Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS OF CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

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Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS OF CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

The following combined discussion and analysis should be read in combination with the Interim Condensed Financial Statements contained in this combined Form 10-Q and the Registrants’ combined 2022 Form 10-K. When discussing CenterPoint Energy’s consolidated financial information, it includes the results of Houston Electric and CERC, which, along with CenterPoint Energy, are collectively referred to as the Registrants. Where appropriate, information relating to a specific Registrant has been segregated and labeled as such. In this combined Form 10-Q, the terms “our,” “we” and “us” are used as abbreviated references to CenterPoint Energy, Inc. together with its consolidated subsidiaries. No Registrant makes any representations as to the information related solely to CenterPoint Energy or the subsidiaries of CenterPoint Energy other than itself.

RECENT EVENTS

Divestiture of Energy Systems Group. On May 21, 2023, Vectren Energy Services entered into an Equity Purchase Agreement to sell all of the outstanding limited liability company interests of Energy Systems Group to ESG Holdings Group, for a purchase price of $157 million, subject to customary adjustments set forth in the Equity Purchase Agreement, including adjustments based on Energy Systems Group’s net working capital at closing, indebtedness, cash and cash equivalents and transaction expenses. The transaction closed on June 30, 2023 for $154 million in cash, subject to finalization of the purchase price adjustment. For further information, see Note 3 to the Interim Condensed Financial Statements.

Regulatory Proceedings. On March 23, 2023, CenterPoint Energy and CERC, collectively, received approximately $1.1 billion in proceeds from the customer rate relief bonds issued by the Texas Public Financing Authority related to the February 2021 Winter Storm Event. On April 5, 2023, a final order was issued approving the $39 million revenue requirement from Houston Electric’s 2021 investment in TEEEF. On April 5, 2023, Houston Electric filed its second TEEEF filing requesting recovery of $188 million of TEEEF related costs incurred through December 31, 2022. On June 29, 2023, Indiana Electric received the net securitization proceeds of $337 million to reimburse it for or fund qualified costs approved by the IURC related to the planned retirement of its A.B. Brown coal-fired generation facilities. For further information, see Note 6 to the Interim Condensed Financial Statements. For information related to our pending and completed regulatory proceedings to date in 2023, see “—Liquidity and Capital Resources —Regulatory Matters” below.

Debt Transactions. During the six months ended June 30, 2023, CenterPoint Energy issued or borrowed a combined $3.7 billion in new debt, including Houston Electric’s issuance of $900 million aggregate principal amount of general mortgage bonds, CERC’s issuance of $1.5 billion aggregate principal amount of senior notes, CERC’s $500 million term loan, Securitization Subsidiary’s issuance of $341 million aggregate principal amount of SIGECO Securitization Bonds, SIGECO’s issuance of $180 million aggregate principal amount of first mortgage bonds and CenterPoint Energy’s $250 million term loan. CenterPoint Energy repaid or redeemed a combined $2.54 billion of debt, including CERC’s repayment of $1.0 billion of term loans and $1.275 billion of senior notes maturing in 2023, CenterPoint Energy’s repayment of its $250 million term loan and SIGECO’s early redemption of $11 million of first mortgage bonds maturing in 2044, excluding scheduled principal payments on Securitization Bonds. For information about debt transactions to date in 2023, see Note 11 to the Interim Condensed Financial Statements.

CenterPoint Energy Leadership Transition. On March 15, 2023, CenterPoint Energy announced the appointment of Christopher Foster to the position of Executive Vice President and Chief Financial Officer, effective May 5, 2023.

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CENTERPOINT ENERGY CONSOLIDATED RESULTS OF OPERATIONS

For information regarding factors that may affect the future results of our consolidated operations, please read “Risk Factors” in Item 1A of Part I of the Registrants’ combined 2022 Form 10-K.

Income available to common shareholders for the three and six months ended June 30, 2023 and 2022 was as follows:


	Three Months Ended June 30,						Six Months Ended June 30,
	2023		2022		Favorable (Unfavorable)		2023		2022		Favorable (Unfavorable)
	(in millions)
Electric	$	180	$	173	$	7	$	303	$	255	$	48
Natural Gas	35		28		7		269		426		(157)
Total Utility Operations	215		201		14		572		681		(109)
Corporate & Other (1)	(109)		(22)		(87)		(153)		16		(169)

Total CenterPoint Energy	$	106	$	179	$	(73)	$	419	$	697	$	(278)

(1)Includes energy performance contracting and sustainable infrastructure services through Energy Systems Group, unallocated corporate costs, interest income and interest expense, intercompany eliminations and the reduction of income allocated to preferred shareholders.

Three months ended June 30, 2023 compared to three months ended June 30, 2022

Income available to common shareholders decreased $73 million primarily due to the following items:

an increase in income available to common shareholders of $7 million for the Electric reportable segment, as further discussed below;
an increase in income available to common shareholders of $7 million for the Natural Gas reportable segment, as further discussed below;
a decrease in income available to common shareholders of $87 million for Corporate and Other, primarily due to a loss on sale of $12 million and current tax expense of $33 million related to the divestiture of Energy Systems Group further discussed in Note 3 to the Interim Condensed Financial Statements, as well as $19 million due to remeasurement of deferred income tax balances. The remaining variance is due largely to an approximately $20 million increase in borrowing costs due to higher interest rates.

Six months ended June 30, 2023 compared to six months ended June 30, 2022

Income available to common shareholders decreased $278 million primarily due to the following items:

an increase in net income of $48 million for the Electric reportable segment, as further discussed below;
a decrease in net income of $157 million for the Natural Gas reportable segment, as further discussed below;
a decrease in income available to common shareholders of $169 million for Corporate and Other, primarily due to the pre-tax net gain of $86 million on the sale of Energy Transfer equity securities in 2022 further discussed in Note 10 to the Interim Condensed Financial Statements, partially offset by $45 million of costs associated with early redemption of long-term debt in first quarter 2022, a loss on sale of $12 million and current tax expense of $33 million related to the divestiture of Energy Systems Group further discussed in Note 3 to the Interim Condensed Financial Statements, as well as $19 million due to remeasurement of deferred income tax balances. The remaining variance is due largely to an approximately $30 million increase in borrowing costs due to higher interest rates.

Income Tax Expense. For a discussion of effective tax rate per period, see Note 12 to the Interim Condensed Financial Statements.

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CENTERPOINT ENERGY’S RESULTS OF OPERATIONS BY REPORTABLE SEGMENT

CenterPoint Energy’s CODM views net income as the measure of profit or loss for the reportable segments. Segment results include inter-segment interest income and expense, which may result in inter-segment profit and loss.

The following discussion of CenterPoint Energy’s results of operations is separated into two reportable segments, Electric and Natural Gas.

Electric (CenterPoint Energy)

For information regarding factors that may affect the future results of operations of CenterPoint Energy’s Electric reportable segment, please read “Risk Factors — Risk Factors Affecting Operations — Electric Generation, Transmission and Distribution,” “— Risk Factors Affecting Regulatory, Environmental and Legal Risks,” “— Risk Factors Affecting Financial, Economic and Market Risks,” “— Risk Factors Affecting Safety and Security Risks” and “— General and Other Risks” in Item 1A of Part I of the Registrants’ combined 2022 Form 10-K.

The following table provides summary data of the Electric reportable segment:


	Three Months Ended June 30,									Six Months Ended June 30,
	2023			2022			Favorable (Unfavorable)			2023			2022			Favorable (Unfavorable)
	(in millions, except operating statistics)
Revenues	$	1,037		$	1,053		$	(16)		$	1,989		$	1,946		$	43
Expenses:
Utility natural gas, fuel and purchased power	19			56			37			79			97			18
Operation and maintenance	450			449			(1)			876			886			10
Depreciation and amortization	218			205			(13)			409			397			(12)
Taxes other than income taxes	68			72			4			135			140			5

Total expenses	755			782			27			1,499			1,520			21
Operating Income	282			271			11			490			426			64
Other Income (Expense):
Interest expense and other finance charges	(71)			(59)			(12)			(132)			(116)			(16)

Other income, net	14			7			7			26			12			14
Income Before Income Taxes	225			219			6			384			322			62
Income tax expense	45			46			1			81			67			(14)
Net Income	$	180		$	173		$	7		$	303		$	255		$	48
Throughput (in GWh):
Residential	9,036			10,003			(10)		%	15,004			16,349			(8)		%
Total	28,009			29,270			(4)		%	49,765			52,425			(5)		%
Weather (percentage of 10-year average for service area):
Cooling degree days	105		%	126		%	(21)		%	109		%	118		%	(9)		%
Heating degree days	78		%	53		%	25		%	86		%	121		%	(35)		%
Number of metered customers at end of period:
Residential	2,561,331			2,517,362			2		%	2,561,331			2,517,362			2		%
Total	2,887,492			2,840,830			2		%	2,887,492			2,840,830			2		%

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The following table provides variance explanations for the three months ended June 30, 2023 compared to the three months ended June 30, 2022 as well as for the six months ended June 30, 2023 compared to the six months ended June 30, 2022 by major income statement caption for the Electric reportable segment:


	Favorable (Unfavorable)
	Three Months Ended June 30, 2023 vs 2022		Six Months Ended June 30, 2023 vs 2022
	(in millions)
Revenues
Transmission Revenues, including TCOS and TCRF, inclusive of costs billed by transmission providers, partially offset in operation and maintenance below	$	19	$	74
Customer rates	46		68
Cost of fuel and purchased power, offset in utility natural gas, fuel and purchased power below	(37)		(18)
Customer growth	6		12


Miscellaneous revenues, including service connections and off-system sales	(7)		(9)
Bond Companies equity return, related to the annual true-up of transition charges for amounts over or under collected in prior periods	(2)		(4)
Energy efficiency, and other pass-through, offset in operation and maintenance below	7		7
Weather, efficiency improvements and other usage impacts	(30)		(48)
Bond Companies, offset in other line items below	(18)		(39)
Total	$	(16)	$	43
Utility natural gas, fuel and purchased power
Cost of fuel, including coal, natural gas, and fuel oil, offset in revenues above	$	6	$	7
Cost of purchased power, offset in revenues above	31		11
Total	$	37	$	18
Operation and maintenance
All other operation and maintenance expense, including materials and supplies and insurance	$	11	$	27
Energy efficiency, and other pass-through, offset in revenues above	(7)		(7)
Labor and benefits	4		13
Contract services	(2)		(2)
Bond Companies, offset in other line items	1		1
Support services, primarily information technology cost	(6)		(1)



Transmission costs billed by transmission providers, offset in revenues above	(2)		(21)
Total	$	(1)	$	10
Depreciation and amortization
Bond Companies, offset in other line items	$	13	$	31
Ongoing additions to plant-in-service	(26)		(43)
Total	$	(13)	$	(12)
Taxes other than income taxes


Franchise fees and other taxes	$	2	$	3
Incremental capital projects placed in service, net of updated property tax rates	2		2
Total	$	4	$	5
Interest expense and other finance charges
Changes in outstanding debt	$	(19)	$	(35)
Bond Companies, offset in other line items	2		4
Other, primarily AFUDC and impacts of regulatory deferrals	5		15
Total	$	(12)	$	(16)
Other income, net
Other income, including AFUDC - Equity	$	7	$	14


Total	$	7	$	14

Income Tax Expense. For a discussion of effective tax rate per period by Registrant, see Note 12 to the Interim Condensed Financial Statements.

