.

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 Other operating 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 Other operating 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

In applying its 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 utility and nonutility plant 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.

Principles of Consolidation

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

Subsequent Events Review

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 12, 2020, the date the financial statements were issued.

Cash & Cash Equivalents

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.

Accounts Receivables and Allowance for Uncollectible Accounts

Accounts receivable are recorded at the invoiced amount and do not bear interest. The Company maintains allowances for uncollectible accounts for estimated losses resulting from the inability of its customers to make required payments. The Company estimates the allowance for uncollectible accounts based on a variety of factors including the length of time receivables are past due, the financial health of its customers, unusual macroeconomic conditions, and historical experience. If the financial condition of its customers deteriorates or other circumstances occur that result in an impairment of customers’ ability to make payments, the Company records additional allowances as needed.

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.

Property, Plant & Equipment

Both the Company’s Utility Plant and Nonutility Plant are stated at historical cost, inclusive of financing costs and direct and indirect construction costs, less accumulated depreciation and when necessary, impairment charges. The cost of renewals and betterments that extend the useful life are capitalized. Maintenance and repairs, including the cost of removal of minor items of property and planned major maintenance projects, are charged to expense as incurred.

Utility Plant & Related Depreciation

Both the IURC and PUCO allow the Company’s utilities to capitalize financing costs associated with Utility Plant based on a computed interest cost and a designated cost of equity funds. These financing costs are commonly referred to as AFUDC and are capitalized for ratemaking purposes and for financial reporting purposes instead of amounts that would otherwise be capitalized when acquiring nonutility plant. The Company reports both the debt and equity components of AFUDC in Other – net in the Consolidated Statements of Income.

When property that represents a retirement unit is replaced or removed, the remaining historical value of such property is charged to Utility Plant, with an offsetting charge to Accumulated depreciation, resulting in no gain or loss. Costs to dismantle and remove retired property are recovered through the depreciation rates as determined by the IURC and PUCO.

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

Nonutility Plant & Related Depreciation

The depreciation of Nonutility Plant is charged against income over its estimated useful life, using the straight-line method of depreciation. When nonutility property is retired, or otherwise disposed of, the asset and accumulated depreciation are removed, and the resulting gain or loss is reflected in income, typically impacting operating expenses.

Impairment Reviews

Property, plant and equipment along with other long-lived assets are reviewed as facts and circumstances indicate the carrying amount may be impaired. This impairment review involves the comparison of an asset’s (or group of assets’) carrying value to the estimated undiscounted future cash flows the asset (or asset group) is expected to generate over a remaining life. If this evaluation were to conclude the carrying value is impaired, an impairment charge would be recorded based on the difference between the carrying amount and its fair value (less costs to sell for assets to be disposed of by sale) as a charge to operations or discontinued operations.

Goodwill

Goodwill recorded on the Consolidated Balance Sheets results from business acquisitions and is based on a fair value allocation of the businesses’ purchase price at the time of acquisition. Goodwill is charged to expense only when it is impaired. The Company tests its goodwill for impairment at an operating segment level because the components within the segments are similar. These tests are performed at least annually. Impairment reviews consist of a comparison of fair value to the carrying amount. If the fair value is less than the carrying amount, an impairment loss is recognized in operations. No goodwill impairments have been recorded during the periods presented.

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. SIGECO 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.

Refundable or Recoverable Gas Costs & Cost of Fuel & 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 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.

Regulatory Assets & Liabilities

Regulatory assets represent certain incurred costs, which will result in probable future cash recoveries from customers through the ratemaking process. Regulatory liabilities represent probable expenditures by the Company for removal costs or future reductions in revenues associated with amounts to be credited to customers through the ratemaking process. The Company continually assesses the recoverability of costs recognized as regulatory assets and liabilities and the ability to recognize new regulatory assets and liabilities associated with its regulated utility operations. Given the current regulatory environment in its jurisdictions, the Company believes such accounting is appropriate.

The Company collects an estimated cost of removal of its utility plant through depreciation rates established in regulatory proceedings. The Company records amounts collected in advance of expenditure as a Regulatory liability because the liability does not meet the threshold of an asset retirement obligation.

Asset Retirement Obligations

A portion of removal costs related to interim retirements of gas utility pipeline and electric utility poles, certain asbestos-related issues, and reclamation activities meet the definition of an asset retirement obligation (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.

Energy Contracts & Derivatives

The Company will periodically execute derivative contracts in the normal course of operations while buying and selling commodities to be used in operations, optimizing its generation assets, and managing risk. A derivative is recognized on the balance sheet as an asset or liability measured at its fair market value and the change in the derivative's fair market value depends on the intended use of the derivative and resulting designation.

When an energy contract that is a derivative is designated and documented as a normal purchase or normal sale (NPNS), it is exempt from mark-to-market accounting. Such energy contracts include Real Time and Day Ahead purchase and sale contracts with the MISO, certain natural gas purchases, and wind farm and other electric generating contracts.

When the Company engages in energy contracts and financial contracts that are derivatives and are not subject to the NPNS or other exclusions, such contracts are recorded at market value as current or noncurrent assets or liabilities depending on their value and when the contracts are expected to be settled. Contracts and any associated collateral with counter-parties subject to master netting arrangements are presented net in the Consolidated Balance Sheets. The offset resulting from carrying the derivative at fair value on the balance sheet is charged to earnings unless it qualifies as a hedge or is subject to regulatory accounting treatment. The offset to contracts affected by regulatory accounting treatment, which include most of the Company's executed energy and financial contracts, are marked to market as a regulatory asset or liability. Market value for derivative contracts is determined using quoted market prices from independent sources or from internal models. As of and for the periods presented, derivative activity, other than NPNS, is not material to these financial statements.

Income Taxes

On February 1, 2019, Vectren became a wholly-owned subsidiary of CenterPoint and included in CenterPoint's consolidated federal income tax return. Vectren and certain subsidiaries are also included in various unitary or consolidated state income tax returns with CenterPoint. 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.

On December 22, 2017, President Trump signed into law comprehensive tax reform legislation informally called the Tax Cuts and Jobs Acts, or TCJA, which resulted in significant changes to federal tax laws effective January 1, 2018. See Note 6 for further discussion of the impacts of tax reform implementation.

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.

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.

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 Statements of Consolidated Income in Utility natural gas, fuel and purchased power, and net sales within that interval are recorded on the Company's Statements of Consolidated 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 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.

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 operating revenues, which totaled $30.3 million in 2019, $31.1 million in 2018, and $29.1 million in 2017. Expense associated with excise and utility receipts taxes are recorded as a component of Taxes other than income taxes.

Operating Segments

The Company's chief operating decision maker is the Chief Executive Officer of CenterPoint, the Parent Company of Vectren. Beginning on February 1, 2019, upon close of the Merger, the measure of profitability used by management for all operations became operating income. Prior period segment results have been recast to reflect management's profitability measure effective during 2019. Operating income is the measure of profitability used by management for all operations. The Company’s operations consist of regulated operations and other operations that provide information technology and other support services to those regulated operations. The Company segregates its regulated operations between a Gas Utility Services operating segment and an Electric Utility Services operating segment.

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, intangible assets, 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

On January 1, 2018, the Company adopted ASC 606 and all the related amendments (“new revenue standard”) applying the modified retrospective method for those contracts that were not completed as of the date of adoption. Substantially all the Company's revenues are within the scope of the new revenue standard, although the ongoing application is expected to continue to be immaterial to the financial position, results of operations and cash flows. The adoption of the new revenue standard resulted in no cumulative adjustment to retained earnings.

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: Gas Utility Services and Electric Utility Services.

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. 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 alternative revenue programs, which are excluded from the scope of the new revenue standard. Revenues from alternative revenue programs are not material to any reporting period. 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 customer class.



(In millions)	Year Ended December 31,
(In millions)	2019		2018
Gas Utility Services
Residential	$	578.9	$	575.2
Commercial	194.3		196.6
Industrial	82.0		78.3
Other	7.2		7.7
Total Gas Utility Services	$	862.4	$	857.8

Electric Utility Services
Residential	$	210.4	$	210.2
Commercial	148.1		149.3
Industrial	159.9		162.1
Other	51.8		60.9
Total Electric Utility Services	$	570.2	$	582.5

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) as of January 1, 2019 or December 31, 2019. Substantially all the Company's accounts receivable results from contracts with customers.

Remaining Performance Obligations

In accordance with the optional exemptions available under the new revenue standard, the Company has not disclosed the value of unsatisfied performance obligations from contracts for which revenue is recognized at the amount to which the Company has the right to invoice for goods provided and services performed. Substantially all the Company's contracts with customers are eligible for this exemption.

4. Utility & Nonutility Plant

The original cost of Utility Plant, together with depreciation rates expressed as a percentage of original cost, follows:



	At and For the Year Ended December 31,
(In millions)	2019				2018
	Original Cost		Depreciation Rates as a Percent of Original Cost		Original Cost		Depreciation Rates as a Percent of Original Cost
Gas utility plant	$	4,636.3	3.4	%	$	4,315.3	3.4	%
Electric utility plant	3,077.3		3.3	%	2,945.8		3.3	%
Common utility plant	70.8		3.5	%	67.6		3.2	%
Construction work in progress	155.9		—		112.6		—
Asset retirement obligations	125.4		—		87.1		—
Total original cost	$	8,065.7			$	7,528.4

SIGECO and Alcoa Generating Corporation (AGC), a subsidiary of Alcoa, Inc. (Alcoa), own a 300 MW unit at the Warrick Power Plant (Warrick Unit 4) as tenants in common. SIGECO's share of the cost of this unit at December 31, 2019, is $194.1 million with accumulated depreciation totaling $136.8 million. AGC and SIGECO share equally in the cost of operation and output of the unit. SIGECO's share of operating costs is included in Other operating expenses in the Consolidated Statements of Income.

Nonutility Plant, net of accumulated depreciation and amortization follows:



	At December 31,
(In millions)	2019		2018
Computer hardware & software	$	145.1	$	161.7
Land & buildings	31.9		33.3
All other	4.7		6.8
Nonutility plant - net	$	181.7	$	201.8

Nonutility plant is presented net of accumulated depreciation and amortization of $323.9 million and $297.7 million as of December 31, 2019 and 2018, respectively. Depreciable lives range from 6 to15 years for computer hardware & software and 30 to 40 years for buildings. For the years ended December 31, 2019 and 2018, the Company capitalized interest totaling $2.7 million and $1.2 million, respectively.

5. Regulatory Assets & Liabilities

Regulatory Assets

Regulatory assets consist of the following:



	At December 31,
(In millions)	2019		2018
Future amounts recoverable from ratepayers related to:
Net deferred income taxes	$	7.0	$	6.6
Asset retirement obligations & other	59.1		34.4
	66.1		41.0
Amounts deferred for future recovery related to:
Indiana cost recovery riders	97.5		97.5
Ohio cost recovery riders	59.3		107.9
	156.8		205.4
Amounts currently recovered in customer rates related to:
Indiana authorized trackers	99.4		67.2
Ohio authorized trackers	7.9		33.0
Ohio authorized cost deferrals	95.8		—
Loss on reacquired debt & hedging costs	40.7		21.4
Deferred coal costs and other	—		7.0
	243.8		128.6
Total regulatory assets	$	466.7	$	375.0

Of the $243.8 million currently being recovered in customer rates, $95.8 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 $40.2 million, is 14 years. 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 Note 10 for further discussion, are 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. The settlement agreement is pending before the IURC, with an order expected in the first half of 2020. If approved, the Company would expect recovery of the approved costs to commence in 2021.

Regulatory Liabilities

At December 31, 2019 and 2018, the Company had regulatory liabilities of $966.3 million and $941.2 million, respectively, of which $548.1 million and $502.1 million related to cost of removal obligations and $416.9 million and $437.7 million related to regulatory liability associated with TCJA, at December 31, 2019 and 2018, respectively. 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.

6. Transactions with Other Vectren Companies and Affiliates

Vectren Infrastructure Services Corporation (VISCO)

VISCO, a wholly owned subsidiary of the Company's parent, provides underground pipeline construction and repair services. VISCO’s customers include the Company's utilities and fees incurred by the Company totaled $149.7 million in 2019, $140.8 million in 2018, and $157.1 million in 2017. Amounts owed to VISCO at December 31, 2019 and 2018 are included in Payables to other Vectren companies.

Support Services & Purchases

The Company's parent provides corporate and general and administrative services to the Company and allocates certain costs to the Company. These costs are allocated using various allocators, including number of employees, number of customers and/or the level of payroll, revenue contribution and capital expenditures. Allocations are at cost. The Company received corporate allocations totaling $91.8 million, $52.7 million, and $64.1 million for the years ended December 31, 2019, 2018 and 2017, respectively. The allocated costs in 2019 include $21.7 million of severance and $25.9 million of stock-based compensation as a result of the Merger with CenterPoint.

Retirement Plans & Other Postretirement Benefits

At December 31, 2019, the Company's parent maintains three closed qualified defined benefit pension plans (Vectren Corporation Non-Bargaining Retirement Plan, The Indiana Gas Company, Inc. Bargaining Unit Retirement Plan, Pension Plan for Hourly Employees of Southern Indiana Gas and Electric Company), a nonqualified supplemental executive retirement plan (SERP), and a postretirement benefit plan. The 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. The Company's current and former employees comprise the vast majority of the participants and retirees covered by these plans.

The Company's parent satisfies the future funding requirements for 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 2019 and contributed $3.5 million in 2018 to the Company's parent for the deferred benefit and pension plans. The Company contributed $17.1 million in 2019 and $4.9 million in 2018 to the Company's parent for SERP and post retirement benefit plans. The combined funded status of Vectren's defined benefit pension plans was approximately 90 percent and 89 percent at December 31, 2019 and 2018, respectively.

The Company's parent allocates retirement plan and other postretirement benefit plan periodic cost calculated pursuant to US 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, 2019, 2018, and 2017, costs totaling $16.2 million, $8.2 million and $8.2 million, respectively, were charged to the Company.

Any difference between the Company's funding requirements to the Company's parent 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 the Company's parent are allocated to individual subsidiaries.

As of December 31, 2019 and 2018, the Company has $54.7 million, and $56.8 million, respectively, included in Other assets representing defined benefit funding by the Company to the Company's parent that is yet to be reflected in costs. As of

December 31, 2019 and 2018, the Company has $39.3 million and $42.3 million, respectively, included in Deferred credits & other liabilities representing costs related to other postretirement benefits charged to the Company that is yet to be funded to the Company's parent. 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

The Company does not have share-based compensation plans separate from the Company's parent. The Company recognizes its allocated portion of costs related to share-based incentive plans and deferred compensation plans in accordance with FASB guidance and to the extent these awards are expected to be settled in cash that liability is pushed down to the Company. As of December 31, 2019 and 2018, $4.4 million and $63.4 million, respectively, is included in Accrued liabilities and Deferred credits & other liabilities and represents obligations that are yet to be funded to the Company's parent. Subsequent to the February 1, 2019 completion of the Merger, and pursuant to the Merger Agreement, all the share-based awards of the Company's parent have been settled and a majority of its deferred compensation liabilities have been settled.

