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 2023 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. Unless the context indicates otherwise, specific references to Houston Electric and CERC also pertain to CenterPoint Energy. 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, including Houston Electric and CERC, unless otherwise stated. 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

May 2024 Storm Events and Hurricane Beryl. Houston Electric’s service territory experienced sudden and destructive severe weather events in May 2024 that included hurricane-like winds and tornadoes. Subsequently, on July 8, 2024, Hurricane Beryl made landfall in Texas, bringing sustained winds, storm surges and torrential rain into Houston Electric’s service territory. The May 2024 Storm Events and Hurricane Beryl caused significant damage to Houston Electric’s electric delivery system and resulted in electric service interruptions peaking at an estimated 922,000 customers and more than 2.1 million customers, respectively.

Various federal, state and local governmental and regulatory agencies and other entities, such as the Texas Governor’s office, the Texas Legislature and the PUCT, have called for or are conducting inquiries and investigations into Hurricane Beryl, the efforts made by Houston Electric to prepare for, and respond to, this event, including the electric service outage issues, and the procurement of temporary generation units. Moreover, additional governmental and regulatory agencies and other entities may conduct such inquiries and investigations, as well. Texas Lieutenant Governor Patrick has publicly urged the PUCT to hold Houston Electric, rather than ratepayers, responsible for paying $800 million, which was the amount the PUCT had previously approved Houston Electric to recover from ratepayers pursuant to Texas legislation passed after the 2021 Winter Storm Event relating to emergency responsiveness and the leasing of temporary generation units. On August 12, 2024, Texas Attorney General Ken Paxton opened an investigation to evaluate CenterPoint Energy’s conduct during Hurricane Beryl. There are significant uncertainties around these inquiries and investigations and potential results and consequences, including whether any financial penalties will be assessed or changes to Houston Electric’s system, service territories, operations and/or regulatory treatment will result therefrom.

Houston Electric announced an initial hurricane preparedness and response action plan to the PUCT on July 25, 2024 to enhance the resiliency of the electric system through various investments. Following a meeting with Texas Governor Abbott on August 1, 2024, Houston Electric publicly committed to accelerating its previously announced initial hurricane preparedness and response action plan. Additionally, Houston Electric announced that it was withdrawing both its base rate application and its application for approval of its transmission and distribution system resiliency plan with the PUCT in order to focus on addressing the impacts of Hurricane Beryl in its service territory and accelerating preparedness and resiliency efforts for the remaining storm season. The withdrawal of the system resiliency plan was granted by the PUCT. Subsequently, intervenors filed a motion to challenge the withdrawal of the base rate proceeding. On August 16, 2024, the ALJ issued an order denying the requested withdrawal of the base rate proceeding, leaving the base rate proceeding abated. Houston Electric filed an appeal of the ALJ’s order to the PUCT, and on October 15, 2024, PUCT commissioners voted to consider the merits of Houston Electric’s appeal at the PUCT’s open meeting scheduled for November 14, 2024. The PUCT’s decision on the withdrawal of the base rate proceeding is expected in the fourth quarter of 2024. CenterPoint Energy cannot predict the outcome of this proceeding.

On August 5, 2024, Houston Electric announced the launch of its GHRI. Subsequently, Houston Electric announced the completion of core resiliency actions as part of the first phase of its GHRI, which included certain vegetation management and pole installation goals. In September 2024, Houston Electric announced the launch of the second phase of its GHRI, which included a series of resiliency plans to install new poles, manage higher-risk vegetation and install certain automated devices prior to the start of the 2025 hurricane season as part of its efforts to strengthen grid resiliency, improve public and customer communications and strengthen local, community and emergency partnerships. Houston Electric also announced a longer-term proposal for approximately $5 billion in resiliency investment from 2026 to 2028. Houston Electric intends to include this longer-term proposal in a new transmission and distribution system resiliency plan that is expected to be filed with the PUCT on or before January 31, 2025 following feedback from customers, external experts, elected officials, local agencies and other stakeholders. Additionally, Houston Electric announced its proposal to forego approximately $110 million of profit related to its storm hardening and TEEEF efforts, which would be represented by (1) Houston Electric not seeking to recover approximately $70 million in incremental storm hardening expenses incurred in connection with accelerated operational activities after

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Hurricane Beryl; and (2) Houston Electric not filing, beginning in 2028, for approximately $40 million in anticipated equity profit associated with load-shed orientated TEEEF leased by Houston Electric through the remaining regulatory life of the leases in 2032 as new dispatchable generation is likely to come online in the state of Texas as a result of the Texas Energy Fund.