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Natural Gas (CenterPoint Energy)

For information regarding factors that may affect the future results of operations of CenterPoint Energy’s Natural Gas reportable segment, please read “Risk Factors — Risk Factors Affecting Operations — Natural Gas,” “— Risk Factors Affecting Regulatory, Environmental and Legal Risks,” “— Risk Factors Affecting Financial, Economic and Market Risks,” “— Risk Factors Affecting Safety and Security Risks” and “— General and Other Risks” in Item 1A of Part I of the Registrants’ combined 2022 Form 10-K.

The following table provides summary data of CenterPoint Energy’s Natural Gas reportable segment:


	Three Months Ended June 30,									Six Months Ended June 30,
	2023			2022			Favorable (Unfavorable)			2023			2022			Favorable (Unfavorable)
	(in millions, except operating statistics)
Revenues	$	764		$	818		$	(54)		$	2,539		$	2,642		$	(103)
Expenses:
Utility natural gas, fuel and purchased power	261			357			96			1,279			1,414			135
Non-utility cost of revenues, including natural gas	—			1			1			1			2			1
Operation and maintenance	222			209			(13)			450			455			5
Depreciation and amortization	128			117			(11)			250			229			(21)
Taxes other than income taxes	59			61			2			129			138			9
Total expenses	670			745			75			2,109			2,238			129
Operating Income	94			73			21			430			404			26
Other Income (Expense):
Gain on sale	—			—			—			—			303			(303)
Interest expense and other finance charges	(48)			(33)			(15)			(92)			(63)			(29)

Other income (expense), net	4			(10)			14			6			(10)			16
Income Before Income Taxes	50			30			20			344			634			(290)
Income tax expense	15			2			(13)			75			208			133
Net Income (Loss)	$	35		$	28		$	7		$	269		$	426		$	(157)



Throughput (in Bcf):
Residential	28			28			—		%	124			151			(18)		%
Commercial and Industrial	91			90			1		%	224			226			(1)		%
Total	119			118			1		%	348			377			(8)		%
Weather (percentage of 10-year average for service area):
Heating degree days	88		%	102		%	(14)		%	88		%	108		%	(20)		%
Number of metered customers at end of period:
Residential	3,965,118			3,919,079			1		%	3,965,118			3,919,079			1		%
Commercial and Industrial	299,213			295,487			1		%	299,213			295,487			1		%
Total	4,264,331			4,214,566			1		%	4,264,331			4,214,566			1		%

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	Favorable (Unfavorable)
	Three Months Ended June 30, 2023 vs 2022		Six Months Ended June 30, 2023 vs 2022
	(in millions)
Revenues
Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale	$	—	$	(38)
Weather and usage	17		(7)
Cost of natural gas, offset in utility natural gas, fuel and purchased power below	(96)		(112)
Gross receipts tax, offset in taxes other than income taxes below	(1)		(7)
Energy efficiency, offset in operation and maintenance below	(5)		(9)



Non-volumetric and miscellaneous revenue	3		4
Changes in non-utility revenues	5		8
Customer growth	4		12
Pass-through revenues, offset in operation and maintenance below	6		15
Customer rates and impact of the change in rate design	13		31
Total	$	(54)	$	(103)
Utility natural gas, fuel and purchased power
Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale	$	—	$	23
Cost of natural gas, offset in revenues above	96		112


Total	$	96	$	135
Non-utility costs of revenues, including natural gas
Other, primarily non-utility cost of revenues	$	1	$	1
Total	$	1	$	1
Operation and maintenance

Corporate support services	$	(2)	$	7
Labor and benefits	(3)		3
Energy efficiency, offset in revenues above	5		9
Miscellaneous operations and maintenance expense, including bad debt expense	(3)		1
Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale	—		3
Contract services	(4)		(3)
Pass-through expense, offset in revenues above	(6)		(15)
Total	$	(13)	$	5
Depreciation and amortization
Incremental capital projects placed in service	$	(11)	$	(23)
Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale	—		2

Total	$	(11)	$	(21)
Taxes other than income taxes
Gross receipts tax, offset in revenues above	$	1	$	7
Other, primarily property taxes	1		1
Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale	—		1

Total	$	2	$	9
Gain on sale
Net gain on sale of Arkansas and Oklahoma Natural Gas businesses	$	—	$	(303)
Total	$	—	$	(303)
Interest expense and other finance charges
Changes in outstanding debt	$	(18)	$	(47)
Other, primarily AFUDC and impacts of regulatory deferrals	3		18
Total	$	(15)	$	(29)



Other income (expense), net
AFUDC - Equity, primarily from increased capital spend	$	3	$	5
Decrease to non-service benefit cost	12		10
Other	(1)		1

Total	$	14	$	16

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Income Tax Expense. For a discussion of effective tax rate per period by Registrant, see Note 12 to the Interim Condensed Financial Statements.

HOUSTON ELECTRIC’S MANAGEMENT’S NARRATIVE ANALYSIS

OF CONSOLIDATED RESULTS OF OPERATIONS

Houston Electric’s CODM views net income as the measure of profit or loss for its single reportable segment. Houston Electric’s results of operations are affected by seasonal fluctuations in the demand for electricity. Houston Electric’s results of operations are also affected by, among other things, the actions of various governmental authorities having jurisdiction over rates Houston Electric charges, debt service costs, income tax expense, Houston Electric’s ability to collect receivables from REPs and Houston Electric’s ability to recover its regulatory assets. For more information regarding factors that may affect the future results of operations of Houston Electric’s business, please read “Risk Factors — Risk Factors Affecting Operations — Electric Generation, Transmission and Distribution,” “— Risk Factors Affecting Regulatory, Environmental and Legal Risks,” “— Risk Factors Affecting Financial, Economic and Market Risks,” “— Risk Factors Affecting Safety and Security Risks” and “— General and Other Risks” in Item 1A of Part I of the Registrants’ combined 2022 Form 10-K.


	Three Months Ended June 30,									Six Months Ended June 30,
	2023			2022			Favorable (Unfavorable)			2023			2022			Favorable (Unfavorable)
	(in millions, except operating statistics)
Revenues:
TDU	$	868		$	822		$	46		$	1,628		$	1,515		$	113
Bond Companies	41			59			(18)			73			112			(39)
Total revenues	909			881			28			1,701			1,627			74
Expenses:
Operation and maintenance, excluding Bond Companies	399			403			4			779			797			18
Depreciation and amortization, excluding Bond Companies	147			120			(27)			276			234			(42)
Taxes other than income taxes	67			68			1			131			131			—
Bond Companies	41			54			13			71			103			32
Total expenses	654			645			(9)			1,257			1,265			8
Operating Income	255			236			19			444			362			82
Other Income (Expense)
Interest expense and other finance charges	(63)			(50)			(13)			(116)			(98)			(18)
Interest expense on Securitization Bonds	(2)			(4)			2			(4)			(8)			4


Other income, net	10			4			6			17			8			9
Income Before Income Taxes	200			186			14			341			264			77
Income tax expense	42			39			(3)			75			56			(19)
Net Income	$	158		$	147		$	11		$	266		$	208		$	58
Throughput (in GWh):
Residential	8,741			9,710			(10)		%	14,393			15,698			(8)		%
Total	26,788			27,704			(3)		%	47,438			49,638			(4)		%
Weather (percentage of 10-year average for service area):
Cooling degree days	105		%	127		%	(22)		%	109		%	118		%	(9)		%
Heating degree days	69		%	13		%	56		%	87		%	124		%	(37)		%
Number of metered customers at end of period:
Residential	2,428,904			2,382,145			2		%	2,428,904			2,382,145			2		%
Total	2,735,799			2,686,295			2		%	2,735,799			2,686,295			2		%


	Favorable (Unfavorable)
	Three Months Ended June 30, 2023 vs 2022		Six Months Ended June 30, 2023 vs 2022
	(in millions)
Revenues
Transmission Revenues, including TCOS and TCRF, inclusive of costs billed by transmission providers	$	19	$	74
Customer rates	50		66

Customer growth	6		12

Equity return, related to the annual true-up of transition charges for amounts over or under collected in prior periods	(2)		(4)

Weather impacts and other usage	(29)		(37)


Energy efficiency, offset in operations and maintenance below	2		2
Bond Companies, offset in other line items below	(18)		(39)

Total	$	28	$	74
Operation and maintenance, excluding Bond Companies
All other operation and maintenance expense, including materials and supplies and insurance	$	9	$	28
Labor and benefits	4		12
Support services, primarily information technology cost	(4)		—
Contract services	(1)		1



Energy efficiency, offset in revenues above	(2)		(2)
Transmission costs billed by transmission providers, offset in revenues above	(2)		(21)
Total	$	4	$	18
Depreciation and amortization, excluding Bond Companies
Ongoing additions to plant-in-service	$	(27)	$	(42)
Total	$	(27)	$	(42)
Taxes other than income taxes
Franchise fees and other taxes	$	1	$	—

Total	$	1	$	—
Bond Companies expense
Operations and maintenance and depreciation expense, offset in revenues above	$	13	$	32
Total	$	13	$	32
Interest expense and other finance charges
Changes in outstanding debt	$	(16)	$	(29)
Other, primarily AFUDC, impacts of regulatory deferrals	3		11
Total	$	(13)	$	(18)




Interest expense on Securitization Bonds
Lower outstanding principal balance, offset in revenues above	$	2	$	4
Total	$	2	$	4
Other income, net
Other income, including AFUDC - Equity	$	6	$	9


Total	$	6	$	9

Income Tax Expense. For a discussion of effective tax rate per period, see Note 12 to the Interim Condensed Financial Statements.