Income Taxes

The Company does not file federal or state income tax returns separate from those filed by its parent, Vectren Corporation. As of February 2, 2019, the Company's parent is included in CenterPoint'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 Deferred credits & other 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, 2019, the Company has $397.5 million in liabilities associated with excess deferred income taxes, and $19.4 million in liabilities associated with the impacts of tax reform on base rates, included in Regulatory Liabilities.

In Indiana, the IURC approved an initial 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. As of December 31, 2019, the case is still pending Commission review and approval, with the expectation that an Order will be received in 2020.

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



	Year Ended December 31,
(In millions)	2019			2018			2017
Current:
Federal	$	2.5		$	25.4		$	10.0
State	(3.9		)	3.8			4.8
Total current taxes	(1.4		)	29.2			14.8
Deferred:
Federal	8.6			(1.2		)	43.9
State	2.6			1.3			2.4
Total deferred taxes	11.2			0.1			46.3
Net investment tax credit deferred / (amortized)	(1.3		)	3.4			(0.4		)
Total income tax expense	$	8.5		$	32.7		$	60.7

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



	Year Ended December 31,
	2019		2018		2017
Statutory rate	21.0	%	21.0	%	35.0	%
Federal tax law change impacts	(11.4	)	(8.0	)	(9.8	)
State and local taxes-net of federal benefit	2.9		2.8		2.8
All other - net	(7.0	)	(1.2	)	(2.3	)
Effective tax rate	5.5	%	14.6	%	25.7	%

Significant components of the net deferred tax liability follow:



	At December 31,
(In millions)	2019		2018
Noncurrent deferred tax assets:
U.S. federal charitable contributions carryforwards	3.3		4.5
Regulatory liabilities settled through future rates	98.0		104.6
Total deferred tax assets	$	101.3	$	109.1
Noncurrent deferred tax liabilities:
Depreciation & cost recovery timing differences	$	567.1	$	548.7
Regulatory assets recoverable through future rates	8.4		8.1
Employee benefit obligations	3.8		(5.8		)
Deferred fuel costs	17.5		14.5
Other – net	35.1		32.6
Total deferred tax liabilities	$	631.9	$	598.1
Net noncurrent deferred tax liability	$	530.6	$	489.0

At December 31, 2019 and 2018, investment tax credits totaling $3.4 million and $4.6 million, respectively, are included in Deferred credits & other liabilities. At December 31, 2019, the Company has no alternative minimum tax carryforwards.

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 $0.8 million and $1.7 million, respectively, at December 31, 2019 and 2018.

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) has concluded examinations of Vectren's U.S. federal income tax return for tax year December 31, 2016 with no adjustments. 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 federal income tax and Indiana income tax have expired with respect to tax years through 2016 except to the extent of refunds claimed on amended tax returns. The statutes of limitations for assessment of the 2013 tax year related to the amended federal tax return will expire in 2020. The statutes of limitations for assessment of the 2012 tax year related to the amended Indiana income tax return expired in 2019. The statutes of limitations for assessment of the 2013 and 2014 tax years related to the amended Indiana income tax returns will expire in 2020.

7. Borrowing Arrangements

Long-Term Debt

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



	At December 31,
(In millions)	2019		2018
Utility Holdings
Fixed Rate Affiliate Debt
2028, 3.20%	$	45.0	—
2032, 3.26%	100.0		—
2023, 3.72%	93.0		—
2035, 3.90%	25.0		—
2047, 3.93%	100.0		—
2043, 4.25%	70.0		—
2045, 4.36%	95.0		—
2055, 4.51%	40.0		—
2049, 3.42%	125.0		—
Fixed Rate Senior Unsecured Notes
2020, 6.28%	100.0		100.0
2021, 4.67%	55.0		55.0
2023, 3.72%	57.0		150.0
2026, 5.02%	60.0		60.0
2028, 3.20%	—		45.0
2032, 3.26%	—		100.0
2035, 6.10%	75.0		75.0
2035, 3.90%	—		25.0
2041, 5.99%	35.0		35.0
2042, 5.00%	100.0		100.0
2043, 4.25%	10.0		80.0
2045, 4.36%	40.0		135.0
2047, 3.93%	—		100.0
2055, 4.51%	—		40.0
Variable Rate Term Loans
2020, current adjustable rate, 2.5125%	300.0		300.0
Commercial Paper backed by long-term facility	268.2		—
Total Utility Holdings	1,793.2		1,400.0



	At December 31,
(In millions)	2019			2018
SIGECO
First Mortgage Bonds
2022, 2013 Series C, current adjustable rate 2.190%, tax-exempt	4.6			4.6
2024, 2013 Series D, current adjustable rate 2.190%, tax-exempt	22.5			22.5
2025, 2014 Series B, current adjustable rate 2.190%, tax-exempt	41.3			41.3
2029, 1999 Series, 6.72%	80.0			80.0
2037, 2013 Series E, current adjustable rate 2.190%, tax-exempt	22.0			22.0
2038, 2013 Series A, current adjustable rate 2.190%, tax-exempt	22.2			22.2
2043, 2013 Series B, current adjustable rate 2.190%, tax-exempt	39.6			39.6
2044, 2014 Series A, 4.00%, tax-exempt	22.3			22.3
2055, 2015 Series Mt. Vernon, 2.375%, tax-exempt	23.0			23.0
2055, 2015 Series Warrick County, 2.375%, tax-exempt	15.2			15.2
Total SIGECO	292.7			292.7
Indiana Gas
Fixed Rate Senior Unsecured Notes
2025, Series E, 6.53%	10.0			10.0
2027, Series E, 6.42%	5.0			5.0
2027, Series E, 6.68%	1.0			1.0
2027, Series F, 6.34%	20.0			20.0
2028, Series F, 6.36%	10.0			10.0
2028, Series F, 6.55%	20.0			20.0
2029, Series G, 7.08%	30.0			30.0
Total Indiana Gas	96.0			96.0
Total long-term debt payable to CenterPoint Energy, Inc.	693.0			—
Total long-term debt payable to third parties	1,488.9			1,788.7
Total long-term debt outstanding	2,181.9			1,788.7
Current maturities of long-term debt	(400.0		)	—
Debt issuance costs	—			(8.4		)
Unamortized debt premium & discount - net	—			(0.5		)
Total long-term debt-net	$	1,781.9		$	1,779.8

Utility Holdings Borrowing Arrangements

In connection with the Merger, the Company made offers to prepay certain outstanding guaranteed senior notes as required pursuant to certain note purchase agreements. In turn, the Company borrowed $568 million to make the prepayment at the same interest rate and term as the notes being prepaid. The CenterPoint notes are not guaranteed by the Company's subsidiaries.

On September 10, 2019, the Company issued a 3.42% promissory note due September 15, 2049 to CenterPoint. Total gross and net proceeds to the Company were $125 million, which were used to repay borrowings under the Company's $400 million commercial paper program.

Credit Facilities: The Company had the following revolving credit facilities as of December 31, 2019:

Financial

Covenant

Limit on

Debt for

Borrowed

Money to

Draw Rate

Money to

Capital

Execution

Size of

of LIBOR

Capital

Ratio as of

Termination

Date

Company

Facility

plus ⁽¹⁾

Ratio

December 31, 2019 ⁽²⁾

Date

(in millions)

July 14, 2017

Utility Holdings ⁽³⁾

400

1.125%

65%

51.6%

July 14, 2022

⁽¹⁾Based on credit ratings as of December 31, 2019.

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

⁽³⁾ This credit facility was issued by VUHI, is guaranteed by SIGECO, Indiana Gas and VEDO and includes a $10 million swing line sublimit and a $20 million letter of credit sublimit. This credit facility backstops, VUHI's commercial paper program.

Pursuant to the Company's short-term credit facility the Merger represented an event of default. However, the banking partner in the facility waived the event of default.

Term Loans

On July 30, 2018, the Company closed a two-year term loan with two banking partners. The term loan agreement provided for a $250 million draw at closing and the remaining $50 million was drawn on December 14, 2018. Proceeds from the term loan were utilized to pay a $100 million, August 1, 2018, debt maturity and for general utility purposes. The term loan’s interest rate is currently priced at one-month LIBOR, plus a credit spread depending on the Company's credit rating. In addition, the term loan contains a provision that should the Company or any of its subsidiaries execute certain capital market transactions, and subject to certain other conditions, the outstanding balance is subject to mandatory prepayment. The term loan is jointly and severally guaranteed by the Company's wholly-owned operating companies, SIGECO, Indiana Gas, and VEDO.

SIGECO Variable Rate Tax-Exempt Bonds

On March 1, 2018 and May 1, 2018, the Company, through SIGECO, executed first and second amendments to a Bond Purchase and Covenants Agreement originally signed in September 2017. These amendments provided SIGECO the ability to remarket bonds that were callable from current bondholders on those dates. Pursuant to these amendments, lenders purchased the following SIGECO bonds on March 1 and May 1, respectively:


•	2013 Series A Notes with a principal of $22.2 million and final maturity date of March 1, 2038; and


•	2013 Series B Notes with a principal of $39.6 million and final maturity date of May 1, 2043.

Prior to the call, the 2013 Series A Notes had an interest rate of 4.0% and the 2013 Series B Notes had an interest rate of 4.05%. The bonds converted to a variable rate based on the one-month LIBOR through May 1, 2023.

The Company has now remarketed $152 million of tax-exempt bonds through the Bonds Purchase and Covenants Agreement, which is the agreement’s full capacity.

The Company, through SIGECO, executed forward starting interest rate swaps during 2017 providing that on January 1, 2020, the Company will begin hedging the variability in interest rates on the 2013 Series A, B, and E Notes through final maturity dates. The swaps contain customary terms and conditions and generally provide offset for changes in the one month LIBOR rate. Other interest rate variability that may arise through the Bond Purchase and Covenants Agreement, such as variability caused by changes in tax law or SIGECO’s credit rating, among others, may result in an actual interest rate above or below the

anticipated fixed rate. Regulatory orders require SIGECO to include the impact of its interest rate risk management activities, such as gains and losses arising from these swaps, in its cost of capital utilized in rate cases and other periodic filings.

Mandatory Tenders

At December 31, 2019, certain series of SIGECO bonds, aggregating $185.7 million were subject to mandatory tenders prior to the bonds' final maturities. $38.2 million will be tendered in 2020 and $147.5 million will be tendered in 2023.

Future Long-Term Debt Sinking Fund Requirements and Maturities

The annual sinking fund requirement of SIGECO's first mortgage bonds is 1 percent of the greatest amount of bonds outstanding under the Mortgage Indenture. This requirement may be satisfied by certification to the Trustee of unfunded property additions in the prescribed amount as provided in the Mortgage Indenture. SIGECO met the 2019 sinking fund requirement by this means and, expects to also meet this requirement in 2019 in this manner. Accordingly, the sinking fund requirement is excluded from Current liabilities in the Consolidated Balance Sheets. At December 31, 2019, $1.8 billion of SIGECO's utility plant remained unfunded under SIGECO's Mortgage Indenture. SIGECO’s gross utility plant balance subject to the Mortgage Indenture approximated $3.9 billion at December 31, 2019.

Consolidated maturities of third-party long-term debt during the years following 2019 (in millions) are $400 in 2020, $55 in 2021, $5 in 2022, $57 in 2023, $23 in 2024, and $682 thereafter. Consolidated maturities of affiliated long-term debt, excluding commercial paper backed by the VUHI credit facility that expires in July 2022, during the five years following 2019 (in millions) are $0 in 2020, $0 in 2021, $0 in 2022, $93 in 2023, $0 in 2024, and $600 thereafter.

Debt Guarantees

The Company's outstanding long-term and commercial paper borrowing arrangements are jointly and severally guaranteed by SIGECO, Indiana Gas, and VEDO. The Company’s third-party long-term debt outstanding at December 31, 2019, was $832 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, 2019, the Company was in compliance with all debt covenants.

8. Commitments & Contingencies

Commitments

The Company’s regulated utilities have both firm and non-firm commitments to purchase natural gas, coal, and electricity as well as certain transportation and storage rights and certain contracts are firm commitments under five and twenty year arrangements. Costs arising from these commitments, while significant, are pass-through costs, generally collected dollar-for-dollar from retail customers through regulator-approved cost recovery mechanisms.

The Company's minimum purchase obligations for these commitments, which have various quantity requirements and duration are $217 million in 2020, $185 million in 2021, $177 million in 2022, $153 million in 2023, $97 million in 2024 and $362 million thereafter.

Letters of Credit

The Company, from time to time, through its subsidiaries, issues letters of credit that support consolidated operations. At December 31, 2019, letters of credit outstanding total $5.0 million.

Legal and Regulatory Proceedings

The Company is party to various legal proceedings, audits, and reviews by taxing authorities and other government agencies arising in the normal course of business. In the opinion of management, there are no legal proceedings or other regulatory reviews or audits pending against the Company that are likely to have a material adverse effect on its financial position, results of operations or cash flows.

9. Regulatory Matters

Electric Generation Transition Plan

The Company must make substantial investments in its generation resources in the near term to comply with environmental regulations. On February 20, 2018, the Company filed a petition seeking authorization from the IURC to construct a new 700-850 MW natural gas combined cycle generating facility to replace the baseload capacity of its existing generation fleet at an approximate cost of $900 million, which includes the cost of a new natural gas pipeline to serve the plant.

As a part of this same proceeding, the Company also sought recovery under Indiana Senate Bill 251 of costs to be incurred for environmental investments to be made at its F.B. Culley generating plant to comply with Effluent Limitation Guidelines (ELG) and Coal Combustion Residuals (CCR) rules. The F.B. Culley investments, estimated to be approximately $95 million, began in 2019 and will allow the F.B. Culley Unit 3 generating facility to comply with environmental requirements and continue to provide generating capacity to Indiana Electric’s customers. Under Indiana Senate Bill 251, the Company sought authority to recover 80 percent of the approved costs, including a return, using a tracking mechanism, with the remaining 20 percent of the costs deferred for recovery in the Company's next base rate proceeding.

On April 24, 2019, the IURC issued an order approving the environmental investments proposed for the F.B. Culley generating facility, along with recovery of prior pollution control investments made in 2014. The order denied the proposed gas combined cycle generating facility. The Company will conduct a new Integrated Resource Plan (IRP), expected to be completed in mid-2020, to identify an appropriate investment of capital in its generation fleet to satisfy the needs of its customers and comply with environmental regulations.

During the 2019 Indiana legislative session, certain proposed legislation would have prohibited the construction of new generation assets 250 MW or larger until 2021, among other prohibitions, by directing the IURC to not issue any final orders in proceedings requesting such construction. Although this proposed legislation was ultimately defeated, a similar moratorium on the construction of new generation assets in Indiana could be reintroduced in a subsequent legislative session. Legislation has been proposed in 2020 that would require IURC approval to retire coal-fired generation. This legislation, by its terms, would sunset in early 2021 and is not expected to impact the Company as currently drafted.

