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 2021 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

Restructuring. CenterPoint Energy completed the Restructuring on June 30, 2022 whereby the equity interests in Indiana Gas and VEDO, each of which were acquired in its acquisition of Vectren on February 1, 2019, were transferred from VUH to CERC Corp. As a result, Indiana Gas and VEDO became wholly owned subsidiaries of CERC Corp. to better align its organizational structure with management and financial reporting and to fund future capital investments more efficiently. For additional information, see Note 1 to the Interim Condensed Financial Statements.

Debt Exchange. As a part of the Restructuring, on May 27, 2022, CERC Corp. and VUH completed an exchange with holders of VUH PPNs whereby CERC Corp. issued new senior notes with an aggregate principal amount of $302 million in return for all of their outstanding VUH PPNs with an aggregate principal amount of $302 million. For additional information, see Note 11 to the Interim Condensed Financial Statements.

VUH Credit Facility. On June 30, 2022, in connection with the Restructuring, VUH repaid in full all outstanding indebtedness and terminated all remaining commitments and other obligations under its $400 million amended and restated credit agreement dated as of February 4, 2021. For additional information, see Note 11 to the Interim Condensed Financial Statements.

Debt Transactions. During the six months ended June 30, 2022, Houston Electric issued $800 million and CERC issued $500 million in new debt, excluding the debt exchange discussed above, and CenterPoint Energy repaid or redeemed a combined $1,030 million of debt, including CERC’s redemption of $425 million of debt, excluding scheduled principal payments on Securitization Bonds. For information about debt transactions to date in 2022, see Note 11 to the Interim Condensed Financial Statements.

Sale of Energy Transfer Equity Securities. During the six months ended June 30, 2022, CenterPoint Energy sold its remaining Energy Transfer Common Units and Energy Transfer Series G Preferred Units for net proceeds of $702 million. For more information, see Note 10 to the Interim Condensed Financial Statements.

Sale of Natural Gas Businesses. On January 10, 2022, CERC Corp. completed the sale of its Arkansas and Oklahoma Natural Gas businesses. For additional information regarding discontinued operations and divestitures, see Note 3 to the Interim Condensed Financial Statements.

Regulatory Proceedings. For information related to our pending and completed regulatory proceedings to date in 2022, see “—Liquidity and Capital Resources —Regulatory Matters” below.

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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 2021 Form 10-K and in Item 1A of Part II of this combined Form 10-Q.

Income available to common shareholders for the three and six months ended June 30, 2022 and 2021 was as follows:


	Three Months Ended June 30,						Six Months Ended June 30,
	2022		2021		Favorable (Unfavorable)		2022		2021		Favorable (Unfavorable)
	(in millions)
Electric	$	173	$	125	$	48	$	255	$	200	$	55
Natural Gas	28		74		(46)		426		303		123
Total Utility Operations	201		199		2		681		503		178

Corporate & Other (1)	(22)		(29)		7		16		(82)		98
Discontinued Operations	—		51		(51)		—		134		(134)
Total CenterPoint Energy	$	179	$	221	$	(42)	$	697	$	555	$	142

(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, 2022 compared to three months ended June 30, 2021

Income available to common shareholders decreased $42 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 $46 million for the Natural Gas reportable segment, as further discussed below;
an increase in income available to common shareholders of $7 million for Corporate and Other, partially driven by a decrease in income allocated to preferred shareholders of $19 million, primarily due to the conversion of the Series B Preferred Stock to Common Stock during 2021; and
a decrease in income of $51 million from discontinued operations, discussed further in Note 3 to the Interim Condensed Financial Statements.

Six months ended June 30, 2022 compared to six months ended June 30, 2021

Income available to common shareholders increased $142 million primarily due to the following items:

an increase in net income of $55 million for the Electric reportable segment, as further discussed below;
an increase in net income of $123 million for the Natural Gas reportable segment, as further discussed below;
an increase in income available to common shareholders of $98 million for Corporate and Other, primarily due to the net gain of $86 million on Energy Transfer equity securities discussed further in Note 10 to the Interim Condensed Financial Statements and a decrease in income allocated to preferred shareholders of $35 million, primarily due to the conversion of the Series B Preferred Stock to Common Stock during 2021; and
a decrease in income of $134 million from discontinued operations, discussed further in Note 3 to the Interim Condensed Financial Statements.

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. During the six months ended June 30, 2022, CenterPoint Energy sold certain assets previously owned by entities within Corporate and Other to businesses within the Electric and Natural Gas reportable segments. Prior year amounts were reclassified as a result of the transaction in the six months ended June 30, 2022.

The following discussion of results of operations by reportable segment concentrates on CenterPoint Energy’s Utility Operations, conducted through two reportable segments, Electric and Natural Gas.

Electric (CenterPoint Energy)

For information regarding factors that may affect the future results of operations of the Electric reportable segment, please read “Risk Factors — Risk Factors Associated with Our Consolidated Financial Condition,” “— Risk Factors Affecting Electric Generation, Transmission and Distribution Businesses,” “— Risk Factors Affecting Our Businesses” and “— General Risk Factors Affecting Our Businesses” in Item 1A of Part I of the Registrants’ combined 2021 Form 10-K and in Item 1A of Part II of this combined Form 10-Q.