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CERC’S MANAGEMENT’S NARRATIVE ANALYSIS OF CONSOLIDATED RESULTS OF OPERATIONS

CERC’s CODM views net income as the measure of profit or loss for its single reportable segment. CERC’s results of operations are affected by seasonal fluctuations in the demand for natural gas. CERC’s results of operations are also affected by, among other things, the actions of various federal, state and local governmental authorities having jurisdiction over rates CERC charges, debt service costs and income tax expense, CERC’s ability to collect receivables from customers and CERC’s ability to recover its regulatory assets. As a result of the Restructuring further discussed in Note 1 to the Interim Condensed Financial Statements, prior year amounts have been recast. For more information regarding factors that may affect the future results of operations for CERC’s business, please read “Risk Factors — Risk Factors Affecting Operations — Natural Gas,” “— Risk Factors Affecting Regulatory, Environmental and Legal Risks,” “— Risk Factors Affecting Financial, Economic and Market Risks,” “— Risk Factors Affecting Safety and Security Risks” and “— General and Other Risks” in Item 1A of Part I of the Registrants’ combined 2022 Form 10-K.


	Three Months Ended June 30,									Six Months Ended June 30,
	2023			2022			Favorable (Unfavorable)			2023			2022			Favorable (Unfavorable)
	(in millions, except operating statistics)
Revenues	$	745		$	796		$	(51)		$	2,462		$	2,560		$	(98)
Expenses:
Utility natural gas, fuel and purchased power	260			351			91			1,258			1,384			126
Non-utility cost of revenues, including natural gas	—			1			1			1			2			1
Operation and maintenance	211			202			(9)			429			440			11
Depreciation and amortization	122			113			(9)			240			220			(20)
Taxes other than income taxes	59			60			1			128			135			7
Total expenses	652			727			75			2,056			2,181			125
Operating Income	93			69			24			406			379			27
Other Income (Expense):
Gain on sale	—			—			—			—			557			(557)
Interest expense and other finance charges	(45)			(30)			(15)			(87)			(59)			(28)

Other income, net	5			(11)			16			6			(11)			17
Income Before Income Taxes	53			28			25			325			866			(541)
Income tax expense	10			1			(9)			70			203			133


Net Income	$	43		$	27		$	16		$	255		$	663		$	(408)
Throughput (in Bcf):
Residential	27			27			—		%	121			147			(18)		%
Commercial and Industrial	81			82			(1)		%	206			207			—		%
Total	108			109			(1)		%	327			354			(8)		%
Weather (percentage of 10-year average for service area):
Heating degree days	88		%	102		%	(14)		%	89		%	109		%	(20)		%
Number of metered customers at end of period:
Residential	3,861,596			3,815,625			1		%	3,861,596			3,815,625			1		%
Commercial and Industrial	288,662			284,914			1		%	288,662			284,914			1		%
Total	4,150,258			4,100,539			1		%	4,150,258			4,100,539			1		%

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	Favorable (Unfavorable)
	Three Months Ended June 30, 2023 vs 2022		Six Months Ended June 30, 2023 vs 2022
	(in millions)
Revenues
Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale	$	—	$	(38)
Weather and usage	17		(7)
Cost of natural gas, offset in utility natural gas, fuel and purchased power below	(91)		(103)
Gross receipts tax, offset in taxes other than income taxes below	(1)		(6)
Energy efficiency, offset in operation and maintenance below	(5)		(8)

Non-volumetric and miscellaneous revenue	3		3
Changes in non-utility revenues	5		8

Pass-through revenues, offset in operation and maintenance below	4		10
Customer growth	4		12
Customer rates and impact of the change in rate design	13		31
Total	$	(51)	$	(98)
Utility natural gas, fuel and purchased power
Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale	$	—	$	23
Cost of natural gas, offset in revenues above	91		103


Total	$	91	$	126
Non-utility costs of revenues, including natural gas
Other, primarily non-utility cost of revenues	$	1	$	1
Total	$	1	$	1
Operation and maintenance
Corporate support services	$	(2)	$	7
Labor and benefits	(3)		4
Energy efficiency, offset in revenues above	5		8
Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale	—		3
Miscellaneous operations and maintenance expense, including bad debt expense	(3)		(1)
Contract services	(2)		—
Pass-through expense, offset in revenues above	(4)		(10)



Total	$	(9)	$	11
Depreciation and amortization
Incremental capital projects placed in service	$	(9)	$	(22)
Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale	—		2

Total	$	(9)	$	(20)
Taxes other than income taxes
Gross receipts tax, offset in revenues above	$	1	$	6

Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale	—		1
Total	$	1	$	7
Gain on sale
Net gain on sale of Arkansas and Oklahoma Natural Gas businesses	$	—	$	(557)
Total	$	—	$	(557)
Interest expense and other finance charges
Changes in outstanding debt	$	(18)	$	(46)
Other, primarily AFUDC and impacts of regulatory deferrals	3		18
Total	$	(15)	$	(28)



Other income (expense), net
AFUDC - Equity, primarily from increased capital spend	$	3	$	4
Decrease to non-service benefit cost	12		10
Other	1		3

Total	$	16	$	17

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Income Tax Expense. For a discussion of effective tax rate per period, see Note 12 to the Interim Condensed Financial Statements.

CERTAIN FACTORS AFFECTING FUTURE EARNINGS

For information on other developments, factors and trends that may have an impact on the Registrants’ future earnings, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Certain Factors Affecting Future Earnings” in Item 7 of Part II and “Risk Factors” in Item 1A of Part I of the Registrants’ combined 2022 Form 10-K, and “Cautionary Statement Regarding Forward-Looking Information” in this combined Form 10-Q.

LIQUIDITY AND CAPITAL RESOURCES

Historical Cash Flows

As a result of the Restructuring further discussed in Note 1 to the Interim Condensed Financial Statements, prior year amounts for CERC have been recast. The following table summarizes the net cash provided by (used in) operating, investing and financing activities during the six months ended June 30, 2023 and 2022:


	Six Months Ended June 30,
	2023						2022
	CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC
	(in millions)
Cash provided by (used in):
Operating activities	$	2,482	$	415	$	2,147	$	978	$	188	$	767
Investing activities	(2,154)		(1,198)		(1,233)		942		(1,391)		1,394
Financing activities	(187)		769		(913)		(1,597)		1,066		(2,173)

Operating Activities. The following items contributed to increased (decreased) net cash provided by operating activities for the six months ended June 30, 2023 compared to the six months ended June 30, 2022:


	CenterPoint Energy		Houston Electric		CERC
	(in millions)
Changes in net income after adjusting for non-cash items	$	150	$	84	$	(10)
Changes in working capital	487		191		320
Change in net regulatory assets and liabilities (1)	909		(80)		1,062





Other	(42)		32		8
	$	1,504	$	227	$	1,380

(1)This change is primarily related to the receipt of proceeds at CenterPoint Energy and CERC from the Texas securitization program. For further details, see Note 6 to the Interim Condensed Financial Statements.

Investing Activities. The following items contributed to (increased) decreased net cash used in investing activities for the six months ended June 30, 2023 compared to the six months ended June 30, 2022:


	CenterPoint Energy		Houston Electric		CERC
	(in millions)
Proceeds from the sale of equity securities	$	(702)	$	—	$	—

Capital expenditures	(379)		(45)		(119)
Net change in notes receivable from affiliated companies	—		272		(417)


Proceeds from divestitures	(1,930)		—		(2,075)


Other	(85)		(34)		(16)
	$	(3,096)	$	193	$	(2,627)

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Financing Activities. The following items contributed to (increased) decreased net cash used in financing activities for the six months ended June 30, 2023 compared to the six months ended June 30, 2022:


	CenterPoint Energy		Houston Electric		CERC
	(in millions)
Net changes in commercial paper outstanding	$	306	$	—	$	(480)


Net changes in long-term debt and term loans outstanding, excluding commercial paper	957		141		(696)


Net changes in debt issuance costs	(11)		(1)		(5)
Net changes in short-term borrowings	29		—		29
Proceeds from government grants	—		—		—
Payment of obligation for finance lease	171		171		—
Increased payment of common stock dividends	(26)		—		—

Net change in notes payable from affiliated companies	—		(20)		1,517
Contribution from parent	—		(493)		375
Dividend to parent	—		(93)		520


Other	(16)		(2)		—
	$	1,410	$	(297)	$	1,260

Future Sources and Uses of Cash

The liquidity and capital requirements of the Registrants are affected primarily by results of operations, capital expenditures, debt service requirements, tax payments, working capital needs and various regulatory actions. Capital expenditures are expected to be used for investment in infrastructure. These capital expenditures are anticipated to maintain reliability and safety, increase resiliency and expand our systems through value-added projects. In addition to dividend payments on CenterPoint Energy’s Series A Preferred Stock and Common Stock and interest payments on debt, the Registrants’ principal anticipated cash requirements for the remaining six months of 2023 include the following:


	CenterPoint Energy		Houston Electric		CERC
	(in millions)
Estimated capital expenditures	$	1,391	$	618	$	620
Scheduled principal payments on Securitization Bonds	79		79		—
Maturing senior notes	57		—		57
Minimum contributions to pension plans and other post-retirement plans	7		1		2

The Registrants expect that anticipated cash needs for the remaining six months of 2023 will be met with borrowings under their credit facilities, proceeds from the issuance of long-term debt, term loans, anticipated cash flows from operations, and, with respect to CenterPoint Energy and CERC, proceeds from commercial paper. Discretionary financing or refinancing may result in the issuance of debt securities of the Registrants in the capital markets or the arrangement of additional credit facilities or term bank loans. Issuances of debt in the capital markets, funds raised in the commercial paper markets and additional credit facilities may not, however, be available on acceptable terms.

Off-Balance Sheet Arrangements

Other than Houston Electric’s general mortgage bonds issued as collateral for tax-exempt long-term debt of CenterPoint Energy as discussed in Note 11 and guarantees as discussed in Note 13(b) to the Interim Condensed Financial Statements, we have no off-balance sheet arrangements.

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Regulatory Matters

February 2021 Winter Storm Event

For further information about the February 2021 Winter Storm Event, see Note 6 to the Interim Condensed Financial Statements.

Indiana Electric Securitization of Planned Generation Retirements (CenterPoint Energy)

For further information about the issuance of SIGECO Securitization Bonds, see Note 6 to the Interim Condensed Financial Statements.

Indiana Electric CPCN (CenterPoint Energy)

BTAs

On February 23, 2021, Indiana Electric filed a CPCN with the IURC seeking approval to purchase the Posey Solar project. On October 27, 2021, the IURC issued an order approving the CPCN, authorizing Indiana Electric to purchase the Posey Solar project through a BTA to acquire its solar array assets for a fixed purchase price and approved recovery of costs via a levelized rate over the anticipated 35-year life. Due to community feedback and rising project costs caused by inflation and supply chain issues affecting the energy industry, Indiana Electric, along with Arevon, the developer, announced plans in January 2022 to downsize the Posey Solar project to 191 MW. Indiana Electric collaboratively agreed to the scope change, and on February 1, 2023, Indiana Electric entered into an amended and restated BTA that is contingent on further IURC review and approval. On February 7, 2023, Indiana Electric filed a CPCN with the IURC to approve the amended BTA. With the passage of the IRA, Indiana Electric can now pursue PTCs for solar projects. Indiana Electric has filed an updated CPCN with a request that project costs, net of PTCs, be recovered in rate base, through base rates or the CECA mechanism, depending on which provides more timely recovery. The Posey Solar project is expected to be placed in service in 2025.