With respect to its upcoming IRP, the Company has conducted a request for proposals targeting 10 to 700 MW of capacity and unit-contingent energy and anticipates filing its 2019/2020 IRP in May 2020. While the IURC does not approve or reject the IRP, the process involves the issuance of a staff report that provides comments on the IRP. Depending on comments received on the IRP, the filing of any future requests for generating facilities could be delayed. Further, certain legislative activities such as the proposed moratorium in 2019 or other legislation restricting or delaying new generation could negatively affect the Company's ability to construct new generation facilities and execution of its capital plan. Even if a generation project is approved, risks associated with the construction of any new generation exist, including the ability to procure resources needed to build at a reasonable cost, scarcity of resources and labor, ability to appropriately estimate costs of new generation, the effects of potential construction delays and cost overruns and the ability to meet capacity requirements. Further, there is no guarantee that the IURC will approve the requests included in any of the Company's future filed petitions relating to its IRP.

50 MW Solar Project

On February 20, 2018, the Company announced it was finalizing details to install an additional 50 MW of universal solar energy, consistent with its IRP, with a petition seeking authority to recover costs associated with the project pursuant to Indiana Senate Bill 29. The Company filed a settlement agreement with the intervening parties whereby the energy produced by the solar farm would be set at a fixed market rate over the life of the investment and recovered within the Company's CECA mechanism. On March 20, 2019, the IURC approved the settlement. The Company reached an agreement with the other settling parties to amend the settlement agreement to ensure the project would not cause negative tax consequences. The Company filed the amended settlement agreement with the IURC on September 16, 2019, and on January 29, 2020 the IURC approved the amended settlement agreement.

A.B. Brown Ash Pond Remediation

On August 14, 2019, the Company filed a petition with the IURC, seeking approval, as a federally mandated project, for the recovery of costs associated with the clean closure of the A.B. Brown Ash Pond pursuant to Indiana Senate Bill 251. This project, expected to last approximately 14 years, would result in the full excavation and recycling of the ponded ash in partnership with a beneficial reuse entity, totaling approximately $160 million. Under Indiana Senate Bill 251, the Company seeks authority to recover via a tracking mechanism 80 percent of the approved costs, with a return on eligible capital investments needed to allow for the extraction of the ponded ash, with the remaining 20 percent of the costs deferred for recovery in the Company's next base rate proceeding. On December 19, 2019 and subsequently on January 10, 2020, the Company filed a settlement agreement with the intervening parties whereby the costs would be recovered as requested, with an additional commitment by the Company to offset the federally mandated costs by at least $25 million, representing a combination of total cash proceeds received from the ash reuser and total insurance proceeds to be received from the Company insurers in confidential settlement agreements in the pending Complaint for Damages and Declaratory Relief filing. The settlement agreement is pending before the IURC, with an order expected in the first half of 2020. If approved, the Company would expect recovery of the approved costs to commence in 2021.

FERC Return on Equity (ROE) Complaints

On November 12, 2013, certain parties representing a group of industrial customers filed a joint complaint with the FERC under Section 206 of the Federal Power Act against the MISO and various MISO transmission owners, including SIGECO (first complaint case). The joint parties sought to reduce the 12.38 percent base ROE used in the MISO transmission owners’ rates, including SIGECO’s formula transmission rates, to 9.15 percent covering the refund period from November 12, 2013 through February 11, 2015 (first refund period). On September 28, 2016, the FERC issued an order authorizing a 10.32 percent base ROE for the first refund period and prospectively from the date of the order. Pursuant to a US Court of Appeals decision in April 2017, which challenged FERC’s prior methodology for calculating ROE, in October 2018, the FERC issued an order which established a modified calculation ROE framework. On November 15, 2018, the FERC issued an order reopening the first complaint case taking the modified ROE framework into consideration. The order proposed a preliminary ROE not materially different from the original order and directed participants to submit briefs regarding the proposed approach. Initial and reply briefs in response to the order were filed in February and April 2019, respectively.

A second customer complaint case was filed on February 11, 2015 covering the refund period from February 12, 2015 through May 11, 2016 (second refund period). An initial decision from the FERC administrative law judge on June 30, 2016, authorized a base ROE of 9.70 percent for the second refund period. Following the resolution of the first complaint case, a base ROE will be established for this period and prospectively from the date of the order.

On November 21, 2019, FERC issued an order adopting a new base ROE calculation resulting in new base ROE of 9.88 percent for the first complaint period, November 12, 2013 through February 11, 2015, in addition to periods subsequent to the original order issued on September 28, 2016. In addition, FERC dismissed the second complaint period, February 12, 2015 through May 11, 2016.

In December 2019, the MISO Transmission Owners Group and other stakeholders filed rehearing requests challenging the methodology utilized to derive the revised base ROE.

On January 21, 2020, FERC issued an order granting rehearing for the limited purpose of allowing additional time for consideration of matters raised.

Separately, on January 6, 2015, the FERC approved a MISO transmission owner joint request for an adder to the approved ROE. Under FERC regulations, transmission owners that are part of a Regional Transmission Organization (RTO) such as the MISO are authorized to earn an incentive of 50 basis points above the FERC approved ROE.

The Company has recorded a reserve for the FERC order in its financial statements, continues to evaluate the potential impacts of the rehearing requests, and does not expect any impact to be material. As of December 31, 2019, the Company had invested approximately $157.7 million in qualifying projects. The net plant balance for these projects totaled $126.7 million at December 31, 2019.

Tax Reform

The IURC and the PUCO both issued orders which initiated proceedings to investigate the impact of the TCJA on utility companies and customers within Indiana and Ohio, respectively. In addition, the IURC and PUCO have ordered each utility to establish regulatory liabilities to record all estimated impacts of tax reform starting January 1, 2018 until the date when rates are adjusted to capture these impacts. In Indiana, in response to the Company’s filing for proposed changes to its rates and charges to consider the impact of the lower federal income tax rates, the IURC approved an initial reduction to 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 Indiana electric customers and in January 2019 for Indiana gas customers. In Ohio, the initial rate reduction to current rates and charges became effective upon conclusion of its pending base rate case on August 28, 2019. In January 2019, an application was filed 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 rider to flow back to customers the tax benefits realized under the TCJA, including the refund of excess deferred taxes and regulatory liabilities. The Company expects this proceeding to be approved in 2020.

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 during 2019 and to date in 2020 for the Company.



	Annual
	Increase
	(Decrease)
	(1)	Filing	Effective	Approval
Mechanism	(in millions)	Date	Date	Date	Additional Information
Indiana South - Gas (IURC)
CSIA	3	October 2018	January 2019	January 2019	Requested an increase of $16 million to rate base, which reflects a $3 million annual increase in current revenues. 80% of revenue requirement is included in requested rate increase and 20% is deferred until next rate case. The mechanism also includes refunds associated with the TCJA, resulting in a change of $(1) million, and a change in the total (over)/under-recovery variance of $(3) million annually.
CSIA	5	April 2019	July 2019	July 2019	Requested an increase of $22 million to rate base, 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. 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 $3 million annually.



	Annual
	Increase
	(Decrease)
	(1)	Filing	Effective	Approval
Mechanism	(in millions)	Date	Date	Date	Additional Information
CSIA	3	October 2019	January 2020	January 2020	Requested an increase of $18 million to rate base, which reflects a $3 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. 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 $(0.2) million annually.
Indiana North - Gas (IURC)
CSIA	3	October 2018	January 2019	January 2019	Requested an increase of $54 million to rate base, which reflects a $3 million annual increase in current revenues. 80% of revenue requirement is included in requested rate increase and 20% is deferred until next rate case. The mechanism also includes refunds associated with the TCJA, resulting in a change of $(11) million, and a change in the total (over)/under-recovery variance of $(19) million annually.
CSIA	12	April 2019	July 2019	July 2019	Requested an increase of $58 million to rate base, which reflects a $12 million annual increase in current revenues. 80% of revenue requirement is included in requested rate increase and 20% is deferred until next rate case. 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 $14 million annually.
CSIA	4	October 2019	January 2020	January 2020	Requested an increase of $29 million to rate base, which reflects a $4 million annual increase in current revenues. 80% of revenue requirement is included in requested rate increase and 20% is deferred until next rate case. 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 $(7) million annually.
Ohio (PUCO)
DRR	11	May 2019	September 2019	August 2019	Requested an increase of $78 million to rate base for investments made in 2018, which reflects a $11 million annual increase in current revenues. A change in (over)/under-recovery variance of $(3) million annually is also included in rates. All pre-2018 investments are included in rate case request.



	Annual
	Increase
	(Decrease)
	(1)	Filing	Effective	Approval
Mechanism	(in millions)	Date	Date	Date	Additional Information
Rate Case	23	March 2018	September 2019	August 2019	Settlement agreement approved by PUCO Order that provides for a $23 million annual increase in current revenues. Order based upon $622 million of total rate base, a 7.48% overall rate of return, and extension of conservation and DRR programs. Order also includes approval of continued deferral authority under HB95 and a Capital Expenditure Program (CEP) Rider for the recovery of accounting deferrals on eligible investments starting with deferrals in 2018.
TSCR (1)	(18)	January 2019	TBD	TBD	Application to flow back to customers certain benefits from the TCJA. Initial impact reflects credits for 2018 of $(10) million and 2019 of $(8) million, with mechanism to begin subsequent to new base rates. Order is expected in early 2020.
Indiana Electric (IURC)
TDSIC	3	February 2019	May 2019	May 2019	Requested an increase of $24 million to rate base, which reflects a $3 million annual increase in current revenues. 80% of revenue requirement is included in requested rate increase and 20% is deferred until next rate case. The mechanism also includes refunds associated with the TCJA, resulting in a change of $5 million, and a change in the total (over)/under-recovery variance of $5 million annually.
TDSIC	4	August 2019	November 2019	November 2019	Requested an increase of $35 million to rate base, which reflects a $4 million annual increase in current revenues. 80% of 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 $4 million annually.
TDSIC (1)	4	February 2020	May 2020	TBD	Requested an increase of $34 million to rate base, which reflects a $4 million annual increase in current revenues. 80% of 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 $2 million annually.
ECA - MATS	13	February 2018	January 2019	April 2019	Requested an increase of $58 million to rate base, which reflects a $13 million annual increase in current revenues. 80% of revenue requirement is included in requested rate increase and 20% is deferred until next rate case. The mechanism includes recovery of prior accounting deferrals associated with investments (depreciation, carrying costs, operating expenses).
CECA	2	February 2019	June 2019	May 2019	Requested an increase of $13 million to rate base related to solar pilot investments, which reflects a $2 million annual increase in current revenues.



	Annual
	Increase
	(Decrease)
	(1)	Filing	Effective	Approval
Mechanism	(in millions)	Date	Date	Date	Additional Information
CECA ⁽¹⁾	—	February 2020	June 2020	TBD	Requested an increase of $0.1 million to rate base related to solar pilot investments, which reflects an immaterial change to current revenues. The mechanism also includes a change in (over) under-recovery variance of $0.1 million annually. Additional solar investment to supply 50 MW of solar capacity is approved and will be included for recovery once completed in 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.

Other Generation Developments

On September 21, 2017, the Company and Alcoa agreed to continue the joint ownership and operation of Warrick Unit 4 through 2023.

10. Environmental and Sustainability Matters

Coal Ash Waste Disposal, Ash Ponds and Water

Coal Combustion Residuals Rule

In April 2015, the EPA finalized its CCR Rule, which regulates ash as non-hazardous material under the Resource Conservation and Recovery Act of 1976 (RCRA). The final rule allows beneficial reuse of ash, and the majority of the ash generated by the Company'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 or ceasing placement of ash in ponds that exceed groundwater protections standards or that fail to meet location restrictions. While the EPA Phase I Reconsideration moves forward, the existing CCR compliance obligations remain in effect. In August 2019, the EPA proposed additional amendments to its CCR Rule with respect to beneficial reuse of ash and other materials. The proposed revisions would not restrict the Company's current beneficial reuse of its fly ash.

The Company 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, the Company 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, with bottom ash handling conversions completed. The Company'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. In March 2018, the Company began posting ground water data monitoring reports annually to its public website in accordance with the requirements of the CCR Rule. This data preliminarily indicates potential groundwater impacts very close to the Company's ash impoundments, and further analysis is ongoing. The CCR Rule required companies to complete location restriction determinations by October 18, 2018. The Company 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, the Company is required to cease disposal of new ash in the ponds and commence closure of the ponds by August 2020. The Company plans to seek extensions available under the CCR Rule that would allow the Company to continue to use the ponds through December 31, 2023. The inability to take these extensions may result in increased and potentially significant operational costs in connection with the accelerated implementation of an alternative ash disposal system or adversely impact the Company's future operations. Failure to comply with these requirements could also result in an enforcement proceeding including the imposition of fines and penalties. On April 24, 2019, the Company received an order from the IURC approving recovery in rates of costs associated with the closure of the Culley West pond, which has already commenced

closure activities. The Company believes the language in the IURC order is favorable for future recovery of closure costs for the Company's remaining ponds.

The Company continues to refine site specific estimates of closure costs. In March 2019, the Company entered into agreements with third parties for the excavation and beneficial reuse of the ash at the A.B. Brown ash pond. On August 14, 2019, the Company 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 the ponded ash. In July 2018, the Company 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. On November 4, 2019, the EPA released a pre-publication copy of proposed revisions to the CCR Rule. The Company will evaluate the proposals to determine potential impacts to current compliance plans for its A.B. Brown and F.B. Culley generating stations.

As of December 31, 2019, the Company has recorded an approximate $68 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 the Company's generation transition plan; changing environmental regulations; and proceeds received from the settlements in the aforementioned insurance proceeding. In addition to these removal costs, the Company also anticipates equipment purchases of between $60 million and $80 million to complete the A.B. Brown closure project.

Effluent Limitation Guidelines (ELG)

Under the Clean Water Act, the EPA sets technology-based guidelines for water discharges from new and existing electric generation facilities. In September 2015, the EPA finalized revisions to the existing steam electric ELG setting stringent technology-based water discharge limits for the electric power industry. The EPA focused this rulemaking on wastewater generated primarily by pollution control equipment necessitated by the comprehensive air regulations, specifically setting strict water discharge limits for arsenic, mercury and selenium for scrubber waste waters. The ELG will be implemented when existing water discharge permits for the plants are renewed. In the case of the Company's water discharge permits, in 2017 the IDEM issued final renewals for the F.B. Culley and A.B. Brown power plants. IDEM agreed that units identified for retirement by December 2023 would not be required to install new treatment technology to meet ELG, and approved a 2020 compliance date for dry bottom ash and a 2023 compliance date for flue gas desulfurization wastewater treatment standards for the remaining coal-fired unit at F.B. Culley.

On April 13, 2017, as part of the U.S. President’s Administration’s regulatory reform initiative, which is focused on the number and nature of regulations, the EPA granted petitions to reconsider the ELG rule, and indicated it would stay the current implementation deadlines in the rule during the pendency of the reconsideration. On September 13, 2017, the EPA finalized a rule postponing certain interim compliance dates by two years, but did not postpone final compliance deadline of December 31, 2023. In April 2018, the EPA published an effluent guidelines program plan that anticipated a December 2019 rule revising the effluent limitations and pre-treatment standards for existing sources of the 2015 rule. On April 12, 2019, the U.S. Court of Appeals for the Fifth Circuit vacated and remanded portions of the ELG that selected impoundment as the best available technology for legacy wastewater and leachate. It is not clear what revisions to the ELG rule the EPA will implement, or what effect those revisions may have. As the Company does not currently have short-term ELG implementation deadlines in its recently renewed wastewater discharge permits, it does not anticipate immediate impacts from the EPA’s two-year extension of preliminary implementation deadlines due to the longer compliance time frames granted by IDEM and will continue to work with IDEM to evaluate further implementation plans.