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


	Three Months Ended June 30,									Six Months Ended June 30,
	2022			2021			Favorable (Unfavorable)			2022			2021			Favorable (Unfavorable)
	(in millions, except operating statistics)
Revenues	$	1,053		$	937		$	116		$	1,946		$	1,767		$	179
Expenses:
Utility natural gas, fuel and purchased power	56			44			(12)			97			89			(8)
Operation and maintenance	449			429			(20)			886			840			(46)
Depreciation and amortization	205			194			(11)			397			368			(29)
Taxes other than income taxes	72			69			(3)			140			136			(4)

Total expenses	782			736			(46)			1,520			1,433			(87)
Operating Income	271			201			70			426			334			92
Other Income (Expense):
Interest expense and other finance charges	(59)			(58)			(1)			(116)			(114)			(2)

Other income, net	7			5			2			12			12			—
Income Before Income Taxes	219			148			71			322			232			90
Income tax expense	46			23			(23)			67			32			(35)
Net Income	$	173		$	125		$	48		$	255		$	200		$	55
Throughput (in GWh):
Residential	10,003			8,323			20		%	16,349			14,393			14		%
Total	29,270			26,886			9		%	52,425			48,127			9		%
Weather (percentage of 10-year average for service area):
Cooling degree days	126		%	103		%	23		%	118		%	104		%	14		%
Heating degree days	53		%	138		%	(85)		%	121		%	105		%	16		%
Number of metered customers at end of period:
Residential	2,517,362			2,464,358			2		%	2,517,362			2,464,358			2		%
Total	2,840,830			2,783,920			2		%	2,840,830			2,783,920			2		%

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The following table provides variance explanations by major income statement caption for the Electric reportable segment:


	Favorable (Unfavorable)
	Three Months Ended June 30, 2022 vs 2021		Six Months Ended June 30, 2022 vs 2021
	(in millions)
Revenues
Transmission Revenues, including TCOS and TCRF, inclusive of costs billed by transmission providers, partially offset in operation and maintenance	$	46	$	75
Weather, efficiency improvements and other usage impacts	34		42
Refund of protected and unprotected EDIT, offset in income tax expense	9		17
Customer growth	7		13
Miscellaneous revenues, primarily related to off-system sales	8		10
Cost of fuel and purchased power, offset in utility natural gas, fuel and purchased power below	12		8
Customer rates	3		7
Bond Companies, offset in other line items	(3)		6
Bond Companies equity return, related to the annual true-up of transition charges for amounts over or under collected in prior periods	1		3
Impacts from increased peak demand in 2021, collected in rates in 2022	1		2
Energy efficiency and pass-through offset in operation and maintenance	(2)		(4)
Total	$	116	$	179
Utility natural gas, fuel and purchased power
Cost of purchased power, offset in revenues above	$	(9)	$	(12)
Cost of fuel, including coal, natural gas, and fuel oil, offset in revenues above	(3)		4
Total	$	(12)	$	(8)
Operation and maintenance
Transmission costs billed by transmission providers, offset in revenues	$	(21)	$	(43)

All other operation and maintenance expense, including insurance and bad debt	(12)		(12)
Materials and supplies, including variable production costs and fuel	(1)		(6)
Contract services	(1)		(8)
Bond Companies, offset in other line items	—		1
Energy efficiency and pass-through offset in revenues	2		5

Support services, primarily information technology cost	13		17
Total	$	(20)	$	(46)
Depreciation and amortization
Bond Companies, offset in other line items	$	1	$	(11)
Ongoing additions to plant-in-service	(12)		(18)
Total	$	(11)	$	(29)
Taxes other than income taxes
Franchise fees and other taxes	$	2	$	3
Incremental capital projects placed in service	(5)		(7)
Total	$	(3)	$	(4)
Interest expense and other finance charges
Bond Companies, offset in other line items	$	2	$	4
Incremental borrowings to fund capital expenditures	(3)		(6)
Total	$	(1)	$	(2)
Other income, net
Other non-operating income	$	2	$	—


Total	$	2	$	—

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 Associated with Our Consolidated Financial Condition,” “— Risk Factors Affecting Natural Gas' Business,” “— Risk Factors Affecting Our Businesses” and “— General Risk Factors Affecting Our Businesses” in Item 1A of Part I of the Registrants’ combined 2021 Form 10-K and in Item 1A of Part II of this combined Form 10-Q.

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


	Three Months Ended June 30,									Six Months Ended June 30,
	2022			2021			Favorable (Unfavorable)			2022			2021			Favorable (Unfavorable)
	(in millions, except operating statistics)
Revenues	$	818		$	740		$	78		$	2,642		$	2,403		$	239
Expenses:
Utility natural gas, fuel and purchased power	357			213			(144)			1,414			1,104			(310)
Non-utility cost of revenues, including natural gas	1			10			9			2			12			10
Operation and maintenance	209			240			31			455			490			35
Depreciation and amortization	117			129			12			229			257			28
Taxes other than income taxes	61			57			(4)			138			131			(7)
Total expenses	745			649			(96)			2,238			1,994			(244)
Operating Income	73			91			(18)			404			409			(5)
Other Income (Expense):
Gain on sale	—			—			—			303			—			303
Interest expense and other finance charges	(33)			(34)			1			(63)			(67)			4

Other income (expense), net	(10)			2			(12)			(10)			2			(12)
Income Before Income Taxes	30			59			(29)			634			344			290
Income tax expense (benefit)	2			(15)			(17)			208			41			(167)
Net Income	$	28		$	74		$	(46)		$	426		$	303		$	123



Throughput (in Bcf):
Residential	28			30			(7)		%	151			158			(4)		%
Commercial and Industrial	90			88			2		%	226			233			(3)		%
Total	118			118			—		%	377			391			(4)		%
Weather (percentage of 10-year average for service area):
Heating degree days	102		%	104		%	(2)		%	108		%	100		%	8		%
Number of metered customers at end of period:
Residential	3,919,079			4,334,297			(10)		%	3,919,079			4,334,297			(10)		%
Commercial and Industrial	295,487			341,963			(14)		%	295,487			341,963			(14)		%
Total	4,214,566			4,676,260			(10)		%	4,214,566			4,676,260			(10)		%

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The following table provides variance explanations by major income statement caption for the Natural Gas reportable segment:


	Favorable (Unfavorable)
	Three Months Ended June 30, 2022 vs 2021		Six Months Ended June 30, 2022 vs 2021
	(in millions)
Revenues
Cost of natural gas, offset in utility natural gas, fuel and purchased power below	$	170	$	406
Customer rates and impact of the change in rate design, exclusive of the TCJA impact	12		56
Gross receipts tax, offset in taxes other than income taxes	5		14
Customer growth	1		5
Refund of protected and unprotected EDIT, offset in income tax expense	1		5
Non-volumetric and miscellaneous revenue	1		9
Energy efficiency, offset in operation and maintenance	—		(2)