For more information regarding regulatory impacts and the term loan facility to fund certain costs related to the May 2024 Storm Events and litigation related to Hurricane Beryl, see Notes 6, 11 and 13 to the Interim Condensed Financial Statements and “Liquidity and Capital Resources” below.

Regulatory Proceedings. 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 2024, see “Liquidity and Capital Resources —Regulatory Matters” below.

Debt Transactions. For information about debt transactions to date in 2024, see Note 11 to the Interim Condensed Financial Statements.

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CENTERPOINT ENERGY CONSOLIDATED RESULTS OF OPERATIONS

For information regarding factors that may affect the future results of our consolidated operations, see “Risk Factors” in Item 1A of Part I of the Registrants’ combined 2023 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 nine months ended September 30, 2024 and 2023 was as follows:


	Three Months Ended September 30,						Nine Months Ended September 30,
	2024		2023		Favorable (Unfavorable)		2024		2023		Favorable (Unfavorable)
	(in millions)
Electric	$	226	$	290	$	(64)	$	562	$	593	$	(31)
Natural Gas	30		27		3		360		296		64
Total Utility Operations	256		317		(61)		922		889		33
Corporate & Other (1)	(63)		(61)		(2)		(151)		(214)		63

Total CenterPoint Energy	$	193	$	256	$	(63)	$	771	$	675	$	96

(1)Includes energy performance contracting and sustainable infrastructure services through Energy Systems Group before June 30, 2023, the date of the sale of Energy Systems Group, unallocated corporate costs, interest income and interest expense, intercompany eliminations and the reduction of income allocated to preferred shareholders before September 1, 2023, the date of the redemption of all of the outstanding shares of the Series A Preferred Stock.

Three months ended September 30, 2024 compared to three months ended September 30, 2023

Income available to common shareholders decreased $63 million primarily due to the following items:

a decrease in income available to common shareholders of $64 million for the Electric reportable segment, as further discussed below;
an increase in income available to common shareholders of $3 million for the Natural Gas reportable segment, as further discussed below; and
a decrease in income available to common shareholders of $2 million for Corporate and Other, primarily due to $9 million of higher state income taxes, $7 million associated with corporate operating expenses, and $6 million associated with increased borrowing costs . The decrease is partially offset by $26 million of income allocated to holders of Series A Preferred Stock in the third quarter of 2023 prior to the redemption of all outstanding shares of Series A Preferred Stock in September 2023 as discussed in Note 18 to the Interim Condensed Financial Statements.

Nine months ended September 30, 2024 compared to nine months ended September 30, 2023

Income available to common shareholders increased $96 million primarily due to the following items:

a decrease in income available to common shareholders of $31 million for the Electric reportable segment, as further discussed below;
an increase in income available to common shareholders of $64 million for the Natural Gas reportable segment, as further discussed below; and
an increase in income available to common shareholders of $63 million for Corporate and Other, primarily due to $50 million of income allocated to holders of Series A Preferred Stock in the nine months ended September 30, 2023 prior to the redemption of all outstanding shares of Series A Preferred Stock in September 2023 as discussed in Note 18 to the Interim Condensed Financial Statements, a loss on sale of $12 million and current tax expense of $33 million related to divestiture of Energy Systems Group recorded in the nine months ended June 30, 2023 further discussed in Note 3 to the Interim Condensed Financial Statements, as well as $19 million due to remeasurement of deferred income tax balances recorded during the six months ended June 30, 2023. The increase is partially offset by $29 million associated with increased borrowing costs, $9 million of higher state income taxes, and $7 million associated with corporate operating expenses.