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 EPA finalized a regulation requiring installation of best technology available (BTA) to mitigate impingement entrainment of aquatic species in cooling water intake structures. The Company is currently completing the required ecological studies and anticipates timely compliance in 2021-2022.

Climate Change and Carbon Strategy

Clean Power Plan and Affordable Clean Energy (ACE) Rule

On August 3, 2015, the EPA released its final Clean Power Plan rule (CPP) which required a 32 percent 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.

In August 2018, the EPA proposed a CPP replacement rule, the ACE Rule, which was finalized in July 2019 and requires states to implement a program of energy efficiency improvement targets for individual coal-fired electric generating units. States have three years to develop state plans to implement the ACE Rule, and we do not expect a state ACE plan to be finalized and approved by the EPA until 2024. We are currently unable to predict the effect of a state plan to implement the ACE Rule but do not anticipate that such a plan would have a material effect on our results of operations, financial condition or cash flows. Additionally, the ACE Rule is currently subject to legal challenges. At this time, we are unable to determine what effect, if any, the legal challenges will have on the ACE Rule.

Impact of Legislative Actions & Other Initiatives

At this time, compliance costs and other effects associated with reductions in greenhouse gases (GHG) emissions or obtaining renewable energy sources remain uncertain. While the requirements of a state ACE rule remain uncertain, the Company will continue to monitor regulatory activity regarding GHG emission standards that may affect its electric generating units.

Manufactured Gas Plants

Vectren 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 potentially responsible parties (PRP) or insurance recovery.

In the Indiana Gas 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 (RI/FS) was completed at one of the sites under an agreed upon order between Indiana Gas 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 Voluntary Remediation Program (VRP). The Company has identified its involvement in five manufactured gas plant sites in SIGECO’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.

The Company has accrued the estimated costs for further investigation, remediation, groundwater monitoring, and related costs for the sites. As of December 31, 2019 and December 31, 2018, approximately $4.5 million and $2.6 million, respectively of accrued, but not yet spent, costs are included in Other Liabilities related to the Indiana Gas and SIGECO sites.

11. Fair Value Measurements

The carrying values and estimated fair values using primarily Level 2 assumptions of the Company's other financial instruments follow:



	At December 31,
	2019				2018
(In millions)	Carrying Amount		Est. Fair Value		Carrying Amount		Est. Fair Value
Long-term debt payable to third parties	$	1,220.7	$	1,329.9	$	1,779.8	$	1,848.7
Long-term debt payable to CenterPoint Energy, Inc.	693.0		717.0		—		—
Commercial Paper ⁽¹⁾	268.2		268.2		166.6		166.6
Cash & cash equivalents	10.9		10.9		22.5		22.5
Natural gas purchase instrument liabilities ⁽²⁾	22.2		22.2		12.1		12.1
Interest rate swap liabilities ⁽³⁾	9.8		9.8		0.1		0.1

⁽¹⁾Presented in "Long-term debt" on the Consolidated Balance Sheets in 2019.

⁽²⁾ Presented in "Accrued liabilities" and "Deferred credits & other liabilities" on the Consolidated Balance Sheets.

⁽³⁾ Presented in "Deferred credits & other liabilities" on the Consolidated Balance Sheets.

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.

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.

As described in Note 7, the Company, through SIGECO, executed forward starting interest rate swaps during 2017 providing that on January 1, 2020, the Company will begin hedging variability in interest rates. 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.

12. Segment Reporting

The Company’s operations consist of Gas Utility Services, Electric Utility Services and Other Operations. The Gas Utility Services segment provides natural gas distribution and transportation services to nearly two-thirds of Indiana and to west-central Ohio. The Electric Utility Services segment provides electric distribution services primarily to southwestern Indiana, and includes the Company’s power generating and wholesale power operations. Other Operations segment provides information technology and other support services to the other two segments. Together, Gas Utility Services and Electric Utility Services

supply natural gas and/or electricity to over one million customers. Beginning on February 1, 2019, upon close of the merger, the Company's measure of profitability used by management for all operations became operating income.

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



	Year Ended December 31,
(In millions)	2019		2018			2017
Revenues
Gas Utility Services	$	862.4	$	857.8		$	812.7
Electric Utility Services	570.2		582.5			569.6
Other Operations	0.4		0.3			0.3
Total revenues	$	1,433.0	$	1,440.6		$	1,382.6
Profitability Measure - Operating Income
Gas Utility Services	$	112.8	$	134.5		$	161.9
Electric Utility Services	91.8		117.5			137.5
Other Operations	17.2		16.7			(19.8		)
Total operating income	$	221.8	$	268.7		$	279.6
Depreciation & Amortization
Gas Utility Services	$	142.8	$	130.1		$	118.9
Electric Utility Services	99.7		91.8			89.5
Other Operations	26.5		28.2			26.1
Total depreciation & amortization	$	269.0	$	250.1		$	234.5
Capital Expenditures
Gas Utility Services	$	348.2	$	377.2		$	391.4
Electric Utility Services	204.1		163.6			105.3
Other Operations	6.5		42.8			60.1
Non-cash costs & changes in accruals	25.6		(12.7		)	(2.6		)
Total capital expenditures	$	584.4	$	570.9		$	554.2



	At December 31,
(In millions)	2019		2018		2017
Assets
Gas Utility Services	$	4,053.9	$	3,794.2	$	3,457.8
Electric Utility Services	2,053.0		1,950.0		1,820.3
Other Operations, net of eliminations	196.1		129.8		219.7
Total assets	$	6,303.0	$	5,874.0	$	5,497.8

13. Additional Balance Sheet & Operational Information

Inventories consist of the following:



	At December 31,
(In millions)	2019		2018
Gas in storage – at LIFO cost	$	39.5	$	36.0
Materials & supplies	37.9		38.0
Coal & oil for electric generation - at average cost	33.4		16.6
Other	1.4		1.4
Total inventories	$	112.2	$	92.0

Based on the average cost of gas purchased during December 2019, the cost of replacing inventories carried at LIFO cost was less than carrying value at December 31, 2019 by $8.0 million. Based on the average cost of gas purchased during December

2018, the cost of replacing inventories carried at LIFO cost was greater than the carrying value at December 31, 2018 by $2.0 million.

Prepayments & other current assets in the Consolidated Balance Sheets consist of the following:



	At December 31,
(In millions)	2019		2018
Prepaid gas delivery service	$	19.4	$	23.2
Prepaid taxes	2.5		4.0
Other prepayments & current assets	5.0		7.2
Total prepayments & other current assets	$	26.9	$	34.4

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



	At December 31,
(In millions)	2019		2018
Cash surrender value of life insurance policies	$	15.4	$	25.6
Other	0.4		0.9
Total other investments	$	15.8	$	26.5

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



	At December 31,
(In millions)	2019		2018
Refunds to customers & customer deposits	$	44.3	$	83.9
Accrued taxes	47.4		44.7
Accrued interest	13.8		15.7
Accrued salaries & other	36.6		36.4
Total accrued liabilities	$	142.1	$	180.7

Asset retirement obligations included in Deferred credits and other liabilities in the Consolidated Balance Sheets roll forward as follows:



(In millions)	2019		2018
Asset retirement obligation, January 1	$	115.9	$	106.9
Accretion	5.7		4.5
Changes in estimates, net of cash payments	38.3		4.5
Asset retirement obligation, December 31	$	159.9	$	115.9

Other – net in the Consolidated Statements of Income consists of the following:



	Year Ended December 31,
(In millions)	2019			2018			2017
AFUDC - borrowed funds	$	26.3		$	29.7		$	24.8
AFUDC - equity funds	4.1			3.4			2.6
Nonutility plant capitalized interest	0.2			1.2			1.2
Pension Settlement Charges	(10.6		)	(1.6		)	(2.1		)
Other income	1.7			3.3			4.1
Total other – net	$	21.7		$	36.0		$	30.6

Supplemental Cash Flow Information:



	Year Ended December 31,
(In millions)	2019			2018		2017
Cash paid (received) for:
Interest	$	85.2		$	83.7	$	71.2
Income taxes	(1.9		)	44.4		(6.1		)

As of December 31, 2019 and 2018, the Company has accruals related to utility and nonutility plant purchases totaling approximately $17.3 million and $35.9 million, respectively.

14. Subsidiary Guarantor & Consolidating Information

The Company’s three operating utility companies, SIGECO, Indiana Gas, and VEDO, are guarantors of the Company’s $1.2 billion in unsecured senior notes outstanding at December 31, 2019, including the Company's $400 million credit facility. The guarantees are full and unconditional and joint and several, and the Company has no subsidiaries other than the subsidiary guarantors. However, it does have operations other than those of the subsidiary guarantors. Pursuant to Item 3-10 of Regulation S-X, disclosure of the results of operations and balance sheets of the subsidiary guarantors, which are wholly owned, separate from the parent company’s operations is required. Following are consolidating financial statements including information on the combined operations of the subsidiary guarantors separate from the other operations of the parent company. Pursuant to a tax sharing agreement, consolidating tax effects, which are calculated on a separate return basis, are reflected at the parent level.

Consolidating Statement of Income for the year ended December 31, 2019 (in millions):



	Subsidiary Guarantors		Parent Company			Reclassifications & Eliminations			Consolidated
OPERATING REVENUES
Gas utility	$	862.4	$	—		$	—		$	862.4
Electric utility	570.2		—			—			570.2
Other	—		4.3			(3.9		)	0.4
Total operating revenues	1,432.6		4.3			(3.9		)	1,433.0
OPERATING EXPENSES
Cost of gas sold	279.8		—			—			279.8
Cost of fuel & purchased power	165.9		—			—			165.9
Other operating	474.0		(43.0		)	(2.2		)	428.8
Depreciation & amortization	242.5		26.4			0.1			269.0
Taxes other than income taxes	65.8		1.9			—			67.7
Total operating expenses	1,228.0		(14.7		)	(2.1		)	1,211.2
OPERATING INCOME	204.6		19.0			(1.8		)	221.8
OTHER INCOME (EXPENSE)
Equity in earnings of consolidated companies	—		130.6			(130.6		)	—
Other – net	20.6		59.8			(58.7		)	21.7
Total other income (expense)	20.6		190.4			(189.3		)	21.7
Interest expense	79.5		68.0			(60.5		)	87.0
INCOME BEFORE INCOME TAXES	145.7		141.4			(130.6		)	156.5
Income taxes	15.1		(6.6		)	—			8.5
NET INCOME	$	130.6	$	148.0		$	(130.6	)	$	148.0

Consolidating Statement of Income for the year ended December 31, 2018 (in millions):



	Subsidiary Guarantors		Parent Company			Reclassifications & Eliminations			Consolidated
OPERATING REVENUES
Gas utility	$	857.8	$	—		$	—		$	857.8
Electric utility	582.5		—			—			582.5
Other	—		47.1			(46.8		)	0.3
Total operating revenues	1,440.3		47.1			(46.8		)	1,440.6
OPERATING EXPENSES
Cost of gas sold	316.7		—			—			316.7
Cost of fuel & purchased power	186.2		—			—			186.2
Other operating	400.9		—			(45.9		)	355.0
Depreciation & amortization	222.4		27.6			0.1			250.1
Taxes other than income taxes	62.0		1.8			0.1			63.9
Total operating expenses	1,188.2		29.4			(45.7		)	1,171.9
OPERATING INCOME	252.1		17.7			(1.1		)	268.7
OTHER INCOME (EXPENSE)
Equity in earnings of consolidated companies	—		175.5			(175.5		)	—
Other – net	34.8		57.5			(56.3		)	36.0
Total other income (expense)	34.8		233.0			(231.8		)	36.0
Interest expense	76.0		62.8			(57.4		)	81.4
INCOME BEFORE INCOME TAXES	210.9		187.9			(175.5		)	223.3
Income taxes	35.4		(2.7		)	—			32.7
NET INCOME	$	175.5	$	190.6		$	(175.5	)	$	190.6

Consolidating Statement of Income for the year ended December 31, 2017 (in millions):



	Subsidiary Guarantors		Parent Company			Reclassifications & Eliminations			Consolidated
OPERATING REVENUES
Gas utility	$	812.7	$	—		$	—		$	812.7
Electric utility	569.6		—			—			569.6
Other	—		45.6			(45.3		)	0.3
Total operating revenues	1,382.3		45.6			(45.3		)	1,382.6
OPERATING EXPENSES
Cost of gas sold	271.5		—			—			271.5
Cost of fuel & purchased power	171.8		—			—			171.8
Other operating	377.5		35.7			(43.9		)	369.3
Depreciation & amortization	208.4		26.0			0.1			234.5
Taxes other than income taxes	53.8		2.0			0.1			55.9
Total operating expenses	1,083.0		63.7			(43.7		)	1,103.0
OPERATING INCOME	299.3		(18.1		)	(1.6		)	279.6
OTHER INCOME (EXPENSE)
Equity in earnings of consolidated companies	—		190.7			(190.7		)	—
Other – net	27.1		50.3			(47.9		)	29.5
Total other income (expense)	27.1		241.0			(238.6		)	29.5
Interest expense	68.8		53.3			(49.5		)	72.6
INCOME BEFORE INCOME TAXES	257.6		169.6			(190.7		)	236.5
Income taxes	66.9		(6.2		)	—			60.7
NET INCOME	$	190.7	$	175.8		$	(190.7	)	$	175.8

Consolidating Balance Sheet as of December 31, 2019 (in millions):



ASSETS	Subsidiary		Parent
	Guarantors		Company			Eliminations			Consolidated
Current Assets
Cash & cash equivalents	$	10.7	$	0.2		$	—		$	10.9
Accounts receivable - less reserves	103.3		0.1			—			103.4
Intercompany receivables	2.0		468.5			(470.5		)	—
Accrued unbilled revenues	87.2		—			—			87.2
Inventories	112.2		—			—			112.2
Recoverable fuel & natural gas costs	2.4		—			—			2.4
Prepayments & other current assets	29.0		(2.1		)	—			26.9
Total current assets	346.8		466.7			(470.5		)	343.0
Utility Plant
Original cost	8,065.7		—			—			8,065.7
Less: accumulated depreciation & amortization	3,052.4		—			—			3,052.4
Net utility plant	5,013.3		—			—			5,013.3
Investments in consolidated subsidiaries	—		2,132.5			(2,132.5		)	—
Notes receivable from consolidated subsidiaries	—		1,080.6			(1,080.6		)	—
Investments in unconsolidated affiliates	0.2		—			—			0.2
Other investments	15.4		0.4			—			15.8
Nonutility plant - net	1.5		180.2			—			181.7
Goodwill - net	205.0		—			—			205.0
Regulatory assets	448.8		17.9			—			466.7
Other assets	76.0		1.3			—			77.3
TOTAL ASSETS	$	6,107.0	$	3,879.6		$	(3,683.6	)	$	6,303.0