Weather and usage	(14)		(5)
Other, primarily non-utility revenues	(20)		(15)
Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale	(78)		(234)
Total	$	78	$	239
Utility natural gas, fuel and purchased power
Cost of natural gas, offset in revenues above	$	(170)	$	(406)
Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale	26		96


Total	$	(144)	$	(310)
Non-utility costs of revenues, including natural gas
Other, primarily non-utility cost of revenues	$	9	$	10
Total	$	9	$	10
Operation and maintenance

Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale	$	31	$	61
Energy efficiency, offset in revenues	—		2
Contract services	1		—
Labor and benefits	3		(3)
Other operation and maintenance expenses, including material and supplies and bad debt	(4)		(25)
Total	$	31	$	35
Depreciation and amortization
Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale	$	15	$	30
Lower depreciation rates in Indiana from recent rate order	5		10
Incremental capital projects placed in service	(8)		(12)

Total	$	12	$	28
Taxes other than income taxes
Gross receipts tax, offset in revenues	$	(5)	$	(14)
Incremental capital projects placed in service	(4)		(5)
Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale	5		12
Total	$	(4)	$	(7)
Gain on Sale
Net gain on sale of Arkansas and Oklahoma Natural Gas businesses	$	—	$	303
Total	$	—	$	303
Interest expense and other finance charges
Impacts of February 2021 Winter Storm costs securitization	$	1	$	3
AFUDC and impacts of regulatory deferrals	1		2
Reduction of long term debt, net of issuances	(1)		(1)
Total	$	1	$	4



Other income (expense), net
Increase in Equity AFUDC	$	1	$	1
Increase to non-service benefit cost	(13)		(13)
Total	$	(12)	$	(12)

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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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 reportable segment. Houston Electric consists of a 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 Associated with Our Consolidated Financial Condition,” “— Risk Factors Affecting Electric Generation, Transmission and Distribution Businesses,” “— Risk Factors Affecting Our Businesses” and “— General Risk Factors Affecting Our Businesses” in Item 1A of Part I of the Registrants’ combined 2021 Form 10-K and in Item 1A of Part II of this combined Form 10-Q.


	Three Months Ended June 30,									Six Months Ended June 30,
	2022			2021			Favorable (Unfavorable)			2022			2021			Favorable (Unfavorable)
	(in millions, except operating statistics)
Revenues:
TDU	$	822		$	725		$	97		$	1,515		$	1,365		$	150
Bond Companies	59			61			(2)			112			105			7
Total revenues	881			786			95			1,627			1,470			157
Expenses:
Operation and maintenance, excluding Bond Companies	403			389			(14)			797			760			(37)
Depreciation and amortization, excluding Bond Companies	120			107			(13)			234			212			(22)
Taxes other than income taxes	68			65			(3)			131			128			(3)
Bond Companies	54			55			1			103			93			(10)
Total expenses	645			616			(29)			1,265			1,193			(72)
Operating Income	236			170			66			362			277			85
Other Income (Expense)
Interest expense and other finance charges	(50)			(47)			(3)			(98)			(92)			(6)
Interest expense on Securitization Bonds	(4)			(5)			1			(8)			(11)			3


Other income, net	4			3			1			8			8			—
Income Before Income Taxes	186			121			65			264			182			82
Income tax expense	39			18			(21)			56			26			(30)
Net Income	$	147		$	103		$	44		$	208		$	156		$	52
Throughput (in GWh):
Residential	9,710			8,024			21		%	15,698			13,725			14		%
Total	27,704			25,396			9		%	49,638			45,135			10		%
Weather (percentage of 10-year average for service area):
Cooling degree days	127		%	103		%	24		%	118		%	104		%	14		%
Heating degree days	13		%	142		%	(129)		%	124		%	105		%	19		%
Number of metered customers at end of period:
Residential	2,382,145			2,333,786			2		%	2,382,145			2,333,786			2		%
Total	2,686,295			2,634,108			2		%	2,686,295			2,634,108			2		%

The following table provides variance explanations by major income statement caption for Houston Electric:


	Favorable (Unfavorable)
	Three Months Ended June 30, 2022 vs 2021		Six Months Ended June 30, 2022 vs 2021
	(in millions)
Revenues
Transmission Revenues, including TCOS and TCRF, inclusive of costs billed by transmission providers	$	46	$	75
Weather impacts and other usage	34		42
Refund of protected and unprotected EDIT, offset in income tax expense	9		17

Customer growth	7		13
Bond Companies, offset in other line items	(3)		6
Equity return, related to the annual true-up of transition charges for amounts over or under collected in prior periods	1		3
Impacts from increased peak demand in 2021, collected in rates in 2022	1		2
Miscellaneous revenues, primarily related to right-of-way revenues	1		2
Energy efficiency, offset in operation and maintenance	(1)		(3)

Total	$	95	$	157
Operation and maintenance, excluding Bond Companies
Transmission costs billed by transmission providers, offset in revenues	$	(21)	$	(43)
Contract services	(1)		(6)
Other operation and maintenance expense, including insurance	(7)		(6)
Materials and Supplies, including fuel	1		(3)
Labor and benefits	1		2


Energy efficiency, offset in revenues	1		3
Support services, primarily information technology cost	12		16
Total	$	(14)	$	(37)
Depreciation and amortization, excluding Bond Companies
Ongoing additions to plant-in-service	$	(13)	$	(22)
Total	$	(13)	$	(22)
Taxes other than income taxes
Franchise fees and other taxes	$	1	$	4
Ongoing additions to plant-in-service	(4)		(7)
Total	$	(3)	$	(3)
Bond Companies expense
Operations and maintenance and depreciation expense, offset in other line items	$	1	$	(10)
	$	1	$	(10)
Interest expense and other finance charges
Incremental borrowings to fund capital expenditures	$	(3)	$	(6)
Total	$	(3)	$	(6)




Interest expense on Securitization Bonds
Lower outstanding principal balance, offset in other line items	$	1	$	3
Total	$	1	$	3
Other income, net
Other non-operating income	$	1	$	—


Total	$	1	$	—

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 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 Associated with Our Consolidated Financial Condition,” “— Risk Factors Affecting Natural Gas’ Business,” “— Risk Factors Affecting Our Businesses” and “— General Risk Factors Affecting Our Businesses” in Item 1A of Part I of the Registrants’ combined 2021 Form 10-K and in Item 1A of Part II of this combined Form 10-Q.