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, see “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 2023 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 Electric reportable segment:


	Three Months Ended September 30,									Nine Months Ended September 30,
	2024			2023			Favorable (Unfavorable)			2024			2023			Favorable (Unfavorable)
	(in millions, except operating statistics)
Revenues	$	1,243		$	1,261		$	(18)		$	3,499		$	3,250		$	249
Expenses:
Utility natural gas, fuel and purchased power	58			51			(7)			151			130			(21)
Operation and maintenance	560			459			(101)			1,532			1,335			(197)
Depreciation and amortization	201			241			40			664			650			(14)
Taxes other than income taxes	73			73			—			228			208			(20)

Total expenses	892			824			(68)			2,575			2,323			(252)
Operating Income	351			437			(86)			924			927			(3)
Other Income (Expense):
Interest expense and other finance charges	(88)			(81)			(7)			(276)			(213)			(63)

Other income, net	16			13			3			45			39			6
Income Before Income Taxes	279			369			(90)			693			753			(60)
Income tax expense	53			79			26			131			160			29
Net Income	$	226		$	290		$	(64)		$	562		$	593		$	(31)
Throughput (in GWh):
Residential	11,807			13,851			(15)		%	27,219			28,855			(6)		%
Total	32,633			35,029			(7)		%	84,730			84,794			—		%
Weather (percentage of normal weather for service area):
Cooling degree days	104		%	123		%	(19)		%	109		%	117		%	(8)		%
Heating degree days	—		%	—		%	—		%	89		%	86		%	3		%
Number of metered customers at end of period:
Residential	2,628,569			2,578,969			2		%	2,628,569			2,578,969			2		%
Total	2,959,281			2,906,307			2		%	2,959,281			2,906,307			2		%

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The following table provides variance explanations for the three months ended September 30, 2024 compared to the three months ended September 30, 2023 as well as for the nine months ended September 30, 2024 compared to the nine months ended September 30, 2023 by major income statement caption for CenterPoint Energy’s Electric reportable segment:


	Favorable (Unfavorable)

	Three Months Ended September 30, 2024 vs. 2023		Nine Months Ended September 30, 2024 vs. 2023
	(in millions)
Revenues
Transmission Revenues, including TCOS and TCRF, inclusive of costs billed by transmission providers, partially offset in operation and maintenance below	$	53	$	168
Customer rates and the impact of the change in rate design	32		121
Customer growth	9		22
Cost of fuel and purchased power, offset in utility natural gas, fuel and purchased power below	7		21
Energy efficiency, and other pass-through, offset in operation and maintenance below	5		3
Miscellaneous revenues, including service connections and off-system sales	(4)		2
Lost revenues as a result of outages associated with Hurricane Beryl	(10)		(10)
Equity return, related to the annual true-up of transition charges for amounts over or under collected in prior periods	(14)		(12)
Weather, efficiency improvements and other usage impacts	(41)		(29)
Bond Companies and SIGECO Securitization Subsidiary, offset in other line items below	(55)		(37)
Total	$	(18)	$	249
Utility natural gas, fuel and purchased power
Cost of purchased power, offset in revenues above	$	(32)	$	(78)
Cost of fuel, including coal, natural gas, and fuel oil, offset in revenues above	25		57
Total	$	(7)	$	(21)
Operation and maintenance
Transmission costs billed by transmission providers, offset in revenues above	$	(28)	$	(90)

Incremental storm hardening expenses incurred in connection with accelerated operational activities after Hurricane Beryl	(70)		(70)
Contract services	(29)		(25)
Corporate support services	(4)		(9)
Labor and benefits	12		(4)
Bond Companies and SIGECO Securitization Subsidiary, offset in other line items	—		(1)
Energy efficiency, and other pass-through, offset in revenues above	(3)		(1)
All other operation and maintenance expense, including materials and supplies and insurance	21		3






Total	$	(101)	$	(197)

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	Favorable (Unfavorable)

	Three Months Ended September 30, 2024 vs. 2023		Nine Months Ended September 30, 2024 vs. 2023
	(in millions)
Depreciation and amortization
Ongoing additions to plant-in-service	$	(13)	$	(55)
Bond Companies and SIGECO Securitization Subsidiary, offset in other line items	53		41
Total	$	40	$	(14)
Taxes other than income taxes