LIABILITIES & SHAREHOLDER'S EQUITY	Subsidiary		Parent
	Guarantors		Company			Eliminations			Consolidated
Current Liabilities
Accounts payable	$	151.7	$	2.9		$	—		$	154.6
Intercompany payables	15.7		—			(15.7		)	—
Payable to CenterPoint Energy, Inc.	0.3		3.7			—			4.0
Payables to other Vectren companies	33.0		—			—			33.0
Accrued liabilities	132.3		9.8			—			142.1
Intercompany short-term borrowings	228.4		2.0			(230.4		)	—
Current maturities of long-term debt	—		400.0			—			400.0
Current maturities of long-term debt due to VUHI	224.4		—			(224.4		)	—
Total current liabilities	785.8		418.4			(470.5		)	733.7
Long-Term Debt
Long-term debt - net of current maturities &
debt subject to tender	388.7		700.2			—			1,088.9
Long-term debt payable to CenterPoint Energy, Inc.	—		693.0			—			693.0
Long-term debt due to VUHI	1,080.6		—			(1,080.6		)	—
Total long-term debt - net	1,469.3		1,393.2			(1,080.6		)	1,781.9
Deferred Income Taxes & Other Liabilities
Deferred income taxes	506.5		24.1			—			530.6
Regulatory liabilities	965.3		1.0			—			966.3
Deferred credits & other liabilities	247.6		1.0			—			248.6
Total deferred credits & other liabilities	1,719.4		26.1			—			1,745.5
Common Shareholder's Equity
Common stock (no par value)	1,097.2		1,033.4			(1,097.2		)	1,033.4
Retained earnings	1,035.3		1,008.5			(1,035.3		)	1,008.5
Total common shareholder's equity	2,132.5		2,041.9			(2,132.5		)	2,041.9
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY	$	6,107.0	$	3,879.6		$	(3,683.6	)	$	6,303.0

Consolidating Balance Sheet as of December 31, 2018 (in millions):



ASSETS	Subsidiary		Parent
	Guarantors		Company		Eliminations			Consolidated
Current Assets
Cash & cash equivalents	$	13.0	$	9.5	$	—		$	22.5
Accounts receivable - less reserves	112.7		0.2		—			112.9
Intercompany receivables	98.8		143.6		(242.4		)	—
Accrued unbilled revenues	99.3		—		—			99.3
Inventories	92.0		—		—			92.0
Recoverable fuel & natural gas costs	6.9		—		—			6.9
Prepayments & other current assets	32.2		3.9		(1.7		)	34.4
Total current assets	454.9		157.2		(244.1		)	368.0
Utility Plant
Original cost	7,528.4		—		—			7,528.4
Less: accumulated depreciation & amortization	2,891.7		—		—			2,891.7
Net utility plant	4,636.7		—		—			4,636.7
Investments in consolidated subsidiaries	—		2,001.8		(2,001.8		)	—
Notes receivable from consolidated subsidiaries	—		1,220.0		(1,220.0		)	—
Investments in unconsolidated affiliates	0.2		—		—			0.2
Other investments	26.1		0.4		—			26.5
Nonutility plant - net	1.6		200.2		—			201.8
Goodwill - net	205.0		—		—			205.0
Regulatory assets	360.4		14.6		—			375.0
Other assets	59.3		1.5		—			60.8
TOTAL ASSETS	$	5,744.2	$	3,595.7	$	(3,465.9	)	$	5,874.0

LIABILITIES & SHAREHOLDER'S EQUITY	Subsidiary		Parent
	Guarantors		Company		Eliminations			Consolidated
Current Liabilities
Accounts payable	$	170.2	$	4.3	$	—		$	174.5
Intercompany payables	12.0		—		(12.0		)	—
Payables to other Vectren companies	27.6		—		—			27.6
Accrued liabilities	168.8		13.6		(1.7		)	180.7
Short-term borrowings	—		166.6		—			166.6
Intercompany short-term borrowings	131.6		98.8		(230.4		)	—
Total current liabilities	510.2		283.3		(244.1		)	549.4
Long-Term Debt
Long-term debt - net of current maturities &
debt subject to tender	384.3		1,395.5		—			1,779.8
Long-term debt due to VUHI	1,220.0		—		(1,220.0		)	—
Total long-term debt - net	1,604.3		1,395.5		(1,220.0		)	1,779.8
Deferred Income Taxes & Other Liabilities
Deferred income taxes	462.8		26.2		—			489.0
Regulatory liabilities	940.1		1.1		—			941.2
Deferred credits & other liabilities	225.0		2.4		—			227.4
Total deferred credits & other liabilities	1,627.9		29.7		—			1,657.6
Common Shareholder's Equity
Common stock (no par value)	1,097.2		979.2		(1,097.2		)	979.2
Retained earnings	904.6		908.0		(904.6		)	908.0
Total common shareholder's equity	2,001.8		1,887.2		(2,001.8		)	1,887.2
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY	$	5,744.2	$	3,595.7	$	(3,465.9	)	$	5,874.0

Consolidating Statement of Cash Flows for the year ended December 31, 2019 (in millions):



	Subsidiary Guarantors			Parent Company				Eliminations			Consolidated
NET CASH FROM OPERATING ACTIVITIES	$	280.0		$	43.4			$	—		$	323.4
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from:
Long-term debt from CenterPoint Energy, Inc.	653.0			693.0				(653.0		)	693.0
Additional capital contribution from parent	—			54.2				—			54.2
Requirements for:
Dividends to parent	—			(47.5		)		—			(47.5		)
Retirement of long-term debt	(568.0		)	(568.0		)		568.0			(568.0		)
Net change in intercompany short-term borrowings	96.8			(96.8		)		—			—
Net change in short-term borrowings	—			101.6				—			101.6
Net cash from financing activities	181.8			136.5				(85.0		)	233.3
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from:
Sale of Company-owned life insurance	20.2			—			—	—			20.2
Sale of investments	34.4			—				—			34.4
Requirements for:
Capital expenditures, excluding AFUDC equity	(577.0		)	(7.4		)		—			(584.4		)
Purchase of investments	(38.5		)	—				—			(38.5		)
Net change in long-term intercompany notes receivable	—			139.3				(139.3		)	—
Net change in short-term intercompany notes receivable	96.8			(321.1		)		224.3			—
Net cash from investing activities	(464.1		)	(189.2		)		85.0			(568.3		)
Net change in cash & cash equivalents	(2.3		)	(9.3		)		—			(11.6		)
Cash & cash equivalents at beginning of period	13.0			9.5				—			22.5
Cash & cash equivalents at end of period	$	10.7		$	0.2			$	—		$	10.9

Consolidating Statement of Cash Flows for the year ended December 31, 2018 (in millions):



	Subsidiary Guarantors			Parent Company			Eliminations			Consolidated
NET CASH FROM OPERATING ACTIVITIES	$	384.9		$	38.5		$	—		$	423.4
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from:
Long-term debt, net of issuance costs	248.7			299.3			(248.7		)	299.3
Additional capital contribution from parent	206.5			101.7			(206.5		)	101.7
Requirements for:
Dividends to parent	(121.2		)	(127.9		)	121.2			(127.9		)
Retirement of long-term debt	(99.0		)	(100.0		)	99.0			(100.0		)
Net change in intercompany short-term borrowings	11.5			98.7			(110.2		)	—
Net change in short-term borrowings	—			(12.9		)	—			(12.9		)
Net cash from financing activities	246.5			258.9			(345.2		)	160.2
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from:
Consolidated subsidiary distributions	—			121.2			(121.2		)	—
Requirements for:
Capital expenditures, excluding AFUDC equity	(527.9		)	(43.0		)	—			(570.9		)
Consolidated subsidiary investments	—			(206.5		)	206.5			—
Net change in long-term intercompany notes receivable	—			(149.7		)	149.7			—
Net change in short-term intercompany notes receivable	(98.7		)	(11.5		)	110.2			—
Net cash from investing activities	(626.6		)	(289.5		)	345.2			(570.9		)
Net change in cash & cash equivalents	4.8			7.9			—			12.7
Cash & cash equivalents at beginning of period	8.2			1.6			—			9.8
Cash & cash equivalents at end of period	$	13.0		$	9.5		$	—		$	22.5

Consolidating Statement of Cash Flows for the year ended December 31, 2017 (in millions):



	Subsidiary Guarantors			Parent Company			Eliminations			Consolidated
NET CASH FROM OPERATING ACTIVITIES	$	398.5		$	48.3		$	—		$	446.8
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from:
Long-term debt, net of issuance costs	123.9			198.9			(124.3		)	198.5
Additional capital contribution from parent	46.3			46.3			(46.3		)	46.3
Requirements for:
Dividends to parent	(73.1		)	(123.3		)	73.1			(123.3		)
Net change in intercompany short-term borrowings	(22.1		)	(17.5		)	39.6			—
Net change in short-term borrowings	—			(14.9		)	—			(14.9		)
Net cash from financing activities	75.0			89.5			(57.9		)	106.6
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from:
Consolidated subsidiary distributions	—			73.1			(73.1		)	—
Other investing activities	2.7			—			—			2.7
Requirements for:
Capital expenditures, excluding AFUDC equity	(491.6		)	(62.6		)	—			(554.2		)
Consolidated subsidiary investments	—			(46.3		)	46.3			—
Purchase of investments	(1.5		)	—			—			(1.5		)
Net change in long-term intercompany notes receivable	—			(124.3		)	124.3			—
Net change in short-term intercompany notes receivable	17.5			22.1			(39.6		)	—
Net cash from investing activities	(472.9		)	(138.0		)	57.9			(553.0		)
Net change in cash & cash equivalents	0.6			(0.2		)	—			0.4
Cash & cash equivalents at beginning of period	7.6			1.8			—			9.4
Cash & cash equivalents at end of period	$	8.2		$	1.6		$	—		$	9.8

15. Impact of Recently Issued Accounting Guidance

The following table provides an overview of recently adopted or issued accounting pronouncements applicable to the Company,

unless otherwise noted:



Recently Adopted Accounting Standards
ASU Number		Date of	Financial Statement Impact
and Name	Description	Adoption	upon Adoption
ASU 2016-02- Leases (Topic 842) and related amendments	ASU 2016-02 provides a comprehensive new lease model that requires lessees to recognize assets and liabilities for most leases and would change certain aspects of lessor accounting. Transition method: modified retrospective	January 1, 2019	The Company adopted the standard and recognized a right-of-use asset and lease liability on their statement of financial position with no material impact on their results of operations and cash flows. See Note 16 for more information.

Issued, Not Yet Effective Accounting Standards
ASU Number			Financial Statement Impact
and Name	Description	Effective Date	upon Adoption
ASU 2016-13- Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments	This standard, including standards amending this standard, requires a new model called CECL to estimate credit losses for (1) financial assets subject to credit losses and measured at amortized cost and (2) certain off-balance sheet credit exposures. Upon initial recognition of the exposure, the CECL model requires an entity to estimate the credit losses expected over the life of an exposure based on historical information, current information and reasonable and supportable forecasts, including estimates of prepayments. Transition method: modified retrospective	January 1, 2020 Early adoption is permitted	The adoption of this standard will result in an immaterial adjustment to the carrying value of the Company's accounts receivable, net. The adoption of this standard will not have a material impact on the Company's financial position, results of operations or cash flows.
ASU 2018-15- Intangibles-Goodwill and Other- Internal-Use Software (Subtopic 350-40): Customer's Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract	This standard aligns accounting for implementation costs incurred in a cloud computing arrangement that is accounted for as a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. The update also prescribes the balance sheet, income statement, and cash flow classification of the capitalized implementation costs and related amortization expense and requires additional quantitative and qualitative disclosures. Transition method: retrospective or prospective	January 1, 2020 Early adoption is permitted	The adoption of this standard will require the Company to capitalize certain costs to implement cloud computing arrangements that are accounted for as service contracts within Prepaid expenses and other current assets on the Company's consolidated balance sheets and record the amortization of such assets within Operation and maintenance expenses on the Company's statements of consolidated income. The adoption of this standard will not have a material impact on the Company's financial position, results of operations, cash flows or disclosures.

Management believed 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.

16. Lease

The Company adopted ASC 842, Leases, and all related amendments on January 1, 2019 using the modified retrospective transition method and elected not to recast comparative periods in the year of adoption as permitted by the standard. There was no adjustment to retained earnings as a result of transition. As a result, disclosures for periods prior to adoption will be presented in accordance with accounting standards in effect for those periods. The Company also elected the package of practical expedients permitted under the transition guidance within the new standard, which among other things, allowed them to carry forward the historical lease classification. Additionally, the Company's elected the practical expedient related to land easements, which allows the carry forward of the accounting treatment for land easements on existing agreements. The total Right of Use (ROU) assets obtained in exchange for new operating lease liabilities upon adoption were $3.6 million.

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 Operations and maintenance expense on the Company's Consolidated Statement of Income, are as follows:



	Year Ended
(In millions)	December 31, 2019

Operating lease cost	$	0.9
Short-term lease cost	1.3
Total lease cost	$	2.2

Supplemental balance sheet information related to lease is as follows:



(In millions, except lease term and discount rate)	December 31, 2019

Assets:
Operating ROU assets ⁽¹⁾	$	2.8
Total leased assets	$	2.8
Liabilities:
Current operating lease liability ⁽²⁾	$	0.8
Non-current operating lease liability ⁽³⁾	2.0
Total lease liabilities	$	2.8

Weighted-average remaining lease term (in years) - operating leases	6.1
Weighted-average discount rate - operating leases	3.57		%

⁽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, 2019, maturities of operating lease liabilities were as follows:



(In millions)
2020	$	0.8
2021	0.7
2022	0.7
2023	0.5
2024	0.1
2025 and beyond	0.3
Total lease payments	$	3.1
Less: Interest	0.3
Present value of lease liabilities	$	2.8

The following table sets forth information concerning the Company's obligations under non-cancelable long-term operating leases as of December 31, 2018:



(In millions)
2019	$	0.9
2020	0.7
2021	0.7
2022	0.6
2023	0.5
2024 and beyond	0.6
Total	$	4.0

Other information related to leases is as follows:



	Year Ended
(In millions)	December 31, 2019

Operating cash flows from operating leases included in the measurement of lease liabilities	$	0.8
ROU assets obtained in exchange for new operating lease liabilities ⁽¹⁾	3.6

⁽¹⁾Includes the transition impact of adoption of ASU 2016-02 Leases as of January 1, 2019.

Exhibit

SOUTHERN INDIANA GAS & ELECTRIC COMPANY

FINANCIAL STATEMENTS

For the year ended December 31, 2019

Contents



	Page Number

Audited Financial Statements
Independent Auditors’ Report	2
Balance Sheets	3-4
Statements of Income	5
Statements of Cash Flows	6
Statements of Common Shareholder’s Equity	7
Notes to the Financial Statements	8-34



DEFINITIONS
AFUDC: allowance for funds used during construction	FASB: Financial Accounting Standards Board
ARO: Asset Retirement Obligation	FERC: Federal Energy Regulatory Commission
ASC: Accounting Standards Codification	IDEM: Indiana Department of Environmental Management
ASU: Accounting Standard Update	IURC: Indiana Utility Regulatory Commission
CECA: Clean Energy Cost Adjustment	MISO: Midcontinent Independent System Operator
CSIA: Compliance and System Improvement Adjustment	MW: megawatts
DSMA: Demand Side Management Adjustment	SERP: Supplemental Executive Retirement Plan
ECA: Environmental Cost Adjustment	SRC: Sales Reconciliation Component
EEFC: Energy Efficiency Funding Component	TCJA: Tax Cuts and Jobs Acts
EEFR: Energy Efficiency Funding Rider	TDSIC: Transmission, Distribution and Storage System Improvement Charge
EPA: Environmental Protection Agency

INDEPENDENT AUDITORS’ REPORT

To the Director of Southern Indiana Gas and Electric Company:

We have audited the accompanying financial statements of Southern Indiana Gas and Electric Company (the "Company")(a wholly owned subsidiary of Vectren Utility Holdings, Inc.), which comprise the balance sheets as of December 31, 2019 and 2018, and the related statements of income, comprehensive income, and common shareholder’s equity, and cash flows for the years then ended, and the related notes to the financial statements.