	Three Months Ended June 30,									Six Months Ended June 30,
	2022			2021			Favorable (Unfavorable)			2022			2021			Favorable (Unfavorable)
	(in millions, except operating statistics)
Revenues	$	796		$	721		$	75		$	2,560		$	2,316		$	244
Expenses:
Utility natural gas, fuel and purchased power	351			210			(141)			1,384			1,057			(327)
Non-utility cost of revenues, including natural gas	1			10			9			2			12			10
Operation and maintenance	202			239			37			440			486			46
Depreciation and amortization	113			118			5			220			236			16
Taxes other than income taxes	60			56			(4)			135			129			(6)
Total expenses	727			633			(94)			2,181			1,920			(261)
Operating Income	69			88			(19)			379			396			(17)
Other Income (Expense):
Gain on sale	—			—			—			557			—			557
Interest expense and other finance charges	(30)			(32)			2			(59)			(64)			5

Other income (expense), net	(11)			1			(12)			(11)			2			(13)
Income Before Income Taxes	28			57			(29)			866			334			532
Income tax expense (benefit)	1			(16)			(17)			203			39			(164)


Net Income	$	27		$	73		$	(46)		$	663		$	295		$	368
Throughput (in Bcf): [to be updated for IGC/VEDO]
Residential	27			29			(7)		%	147			154			(5)		%
Commercial and Industrial	82			80			3		%	207			217			(5)		%
Total	109			109			—		%	354			371			(5)		%
Weather (percentage of 10-year average for service area):
Heating degree days	102		%	104		%	(2)		%	109		%	100		%	9		%
Number of metered customers at end of period:
Residential	3,815,625			4,231,270			(10)		%	3,815,625			4,231,270			(10)		%
Commercial and Industrial	284,914			331,547			(14)		%	284,914			331,547			(14)		%
Total	4,100,539			4,562,817			(10)		%	4,100,539			4,562,817			(10)		%

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The following table provides variance explanations by major income statement caption for CERC:


	Favorable (Unfavorable)
	Three Months Ended June 30, 2022 vs 2021		Six Months Ended June 30, 2022 vs 2021
	(in millions)
Revenues
Cost of natural gas, offset in utility natural gas, fuel and purchased power below	$	167	$	423
Customer rates and impact of the change in rate design, exclusive of the TCJA impact	11		42
Gross receipts tax, offset in taxes other than income taxes	5		14
Customer growth	1		5
Refund of protected and unprotected EDIT, offset in income tax expense	1		5
Non-volumetric and miscellaneous revenue	1		8
Energy efficiency, offset in operation and maintenance	1		2
Weather and usage	(14)		(6)

Other, primarily non-utility revenues	(20)		(15)
Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale	(78)		(234)
Total	$	75	$	244
Utility natural gas, fuel and purchased power
Cost of natural gas, offset in revenues above	$	(167)	$	(423)
Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale	26		96


Total	$	(141)	$	(327)
Non-utility costs of revenues, including natural gas
Other, primarily non-utility cost of revenues	$	9	$	10
Total	$	9	$	10
Operation and maintenance
Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale	$	31	$	61
Contract services	2		—
Labor and benefits	4		(2)
Energy efficiency, offset in revenues	(1)		(2)
Other operating and maintenance expense, including materials and supplies and insurance	1		(11)



Total	$	37	$	46
Depreciation and amortization
Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale	$	15	$	30
Indiana lower depreciation rates from recent rate order	5		10
Incremental capital projects placed in service	(15)		(24)

Total	$	5	$	16
Taxes other than income taxes
Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale	$	5	$	12
Incremental capital projects placed in service	(4)		(4)
Gross receipts tax, offset in revenues	(5)		(14)
Total	$	(4)	$	(6)
Gain on Sale
Net gain on sale of Arkansas and Oklahoma Natural Gas businesses	$	—	$	557
Total	$	—	$	557
Interest expense and other finance charges
Impacts of February 2021 Winter Storm costs securitization	$	1	$	3
AFUDC and impacts of regulatory deferrals	2		3
Reduction of long term debt, net of issuances	(1)		(1)
Total	$	2	$	5



Other income (expense), net
Increase in Equity AFUDC	$	1	$	1
Increase to non-service benefit cost	(13)		(14)
Total	$	(12)	$	(13)

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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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 2021 Form 10-K, in Item 1A of Part II of this combined Form 10-Q 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, 2022 and 2021:


	Six Months Ended June 30,
	2022						2021
	CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC
	(in millions)
Cash provided by (used in):
Operating activities	$	978	$	188	$	767	$	(1,076)	$	254	$	(1,504)
Investing activities	942		(1,391)		1,394		(1,376)		(837)		(528)
Financing activities	(1,597)		1,066		(2,173)		2,442		566		2,028

Operating Activities. The following items contributed to increased (decreased) net cash provided by operating activities for the six months ended June 30, 2022 compared to the six months ended June 30, 2021:


	CenterPoint Energy		Houston Electric		CERC
	(in millions)
Changes in net income after adjusting for non-cash items	$	(305)	$	125	$	(31)
Changes in working capital	(276)		(207)		6
Change in net regulatory assets and liabilities (1)	2,442		30		2,273
Change in equity in earnings of unconsolidated affiliates (2)	175		—		—
Change in distributions from unconsolidated affiliates (2)	(77)		—		—

Lower pension contribution	4		—		—
Other	91		(14)		23
	$	2,054	$	(66)	$	2,271

(1)The change in net regulatory assets and liabilities at CenterPoint Energy and CERC is primarily due to the extraordinary natural gas costs associated with the February 2021 Winter Storm Event. See Note 6 to the Interim Condensed Financial Statements for more information on the February 2021 Winter Storm Event.