Incremental capital projects placed in service, and the impact of updated property tax rates	$	—	$	(14)
Franchise fees and other taxes	—		(6)
Total	$	—	$	(20)
Interest expense and other finance charges
Changes in outstanding debt	$	(14)	$	(46)
Other, primarily AFUDC and impacts of regulatory deferrals	6		(12)
Bond Companies and SIGECO Securitization Subsidiary, offset in other line items	1		(5)
Total	$	(7)	$	(63)
Other income, net
Other income, including AFUDC - Equity	$	2	$	4
Bond Companies and SIGECO Securitization Subsidiary, offset in other line items	1		2


Total	$	3	$	6

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, see “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 2023 Form 10-K.

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


	Three Months Ended September 30,									Nine Months Ended September 30,
	2024			2023			Favorable (Unfavorable)			2024			2023			Favorable (Unfavorable)
	(in millions, except operating statistics)
Revenues	$	611		$	597		$	14		$	2,876		$	3,136		$	(260)
Expenses:
Utility natural gas and fuel	139			141			2			1,066			1,420			354
Non-utility cost of revenues, including natural gas	2			1			(1)			3			2			(1)
Operation and maintenance	214			198			(16)			637			648			11
Depreciation and amortization	129			130			1			403			380			(23)
Taxes other than income taxes	51			53			2			177			182			5
Total expenses	535			523			(12)			2,286			2,632			346
Operating Income	76			74			2			590			504			86
Other Income (Expense):

Interest expense and other finance charges	(40)			(46)			6			(152)			(138)			(14)

Other income, net	3			8			(5)			10			14			(4)
Income Before Income Taxes	39			36			3			448			380			68
Income tax expense	9			9			—			88			84			(4)
Net Income	$	30		$	27		$	3		$	360		$	296		$	64



Throughput (in Bcf):
Residential	16			14			14		%	141			138			2		%
Commercial and Industrial	91			84			8		%	321			308			4		%
Total	107			98			9		%	462			446			4		%
Weather (percentage of 10-year average for service area):
Heating degree days	23		%	20		%	3		%	79		%	87		%	(8)		%
Number of metered customers at end of period:
Residential	4,031,298			3,967,080			2		%	4,031,298			3,967,080			2		%
Commercial and Industrial	300,709			299,915			—		%	300,709			299,915			—		%
Total	4,332,007			4,266,995			2		%	4,332,007			4,266,995			2		%

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	Favorable (Unfavorable)

	Three Months Ended September 30, 2024 vs. 2023		Nine Months Ended September 30, 2024 vs. 2023
	(in millions)
Revenues

Cost of natural gas, offset in utility natural gas and fuel below	$	(2)	$	(354)
Energy efficiency and other pass-through, offset in operation and maintenance below	(5)		(25)
Gross receipts tax, offset in taxes other than income taxes below	2		(2)




Non-volumetric and miscellaneous revenue	(2)		(2)
Weather and usage	1		4
Customer growth	2		9
Non-utility revenues	1		10
Customer rates	17		100
Total	$	14	$	(260)
Utility natural gas and fuel

Cost of natural gas, offset in revenues above	$	2	$	354


Total	$	2	$	354
Non-utility costs of revenues, including natural gas
Non-utility cost of revenues, including natural gas	$	(1)	$	(1)
Total	$	(1)	$	(1)
Operation and maintenance

All other operations and maintenance expense, including bad debt expense	$	(26)	$	(17)
Contract services	(3)		(5)
Labor and benefits	2		1
Corporate support services	6		7
Energy efficiency and other pass-through, offset in revenues above	5		25



Total	$	(16)	$	11
Depreciation and amortization	$	—
Ongoing additions to plant-in-service	$	1	$	(23)


Total	$	1	$	(23)
Taxes other than income taxes
Gross receipts tax, offset in revenues above	$	(2)	$	2
Incremental capital projects placed in service, and the impact of updated property tax rates	4		3


Total	$	2	$	5



Interest expense and other finance charges
Other, primarily AFUDC and impacts of regulatory deferrals	$	13	$	(8)
Changes in outstanding debt	(7)		(6)
Total	$	6	$	(14)



Other income, net
Other income, including AFUDC - Equity	$	1	$	3

Other	(6)		(7)

Total	$	(5)	$	(4)

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 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, see “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 2023 Form 10-K and in Item 1A of Part II of this combined Form 10-Q.