Management's Responsibility for the Financial Statements

Management is responsible for the preparation and fair presentation of these financial statements in accordance with accounting principles generally accepted in the United States of America; this includes 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.

Auditors' Responsibility

Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the Company's preparation and fair presentation of the financial statements 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, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Southern Indiana Gas and Electric Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for the years then ended in accordance with accounting principles generally accepted in the United States of America.

/s/ DELOITTE & TOUCHE LLP

Indianapolis, Indiana

March 19, 2020

FINANCIAL STATEMENTS

SOUTHERN INDIANA GAS & ELECTRIC COMPANY

BALANCE SHEETS

(In millions)



	December 31,
	2019		2018
ASSETS

Utility Plant
Original cost	$	3,862.0	$	3,618.3
Less: accumulated depreciation & amortization	1,666.9		1,595.3
Net utility plant	2,195.1		2,023.0
Current Assets
Cash & cash equivalents	3.7		2.3
Notes receivable from Vectren Utility Holdings	2.0		98.7
Accounts receivable - less reserves of $1.9 &
$1.8, respectively	44.2		45.6
Accrued receivable from Vectren Utility Holdings	—		0.1
Accrued unbilled revenues	24.4		28.3
Inventories	86.0		69.9
Recoverable fuel & natural gas costs	1.4		2.4
Prepayments & other current assets	9.3		6.4
Total current assets	171.0		253.7
Investments in unconsolidated affiliates	0.2		0.2
Other investments	7.3		12.4
Nonutility plant - net	1.4		1.5
Goodwill - net	5.6		5.6
Regulatory assets	145.4		105.8
Other assets	45.7		26.7
TOTAL ASSETS	$	2,571.7	$	2,428.9

The accompanying notes are an integral part of these financial statements

SOUTHERN INDIANA GAS & ELECTRIC COMPANY

BALANCE SHEETS

(In millions)



	December 31,
	2019		2018
LIABILITIES & SHAREHOLDER'S EQUITY
Common shareholder's equity
Common stock (no par value)	$	433.3	$	433.3
Retained earnings	638.1		581.6
Total common shareholder's equity	1,071.4		1,014.9
Long-term debt payable to third parties	292.7		288.3
Long-term debt payable to Vectren Utility Holdings - net of current maturities	373.5		448.0
Total long-term debt	666.2		736.3
Commitments & Contingencies (Notes 6, 8-10)
Current Liabilities
Accounts payable	53.8		49.7
Payables to CenterPoint Energy, Inc.	0.3		—
Payables to other Vectren companies	16.3		11.7
Refundable fuel & natural gas costs	1.2		—
Accrued liabilities	39.5		56.5
Current maturities of long-term debt payable to Utility Holdings	114.5		—
Total current liabilities	225.6		117.9
Deferred Credits & Other Liabilities
Deferred income taxes	213.9		190.0
Regulatory liabilities	260.5		256.0
Deferred credits & other liabilities	134.1		113.8
Total deferred credits & other liabilities	608.5		559.8
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY	$	2,571.7	$	2,428.9

The accompanying notes are an integral part of these financial statements

SOUTHERN INDIANA GAS & ELECTRIC COMPANY

STATEMENTS OF INCOME

(In millions)



	Year Ended December 31,
	2019		2018
OPERATING REVENUES
Electric utility	$	570.2	$	582.5
Gas utility	99.5		100.0
Total operating revenues	669.7		682.5
OPERATING EXPENSES
Cost of fuel & purchased power	165.9		186.2
Cost of gas sold	33.6		40.3
Other operating	241.9		203.6
Depreciation & amortization	114.0		104.7
Taxes other than income taxes	19.2		18.7
Total operating expenses	574.6		553.5
OPERATING INCOME	95.1		129.0
Other income – net	4.1		7.9
Interest expense	33.7		32.9
INCOME BEFORE INCOME TAXES	65.5		104.0
Income taxes	9.0		22.5
NET INCOME	$	56.5	$	81.5

The accompanying notes are an integral part of these financial statements

SOUTHERN INDIANA GAS & ELECTRIC COMPANY

STATEMENTS OF CASH FLOWS

(In millions)



	Year Ended December 31,
		2019			2018
CASH FLOWS FROM OPERATING ACTIVITIES
Net income		$	56.5		$	81.5
Adjustments to reconcile net income to cash from operating activities:
Depreciation & amortization		114.0			104.7
Deferred income taxes & investment tax credits		19.8			(6.3		)
Provision for uncollectible accounts		2.2			2.2
Expense portion of pension & postretirement benefit cost		6.4			1.9
Other non-cash items - net		(7.4		)	(0.3		)
Changes in working capital accounts:
Accounts receivable & accrued unbilled revenue		3.1			8.2
Inventories		(16.1		)	23.4
Recoverable/refundable fuel & natural gas costs		2.2			7.4
Prepayments & other current assets		5.1			(4.8		)
Accounts payable		17.1			10.2
Accrued liabilities		(14.1		)	5.5
Changes in noncurrent assets		(30.3		)	(2.4		)
Changes in noncurrent liabilities		(32.0		)	(17.3		)
Net cash from operating activities		126.5			213.9
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from:
Long-term debt from CenterPoint Energy, Inc.		40.0			—
Long-term debt, net of issuance costs		—			113.4
Capital contributions from parent		—			120.0
Requirements for:
Dividends to parent		—			(57.0		)
Retirement of long-term debt		—			(61.9		)
Net change in commercial paper and short-term borrowings to third parties		—			(1.8		)
Net cash from financing activities		40.0			112.7
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from:
Sale of Company-owned life insurance		9.6			—
Sale of investments		16.2			—
Requirements for:
Capital expenditures, excluding AFUDC equity		(269.4		)	(227.9		)
Net change in short-term intercompany notes receivable		96.7			(98.7		)
Purchase of investments		(18.2		)	—
Net cash from investing activities		(165.1		)	(326.6		)
Net change in cash & cash equivalents		1.4			—
Cash & cash equivalents at beginning of period		2.3			2.3
Cash & cash equivalents at end of period		$	3.7		$	2.3

The accompanying notes are an integral part of these financial statements

SOUTHERN INDIANA GAS & ELECTRIC COMPANY

STATEMENTS OF COMMON SHAREHOLDER’S EQUITY

(In millions)





	Common		Retained
	Stock		Earnings			Total
Balance at January 1, 2018	$	313.3	$	557.1		$	870.4
Net income			81.5			81.5
Common stock:
Capital contribution from Utility Holdings	120.0					120.0
Dividends to Utility Holdings			(57.0		)	(57.0		)
Balance at December 31, 2018	$	433.3	$	581.6		$	1,014.9
Net income			56.5			56.5
Common stock:
Capital contribution from Utility Holdings	—					—
Dividends to Utility Holdings			—			—
Balance at December 31, 2019	$	433.3	$	638.1		$	1,071.4

The accompanying notes are an integral part of these financial statements

SOUTHERN INDIANA GAS AND ELECTRIC COMPANY

NOTES TO THE FINANCIAL STATEMENTS


1.	Organization and Nature of Operation

Southern Indiana Gas and Electric Company (the Company, or SIGECO), an Indiana corporation, provides energy delivery services to 147,942 electric customers and 113,193 gas customers located near Evansville in southwestern Indiana. Of these customers, 85,681 receive combined electric and gas distribution services. SIGECO also owns and operates electric generation assets to serve its electric customers and optimizes those assets in the wholesale power market. SIGECO is a direct, wholly owned subsidiary of Vectren Utility Holdings, Inc. (Utility Holdings or the Company's parent). The Company's parent is a direct, wholly owned subsidiary of Vectren Corporation (Vectren). Vectren, a wholly owned subsidiary of CenterPoint Energy, Inc. (CenterPoint), is an energy holding company headquartered in Evansville, Indiana. SIGECO generally does business as Vectren Energy Delivery of Indiana, Inc.

Merger with CenterPoint Energy, Inc.

On February 1, 2019, pursuant to the Merger Agreement, Vectren consummated the previously announced merger with CenterPoint and was acquired for approximately $6 billion in cash.

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, the Company recorded an incremental cost of $12 million in Other operating 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, Sigeco recognized severance totaling $18 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 Other operating expenses on its Consolidated Statements of Income during the year ended December 31, 2019.


2.	Summary of Significant Accounting Policies

In applying its accounting policies, the Company makes judgments, assumptions, and estimates that affect the amounts reported in these 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 utility and nonutility plant 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.

Subsequent Events Review

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 19, 2020, the date the financial statements were issued.

Cash & Cash Equivalents

Accounts Receivables and Allowance for Uncollectible Accounts

its customers deteriorates or other circumstances occur that result in an impairment of customers’ ability to make payments, the Company records additional allowances as needed.

Inventories

In most circumstances, the Company’s inventory components are recorded using an average cost method; however, natural gas in storage is recorded using the Last In – First Out (LIFO) method. Inventory 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.

Property, Plant & Equipment

Utility Plant & Related Depreciation

The IURC allows the Company to capitalize financing costs associated with Utility Plant based on a computed interest cost and a designated cost of equity funds. These financing costs are commonly referred to as AFUDC and are capitalized for ratemaking purposes and for financial reporting purposes instead of amounts that would otherwise be capitalized when acquiring nonutility plant. The Company reports both the debt and equity components of AFUDC in Other income – net in the Statements of Income.

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

Nonutility Plant & Related Depreciation

Impairment Reviews

Goodwill

Goodwill recorded on the Balance Sheets results from business acquisitions and is based on a fair value allocation of the businesses’ purchase price at the time of acquisition. Goodwill is charged to expense only when it is impaired. The Company tests its goodwill for impairment at a reporting unit level. These tests are performed at least annually. Impairment reviews consist of a comparison of fair value to the carrying amount. If the fair value is less than the carrying amount, an impairment loss is recognized in operations. No goodwill impairments have been recorded during the periods presented.

Regulation

Retail public utility operations are subject to regulation by the IURC. The Company 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.

Refundable or Recoverable Gas Costs & Cost of Fuel & Purchased Power

All metered gas rates 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 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.

Regulatory Assets & Liabilities

Regulatory assets represent certain incurred costs, which will result in probable future cash recoveries from customers through the ratemaking process. Regulatory liabilities represent probable expenditures by the Company for removal costs or future reductions in revenues associated with amounts to be credited to customers through the ratemaking process. The Company continually assesses the recoverability of costs recognized as regulatory assets and liabilities and the ability to recognize new regulatory assets and liabilities associated with its regulated utility operations. Given the current regulatory environment in its jurisdiction, the Company believes such accounting is appropriate.

Asset Retirement Obligations

Energy Contracts & Derivatives

When the Company engages in energy contracts and financial contracts that are derivatives and are not subject to the NPNS or other exclusions, such contracts are recorded at market value as current or noncurrent assets or liabilities depending on their value and when the contracts are expected to be settled. Contracts and any associated collateral with counter-parties subject to master netting arrangements are presented net in the Balance Sheets. The offset resulting from carrying the derivative at fair value on the balance sheet is charged to earnings unless it qualifies as a hedge or is subject to regulatory accounting treatment. The offset to contracts affected by regulatory accounting treatment, which include most of the Company's executed energy and financial contracts, are marked to market as a regulatory asset or liability. Market value for derivative contracts is determined using quoted market prices from independent sources or from internal models. As of and for the periods presented, derivative activity, other than NPNS, is not material to these financial statements.

Income Taxes

returns with CenterPoint. 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.

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

Revenue Policy

MISO Transactions

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 Statements of Income in Utility natural gas, fuel and purchased power, and net sales within that interval are recorded on the Company's 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.

Utility Receipts Taxes

A portion of utility receipts taxes are included in rates charged to customers. Accordingly, the Company records these taxes received as a component of operating revenues, which totaled $8.6 million in 2019 and $8.8 million in 2018. Expense associated with utility receipts taxes are recorded as a component of Taxes other than income taxes.

Operating Segments

Fair Value Measurements



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.

Other Significant Policies

Included elsewhere in these notes are significant accounting policies related to retirement plans and other postretirement benefits, intercompany allocations and income taxes (Note 6).


3.	Revenue

The Company provides commodity service to customers at rates, charges, and terms and conditions included in tariffs approved by regulators. The Company bills customers monthly and has 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. 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

alternative revenue programs, which are excluded from the scope of the new revenue standard. Revenues from alternative revenue programs are not material to any reporting period. 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 customer class.



(In millions)	Year Ended December 31,
(In millions)	2019		2018
Gas Utility Services
Residential	64.7		$	65.1
Commercial	22.5		24.1
Industrial	12.0		10.6
Other	0.3		0.2
Total Gas Utility Services	$	99.5	$	100.0

Electric Utility Services
Residential	210.4		$	210.2
Commercial	148.1		149.3
Industrial	159.9		162.1
Other	51.8		60.9
Total Electric Utility Services	$	570.2	$	582.5

Contract Balances

Remaining Performance Obligations


4.	Utility Plant & Deprecation

The original cost of Utility plant, together with depreciation rates expressed as a percentage of original cost, follows:



	At and For the Year Ended December 31,
(In millions)	2019				2018
	Original Cost		Depreciation Rates as a Percent of Original Cost		Original Cost		Depreciation Rates as a Percent of Original Cost
Electric utility plant	$	3,077.3	3.3	%	$	2,945.8	3.3	%
Gas utility plant	520.6		2.9	%	482.2		2.8	%
Common utility plant	70.8		3.5	%	67.6		3.2	%
Construction work in progress	117.7		—		71.5		—
Asset retirement obligations	75.6		—		51.2		—
Total original cost	$	3,862.0			$	3,618.3

The Company and Alcoa Generating Corporation (AGC), a subsidiary of Alcoa, Inc. (Alcoa), own a 300 MW unit at the Warrick Power Plant (Warrick Unit 4) as tenants in common. The Company's share of the cost of this unit at December 31, 2019, is $194.1 million with accumulated depreciation totaling $136.8 million. AGC and the Company share equally in the cost of operation and output of the unit. The Company's share of operating costs is included in Other operating expenses in the Statements of Income.

5. Regulatory Assets & Liabilities

Regulatory Assets

Regulatory assets consist of the following:



	At December 31,
(In millions)	2019		2018
Future amounts recoverable from ratepayers related to:
Asset retirement obligations & other	$	40.3	$	24.0
Net deferred income taxes	3.5		3.0
	43.8		27.0
Amounts deferred for future recovery related to:
Cost recovery riders & other	31.7		47.4
	31.7		47.4
Amounts currently recovered through customer rates related to:
Authorized trackers	61.1		19.5
Deferred coal costs	—		7.0
Unamortized debt issue costs, reacquisition premiums & hedging proceeds	8.8		4.9
	69.9		31.4
Total regulatory assets	$	145.4	$	105.8

Of the $69.9 million currently being recovered in rates charged to customers, no amounts are earning a return. The weighted average recovery period of regulatory assets currently being recovered in base rates, which totals $8.8 million, is 20 years. The remainder of the regulatory assets are being recovered timely through periodic recovery mechanisms.