(2)In September 2021, CenterPoint Energy’s equity investment in Enable met the held for sale criteria and is reflected as discontinued operations on CenterPoint Energy’s Condensed Statements of Consolidated Income. For further information, see Note 3 to the Interim Condensed Financial Statements.

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Investing Activities. The following items contributed to (increased) decreased net cash used in investing activities for the six months ended June 30, 2022 compared to the six months ended June 30, 2021:


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

Capital expenditures	(497)		(405)		(140)
Net change in notes receivable from affiliated companies	—		(175)		—


Proceeds from divestitures	2,075		—		2,075


Other	38		26		(13)
	$	2,318	$	(554)	$	1,922

Financing Activities. The following items contributed to (increased) decreased net cash used in financing activities for the six months ended June 30, 2022 compared to the six months ended June 30, 2021:


	CenterPoint Energy		Houston Electric		CERC
	(in millions)
Net changes in commercial paper outstanding	$	(1,451)	$	—	$	(542)


Net changes in long-term debt outstanding, excluding commercial paper	(2,428)		94		(1,272)


Net changes in debt issuance costs	20		4		2
Net changes in short-term borrowings	(16)		—		(16)

Payment of obligation for finance lease	(171)		(171)		—
Increased payment of common stock dividends	(31)		—		—
Decreased payment of preferred stock dividends	41		—		—
Net change in notes payable from affiliated companies	—		(504)		(1,668)
Contribution from parent	—		1,143		125
Dividend to parent	—		(67)		(831)


Other	(3)		1		1
	$	(4,039)	$	500	$	(4,201)

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 2022 include the following:


	CenterPoint Energy		Houston Electric		CERC
	(in millions)
Estimated capital expenditures	$	1,901	$	897	$	802
Scheduled principal payments on Securitization Bonds	107		107		—
Minimum contributions to pension plans and other post-retirement plans	7		—		2
Finance lease for mobile generation	347		347		—

The Registrants expect that anticipated cash needs for the remaining six months of 2022 will be met with borrowings under their credit facilities, proceeds from the issuance of long-term debt, term loans, anticipated proceeds from the Texas Public Financing Authority customer rate relief bonds for recovery of the gas cost incurred in Texas during the February 2021 Winter Storm Event, 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

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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.

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 CPCN (CenterPoint Energy)

On February 9, 2021, Indiana Electric entered into a BTA with a subsidiary of Capital Dynamics. Under the agreement, Capital Dynamics, with its partner Tenaska, contracted to build a 300 MW solar array in Posey County, Indiana through a special purpose entity, Posey Solar. Upon completion of construction, Indiana Electric will acquire Posey Solar and its solar array assets for a fixed purchase price. On February 23, 2021, Indiana Electric filed a CPCN with the IURC seeking approval to purchase the project. Indiana Electric also sought approval for a 100 MW solar PPA with Clenera LLC in Warrick County, Indiana. The request accounted for increased cost of debt related to this PPA, which provides equivalent equity return to offset imputed debt during the 25 year life of the PPA. A hearing was conducted on June 21, 2021. On October 27, 2021, the IURC issued an order approving the CPCN, authorizing Indiana Electric to purchase the Posey solar project through a BTA and approved recovery of costs via a levelized rate over the anticipated 35-year life. The IURC also approved the Warrick County solar PPA but denied the request to preemptively offset imputed debt in the PPA cost. Due to rising cost for the project, caused in part by supply chain issues in the energy industry, the rising costs of commodities and community feedback, we, along with Capital Dynamics, announced plans in January 2022 to downsize the Posey solar project to approximately 200 MW. The Posey solar project is expected to be placed in service by 2023. Indiana Electric collaboratively agreed to the scope change and is currently working through contract negotiations, contingent on further IURC review and approval.

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. A hearing was conducted on January 26 through 28, 2022, and on June 28, 2022 the IURC approved the CPCN. On July 18, 2022, the OUCC filed a petition for rehearing and reconsideration with the IURC of the approved turbine cost estimate and pipeline cost recovery issues and, as of July 29, 2022, three organizations, the OUCC, Citizens Action Coalition and Indiana Industrial Energy Consumers, had filed notices of appeal of the petition with the Indiana Court of Appeals. Because the IURC order is effective pending the appeal, Indiana Electric will continue pursuing the construction of the combustion turbine facility during the period of the appeal with statutory assurances of cost recovery for reasonable costs incurred pursuing the project during the pendency of the appeal. 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 requiring FERC approval would also be constructed and operated by Texas Gas Transmission, LLC to supply natural gas to the turbine facility. Construction of the turbines will begin following receipt of regulatory approval by FERC, which is anticipated between the fourth quarter of 2022 and first quarter of 2023. The turbines are targeted to be operational by year end 2025 but any delays resulting from an adverse decision from the IURC or the Indiana Court of Appeals could negatively impact that timing. Recovery of the proposed natural gas combustion turbines and regulatory asset will be requested in the next Indiana Electric rate case expected in 2023.

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 LLC, which is developing a solar project in Vermillion County, Indiana, and 150 MW of solar power, under a 20-year PPA, from Origis Energy USA Inc., which is developing a solar project in Knox County, Indiana. On May 4, 2022, the IURC issued an order approving Indiana Electric to enter into both PPAs. Both solar arrays are expected to be placed in service by the end of 2023.

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. Pending approval, the project is expected to be placed in service by 2025.

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For more information regarding uncertainties related to our solar projects, see Item 1A of Part II of this combined Form 10-Q and “ —Solar Panel Issues” below.