The following table provides summary data of Houston Electric’s single reportable segment:


	Three Months Ended September 30,									Nine Months Ended September 30,
	2024			2023			Favorable (Unfavorable)			2024			2023			Favorable (Unfavorable)
	(in millions, except operating statistics)
Revenues:
TDU	$	1,057		$	1,027		$	30		$	2,926		$	2,655		$	271
Bond Companies	1			56			(55)			77			129			(52)
Total revenues	1,058			1,083			(25)			3,003			2,784			219
Expenses:
Operation and maintenance, excluding Bond Companies	533			407			(126)			1,423			1,186			(237)
Depreciation and amortization, excluding Bond Companies	170			157			(13)			506			433			(73)
Taxes other than income taxes	71			70			(1)			221			201			(20)
Bond Companies	1			55			54			77			126			49
Total expenses	775			689			(86)			2,227			1,946			(281)
Operating Income	283			394			(111)			776			838			(62)
Other Income (Expense):
Interest expense and other finance charges	(74)			(69)			(5)			(229)			(185)			(44)
Interest expense on Securitization Bonds	(1)			(2)			1			(3)			(6)			3


Other income, net	12			5			7			33			22			11
Income Before Income Taxes	220			328			(108)			577			669			(92)
Income tax expense	41			72			31			112			147			35
Net Income	$	179		$	256		$	(77)		$	465		$	522		$	(57)
Throughput (in GWh):
Residential	11,364			13,410			(15)		%	26,108			27,803			(6)		%
Total	31,228			33,546			(7)		%	81,059			80,984			—		%
Weather (percentage of 10-year average for service area):
Cooling degree days	104		%	123		%	(19)		%	109		%	117		%	(8)		%
Heating degree days	—		%	—		%	—		%	92		%	87		%	5		%
Number of metered customers at end of period:
Residential	2,495,669			2,443,150			2		%	2,495,669			2,443,150			2		%
Total	2,806,984			2,751,218			2		%	2,806,984			2,751,218			2		%


	Favorable (Unfavorable)

	Three Months Ended September 30, 2024 vs. 2023		Nine Months Ended September 30, 2024 vs. 2023
	(in millions)
Revenues
Transmission Revenues, including TCOS and TCRF, inclusive of costs billed by transmission providers, partially offset in operation and maintenance below	$	53	$	168
Customer rates and the impact of the change in rate design	27		131

Customer growth	8		20
Energy efficiency, partially offset in operations and maintenance below	5		7
Miscellaneous revenues	1		2
Lost revenues as a result of outages associated with Hurricane Beryl	(10)		(10)
Equity return, related to the annual true-up of transition charges for amounts over or under collected in prior periods	(13)		(12)
Weather, efficiency improvements and other usage impacts	(41)		(35)
Bond Companies, offset in other line items below	(55)		(52)



Total	$	(25)	$	219
Operation and maintenance, excluding Bond Companies
Transmission costs billed by transmission providers, offset in revenues above	$	(28)	$	(90)

Incremental storm hardening expenses incurred in connection with accelerated operational activities after Hurricane Beryl	(70)		(70)
Contract services	(30)		(31)
All other operation and maintenance expense, including materials and supplies and insurance	(3)		(25)
Corporate support services	(2)		(8)
Energy efficiency, offset in revenues above	(5)		(7)
Labor and benefits	12		(6)
Total	$	(126)	$	(237)
Depreciation and amortization, excluding Bond Companies
Ongoing additions to plant-in-service	$	(13)	$	(73)
Total	$	(13)	$	(73)
Taxes other than income taxes
Incremental capital projects placed in service, and the impact of changes to tax rates	$	(1)	$	(20)


Total	$	(1)	$	(20)
Bond Companies expense
Operations and maintenance and depreciation expense, offset in revenues above	$	54	$	49
Total	$	54	$	49
Interest expense and other finance charges
Changes in outstanding debt	$	(12)	$	(40)
Other, primarily AFUDC and impacts of regulatory deferrals	7		(4)
Total	$	(5)	$	(44)




Interest expense on Securitization Bonds
Lower outstanding principal balance, offset in revenues above	$	1	$	3
Total	$	1	$	3
Other income, net
Other income, including AFUDC - Equity	$	7	$	11


Total	$	7	$	11

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 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. For more information regarding factors that may affect the future results of operations for CERC’s business, see “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 2023 Form 10-K.