Regulatory assets for asset retirement obligations are 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 costs are currently being recovered in rates.

Regulatory Liabilities

At December 31, 2019 and 2018, the Company had regulatory liabilities $260.5 million and $256.0 million, respectively, of which $68.7 million and $54.3 million related to cost of removal obligations and $191.5 million and $201.4 million related to deferred taxes, at December 31, 2019 and 2018, respectively. 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 as ordered by the IURC.

6. Transactions with Other Vectren Companies & Affiliates

Vectren Infrastructure Services Corporation (VISCO)

VISCO, a wholly owned subsidiary of Vectren, provides underground pipeline construction and repair services. VISCO's customers include the Company and fees incurred by the Company totaled $19.7 million in 2019 and $16.0 million in 2018. Amounts owed to VISCO at December 31, 2019 and 2018 are included in Payables to other Vectren companies.

Support Services and Purchases

Vectren and the Company's parent provide corporate and general and administrative services to the Company and allocate certain costs to the Company. These costs are allocated using various allocators, including number of employees, number of customers and/or the level of payroll, revenue contribution and capital expenditures. Allocations are at cost. The Company received corporate allocations totaling $78.5 million and $52.9 million for the years ended December 31, 2019, and 2018, respectively. The allocated costs in 2019 include $17.8 million of severance and $12.2 million of stock-based compensation as a result of the Merger with CenterPoint. Amounts owed to Vectren and the Company's parent at December 31, 2019 and 2018 are included in Payables to other Vectren companies.

Retirement Plans & Other Postretirement Benefits

At December 31, 2019, Vectren maintains three closed qualified defined benefit pension plans (Vectren Corporation Non-Bargaining Retirement Plan, The Indiana Gas Company, Inc. Bargaining Unit Retirement Plan, Pension Plan for Hourly Employees of Southern Indiana Gas and Electric Company), a nonqualified supplemental executive retirement plan (SERP), and a postretirement benefit plan. The 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. Current and former employees of Vectren and its subsidiaries, which include the Company, comprise the vast majority of the participants and retirees covered by these plans.

Vectren satisfies the future funding requirements for 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 2019 and contributed $1.5 million in 2018 to Vectren for the deferred benefit and pension plans. The Company contributed $7.7 million in 2019 and $2.2 million in 2018 to Vectren for SERP and post retirement benefit plans. The combined funded status of Vectren’s defined benefit pension plans was approximately 90 percent and 89 percent at December 31, 2019 and 2018, respectively.

Vectren allocates retirement plan and other postretirement benefit plan periodic cost calculated pursuant to US GAAP to its subsidiaries, which is also how the Company recovers retirement plan periodic costs through base rates. Periodic cost is charged to the Company following a labor cost allocation methodology and results in retirement costs being allocated to both operating expense and capital projects. Costs totaling $7.3 million and $3.7 million were charged to the Company in years ended December 31, 2019 and 2018, respectively.

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, 2019 and 2018, the Company had $24.6 million and $25.6 million, respectively, included in Other Assets representing defined benefit pension funding by the Company to Vectren that is yet to be reflected in costs. As of December 31, 2019 and 2018, the Company had $17.7 million and $19.0 million, respectively, included in Deferred credits & other 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 Vectren, which is consistent with the regulatory ratemaking processes of the Company.

Share-Based Incentive Plans and Deferred Compensation Plans

The Company does not have share-based compensation plans separate from Vectren. The Company recognizes its allocated portion of expenses related to share-based incentive plans and deferred compensation plans in accordance with FASB guidance and to the extent these awards are expected to be settled in cash, that liability is pushed down to SIGECO. As of December 31, 2019 and 2018, $2.1 million and $29.4 million, respectively, is included in Accrued liabilities and Deferred credits & other liabilities and represents obligations that are yet to be funded to Vectren. Subsequent to the February 1, 2019 completion of the Merger, and pursuant to the Merger Agreement, all Vectren's share-based awards have been settled and a majority of its deferred compensation liabilities have been settled.

Cash Management Arrangements

The Company participates in the centralized cash management program of the Company's parent. See Note 7 regarding long-term and short-term intercompany borrowing arrangements.

Guarantees of the Company's Parent

The three operating utility companies of the Company's parent, SIGECO, Indiana Gas Company, Inc. (Indiana Gas) and Vectren Energy Delivery of Ohio, Inc. (VEDO) are guarantors of its $400 million commercial paper borrowing arrangements and its $832 million in unsecured senior notes and term loans outstanding at December 31, 2019. The majority of the unsecured senior notes and term loans outstanding of the Company's parent are allocated to the operating utility companies. The guarantees are full and unconditional and joint and several, and the Company's parent has no subsidiaries other than the subsidiary guarantors.

In connection with the Merger, the Company's parent made offers to prepay certain outstanding guaranteed senior notes as required pursuant to certain purchase agreements. In turn, the Company's parent borrowed $568 million to make the prepayment at the same interest rate and term as the notes being prepaid. The CenterPoint notes are not guaranteed by the Company or the other operating utility companies of the Company's parent.

Income Taxes

The Company does not file federal or state income tax returns separate from those filed by Vectren. As of February 2, 2019, Vectren is included in CenterPoint'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 Vectren's consolidated tax group are recorded at the Company's parent level. Current taxes payable/receivable are settled with Vectren 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 recognizes 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 Statements of Income and reports tax liabilities related to unrecognized tax benefits as part of Deferred credits & other liabilities.

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

The IURC approved an initial 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 electric customers and in January 2019 for the Company’s gas customers.

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



	Year Ended December 31,
(In millions)	2019			2018
Current:
Federal	$	(1.7	)	$	28.2
State	(1.4		)	4.9
Total current tax expense	(3.1		)	33.1
Deferred:
Federal	9.2			(15.4		)
State	4.2			1.4
Total deferred tax expense	13.4			(14.0		)
Amortization of investment tax credit deferred / (amortized)	(1.3		)	3.4
Total income tax expense	$	9.0		$	22.5

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




	Year Ended December 31,
	2019		2018

Statutory rate	21.0	%	21.0	%
Federal tax law change impacts	(6.5	)	(4.1	)
State & local taxes, net of federal benefit	5.4		5.0
Research & Development Tax Credits	(4.4	)	(0.7	)
All other - net	(1.8	)	0.4
Effective tax rate	13.7	%	21.6	%

Significant components of the net deferred tax liability follow:



	At December 31,
(In million)	2019		2018
Noncurrent deferred tax assets:
Regulatory liabilities settled through future rates	$	49.4	51.7
Total deferred tax liabilities:	49.4		51.7
Noncurrent deferred tax assets:
Depreciation & cost recovery timing differences	$	244.0	$	232.1
Regulatory assets recoverable through future rates	5.3		4.9
Employee benefit obligations	1.7		(2.8		)
Deferred fuel costs	5.7		5.8
Other – net	6.6		1.7
Total deferred tax liabilities	$	263.3	$	241.7
Net deferred tax liability	$	213.9	$	190.0

At December 31, 2019 and 2018, investment tax credits totaling $3.3 million and $4.5 million, respectively, are included in Deferred credits & other liabilities.

Uncertain Tax Positions

Unrecognized tax benefits for all periods presented were not material to the Company. The net liability on the Balance Sheet for unrecognized tax benefits inclusive of interest and penalties totaled $0.3 million and $0.3 million at December 31, 2019 and 2018, respectively.

Vectren and certain of its subsidiaries file income tax returns in the U.S. federal jurisdiction and various states. The Internal Revenue Service (IRS) has concluded examinations of Vectren's U.S. federal income tax return for tax year December 31, 2016 with no adjustments. 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 federal income tax and Indiana income tax have expired with respect to tax years through 2016 except to the extent of refunds claimed on amended tax returns. The statutes of limitations for assessment of the 2013 tax year related to the amended federal tax return will expire in 2020. The statutes of limitations for assessment of the 2012 tax year related to the amended Indiana income tax return expired in 2019. The statues of limitations for assessment of the 2013 and 2014 tax years related to the amended Indiana income tax returns will expire in 2020.


7.	Borrowing Arrangements & Other Financing Transactions

Long-Term Debt

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



	At December 31,
(In millions)	2019			2018
Fixed Rate Senior Unsecured Notes Payable to Utility Holdings:
2020, 6.28%	99.5			99.5
2021, 4.67%	54.6			54.6
2023, 3.72%	24.8			24.8
2028, 3.20%	26.9			26.9
2032, 3.26%	74.6			74.6
2035, 6.10%	25.3			25.3
2035, 3.90%	16.6			16.6
2043, 4.25%	47.7			47.7
2045, 4.36%	16.6			16.6
2047, 3.93%	29.8			29.8
2055, 4.51%	16.6			16.6
2049, 3.42%	40.0			—
Variable Rate Term Loans
2020, current adjustable rate, 2.5125%	15.0			15.0
Total long-term debt payable to Utility Holdings	488.0			448.0
Current maturities	(114.5		)	—
Total long-term debt payable to Utility Holdings	$	373.5		$	448.0

First Mortgage Bonds Payable to Third Parties:
2022, 2013 Series C, current adjustable rate 2.190%, tax-exempt	$	4.6		$	4.6
2024, 2013 Series D, current adjustable rate 2.190%, tax-exempt	22.5			22.5
2025, 2014 Series B, current adjustable rate 2.190%, tax-exempt	41.3			41.3
2029, 1999 Series, 6.72%	80.0			80.0
2037, 2013 Series E, current adjustable rate 2.190%, tax-exempt	22.0			22.0
2038, 2013 Series A, current adjustable rate 2.190%, tax-exempt	22.2			22.2
2043, 2013 Series B, current adjustable rate, 2.190%, tax-exempt	39.6			39.6
2044, 2014 Series A, 4.00%, tax exempt	22.3			22.3
2055, 2015 Series Mt. Vernon, 2.375%, tax-exempt	23.0			23.0
2055, 2015 Series Warrick County, 2.375%, tax-exempt	15.2			15.2
Total first mortgage bonds payable to third parties	292.7			292.7
Debt issuance cost	—			(4.0		)
Unamortized debt premium, discount & other - net	—			(0.4		)
Total long-term debt payable to third parties - net	$	292.7		$	288.3

Term Loan

On July 30, 2018, the Company's parent closed a two-year term loan with two banking partners. The term loan agreement provided for a $250 million draw at closing and the remaining $50 million was drawn on December 14, 2018. Proceeds from the term loan were utilized to pay a $100 million, August 1, 2018, debt maturity and for general utility purposes. The term loan’s interest rate is currently priced at one-month LIBOR, plus a credit spread depending on the Company's parent credit rating. In addition, the term loan contains a provision that should the Company's parent or any of its subsidiaries execute certain capital market transactions, and subject to certain other conditions, the outstanding balance is subject to mandatory prepayment. The term loan is jointly and severally guaranteed by the Company's parent wholly-owned operating companies, SIGECO, Indiana Gas, and VEDO. The Company received approximately $15 million of these proceeds.

SIGECO Variable Rate Tax-Exempt Bonds

On March 1, 2018 and May 1, 2018, the Company executed first and second amendments to a Bond Purchase and Covenants Agreement originally signed in September 2017. These amendments provided the Company the ability to remarket bonds that were callable from current bondholders on those dates. Pursuant to these amendments, lenders purchased the following SIGECO bonds on March 1 and May 1, respectively:


•	2013 Series A Notes with a principal of $22.2 million and final maturity date of March 1, 2038; and


•	2013 Series B Notes with a principal of $39.6 million and final maturity date of May 1, 2043.

The Company has now remarketed $152 million of tax exempt bonds through the Bonds Purchase and Covenants Agreement, which is the agreement’s full capacity.

The Company executed forward starting interest rate swaps during 2017 providing that on January 1, 2020, the Company will begin hedging the variability in interest rates on the 2013 Series A, B, and E Notes through final maturity dates. The swaps contain customary terms and conditions and generally provide offset for changes in the one month LIBOR rate. Other interest rate variability that may arise through the Bond Purchase and Covenants Agreement, such as variability caused by changes in tax law or the Company's credit rating, among others, may result in an actual interest rate above or below the anticipated fixed rate. Regulatory orders require the Company to include the impact of its interest rate risk management activities, such as gains and losses arising from these swaps, in its cost of capital utilized in rate cases and other periodic filings.

Mandatory Tenders

At December 31, 2019, certain series of SIGECO bonds, aggregating $185.7 million are subject to mandatory tenders prior to the bonds' final maturities. $38.2 million will be tendered in 2020 and $147.5 million will be tendered in 2023.

Future Long-Term Debt Sinking Fund Requirements and Maturities

The annual sinking fund requirement of the Company's first mortgage bonds is 1 percent of the greatest amount of bonds outstanding under the Mortgage Indenture. This requirement may be satisfied by certification to the Trustee of unfunded property additions in the prescribed amount as provided in the Mortgage Indenture. The Company met the 2019 sinking fund requirement by this means and expects to also meet this requirement in 2019 in this manner. Accordingly, the sinking fund requirement is excluded from Current liabilities in the Balance Sheets. At December 31, 2019, $1.8 billion of utility plant remained unfunded under the Company's Mortgage Indenture. The Company’s gross utility plant balance subject to the Mortgage Indenture approximated $3.9 billion at December 31, 2019.

Maturities of long-term debt during the five years following 2019 (in millions) are $114.5 in 2020, $54.6 in 2021, $4.6 in 2022, $24.8 in 2023, $22.5 in 2024, and $559.7 thereafter.

Covenants

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. As of December 31, 2019, the Company was in compliance with all financial debt covenants.


8.	Commitments & Contingencies

Purchase Commitments

The Company has firm commitments to purchase natural gas for up to a five year term, with the majority of these commitments being a term of two years or less. The Company also has other firm and non-firm commitments to purchase coal, electricity, as well as certain transportation and storage rights, some of which are firm commitments under five and twenty year arrangements. Costs arising from these commitments, while significant, are pass-through costs, generally collected dollar-for-dollar from retail customers through regulator-approved cost recovery mechanisms.

The Company's minimum purchase obligations for these commitments, which have various quantity requirements and duration are $112 million in 2020, $95 million in 2021, $97 million in 2022, $81 million in 2023, $46 million in 2024, and $144 million thereafter.

Letters of Credit

The Company, from time to time, issues letters of credit to support operations. At December 31, 2019, letters of credit outstanding total $5.0 million.

Legal and Regulatory Proceedings


9.	Regulatory Matters

Electric Generation Transition Plan

the process involves the issuance of a staff report that provides comments on the IRP. Depending on comments received on the IRP, the filing of any future requests for generating facilities could be delayed. Further, certain legislative activities such as the proposed moratorium in 2019 or other legislation restricting or delaying new generation could negatively affect the Company's ability to construct new generation facilities and execution of its capital plan. Even if a generation project is approved, risks associated with the construction of any new generation exist, including the ability to procure resources needed to build at a reasonable cost, scarcity of resources and labor, ability to appropriately estimate costs of new generation, the effects of potential construction delays and cost overruns and the ability to meet capacity requirements. Further, there is no guarantee that the IURC will approve the requests included in any of the Company's future filed petitions relating to its IRP.