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, and it remains out of service. CenterPoint Energy is investigating this incident. The current estimate of the costs to repair F.B. Culley Unit 3 is approximately $7 million to $9 million, which will largely be capital expenditures. F.B. Culley Unit 3 is expected to return to service in 6 to 12 months depending on the availability of a replacement turbine and related materials. CenterPoint Energy is evaluating the applicability of insurance coverages. For the duration of the unplanned outage, CenterPoint Energy expects to meet its generation capacity needs from its other generation units and power purchase agreements.

Indiana Electric Securitization of Planned Generation Retirements (CenterPoint Energy)

The State of Indiana has enacted legislation, Senate Bill 386, that would enable CenterPoint Energy to request approval from the IURC to securitize the remaining book value and removal costs associated with generating facilities to be retired in the next twenty-four months. The Governor of Indiana signed the legislation on April 19, 2021. On May 10, 2022, CenterPoint Energy (Indiana Electric) filed with the IURC to securitize qualified costs associated with its planned retirements of coal generation facilities. Total qualified costs are estimated at $359 million, of which $350 million would be financed and $9 million are estimated total ongoing costs. A hearing is scheduled before the IURC on September 7, 2022 and a final order is anticipated in early 2023.

Restructuring (CenterPoint Energy and CERC)

In July 2021, Indiana North and SIGECO filed petitions with the IURC for the approval of a new financial services agreement and the confirmation of Indiana North’s financing authority, and final orders were issued by the IURC on December 28, 2021. VEDO filed a similar application with the PUCO in September 2021 and the PUCO issued an order on January 26, 2022 adopting recommendations by PUCO staff. Both the IURC and PUCO approved the petitions. The orders allow the reissuance of existing debt of Indiana Gas and VEDO to CERC, to continue to amortize existing issuance expenses and discounts, and to treat any potential exchange fees as discounts to be amortized over the life of the debt. As a part of the Restructuring, on May 27, 2022, CERC Corp. and VUH completed an exchange with holders of VUH PPNs whereby CERC Corp. issued new senior notes with an aggregate principal amount of $302 million in return for all of their outstanding VUH PPNs with an aggregate principal amount of $302 million. For further information on the debt exchange, see Note 11 to the Interim Condensed Financial Statements. CenterPoint Energy completed the transfer of Indiana Gas and VEDO from VUH to CERC on June 30, 2022 to better align its organizational structure with management and financial reporting and to fund future capital investments more efficiently. See Note 1 to the Interim Condensed Financial Statements for further information.

Texas Legislation (CenterPoint Energy and Houston Electric)

Houston Electric continues to review the effects of legislation passed in 2021 and is working with the PUCT regarding proposed rulemakings and pursuing implementation of these items where applicable. For example, in 2021 Houston Electric entered into two leases for temporary emergency electric energy (mobile generation): (1) a temporary short-term lease of 220 MW as of December 31, 2021 and reduced to 92 MW as of June 30, 2022 as assets were delivered under the long-term lease agreement and (2) a 7.5 year lease for up to 505 MW of mobile generation of which 253 MW and 125 MW was delivered as of June 30, 2022 and December 31, 2021. Houston Electric filed its DCRF application with the PUCT on April 5, 2022, and subsequently amended such filing on July 1, 2022 to show mobile generation in a separate Rider TEEEF, seeking recovery of deferred costs and the applicable return as of December 31, 2021 under these lease agreements of approximating $200 million. The annual revenue increase requested for these lease agreements is approximately $57 million. These mobile generation leases are expected to support resiliency in major weather events, as was the case during the restoration process for Hurricane Nicholas in 2021. For additional information, see Note 19 to the Interim Condensed Financial Statements.

In addition to these measures taken by Houston Electric to support system preparedness and reliability, in February 2022, the City of Houston launched the first-of-its-kind long-term strategic power resilience initiative called “Resilient Now.” In a joint effort, Houston Electric is working with the City of Houston to develop the Master Energy Plan for the city to help the community thrive through economic changes, digital transformation, and advancing environmental goals for the benefit of its communities. The Master Energy Plan could develop into capital opportunities for Houston Electric, including relating to infrastructure modernization, residential weatherization, and investments around electric vehicles infrastructure.

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Minnesota Base Rate Cases (CenterPoint Energy and CERC)

On November 1, 2021, CERC filed a general rate case with the MPUC seeking approval for a revenue increase of approximately $67 million with a projected test year ended December 31, 2022. The revenue increase is based upon a requested ROE of 10.2% and an overall rate of return of 7.06% on a total rate base of approximately $1.8 billion. CERC requested that an interim rate increase of approximately $52 million be implemented January 1, 2022 while the rate case is litigated. An alternative request was also filed on November 1, 2021. The alternative request proposed a final rate increase of $40 million that would be implemented in the rate case on January 1, 2022, and offered: an increase in rates for plant investment only using the overall rate of return approved in the prior rate case, an asymmetrical capital true-up, extension of the recovery of gas costs incurred to serve customers in February 2021 from the then current 27 month mechanism to 63 months, an income tax rider, continuation of the existing property tax rider and continued deferral of COVID-19 incremental costs along with additional adjustments. On December 30, 2021, the MPUC issued a written order denying the alternative request but extended the recovery for extraordinary gas costs to 63-months beginning on January 1, 2022. The MPUC also issued written orders on the general rate case filing which (1) accepted CERC’s rate-increase application with a time for final determination of September 1, 2022, (2) authorized the implementation of interim rates on January 1, 2022, of $42 million based on an overall rate of return of 6.46%, and (3) referred the case to the Office of Administrative Hearings for a contested case proceeding. On March 14, 2022, an Offer of Settlement was filed with the Office of Administrative Hearings which would resolve all issues in the rate case. The Settlement provides for a general revenue increase of $48.5 million and overall rate of return of 6.65% and is currently subject to review and approval by the MPUC. Final rate implementation is expected before the end of 2022.

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. 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).