On July 5, 2022, Indiana Electric entered into a BTA to acquire a 130 MW solar array in Pike County, Indiana through a special purpose entity for a capped purchase price. A CPCN for the project was filed with the IURC on July 29, 2022. On September 21, 2022, an agreement in principle was reached resolving all the issues between Indiana Electric and OUCC. The Stipulation and Settlement agreement was filed on October 6, 2022 and a settlement hearing was held on November 1, 2022. On January 11, 2023, the IURC issued an order approving the settlement agreement granting Indiana Electric to purchase and acquire the Pike County solar project through a BTA and approved the estimated cost. The IURC also designated the project as a clean energy project, approved the proposed levelized rate and associated ratemaking and accounting treatment. The project is expected to be placed in service by the first quarter of 2025.

On January 10, 2023, Indiana Electric filed a CPCN with the IURC to acquire a wind energy generating facility with installed capacity of 200 MWs through a BTA, consistent with its 2019/2020 IRP that calls for up to 300 MWs of wind generation. The wind project is located in MISO’s Central Region zone 4. Commercial operation is expected as early as the end of 2025; however, factors (such as MISO interconnection process timing) could delay the project into 2026. Indiana Electric has requested recovery via the CECA mechanism or through base rates in the next general rate case, depending on which provides more timely recovery. On June 6, 2023 the IURC issued an order approving the CPCN, and thereby authorizing Indiana Electric to purchase the wind generating facility. However, as of the date of the filing of this Form 10-Q, Indiana Electric has not entered into any definitive agreement relating to this wind energy generating facility, and it is not certain that a definitive agreement will be entered into at all.

PPAs

Indiana Electric also sought approval in February 2021 for a 100 MW solar PPA with Clenera LLC in Warrick County, Indiana. The request accounted for increased cost of debt related to this PPA, which provides equivalent equity return to offset imputed debt during the 25 year life of the PPA. In October 2021, the IURC approved the Warrick County solar PPA but denied the request to preemptively offset imputed debt in the PPA cost. Due to rising project costs caused by inflation and supply chain issues affecting the energy industry, Clenera LLC and Indiana Electric were compelled to renegotiate terms of the agreement to increase the PPA price. On January 17, 2023, Indiana Electric filed a request with the IURC to amend the previously approved PPA with certain modifications. Revised purchase power costs are requested to be recovered through the

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fuel adjustment clause proceedings over the term of the amended PPA. The amended PPA was approved by the IURC in the second quarter of 2023. The Clenera LLC solar array is expected to be placed in service in the second quarter of 2025.

On August 25, 2021, Indiana Electric filed with the IURC seeking approval to purchase 185 MW of solar power, under a 15-year PPA, from Oriden, which is developing a solar project in Vermillion County, Indiana, and 150 MW of solar power, under a 20-year PPA, from Origis, which is developing a solar project in Knox County, Indiana. On May 4, 2022, the IURC issued an order approving Indiana Electric to enter into both PPAs. In March 2022, when the results of the MISO interconnection study were completed, Origis advised Indiana Electric that the costs to construct the solar project in Knox County, Indiana had increased. The increase was largely driven by escalating commodity and supply chain costs impacting manufacturers worldwide. In August 2022, Indiana Electric and Origis entered into an amended PPA, which reiterated the terms contained in the 2021 PPA with certain modifications. On October 19, 2022, Indiana Electric filed with the IURC seeking approval of the amended PPA with Origis and a hearing was held on January 4, 2023. On February 22, 2023, the IURC issued an order authorizing Indiana Electric to (i) enter into the amended PPA with Origis; (ii) recover the cost of the amended PPA over its full term as proposed; and (iii) use the proposed ratemaking treatment. On January 17, 2023, Indiana Electric filed a request with the IURC to amend the previously approved PPA with Oriden with certain modifications. Revised purchase power costs are requested to be recovered through the fuel adjustment clause proceedings over the term of the amended PPA with Oriden. The amended PPA with Oriden was approved by the IURC in the second quarter of 2023. The Oriden solar array is expected to be placed in service in the second quarter of 2025 and the Origis solar array is expected to be placed in service by the third quarter of 2024.

Natural Gas Combustion Turbines

On June 17, 2021, Indiana Electric filed a CPCN with the IURC seeking approval to construct two natural gas combustion turbines to replace portions of its existing coal-fired generation fleet. On June 28, 2022, the IURC approved the CPCN. The estimated $334 million turbine facility is planned to be constructed at the current site of the A.B. Brown power plant in Posey County, Indiana and would provide a combined output of 460 MW. Indiana Electric received approval for depreciation expense and post in-service carrying costs to be deferred in a regulatory asset until the date Indiana South’s base rates include a return on and recovery of depreciation expense on the facility. A new approximately 23.5 mile pipeline will be constructed and operated by Texas Gas Transmission, LLC to supply natural gas to the turbine facility. Indiana Electric entered into an agreement with Texas Gas Transmission, pending FERC approval of a necessary pipeline, to supply firm gas service to the new combustion turbines being constructed as part of the generation transition. On October 20, 2022, FERC granted Texas Gas Transmission a certificate to construct the pipeline. On November 21, 2022, the Citizens Action Coalition of Indiana, Inc. filed a request for rehearing which was denied on June 8, 2023 when FERC issued a Notice of Denial of Rehearing by Operation of Law. Separately, on February 21, 2023, Citizens Action Coalition of Indiana, Inc. filed a Petition for Review at the United States Court of Appeals for the District of Columbia. The appeal is pending with the briefing schedule recently being released. Finally, on July 7, 2023, FERC issued a Notice to Proceed with Full Construction and Modification Approvals, granting Texas Gas Transmission’s request to proceed, in full, with construction of the Henderson County Expansion Project. Indiana Electric granted its contractor a full notice to proceed to construct the turbines on December 9, 2022. The facility is targeted to be operational by mid-2025. Recovery of the proposed natural gas combustion turbines and regulatory asset will be requested in the next Indiana Electric rate case expected in 2023.

Culley Unit 3 Operations

In June 2022, F.B. Culley Unit 3, an Indiana Electric coal-fired electric generation unit with an installed generating capacity of 270 MW, experienced an operating issue relating to its boiler feed pump turbine. The unit returned to service in March 2023.

Space City Solar Transmission Interconnection Project (CenterPoint Energy and Houston Electric)

On December 17, 2020, Houston Electric filed a certificate of convenience and necessity application with the PUCT for approval to build a 345 kV transmission line in Wharton County, Texas connecting the Hillje substation on Houston Electric’s transmission system to the planned 610 MW Space City Solar Generation facility being developed by third-party developer EDF Renewables. The actual capital costs of the project will depend on actual land acquisition costs, construction costs, and other factors. In November 2021, the PUCT approved a route that was estimated to cost $25 million and issued a final order on

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January 12, 2022. There have been project delays due to supply chain constraints in the developer acquiring solar panels. Houston Electric expects to complete construction and the transmission line will be ready to be energized by the end of 2023.

Texas Legislation (CenterPoint Energy, Houston Electric and CERC)

Houston Electric continues to review the effects of legislation passed in 2021. For example, pursuant to legislation passed in 2021, Houston Electric entered into two leases for TEEEF (mobile generation). Additionally, the 2021 legislation allows Houston Electric to seek recovery of transmission and distribution facilities that have a lead time of at least six months and would aid in restoring power to Houston Electric’s distribution customers following certain widespread power outages. Houston Electric plans to seek recovery of costs associated with LLTF in a future DCRF or ratemaking proceeding. For additional information, see Note 6 to the Interim Condensed Financial Statements.

Houston Electric and CERC are also reviewing legislation passed in 2023, including the following pieces of legislation that became law during the 88th Texas Legislature, including:

House Bill 1500 is effective September 1, 2023 and continues the functions of the PUCT, the Office of Public Utility Counsel, and ERCOT through 2029. This bill also includes an amendment that clarifies the use cases under which TDUs may lease and operate temporary generation during “significant” power outages;
House Bill 2263 is effective June 12, 2023 and authorizes local distribution companies to offer programs to promote energy conservation and to recover costs prudently incurred to implement such programs under Railroad Commission authority;
House Bill 2555 is effective June 13, 2023 and allows an electric utility to create a transmission and distribution system resiliency plan with the PUCT and associated cost recovery to enhance its system through hardening, undergrounding certain lines, flood mitigation measures, and vegetation management. We anticipate that the PUCT will open a rule making proceeding; the PUCT has until December 10, 2023 to adopt a rule;
Senate Bill 947 is effective September 1, 2023 and creates severe criminal offenses for intentional damage to critical infrastructure facilities that create extended power outages;
Senate Bill 1015 is effective June 18, 2023 and allows utilities to file the DCRF twice a year, on any day the PUCT is open (at least 185 days after filing a full base rate proceeding) and setting an administrative approval timeline of 60 days;
Senate Bill 1016 is effective May 5, 2023 and requires the PUCT to presume that all employee compensation and benefits are reasonable and necessary when establishing a utility’s rates if based upon market compensation studies issued within the last three years; it includes exceptions for utility officer incentives that are based on financial metrics. Certain incentive compensation that is in-line with market studies will be presumed reasonable and recoverable; and
Senate Bill 1076 is effective June 2, 2023 and moves the timeline for the PUCT to approve certificates of convenience and necessity for transmission projects to 180 days after the date of filing, rather than the first anniversary of the day it was filed.

Minnesota Legislation (CenterPoint Energy and CERC)

The Natural Gas Innovation Act was passed by the Minnesota legislature in June 2021 with bipartisan support. This law establishes a regulatory framework to enable the state’s investor-owned natural gas utilities to provide customers with access to renewable energy resources and innovative technologies, with the goal of reducing greenhouse gas emissions and advancing the state’s clean energy future. The maximum allowable cost for an innovation plan will start at 1.75% of the utility's revenue in the state and could increase to 4% by 2033, subject to review and approval by the MPUC. Specifically, the Natural Gas Innovation Act allows a natural gas utility to submit an innovation plan for approval by the MPUC which could propose the use of renewable energy resources and innovative technologies such as:

renewable natural gas (produces energy from organic materials such as wastewater, agricultural manure, food waste, agricultural or forest waste);
renewable hydrogen gas (produces energy from water through electrolysis with renewable electricity such as solar);
energy efficiency measures (avoids energy consumption in excess of the utility’s existing conservation programs); and
innovative technologies (reduces or avoids greenhouse gas emissions using technologies such as carbon capture).