50 MW Solar Project

A.B. Brown Ash Pond Remediation

FERC Return on Equity (ROE) Complaints

On November 21, 2019, FERC issued an order adopting a new base ROE calculation resulting in new base ROE of 9.88

percent for the first complaint period, November 12, 2013 through February 11, 2015, in addition to periods subsequent to the original order issued on September 28, 2016. In addition, FERC dismissed the second complaint period, February 12, 2015 through May 11, 2016.

In December 2019, the MISO Transmission Owners Group and other stakeholders filed rehearing requests challenging the methodology utilized to derive the revised base ROE.

On January 21, 2020, FERC issued an order granting rehearing for the limited purpose of allowing additional time for consideration of matters raised.

Tax Reform

The IURC issued an order which initiated proceedings to investigate the impact of the TCJA on utility companies and customers in Indiana. In addition, the IURC ordered the Company to establish regulatory liabilities to record all estimated impacts of tax reform starting January 1, 2018 until the date when rates are adjusted to capture these impacts. In response to the Company’s filing for proposed changes to its rates and charges to consider the impact of the lower federal income tax rates, the IURC approved an initial reduction to 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 Indiana electric customers and in January 2019 for Indiana gas customers.

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 (CSIA for gas and TDSIC, ECA and CECA for Electric) its decoupling mechanism (SRC for gas), and its energy efficiency cost trackers (EEFC for gas and DSMA for electric).

The table below reflects significant applications pending or completed during 2019 and to date in 2020 for the Company



	Annual
	Increase
	(Decrease)
	(1)	Filing	Effective	Approval
Mechanism	(in millions)	Date	Date	Date	Additional Information
Indiana South - Gas (IURC)
CSIA	3	October 2018	January 2019	January 2019	Requested an increase of $16 million to rate base, which reflects a $3 million annual increase in current revenues. 80% of revenue requirement is included in requested rate increase and 20% is deferred until next rate case. The mechanism also includes refunds associated with the TCJA, resulting in a change of $(1) million, and a change in the total (over)/under-recovery variance of $(3) million annually.



	Annual
	Increase
	(Decrease)
	(1)	Filing	Effective	Approval
Mechanism	(in millions)	Date	Date	Date	Additional Information
CSIA	5	April 2019	July 2019	July 2019	Requested an increase of $22 million to rate base, 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. 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 $3 million annually.
CSIA	3	October 2019	January 2020	January 2020	Requested an increase of $18 million to rate base, which reflects a $3 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. 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 $(0.2) million annually.
Indiana Electric (IURC)
TDSIC	3	February 2019	May 2019	May 2019	Requested an increase of $24 million to rate base, which reflects a $3 million annual increase in current revenues. 80% of revenue requirement is included in requested rate increase and 20% is deferred until next rate case. The mechanism also includes refunds associated with the TCJA, resulting in a change of $5 million, and a change in the total (over)/under-recovery variance of $5 million annually.
TDSIC	4	August 2019	November 2019	November 2019	Requested an increase of $35 million to rate base, which reflects a $4 million annual increase in current revenues. 80% of 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 $4 million annually.
TDSIC (1)	4	February 2020	May 2020	TBD	Requested an increase of $34 million to rate base, which reflects a $4 million annual increase in current revenues. 80% of 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 $2 million annually.
ECA - MATS	13	February 2018	January 2019	April 2019	Requested an increase of $58 million to rate base, which reflects a $13 million annual increase in current revenues. 80% of revenue requirement is included in requested rate increase and 20% is deferred until next rate case. The mechanism includes recovery of prior accounting deferrals associated with investments (depreciation, carrying costs, operating expenses).
CECA	2	February 2019	June 2019	May 2019	Requested an increase of $13 million to rate base related to solar pilot investments, which reflects a $2 million annual increase in current revenues.



	Annual
	Increase
	(Decrease)
	(1)	Filing	Effective	Approval
Mechanism	(in millions)	Date	Date	Date	Additional Information
CECA ⁽¹⁾	—	February 2020	June 2020	TBD	Requested an increase of $0.1 million to rate base related to solar pilot investments, which reflects an immaterial change to current revenues. The mechanism also includes a change in (over) under-recovery variance of $0.1 million annually. Additional solar investment to supply 50 MW of solar capacity is approved and will be included for recovery once completed in 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.

Other Generation Developments

On September 21, 2017, the Company and Alcoa agreed to continue the joint ownership and operation of Warrick Unit 4 through 2023.

10. Environmental and Sustainability Matters

Coal Ash Waste Disposal, Ash Ponds and Water

Coal Combustion Residuals Rule

determinations by October 18, 2018. The Company 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, the Company is required to cease disposal of new ash in the ponds and commence closure of the ponds by August 2020. The Company plans to seek extensions available under the CCR Rule that would allow the Company to continue to use the ponds through December 31, 2023. The inability to take these extensions may result in increased and potentially significant operational costs in connection with the accelerated implementation of an alternative ash disposal system or adversely impact the Company's future operations. Failure to comply with these requirements could also result in an enforcement proceeding including the imposition of fines and penalties. On April 24, 2019, the Company received an order from the IURC approving recovery in rates of costs associated with the closure of the Culley West pond, which has already commenced closure activities. The Company believes the language in the IURC order is favorable for future recovery of closure costs for the Company's remaining ponds.

Effluent Limitation Guidelines (ELG)

Cooling Water Intake Structures

Climate Change and Carbon Strategy

Clean Power Plan and Affordable Clean Energy (ACE) Rule

Impact of Legislative Actions & Other Initiatives

Manufactured Gas Plants

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 potentially responsible parties (PRP) or insurance recovery.

The Company has identified its involvement in five manufactured gas plant sites in SIGECO’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.

The Company has accrued the estimated costs for further investigation, remediation, groundwater monitoring, and related costs for the sites. As of December 31, 2019 and December 31, 2018, approximately $2.8 million and $1.4 million, respectively of accrued, but not yet spent, costs are included in Other Liabilities related to these sites.

11. Fair Value Measurements

The carrying values and estimated fair values using primarily Level 2 assumptions of the Company's other financial instruments follow:



	At December 31,
	2019				2018
(In millions)	Carrying Amount		Est. Fair Value		Carrying Amount		Est. Fair Value
Long-term debt payable to third parties	$	292.7	$	318.1	$	288.3	$	301.5
Long-term debt payable to Utility Holdings	488.0		507.3		448.0		455.6
Short-term notes receivable from Utility Holdings	2.0		2.0		98.7		98.7
Natural gas purchase instrument liabilities ⁽¹⁾	3.4		3.4		1.7		1.7
Interest rate swap liabilities ⁽²⁾	9.8		9.8		0.1		0.1
Cash & cash equivalents	3.7		3.7		2.3		2.3

⁽¹⁾ Presented in "Accrued liabilities" and "Deferred credits & other liabilities" on the Balance Sheets.

⁽²⁾ Presented in "Deferred credits & other liabilities" on the Balance Sheets.

The Company entered into two 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 gas cost recovery mechanism.

The Company executed forward starting interest rate swaps during 2017 providing that on January 1, 2020, the Company will begin hedging the variability in interest rates. 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.

12. Segment Reporting

The Company’s operations consist of Gas Utility Services and Electric Utility Services. The Gas Utility Services segment provides natural gas distribution and transportation services primarily to southwestern Indiana. The Electric Utility Services segment provides electric distribution services primarily to southwestern Indiana, and includes the Company’s power generating and wholesale power operations. Beginning on February 1, 2019, upon close of the merger, the Company's measure of profitability used by management for all operations became operating income.

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



	Year Ended December 31,
(In millions)	2019		2018
Revenues
Gas Utility Services	$	99.5	$	100.0
Electric Utility Services	570.2		582.5
Total revenues	$	669.7	$	682.5
Profitability Measure - Operating Income
Gas Utility Services	$	3.3	$	11.5
Electric Utility Services	91.8		117.5
Total operating income	$	95.1	$	129.0
Depreciation & Amortization
Gas Utility Services	$	14.3	$	12.9
Electric Utility Services	99.7		91.8
Total depreciation & amortization	$	114.0	$	104.7
Capital Expenditures
Gas Utility Services	$	49.3	$	59.0
Electric Utility Services	204.1		163.6
Non-cash costs & changes in accruals	16.0		5.3
Total capital expenditures	$	269.4	$	227.9



	At December 31,
(In millions)	2019		2018
Assets
Gas Utility Services	$	518.7	$	478.9
Electric Utility Services	2,053.0		1,950.0
Total assets	$	2,571.7	$	2,428.9


13.	Additional Balance Sheet & Operational Information

Inventories in the Balance Sheets consist of the following:



	At December 31,
(In millions)	2019		2018
Materials & supplies	$	33.1	$	33.5
Fuel (coal and oil) for electric generation	33.4		16.7
Gas in storage – at LIFO cost	19.5		19.7
Total inventories	$	86.0	$	69.9

Based on the average cost of gas purchased during December 2019 and 2018, the cost of replacing gas in storage carried at LIFO cost is less than the carrying value at December 31, 2019 and 2018 by approximately $7 million and $3 million, respectively. All other inventories are carried at average cost. The Company sources most of its coal supply from a single third party and also purchases most of its natural gas from a different single third party. Rates charged to natural gas customers contain a gas cost adjustment clause and electric rates contain a fuel adjustment clause that allow for the timely adjustment in charges to reflect changes in the cost of gas and cost for fuel.

Prepayments & other current assets in the Balance Sheets consist of the following:



	At December 31,
(In millions)	2019		2018
Prepaid taxes	$	7.2	$	4.3
Other	2.1		2.1
Total prepayments & other current assets	$	9.3	$	6.4

Accrued liabilities in the Balance Sheets consist of the following:



	At December 31,
(In millions)	2019		2018
Accrued taxes	$	10.8	$	11.3
Refunds to customers & customer deposits	12.1		26.4
Accrued interest	5.2		5.1
Tax collections payable	6.1		2.9
Accrued salaries & other	5.3		10.8
Total accrued liabilities	$	39.5	$	56.5

Asset retirement obligations included in Deferred Credits and Other Liabilities in the Balance Sheets roll forward as follows:




(In millions)	2019		2018
Asset retirement obligation, January 1	$	64.3	$	61.1
Accretion	3.2		2.3
Changes in estimates, net of cash payments	24.4		0.9
Asset retirement obligation, December 31	$	91.9	$	64.3

Other income – net in the Statements of Income consists of the following:



	Year ended December 31,
(In millions)	2019			2018
AFUDC – borrowed funds	$	4.6		$	5.3
AFUDC – equity funds	3.5			2.6
Pension Settlement Charges	(4.8		)	(0.7		)
Other	0.8			0.7
Total other income - net	$	4.1		$	7.9

Supplemental Cash Flow Information:



	Year ended December 31,
(In millions)	2019			2018
Cash paid (received) for:
Income taxes	$	(0.2	)	$	44.1
Interest	33.5			33.1

As of December 31, 2019 and 2018, the Company has accruals related to utility plant purchases totaling approximately $4.8 million and $13.1 million, respectively.


14.	Impact of Recently Issued Accounting Standards

The following table provides an overview of recently adopted or issued accounting pronouncements applicable to the Company,

unless otherwise noted:



Recently Adopted Accounting Standards
ASU Number		Date of	Financial Statement Impact
and Name	Description	Adoption	upon Adoption
ASU 2016-02- Leases (Topic 842) and related amendments	ASU 2016-02 provides a comprehensive new lease model that requires lessees to recognize assets and liabilities for most leases and would change certain aspects of lessor accounting. Transition method: modified retrospective	January 1, 2019	The Company adopted the standard and recognized a right-of-use asset and lease liability on their statement of financial position with no material impact on their results of operations and cash flows. See Note 16 for more information.

Issued, Not Yet Effective Accounting Standards
ASU Number			Financial Statement Impact
and Name	Description	Effective Date	upon Adoption
ASU 2016-13- Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments	This standard, including standards amending this standard, requires a new model called CECL to estimate credit losses for (1) financial assets subject to credit losses and measured at amortized cost and (2) certain off-balance sheet credit exposures. Upon initial recognition of the exposure, the CECL model requires an entity to estimate the credit losses expected over the life of an exposure based on historical information, current information and reasonable and supportable forecasts, including estimates of prepayments. Transition method: modified retrospective	January 1, 2020 Early adoption is permitted	The adoption of this standard will result in an immaterial adjustment to the carrying value of the Company's accounts receivable, net. The adoption of this standard will not have a material impact on the Company's financial position, results of operations or cash flows.
ASU 2018-15- Intangibles-Goodwill and Other- Internal-Use Software (Subtopic 350-40): Customer's Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract	This standard aligns accounting for implementation costs incurred in a cloud computing arrangement that is accounted for as a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. The update also prescribes the balance sheet, income statement, and cash flow classification of the capitalized implementation costs and related amortization expense and requires additional quantitative and qualitative disclosures. Transition method: retrospective or prospective	January 1, 2020 Early adoption is permitted	The adoption of this standard will require the Company to capitalize certain costs to implement cloud computing arrangements that are accounted for as service contracts within Prepaid expenses and other current assets on the Company's consolidated balance sheets and record the amortization of such assets within Operation and maintenance expenses on the Company's statements of consolidated income. The adoption of this standard will not have a material impact on the Company's financial position, results of operations, cash flows or disclosures.

15. Lease

The components of lease cost, included in Operations and maintenance expense on the Company's Consolidated Statement of Income, are as follows:



	Year Ended
(In millions)	December 31, 2019

Operating lease cost	$	0.6
Short-term lease cost	1.0
Total lease cost	$	1.6

Supplemental balance sheet information related to lease is as follows:



(In millions, except lease term and discount rate)	December 31, 2019

Assets:
Operating ROU assets ⁽¹⁾	$	2.6
Total leased assets	$	2.6
Liabilities:
Current operating lease liability ⁽²⁾	$	0.7
Non-current operating lease liability ⁽³⁾	1.9
Total lease liabilities	$	2.6

Weighted-average remaining lease term (in years) - operating leases	6.4
Weighted-average discount rate - operating leases	3.59		%

⁽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, 2019, maturities of operating lease liabilities were as follows:



(In millions)
2020	$	0.7
2021	0.7
2022	0.6
2023	0.5
2024	—
2025 and beyond	0.3
Total lease payments	$	2.8
Less: Interest	0.2
Present value of lease liabilities	$	2.6

The following table sets forth information concerning the Company's obligations under non-cancelable long-term operating leases as of December 31, 2018:



(In millions)
2019	$	0.7
2020	0.7
2021	0.7
2022	0.6
2023	0.5
2024 and beyond	0.3
Total	$	3.5

Other information related to leases is as follows:



	Year Ended
(In millions)	December 31, 2019

Operating cash flows from operating leases included in the measurement of lease liabilities	$	0.5
ROU assets obtained in exchange for new operating lease liabilities ⁽¹⁾	3.0

⁽¹⁾Includes the transition impact of adoption of ASU 2016-02 Leases as of January 1, 2019.