CERC expects to submit its first innovation plan to the MPUC in the first half of 2023. 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.

Solar Panel Issues (CenterPoint Energy)

CenterPoint Energy’s current and future solar projects may be significantly impacted by delays and/or increased costs. The potential 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. Preliminary findings from the DOC investigation, including potential tariff amounts, are expected to be released in August 2022, with a final decision expected between January and March 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 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. If any of these impacts result in cost increases for certain projects, such potential impacts 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’ 2021 Form 10-K and Item 1A of Part II of this combined Form 10-Q.

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, Houston Electric is periodically involved in proceedings to adjust its capital tracking mechanisms (TCOS and DCRF) and annually files to adjust

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its EECRF. CERC is periodically involved in proceedings to adjust its capital tracking mechanisms in Texas (GRIP), its cost of service adjustments in Louisiana and Mississippi (RSP and RRA, respectively), its decoupling mechanism in Minnesota, and its energy efficiency cost trackers in Minnesota and Mississippi (CIP and EECR, respectively). CenterPoint Energy is periodically involved in proceedings to adjust its capital tracking mechanisms in Indiana (CSIA for gas and TDSIC for electric) and Ohio (DRR), its decoupling mechanism in Indiana (SRC for gas), and its energy efficiency cost trackers in Indiana (EEFC for gas and DSMA for electric) and Ohio (EEFR). The table below reflects significant applications pending or completed since the Registrants’ combined 2021 Form 10-K was filed with the SEC through July 29, 2022.


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










CenterPoint Energy and Houston Electric (PUCT)
EECRF (1)	23	June 2022	TBD	TBD	The requested amount is comprised of the following: 2023 Program and Evaluation, Measurement and Verification costs of $38 million, a charge of $3 million related to the under-recovery of 2021 program costs including interest and rate case expenses, 2021 earned bonus of $23 million for a total of $64 million.
DCRF (1)	142	April 2022	TBD	TBD	As amended on July 1, 2022, the net change in distribution invested capital since its last base rate proceeding of over $1 billion for the period January 1, 2019 through December 31, 2021 for a revenue increase of $86 million, adjusted for load growth. In addition, the request includes approximately $200 million in mobile generation facilities during the calendar year ending December 31, 2021 representing a revenue increase of $57 million. The requested overall revenue increase is $142 million with a proposed effective date of September 1, 2022. On July 11, 2022, a partial settlement was filed resolving the non-mobile generation issues. The settlement provides for a black box reduction to the revenue requirement of $7.8 million for a revenue increase of $78 million and a September 1, 2022 effective date for rates. A hearing on mobile generation issues is currently scheduled for October 18 and 19, 2022.
TCOS	64	February 2022	April 2022	April 2022	Based on net change of invested capital of $574 million.









CenterPoint Energy and CERC - Beaumont/East Texas, South Texas, Houston and Texas Coast (Railroad Commission)
GRIP	34	March 2022	June 2022	June 2022	Based on net change in invested capital for calendar year 2021 of $213 million.
CenterPoint Energy and CERC - Minnesota (MPUC)
CIP Financial Incentive (1)	8	May 2022	TBD	TBD	CIP Financial Incentive based on 2021 CIP program activity.
Rate Case (1)	67	November 2021	TBD	TBD	See discussion above under Minnesota Base Rate Case.
Decoupling	N/A	September 2021	September 2021	April 2022	Represents under-recovery of approximately $19 million recorded for and during the period July 1, 2020 through June 30, 2021, including an approximately $5 million adjustment related to the implementation of final rates from the general rate case filed in 2019.




















CenterPoint Energy and CERC - Mississippi (MPSC)
RRA (1)	3	April 2022	August 2022	TBD	Based on ROE of 9.568% with 100 basis point (+/-) earnings band. Revenue increase of approximately $3 million based on 2021 test year adjusted earned ROE of 7.74%. Interim increase of approximately $1 million implemented May 31, 2022. A joint stipulation was filed on July 29, 2022 resolving all issues and an agreed revenue increase of $2 million based on 2021 test year adjusted earned ROE of 8.27% with rates expected to be effective in August 2022.
CenterPoint Energy and CERC - Ohio (PUCO)
DRR (1)	9	April 2022	TBD	TBD	Requested an increase of $63 million to rate base for investments made in 2021, which reflects a $9 million annual increase in current revenues. A change in (over)/under-recovery variance of $(4 million) annually is also included in rates.
CenterPoint Energy - Indiana Electric (IURC)
TDSIC	3	February 2022	May 2022	May 2022	Requested an increase of $42 million to rate base, which reflects a $3 million annual increase in current revenues. 80% of the revenue requirement is included in requested rate increase and 20% is deferred until next rate case. The mechanism also includes a change in (over)/under-recovery variance of less than $1 million.
CECA	(2)	February 2022	June 2022	May 2022	Requested a decrease of less than $1 million to rate base, which reflects a $3 million annual decrease in current revenues. The mechanism also includes a change in (over)/under-recovery variance of less than $1 million. This mechanism includes a non-traditional rate making approach related to a 50 MW universal solar array placed in service in January 2021.

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

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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 U.S. EPA exceeded its authority in promulgating the CPP. The EPA has announced it plans on issuing new greenhouse gas rules in the future.

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 new net zero emissions goals for both Scope 1 and Scope 2 emissions by 2035 as well as a goal to reduce Scope 3 emissions by 20% to 30% by 2035. 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 exclude emissions related to purchased power in Indiana between 2024 and 2026 as estimated. CenterPoint Energy’s Scope 3 estimates 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. In addition, the EPA has indicated that it intends to implement new regulations targeting reductions in methane emissions, which are likely to increase costs related to production, transmission and storage of natural gas. Houston Electric, in contrast to some electric utilities including Indiana Electric, does not generate electricity, other than leasing facilities that provide temporary emergency electric energy to aid in restoring power to distribution customers during certain widespread power outages as allowed by a new law enacted after the February 2021 Winter Storm Event, 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 new 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

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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 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 or legislators could harm its reputation.