On June 28, 2023, CERC submitted its first innovation plan to the MPUC; the five-year plan includes 18 pilot projects and seven smaller research-and-development projects. These projects will deploy and evaluate a broad array of innovative resources including made-in-Minnesota alternative gases such as renewable natural gas and green hydrogen as well as pioneering technologies such as a networked geothermal district energy system and end-use carbon capture. The proposed plan requires approval from the MPUC through a review process that is expected to take about one year. The MPUC has asked for comments by September 15, 2023 if parties believe that the filing is incomplete based on the reporting requirements or if parties do not

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believe that that the MPUC’s standard informal proceeding process is appropriate. The initial comment period closes November 3, 2023, reply comments are due January 12, 2024 and supplemental comments are due February 2, 2024; the MPUC has indicated that unless warranted by comments received by September 15, 2023, it does not intend to hear this matter before the completion of the entire comment period.

Solar Panel Issues (CenterPoint Energy)

CenterPoint Energy’s current and future solar projects have been impacted by delays and/or increased costs. The delays and inflationary cost pressures communicated from the developers of our solar projects are primarily due to (i) unavailability of solar panels and other uncertainties related to the pending DOC investigation on anti-dumping and countervailing duties petition filed by a domestic solar manufacturer, (ii) the December 2021 Uyghur Forced Labor Prevention Act on solar modules and other products manufactured in China's Xinjiang Uyghur Autonomous Region and (iii) persistent general global supply chain and labor availability issues. On December 2, 2022, the DOC issued its preliminary determination, finding four of the eight companies being investigated are attempting to bypass U.S. duties; however, the investigation continues and the DOC’s final determination is now expected in August 2023. In June 2022, President Biden authorized an executive order which would suspend anti-circumvention tariffs on solar panels for two years; however, the executive order could be subject to legal and legislative challenges and its effects remain uncertain. The resolution of these issues will determine what additional costs or delays our solar projects will be subject to. These impacts have resulted in cost increases for certain projects, and may result in cost increases in other projects, and such impacts have resulted in, or are expected to result in, the need for us to seek additional regulatory review and approvals. Additionally, significant changes to project costs and schedules as a result of these factors could impact the viability of the projects. For more information regarding potential delays, cancellations and supply chain disruptions, see “Item 1A. Risk Factors” in the Registrants’ 2022 Form 10-K.

Rate Change Applications

The Registrants are 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, Registrants are periodically involved in proceedings to adjust its capital tracking mechanisms (e.g., CSIA, DCRF, DRR, GRIP, TCOS and TDSIC), its cost of service adjustments (e.g., RSP and RRA), its decoupling mechanism (e.g., Decoupling and SRC), and its energy efficiency cost trackers (e.g., CIP, DSMA, EECR, EECRF, EEFC and EEFR). The table below reflects significant applications pending or completed since the Registrants’ combined 2022 Form 10-K was filed with the SEC through the date of the filing of this Form 10-Q.


Mechanism	Annual Increase (Decrease) (1) (in millions)	Filing Date	Effective Date	Approval Date	Additional Information










CenterPoint Energy and Houston Electric (PUCT)
DCRF (1)	85	April 2023	TBD	TBD	The net change in distribution invested capital since its last base rate proceeding of approximately $1.9 billion for the period January 1, 2019 through December 31, 2022 for a revenue increase of $85 million, adjusted for load growth. On July 14, 2023 a settlement was filed that results in a revenue increase of $70 million adjusted for load growth.
TEEEF (1)	149	April 2023	TBD	TBD	A total Rider TEEEF revenue requirement of $188 million for cost incurred through December 31, 2022. The revenue change between the rates resulting from the 2022 TEEEF and this application is $149 million.
TCOS	40	March 2023	May 2023	May 2023	Based on net change in invested capital of $367 million for the period August 1, 2022 through January 31, 2023.
DCRF	117	April 2022	April 2023	April 2023	A final order was issued on April 5, 2023 approving a TEEEF revenue requirement of $39 million with rates effective April 15, 2023. On April 28, 2023 and May 1, 2023 certain intervenors filed motions for rehearing of the PUCT’s April 5, 2023 order. On May 25, 2023 the PUCT issued its order on rehearing which clarified some of the findings, but did not change the approval of TEEEF cost recovery. On June 19, 2023 certain intervenors filed motions for rehearing of the May 25, 2023 order on rehearing. The PUCT is expected to consider these motions at its August 3, 2023 open meeting. See Note 6 to the Interim Condensed Financial Statements for further information.
EECRF	16	June 2023	TBD	TBD	The requested $53 million is comprised primarily of the following: 2024 Program costs of $38 million; a credit of $2 million related to the over-recovery of 2022 program cost; the 2022 Earned bonus of $16 million and 2024 projected evaluation, measurement and verification costs of $1 million.

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Mechanism	Annual Increase (Decrease) (1) (in millions)	Filing Date	Effective Date	Approval Date	Additional Information
CenterPoint Energy and CERC - Beaumont/East Texas, South Texas, Houston and Texas Coast (Railroad Commission)
GRIP	60	March 2023	June 2023	June 2023	Based on net change in invested capital for calendar year 2022 of $390 million.
CenterPoint Energy and CERC - Minnesota (MPUC)
CIP Financial Incentive (1)	8	May 2023	TBD	TBD	CIP Financial Incentive based on 2022 CIP program activity.
CenterPoint Energy and CERC - Mississippi
RRA (1)	8	May 2023	TBD	TBD	Based ROE of 10.098% with 100 basis point (+/-) earnings band. Revenue increase of approximately $8 million based on 2022 test year adjusted earned ROE of 5.66%. Interim increase of approximately $1 million implemented May 31, 2023.
CenterPoint Energy and CERC - Louisiana (LPSC)
RSP	6	September 2022	May 2023	April 2023	Based on ROE of 9.95% with 50 basis point (+/-) earnings band. The North Louisiana increase, net of TCJA effects considered outside of the earnings band, is $3 million based on a test year ended June 2022 and adjusted ROE of 7.05%. The South Louisiana increase, net of TCJA effects considered outside of the earnings band, is $5 million based on a test year ended June 2022 and adjusted ROE of 4.19%. The TCJA refund impact to North Louisiana and South Louisiana was $1 million and $1 million, respectively. North Louisiana and South Louisiana also seek to recover regulatory assets due to COVID-19 bad debt expenses in the amounts of $0.7 million and $0.3 million, respectively. Interim rates implemented on December 28, 2022, subject to refund. On April 5, 2023 the LPSC issued an order approving a joint settlement for $2.7 million in North Louisiana and $4.6 million in South Louisiana in addition to the full impacts of TCJA and COVID-19 recoveries. Implementation occurred in May 2023 upon approval of compliance tariff.























CenterPoint Energy - Indiana South - Gas (IURC)
CSIA (1)	3	April 2023	July 2023	July 2023	Requested an increase of $33 million to rate base, which reflects approximately $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 a change in (over)/under-recovery variance of $1 million annually. Also included are unrecovered deferred Operations & Management expenses of $9 million. OUCC filed on June 2, 2023, recommending approval of the proposed CSIA rates and updated plan as filed, with non-cost recommendations. Rebuttal testimony filed June 16, 2023. A hearing was held June 28, 2023. The IURC issued an Order approving the CSIA on July 26, 2023.
CenterPoint Energy and CERC - Indiana North - Gas (IURC)
CSIA (1)	9	April 2023	July 2023	July 2023	Requested an increase of $95 million to rate base, which reflects approximately $9 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 a change in (over)/under-recovery variance of $5 million annually. Also included are unrecovered deferred O&M expenses of $20 million. OUCC filed on June 2, 2023, recommending approval of the proposed CSIA rates and updated plan as filed, with non-cost recommendations. Rebuttal testimony was filed on June 16, 2023. A hearing was held June 28, 2023. The IURC issued an Order approving the CSIA on July 26, 2023.

CenterPoint Energy and CERC - Ohio (PUCO)
DRR (1)	6	May 2023	TBD	TBD	Requested an increase of $46 million to rate base for investments made in 2022, which reflects a $6 million annual increase in current revenues. A change in (over)/under-recovery variance of $0.3 million annually is also included in rates. PUCO staff review and recommendation filed June 29, 2023 recommending approval as proposed. VEDO statement of issues resolved in case filed July 14, 2023.

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Mechanism	Annual Increase (Decrease) (1) (in millions)	Filing Date	Effective Date	Approval Date	Additional Information
CenterPoint Energy - Indiana Electric (IURC)
TDSIC (1)	2	February 2023	June 2023	May 2023	Requested an increase of $31 million to rate base, which reflects a $5 million annual increase in current revenues. 80% of the revenue requirement is included in requested rate increase and 20% is deferred until next rate case. The mechanism also includes a change in (over)/under-recovery variance and a tax reform credit for a total of ($1 million). OUCC filed on April 3, 2023, recommending approval of the proposed TDSIC rates and updated plan as filed. A hearing was held on May 3, 2023. On May 30, 2023, the IURC issued an order approving the TDSIC rates an updated plan as filed with rates effective June 1, 2023.
CECA (1)	—	February 2023	June 2023	May 2023	Requested an increase of less than $1 million to rate base, which reflects an annual increase of less than $1 million in current revenues. The mechanism also includes a change in (over)/under-recovery variance of less than ($1 million). OUCC filed on March 31, 2023, recommending approval of the proposed CECA cost recovery with a reduction of approximately $0.3 million. Rebuttal testimony was filed on April 6, 2023. A hearing was held on May 3, 2023. On May 30, 2023, the IURC issued an order approving the CECA rates with a cost recovery reduction of approximately $0.3 million with rates effective June 6, 2023.
ECA (1)	1	May 2023	TBD	TBD	Requested an increase of $51 million to rate base, which reflects a $1 million annual increase in current revenues. 80% of the revenue requirement is included in requested rate increase and 20% is deferred until next rate case. The mechanism also includes a change in (over)/under-recovery variance of less than $1 million.
DSMA (1)	16	July 2023	TBD	TBD	The requested $45 million is comprised primarily of the following: 2024 program costs of $11 million and $26 million of lost revenue, $3 million related to the over-recovery of 2022 program costs and $11 million under-recovery related to a prior period variance adjustment; the requested $45 million is an increase of $16 million compared to the prior DSMA.