To address these developments, CenterPoint Energy announced its new net zero emissions goals for both Scope 1 and Scope 2 emissions by 2035. In June of 2020, Indiana Electric identified a preferred generation resource in its most recent IRP submitted to the IURC that aligns with its new net zero emissions goals and includes the replacement of 730 MWs of coal-fired generation facilities with a significant portion comprised of renewables, including solar and wind, supported by dispatchable natural gas combustion turbines, including a pipeline to serve such natural gas generation, as well as storage. 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 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 newly adopted net zero emissions goals support global efforts to reduce the impacts of climate change.

To the extent climate changes result in warmer temperatures in the 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 recently announced 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, leasing facilities that provide temporary emergency electric energy to aid in restoring power to distribution customers during certain widespread power outages as allowed by a new law enacted after the February 2021 Winter Storm Event. 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.

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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.

On June 30, 2022, in connection with the Restructuring, VUH repaid in full all outstanding indebtedness and terminated all remaining commitments and other obligations under its $400 million amended and restated credit agreement dated as of February 4, 2021. VUH did not incur any penalties in connection with the early termination.

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 $3.6 billion as of June 30, 2022. As of July 21, 2022, the Registrants had the following revolving credit facilities and utilization of such facilities:


			Amount Utilized as of July 21, 2022
Registrant	Size of Facility		Loans		Letters of Credit		Commercial Paper		Weighted Average Interest Rate	Termination Date
	(in millions)
CenterPoint Energy	$	2,400	$	—	$	11	$	443	1.87%	February 4, 2024



Houston Electric	300		—		—		—		—%	February 4, 2024
CERC	900		—		—		612		2.12%	February 4, 2024
Total	$	3,600	$	—	$	11	$	1,055

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 LIBOR 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 LIBOR with possible alternative benchmarks upon certain benchmark replacement events. The borrowers are currently in compliance with the various business and financial covenants in the three revolving credit facilities.

Long-term Debt

For detailed information about the Registrants’ debt transactions in 2022, see Note 11 to the Interim Condensed Financial Statements.

Securities Registered with the SEC

On May 29, 2020, 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 29, 2023. For information related to the Registrants’ debt issuances in 2022, see Note 11 to the Interim Condensed Financial Statements.

Temporary Investments

As of July 21, 2022, the Registrants had no temporary investments.

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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.

The table below summarizes CenterPoint Energy money pool activity by Registrant as of July 21, 2022:


	Weighted Average Interest Rate	Houston Electric		CERC
		(in millions)
Money pool investments (borrowings)	1.89%	$	162	$	—

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 21, 2022, 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	VUH Senior Unsecured Debt	A3	Stable	BBB+	Stable	n/a	n/a
CenterPoint Energy	Indiana Gas Senior Unsecured Debt	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

(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, 2022, the impact on the borrowing costs under the four 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,

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CERC might need to provide cash or other collateral of as much as $211 million as of June 30, 2022. 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 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, 2022, deferred taxes of approximately $602 million would have been payable in 2022. If all the ZENS-Related Securities had been sold on June 30, 2022, capital gains taxes of approximately $112 million would have been payable in 2022 based on 2022 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, a payment default on, or a non-payment default 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. 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. As announced in September 2021 and reiterated in May 2022, CenterPoint Energy plans to increase its planned capital expenditures in its Electric and Natural Gas businesses to support rate base growth and may explore asset sales, in addition to the recently completed sale of its Natural Gas businesses located in Arkansas and Oklahoma, as a means to efficiently finance a portion of such increased capital expenditures. 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. 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

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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 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 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;
increases in commodity prices;
various legislative or regulatory actions, including recovery of costs such as those associated with the mobile generation leases;
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, including the negative impact on such ability related to the February 2021 Winter Storm Event;
slower customer payments and increased write-offs of receivables due to higher natural gas prices, changing economic conditions or the February 2021 Winter Storm Event (CenterPoint Energy and CERC);
the satisfaction of any obligations pursuant to guarantees;
contributions to pension and postretirement benefit plans;
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 2021 Form 10-K and in Item 1A of Part II of this combined Form 10-Q.

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

For information about the total debt to capitalization financial covenants in the Registrants’ and certain of CenterPoint Energy’s subsidiaries’ 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.

Common control transactions (CenterPoint Energy and CERC)

When accounting for a transfer of net assets or exchange of equity interests between entities under common control, the entity that receives the net assets or the equity interests shall initially recognize the assets and liabilities transferred at the date of transfer based on the ultimate parent company’s basis, which in the case of the Restructuring is CenterPoint Energy’s basis. CenterPoint Energy’s basis in net assets of an entity may differ from the historical net assets of that entity on a standalone basis, for example, because push-down accounting had not been applied on a standalone basis. Additionally, when the net assets

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transferred in a common-control transaction meet the definition of a business, the receiving entity will record an allocation of goodwill from the reporting unit based on the relative fair value of the businesses transferred within that reporting unit. As a result, on June 30, 2022, CERC received $972 million of goodwill from CenterPoint Energy’s Natural Gas reporting unit in connection with the Restructuring. CERC recast prior periods to reflect the Restructuring as if it occurred at the earliest period presented for which CenterPoint Energy had common control. The Restructuring did not impact CenterPoint Energy’s basis in any entity, its allocation of goodwill to its reporting units, or its segment presentation. Neither CenterPoint Energy nor CERC recognized any gains or losses in connection with the Restructuring. SIGECO was not acquired by CERC and remains a subsidiary of VUH.

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 depend on unobservable inputs, including (i) projected timing and amounts 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 or relative fair value.

The fair value of the businesses within the Natural Gas reporting unit was estimated based on a weighted combination of income and market approaches, consistent with the methodology used in the 2021 annual goodwill impairment test.

Other than the common control transaction discussed above, there have been no significant changes in our critical accounting policies during the three and six months ended June 30, 2022, 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 2021 Form 10-K.

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