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

Inflation Reduction Act (IRA)

On August 16, 2022, the IRA was signed into law. The new law extends or creates tax-related energy incentives for solar, wind and alternative clean energy sources, implements, subject to certain exceptions, a 1% tax on share repurchases after December 31, 2022, and implements a 15% corporate alternative minimum tax based on the AFSI of those corporations with an average AFSI of $1 billion over the most recent three-year period (i.e., the CAMT). The IRA did not have a material impact on the Registrants’ 2022 financial results and no material impact is expected for 2023 financial results. The Registrants may be currently subject to the CAMT, pending future guidance relating to comments requested in response to Notice 2023-7. If the Registrants are subject to the CAMT for 2023, the calculation of regular tax will exceed minimum tax for 2023; therefore, no minimum tax is expected to be paid. Further guidance on the tax provisions of the IRA is expected and the Registrants continue to evaluate the IRA provisions for the effect on their future financial results.

Greenhouse Gas Regulation and Compliance (CenterPoint Energy)

On August 3, 2015, the EPA released its CPP rule, which required a 32% reduction in carbon emissions from 2005 levels. The final rule was published in the Federal Register on October 23, 2015, and that action was immediately followed by litigation ultimately resulting in the U.S. Supreme Court staying implementation of the rule. On July 8, 2019, the EPA published the ACE rule, which (i) repealed the CPP rule; (ii) replaced the CPP rule with a program that requires states to implement a program of energy efficiency improvement targets for individual coal-fired electric generating units; and (iii) amended the implementing regulations for Section 111(d) of the Clean Air Act. On January 19, 2021, the majority of the ACE rule — including the CPP repeal, CPP replacement, and the timing-related portions of the Section 111(d) implementing rule — was struck down by the U.S. Court of Appeals for the D.C. Circuit and on October 29, 2021, the U.S. Supreme Court agreed to consider four petitions filed by various coal interests and a coalition of 19 states. On June 30, 2022, the U.S. Supreme Court ruled that the EPA exceeded its authority in promulgating the CPP. On May 10, 2023, the EPA proposed regulations under Section 111 of the Clean Air Act which, if finalized, apply new GHG performance standards for those existing coal-fired units expected to continue operation beyond December 31, 2029. We are currently reviewing the proposal for applicability to existing and new gas-fired generating units, but would note that CenterPoint Energy does not currently have plans to operate any of its coal-fired units beyond December 2029.

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The Biden administration recommitted the United States to the Paris Agreement, which can be expected to drive a renewed regulatory push to require further GHG emission reductions from the energy sector and proceeded to lead negotiations at the global climate conference in Glasgow, Scotland. On April 22, 2021, President Biden announced new goals of 50% reduction of economy-wide GHG emissions, and 100% carbon-free electricity by 2035, which formed the basis of the U.S. commitments announced in Glasgow. In September 2021, CenterPoint Energy announced its net zero emissions goals for both Scope 1 and certain Scope 2 emissions by 2035 as well as a goal to reduce certain Scope 3 emissions by 20% to 30% by 2035. Because Texas is an unregulated market, CenterPoint Energy’s Scope 2 estimates do not take into account Texas electric transmission and distribution assets in the line loss calculation and, in addition, exclude emissions related to purchased power in Indiana between 2024 and 2026 as estimated. CenterPoint Energy’s Scope 3 estimates are based on the total natural gas supply delivered to residential and commercial customers as reported in the U.S. Energy Information Administration (EIA) Form EIA-176 reports and do not take into account the emissions of transport customers and emissions related to upstream extraction. These emission goals are expected to be used to position CenterPoint Energy to comply with anticipated future regulatory requirements from the current and future administrations to further reduce GHG emissions. CenterPoint Energy’s and CERC’s revenues, operating costs and capital requirements could be adversely affected as a result of any regulatory action that would require installation of new control technologies or a modification of their operations or would have the effect of reducing the consumption of natural gas. The IRA established the Methane Emissions Reduction Program, which imposes a charge on methane emissions from certain natural gas transmission facilities, and the EPA has proposed new regulations targeting reductions in methane emissions, which if implemented will increase costs related to production, transmission and storage of natural gas. Houston Electric, in contrast to some electric utilities including Indiana Electric, does not generate electricity, other than TEEEF, and thus is not directly exposed to the risk of high capital costs and regulatory uncertainties that face electric utilities that burn fossil fuels to generate electricity. CenterPoint Energy’s net zero emissions goals are aligned with Indiana Electric’s generation transition plan and are expected to position Indiana Electric to comply with anticipated future regulatory requirements related to GHG emissions reductions. Nevertheless, Houston Electric’s and Indiana Electric’s revenues could be adversely affected to the extent any resulting regulatory action has the effect of reducing consumption of electricity by ultimate consumers within their respective service territories. Likewise, incentives to conserve energy or to use energy sources other than natural gas could result in a decrease in demand for the Registrants’ services. For example, Minnesota has enacted the Natural Gas Innovation Act that seeks to provide customers with access to renewable energy resources and innovative technologies, with the goal of reducing GHG emissions. Further, certain local government bodies have introduced or are considering requirements and/or incentives to reduce energy consumption by certain specified dates. For example, Minneapolis has adopted carbon emission reduction goals in an effort to decrease reliance on fossil gas. Additionally, cities in Minnesota within CenterPoint Energy’s Natural Gas operational footprint are considering initiatives to eliminate natural gas use in buildings and focus on electrification. Also, Minnesota cities may consider seeking legislative authority for the ability to enact voluntary enhanced energy standards for all development projects. These initiatives could have a significant impact on CenterPoint Energy and its operations, and this impact could increase if other cities and jurisdictions in its service area enact similar initiatives. Further, our third party suppliers, vendors and partners may also be impacted by climate change laws and regulations, which could impact CenterPoint Energy’s business by, among other things, causing permitting and construction delays, project cancellations or increased project costs passed on to CenterPoint Energy. Conversely, regulatory actions that effectively promote the consumption of natural gas because of its lower emissions characteristics would be expected to benefit CenterPoint Energy and CERC and their natural gas-related businesses. At this time, however, we cannot quantify the magnitude of the impacts from possible new regulatory actions related to GHG emissions, either positive or negative, on the Registrants’ businesses.

Compliance costs and other effects associated with climate change, reductions in GHG emissions and obtaining renewable energy sources remain uncertain. Although the amount of compliance costs remains uncertain, any new regulation or legislation relating to climate change will likely result in an increase in compliance costs. While the requirements of a federal or state rule remain uncertain, CenterPoint Energy will continue to monitor regulatory activity regarding GHG emission standards that may affect its business. Currently, CenterPoint Energy does not purchase carbon credits. In connection with its net zero emissions goals, CenterPoint Energy is expected to purchase carbon credits in the future; however, CenterPoint Energy does not currently expect the number of credits, or cost for those credits, to be material.

Climate Change Trends and Uncertainties

As a result of increased awareness regarding climate change, coupled with adverse economic conditions, availability of alternative energy sources, including private solar, microturbines, fuel cells, energy-efficient buildings and energy storage devices, and new regulations restricting emissions, including potential regulations of methane emissions, some consumers and companies may use less energy, meet their own energy needs through alternative energy sources or avoid expansions of their facilities, including natural gas facilities, resulting in less demand for the Registrants’ services. As these technologies become a more cost-competitive option over time, whether through cost effectiveness or government incentives and subsidies, certain customers may choose to meet their own energy needs and subsequently decrease usage of the Registrants’ systems and

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services, which may result in, among other things, Indiana Electric’s generating facilities becoming less competitive and economical. Further, evolving investor sentiment related to the use of fossil fuels and initiatives to restrict continued production of fossil fuels have had significant impacts on CenterPoint Energy’s electric generation and natural gas businesses. For example, because Indiana Electric’s current generating facilities substantially rely on coal for their operations, certain financial institutions choose not to participate in CenterPoint Energy’s financing arrangements. Conversely, demand for the Registrants’ services may increase as a result of customer changes in response to climate change. For example, as the utilization of electric vehicles increases, demand for electricity may increase, resulting in increased usage of CenterPoint Energy’s systems and services. Any negative opinions with respect to CenterPoint Energy’s environmental practices or its ability to meet the challenges posed by climate change formed by regulators, customers, investors, legislators or other stakeholders could harm its reputation.

To address these developments, CenterPoint Energy announced its net zero emissions goals for both Scope 1 and certain Scope 2 emissions by 2035. Indiana Electric’s 2019/2020 IRP identified a preferred portfolio that retires 730 MW of coal-fired generation facilities and replaces these resources with a mix of generating resources composed primarily of renewables, including solar, wind, and solar with storage, supported by dispatchable natural gas combustion turbines including a pipeline to serve such natural gas generation. Indiana Electric continues to execute on its 2019/2020 IRP and has received initial approvals for 756 MWs of the 700-1,000 MWs identified within Indiana Electric’s 2019/2020 IRP. Additionally, as reflected in its 10-year capital plan announced in September 2021, CenterPoint Energy anticipates spending over $3 billion in clean energy investments and enablement, which may be used to support, among other things, renewable energy generation and electric vehicle expansion. CenterPoint Energy believes its planned investments in renewable energy generation and corresponding planned reduction in its GHG emissions as part of its net zero emissions goals support global efforts to reduce the impacts of climate change. Indiana Electric has conducted a new IRP, which was submitted to the IURC in May 2023, to identify an appropriate generation resource portfolio to satisfy the needs of its customers and comply with environmental regulations. The proposed preferred portfolio is the second evolution to the generation transition plan to move away from coal-fired generation to a more sustainable portfolio of resources. Indiana Electric plans to convert its last remaining coal unit to natural gas by 2027 and to add a significant amount of additional renewable resources through 2033.

To the extent climate changes result in warmer temperatures in the Registrants’ service territories, financial results from the Registrants’ businesses could be adversely impacted. For example, CenterPoint Energy’s and CERC’s Natural Gas could be adversely affected through lower natural gas sales. On the other hand, warmer temperatures in CenterPoint Energy’s and Houston Electric’s electric service territory may increase revenues from transmission and distribution and generation through increased demand for electricity used for cooling. Another possible result of climate change is more frequent and more severe weather events, such as hurricanes, tornadoes and flooding, including such storms as the February 2021 Winter Storm Event. Since many of the Registrants’ facilities are located along or near the Texas gulf coast, increased or more severe hurricanes or tornadoes could increase costs to repair damaged facilities and restore service to customers. CenterPoint Energy’s current 10-year capital plan includes capital expenditures to maintain reliability and safety and increase resiliency of its systems as climate change may result in more frequent significant weather events. Houston Electric does not own or operate any electric generation facilities other than, since September 2021, its operation of TEEEF. Houston Electric transmits and distributes to customers of REPs electric power that the REPs obtain from power generation facilities owned by third parties. To the extent adverse weather conditions affect the Registrants’ suppliers, results from their energy delivery businesses may suffer. For example, in Texas, the February 2021 Winter Storm Event caused an electricity generation shortage that was severely disruptive to Houston Electric’s service territory and the wholesale generation market and also caused a reduction in available natural gas capacity. When the Registrants cannot deliver electricity or natural gas to customers, or customers cannot receive services, the Registrants’ financial results can be impacted by lost revenues, and they generally must seek approval from regulators to recover restoration costs. To the extent the Registrants are unable to recover those costs, or if higher rates resulting from recovery of such costs result in reduced demand for services, the Registrants’ future financial results may be adversely impacted. Further, as the intensity and frequency of significant weather events continues, it may impact our ability to secure cost-efficient insurance.

Other Matters

Credit Facilities

The Registrants may draw on their respective revolving credit facilities from time to time to provide funds used for general corporate and limited liability company purposes, including to backstop CenterPoint Energy’s and CERC’s commercial paper programs. The facilities may also be utilized to obtain letters of credit. For further details related to the Registrants’ revolving credit facilities, see Note 11 to the Interim Condensed Financial Statements.

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Based on the consolidated debt to capitalization covenant in the Registrants’ revolving credit facilities, the Registrants would have been permitted to utilize the full capacity of such revolving credit facilities, which aggregated approximately $4.0 billion as of June 30, 2023. As of July 19, 2023, the Registrants had the following revolving credit facilities and utilization of such facilities:


			Amount Utilized as of July 19, 2023
Registrant	Size of Facility		Loans		Letters of Credit		Commercial Paper		Weighted Average Interest Rate	Termination Date
	(in millions)
CenterPoint Energy	$	2,400	$	—	$	8	$	1,564	5.44%	December 6, 2027
CenterPoint Energy (1)	250		—		—		—		—%	December 6, 2027


Houston Electric	300		—		—		—		—%	December 6, 2027
CERC	1,050		—		1		—		—%	December 6, 2027
Total	$	4,000	$	—	$	9	$	1,564

(1)This credit facility was issued by SIGECO.

Borrowings under each of the revolving credit facilities are subject to customary terms and conditions. However, there is no requirement that the borrower makes representations prior to borrowing as to the absence of material adverse changes or litigation that could be expected to have a material adverse effect. Borrowings under each of the revolving credit facilities are subject to acceleration upon the occurrence of events of default that we consider customary. The revolving credit facilities also provide for customary fees, including commitment fees, administrative agent fees, fees in respect of letters of credit and other fees. In each of the revolving credit facilities, the spread to SOFR and the commitment fees fluctuate based on the borrower’s credit rating. Each of the Registrant’s credit facilities provide for a mechanism to replace SOFR with possible alternative benchmarks upon certain benchmark replacement events. The borrowers are currently in compliance with the various business and financial covenants in the four revolving credit facilities.

Debt Transactions

For detailed information about the Registrants’ debt transactions to date in 2023, see Note 11 to the Interim Condensed Financial Statements.

Securities Registered with the SEC

On May 17, 2023, the Registrants filed a joint shelf registration statement with the SEC registering indeterminate principal amounts of Houston Electric’s general mortgage bonds, CERC Corp.’s senior debt securities and CenterPoint Energy’s senior debt securities and junior subordinated debt securities and an indeterminate number of shares of Common Stock, shares of preferred stock, depositary shares, as well as stock purchase contracts and equity units. The joint shelf registration statement will expire on May 17, 2026. For information related to the Registrants’ debt issuances in 2023, see Note 11 to the Interim Condensed Financial Statements.

Temporary Investments

As of July 19, 2023, the Registrants had no temporary investments.

Money Pool

The Registrants participate in a money pool through which they and certain of their subsidiaries can borrow or invest on a short-term basis. Funding needs are aggregated and external borrowing or investing is based on the net cash position. The net funding requirements of the CenterPoint Energy money pool are expected to be met with borrowings under CenterPoint Energy’s revolving credit facility or the sale of CenterPoint Energy’s commercial paper. The net funding requirements of the CERC money pool are expected to be met with borrowings under CERC’s revolving credit facility or the sale of CERC’s commercial paper. The money pool may not provide sufficient funds to meet the Registrants’ cash needs.

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The table below summarizes CenterPoint Energy money pool activity by Registrant as of July 19, 2023:


	Weighted Average Interest Rate	Houston Electric		CERC
		(in millions)
Money pool investments	5.49%	$	(183)	$	327

Impact on Liquidity of a Downgrade in Credit Ratings

The interest rate on borrowings under the credit facilities is based on each respective borrower’s credit ratings. As of July 19, 2023, Moody’s, S&P and Fitch had assigned the following credit ratings to the borrowers:


		Moody’s		S&P		Fitch
Registrant	Borrower/Instrument	Rating	Outlook (1)	Rating	Outlook (2)	Rating	Outlook (3)
CenterPoint Energy	CenterPoint Energy Senior Unsecured Debt	Baa2	Stable	BBB	Stable	BBB	Stable
CenterPoint Energy	Vectren Corp. Issuer Rating	n/a	n/a	BBB+	Stable	n/a	n/a
CenterPoint Energy	SIGECO Senior Secured Debt	A1	Stable	A	Stable	n/a	n/a
Houston Electric	Houston Electric Senior Secured Debt	A2	Stable	A	Stable	A	Stable
CERC	CERC Corp. Senior Unsecured Debt	A3	Stable	BBB+	Stable	A-	Stable
CERC	Indiana Gas Senior Unsecured Debt	n/a	n/a	BBB+	Stable	n/a	n/a

(1)A Moody’s rating outlook is an opinion regarding the likely direction of an issuer’s rating over the medium term.

(2)An S&P outlook assesses the potential direction of a long-term credit rating over the intermediate to longer term.

(3)A Fitch rating outlook indicates the direction a rating is likely to move over a one- to two-year period.

The Registrants cannot assure that the ratings set forth above will remain in effect for any given period of time or that one or more of these ratings will not be lowered or withdrawn entirely by a rating agency. The Registrants note that these credit ratings are included for informational purposes and are not recommendations to buy, sell or hold the Registrants’ securities and may be revised or withdrawn at any time by the rating agency. Each rating should be evaluated independently of any other rating. Any future reduction or withdrawal of one or more of the Registrants’ credit ratings could have a material adverse impact on the Registrants’ ability to obtain short- and long-term financing, the cost of such financings and the execution of the Registrants’ commercial strategies.

A decline in credit ratings could increase borrowing costs under the Registrants’ revolving credit facilities. If the Registrants’ credit ratings had been downgraded one notch by S&P and Moody’s from the ratings that existed as of June 30, 2023, the impact on the borrowing costs under the three revolving credit facilities would have been insignificant. A decline in credit ratings would also increase the interest rate on long-term debt to be issued in the capital markets and could negatively impact the Registrants’ ability to complete capital market transactions and to access the commercial paper market. Additionally, a decline in credit ratings could increase cash collateral requirements and reduce earnings of CenterPoint Energy’s and CERC’s Natural Gas reportable segments.

Pipeline tariffs and contracts typically provide that if the credit ratings of a shipper or the shipper’s guarantor drop below a threshold level, which is generally investment grade ratings from both Moody’s and S&P, cash or other collateral may be demanded from the shipper in an amount equal to the sum of three months’ charges for pipeline services plus the unrecouped cost of any lateral built for such shipper. If the credit ratings of CERC Corp. decline below the applicable threshold levels, CERC might need to provide cash or other collateral of up to $249 million as of June 30, 2023. The amount of collateral will depend on seasonal variations in transportation levels.

ZENS and Securities Related to ZENS (CenterPoint Energy)

If CenterPoint Energy’s creditworthiness were to drop such that ZENS holders thought its liquidity was adversely affected or the market for the ZENS were to become illiquid, some ZENS holders might decide to exchange their ZENS for cash. Funds for the payment of cash upon exchange could be obtained from the sale of the shares of ZENS-Related Securities that CenterPoint Energy owns or from other sources. CenterPoint Energy owns shares of ZENS-Related Securities equal to approximately 100% of the reference shares used to calculate its obligation to the holders of the ZENS. ZENS exchanges result

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in a cash outflow because tax deferrals related to the ZENS and shares of ZENS-Related Securities would typically cease when ZENS are exchanged or otherwise retired and shares of ZENS-Related Securities are sold. The ultimate tax liability related to the ZENS and ZENS-Related Securities continues to increase by the amount of the tax benefit realized each year, and there could be a significant cash outflow when the taxes are paid as a result of the retirement or exchange of the ZENS. If all ZENS had been exchanged for cash on June 30, 2023, deferred taxes of approximately $697 million would have been payable in 2023. If all the ZENS-Related Securities had been sold on June 30, 2023, capital gains taxes of approximately $76 million would have been payable in 2023 based on 2023 tax rates in effect. For additional information about ZENS, see Note 10 to the Interim Condensed Financial Statements.

Cross Defaults

Under each of CenterPoint Energy’s, Houston Electric’s and CERC’s respective revolving credit facilities and CERC’s term loan agreement, a payment default on, or a non-payment default, event or condition that permits acceleration of, any indebtedness for borrowed money and certain other specified types of obligations (including guarantees) exceeding $125 million by the borrower or any of their respective significant subsidiaries will cause a default under such borrower’s respective credit facility or term loan agreement. Under SIGECO’s revolving credit facility, a payment default on, or a non-payment default, event or condition that permits acceleration of, any indebtedness for borrowed money and certain other specific types of obligations (including guarantees) exceeding $75 million by SIGECO or any of its significant subsidiaries will cause a default under SIGECO’s credit facility. A default by CenterPoint Energy would not trigger a default under its subsidiaries’ debt instruments or revolving credit facilities.

Possible Acquisitions, Divestitures and Joint Ventures

From time to time, the Registrants consider the acquisition or the disposition of assets or businesses or possible joint ventures, strategic initiatives or other joint ownership arrangements with respect to assets or businesses. Any determination to take action in this regard will be based on market conditions and opportunities existing at the time, and accordingly, the timing, size or success of any efforts and the associated potential capital commitments are unpredictable. The Registrants may seek to fund all or part of any such efforts with proceeds from debt and/or equity issuances. Debt or equity financing may not, however, be available to the Registrants at that time due to a variety of events, including, among others, maintenance of our credit ratings, industry conditions, general economic conditions, market conditions and market perceptions. CenterPoint Energy most recently increased its planned capital expenditures in its Electric and Natural Gas businesses in July 2023 to support further rate base growth. The Registrants may continue to explore asset sales as a means to efficiently finance a portion of its increased capital expenditures in the future, subject to the conditions listed above. For further information, see Note 3 to the Interim Condensed Financial Statements.

Hedging of Interest Expense for Future Debt Issuances

From time to time, the Registrants may enter into interest rate agreements to hedge, in part, volatility in the U.S. treasury rates by reducing variability in cash flows related to interest payments. As of June 30, 2023, the total notional amount of CenterPoint Energy’s forward interest rate agreements was $75 million. For further information, see Note 7(a) to the Interim Condensed Financial Statements.

Collection of Receivables from REPs (CenterPoint Energy and Houston Electric)

Houston Electric’s receivables from the distribution of electricity are collected from REPs that supply the electricity Houston Electric distributes to their customers. Before conducting business, a REP must register with the PUCT and must meet certain financial qualifications. Nevertheless, adverse economic conditions, the February 2021 Winter Storm Event, structural problems in the market served by ERCOT or financial difficulties of one or more REPs could impair the ability of these REPs to pay for Houston Electric’s services or could cause them to delay such payments. Houston Electric depends on these REPs to remit payments on a timely basis, and any delay or default in payment by REPs could adversely affect Houston Electric’s cash flows. In the event of a REP default, Houston Electric’s tariff provides a number of remedies, including the option for Houston Electric to request that the PUCT suspend or revoke the certification of the REP. Applicable regulatory provisions require that customers be shifted to another REP or a provider of last resort if a REP cannot make timely payments. However, Houston Electric remains at risk for payments related to services provided prior to the shift to the replacement REP or the provider of last resort. If a REP were unable to meet its obligations, it could consider, among various options, restructuring under the bankruptcy laws, in which event such REP might seek to avoid honoring its obligations and claims might be made against Houston Electric involving payments it had received from such REP. If a REP were to file for bankruptcy, Houston Electric may not be successful in recovering accrued receivables owed by such REP that are unpaid as of the date the REP filed for

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bankruptcy. However, PUCT regulations authorize utilities, such as Houston Electric, to defer bad debts resulting from defaults by REPs for recovery in future rate cases, subject to a review of reasonableness and necessity.

Other Factors that Could Affect Cash Requirements

In addition to the above factors, the Registrants’ liquidity and capital resources could also be negatively affected by:

cash collateral requirements that could exist in connection with certain contracts, including weather hedging arrangements, and natural gas purchases, natural gas price and natural gas storage activities of CenterPoint Energy’s and CERC’s Natural Gas reportable segment;
acceleration of payment dates on certain gas supply contracts, under certain circumstances, as a result of increased natural gas prices, and concentration of natural gas suppliers (CenterPoint Energy and CERC);
increased costs related to the acquisition of natural gas (CenterPoint Energy and CERC);
increases in interest expense in connection with debt refinancings and borrowings under credit facilities or term loans or the use of alternative sources of financings on capital and other financial markets;
various legislative or regulatory actions;
incremental collateral, if any, that may be required due to regulation of derivatives (CenterPoint Energy);
the ability of REPs, including REP affiliates of NRG and Vistra Energy Corp., to satisfy their obligations to CenterPoint Energy and Houston Electric;
slower customer payments and increased write-offs of receivables due to higher natural gas prices, changing economic conditions, public health threats or severe weather events (CenterPoint Energy and CERC);
the satisfaction of any obligations pursuant to guarantees;
the outcome of litigation, including litigation related to the February 2021 Winter Storm Event;
contributions to pension and postretirement benefit plans;
disruptions in the banking industry, including bank failures and uncertainty regarding bank stability;
restoration costs and revenue losses resulting from future natural disasters such as hurricanes and the timing of recovery of such restoration costs; and
various other risks identified in “Risk Factors” in Item 1A of Part I of the Registrants’ combined 2022 Form 10-K.

Certain Contractual Limits on Our Ability to Issue Securities and Borrow Money

Certain provisions in certain note purchase agreements relating to debt issued by CERC have the effect of restricting the amount of secured debt issued by CERC and debt issued by subsidiaries of CERC Corp. Additionally, Houston Electric and SIGECO are limited in the amount of mortgage bonds they can issue by the General Mortgage and SIGECO’s mortgage indenture, respectively. For information about the total debt to capitalization financial covenants in the Registrants’ and SIGECO’s revolving credit facilities, see Note 11 to the Interim Condensed Financial Statements.

CRITICAL ACCOUNTING POLICIES

A critical accounting policy is one that is both important to the presentation of the Registrants’ financial condition and results of operations and requires management to make difficult, subjective or complex accounting estimates. An accounting estimate is an approximation made by management of a financial statement element, item or account in the financial statements. Accounting estimates in the Registrants’ historical consolidated financial statements measure the effects of past business transactions or events, or the present status of an asset or liability. Additionally, different estimates that the Registrants could have used or changes in an accounting estimate that are reasonably likely to occur could have a material impact on the presentation of their financial condition, results of operations or cash flows. The circumstances that make these judgments difficult, subjective and/or complex have to do with the need to make estimates about the effect of matters that are inherently uncertain. Estimates and assumptions about future events and their effects cannot be predicted with certainty. The Registrants base their estimates on historical experience and on various other assumptions that they believe to be reasonable under the circumstances, the results of which form the basis for making judgments. These estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as the Registrants’ operating environment changes.

Impairment of Long-Lived Assets, Including Identifiable Intangibles and Goodwill

The Registrants review the carrying value of long-lived assets, including identifiable intangibles and goodwill, whenever events or changes in circumstances indicate that such carrying values may not be recoverable, and at least annually, goodwill is tested for impairment as required by accounting guidance for goodwill and other intangible assets. Unforeseen events, changes in market conditions, and probable regulatory disallowances, where applicable, could have a material effect on the value of long-lived assets, including intangibles and goodwill, future cash flows, interest rate, and regulatory matters, and could result in an impairment charge.

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CenterPoint Energy and CERC completed their 2022 annual goodwill impairment test during the third quarter of 2022 and determined, based on an income approach or a weighted combination of income and market approaches, that no goodwill impairment charge was required for any reporting unit. The fair values of each reporting unit significantly exceeded the carrying value of the reporting unit as of the last annual test.

From time to time, the Registrants consider the acquisition or the disposition of assets or businesses, and market information obtained through these exploratory activities is considered during the preparation of the financial statements to determine if an interim impairment test is required. The Registrants did not identify triggering events in connection with their preparation of the financial statements for the three months ended June 30, 2023, and goodwill impairment of long-lived asset impairments tests were not required or performed. See discussion below for goodwill attributable to disposed businesses, including assets held for sale.

Divestitures, including assets held for sale

Generally, a long-lived asset to be sold is classified as held for sale in the period in which management, with approval from the Board of Directors, as applicable, commits to a plan to sell, and a sale is expected to be completed within one year. The Registrants record assets and liabilities held for sale, or the disposal group, at the lower of their carrying value or their estimated fair value less cost to sell. If a disposal group reflects a component of a reporting unit and meets the definition of a business, the goodwill within that reporting unit is allocated to the disposal group based on the relative fair value of the components representing a business that will be retained and disposed. Goodwill is not allocated to a portion of a reporting unit that does not meet the definition of a business.

During the three and six months ended June 30, 2023, as described further in Note 3 to the Interim Condensed Financial Statements, certain assets and liabilities of Energy Systems Group representing a business were disposed. As a result of the held for sale criteria being met during the same period as the completion of the sale, goodwill attributable to Energy Systems Group of $134 million was reflected in the pre-tax loss on sale of $12 million based on the actual sale proceeds received at closing during the three and six months ended June 30, 2023.

Fair value is the amount at which an asset, liability or business could be bought or sold in a current transaction between willing parties and may be estimated using a number of techniques, including quoted market prices, present value techniques based on estimates of cash flows, or multiples of earnings or revenue performance measures. The fair value could be different if different estimates and assumptions in these valuation techniques were applied.

Fair value measurements require significant judgment and often unobservable inputs, including (i) projected timing and amount of future cash flows, which factor in planned growth initiatives, (ii) the regulatory environment, as applicable, and (iii) discount rates reflecting risk inherent in the future market prices. Changes in these assumptions could have a significant impact on the resulting fair value.

For further information, see Note 3 to the Interim Condensed Financial Statements.

Accounting for Securitization of Planned Generation Retirements

Accounting guidance for rate regulated long-lived asset abandonment requires that the carrying value of an operating asset or an asset under construction is removed from property, plant and equipment when it becomes probable that the asset will be abandoned. The Registrants recognize either a loss on abandonment or regulatory asset when they concluded it is probable the cost will be recovered in future rates. The portion of property, plant and equipment that will remain used and useful until abandonment and recovered through depreciation expense in rates will continue to be classified as property, plant and equipment until the asset is abandoned. The Registrants evaluate if an adjustment to the estimated life of the asset and, accordingly, the rate of depreciation, is required to recover the asset while it is still providing service. Determining probability of abandonment or probability of recovery requires significant judgment on the part of management and includes, but is not limited to, consideration of testimony presented in regulatory hearings, proposed regulatory decisions, final regulatory orders and the strength or status of applications for rehearing or state court appeals.

In connection with the securitization financing of qualified costs in the second quarter of 2023 associated with the planned retirement of SIGECO’s A.B. Brown coal generation facilities, CenterPoint Energy evaluated the VIE consisting of the Securitization Subsidiary, a wholly-owned, bankruptcy-remote, special purpose entity, for possible consolidation, including review of qualitative factors such as the power to direct the activities of the VIE and the obligation to absorb losses of the VIE. CenterPoint Energy has the power to direct the significant activities of the VIE and is most closely associated with the VIE as

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compared to other interests held by the holders of the SIGECO Securitization Bonds. CenterPoint Energy is, therefore, considered the primary beneficiary and consolidated the VIE.

For purposes of reporting cash flows, the Registrants consider cash equivalents to be short-term, highly-liquid investments with maturities of three months or less from the date of purchase. Cash and cash equivalents held by the Securitization Subsidiary solely to support servicing the SIGECO Securitization Bonds as of June 30, 2023 are reflected on CenterPoint Energy’s Consolidated Balance Sheet.

In connection with the issuance of the SIGECO Securitization Bonds, CenterPoint Energy was required to establish a restricted cash account to collateralize the SIGECO Securitization Bonds that were issued in the financing transaction. The restricted cash account is not available for withdrawal until the maturity of the SIGECO Securitization Bonds and is not included in cash and cash equivalents.

For further information, see Notes 1 and 6 to the Interim Condensed Financial Statements.

Other than the interim goodwill impairment review and securitization transaction discussed above, there have been no significant changes in our critical accounting policies during the six months ended June 30, 2023, as compared to the critical accounting policies disclosed in Management’s Discussion and Analysis of Financial Condition and Results of Operations included in the Registrants’ combined 2022 Form 10-K.

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