	Three Months Ended September 30,									Nine Months Ended September 30,
	2024			2023			Favorable (Unfavorable)			2024			2023			Favorable (Unfavorable)
	(in millions, except operating statistics)
Revenues	$	600		$	583		$	17		$	2,791		$	3,045		$	(254)
Expenses:
Utility natural gas	140			141			1			1,046			1,399			353
Non-utility cost of revenues, including natural gas	1			1			—			2			2			—
Operation and maintenance	207			187			(20)			614			616			2
Depreciation and amortization	124			125			1			389			365			(24)
Taxes other than income taxes	51			53			2			176			181			5
Total expenses	523			507			(16)			2,227			2,563			336
Operating Income	77			76			1			564			482			82
Other Income (Expense):

Interest expense and other finance charges	(38)			(44)			6			(145)			(131)			(14)

Other income, net	4			6			(2)			10			12			(2)
Income Before Income Taxes	43			38			5			429			363			66
Income tax expense	9			10			1			84			80			(4)


Net Income	$	34		$	28		$	6		$	345		$	283		$	62
Throughput (in Bcf):
Residential	15			14			7		%	137			135			1		%
Commercial and Industrial	81			76			7		%	294			282			4		%
Total	96			90			7		%	431			417			3		%
Weather (percentage of 10-year average for service area):
Heating degree days	24		%	21		%	3		%	79		%	88		%	(9)		%
Number of metered customers at end of period:
Residential	3,926,819			3,863,739			2		%	3,926,819			3,863,739			2		%
Commercial and Industrial	290,128			289,376			—		%	290,128			289,376			—		%
Total	4,216,947			4,153,115			2		%	4,216,947			4,153,115			2		%

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	Favorable (Unfavorable)

	Three Months Ended September 30, 2024 vs. 2023		Nine Months Ended September 30, 2024 vs. 2023
	(in millions)
Revenues

Cost of natural gas, offset in utility natural gas below	$	(1)	$	(353)
Energy efficiency and other pass-through, offset in operation and maintenance below	(3)		(18)
Gross receipts tax, offset in taxes other than income taxes below	2		(2)


Non-volumetric and miscellaneous revenue	(2)		(1)
Weather and usage	3		6

Customer growth	2		9
Non-utility revenues	1		10
Customer rates	15		95
Total	$	17	$	(254)
Utility natural gas

Cost of natural gas, offset in revenues above	$	1	$	353


Total	$	1	$	353



Operation and maintenance
All other operations and maintenance expense, including bad debt expense	$	(29)	$	(20)
Contract services	(3)		(5)
Labor and benefits	3		2
Corporate support services	6		7
Energy efficiency and other pass-through, offset in revenues above	$	3	$	18





Total	$	(20)	$	2
Depreciation and amortization
Ongoing additions to plant-in-service	$	1	$	(24)


Total	$	1	$	(24)
Taxes other than income taxes
Gross receipts tax, offset in revenues above	$	(2)	$	2
Incremental capital projects placed in service, and the impact of updated property tax rates	4		3

Total	$	2	$	5



Interest expense and other finance charges
Other, primarily AFUDC and impacts of regulatory deferrals	$	12	$	(9)
Changes in outstanding debt	(6)		(5)
Total	$	6	$	(14)



Other income, net
Other income, including AFUDC - Equity	$	1	$	3

Other	(3)		(5)

Total	$	(2)	$	(2)

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 impact the Registrants’ future earnings, see “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 2023 Form 10-K, and “Cautionary Statement Regarding Forward-Looking Information” and “Risk Factors” in this combined Form 10-Q.

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LIQUIDITY AND CAPITAL RESOURCES

Historical Cash Flows

The following table summarizes the net cash provided by (used in) operating, investing and financing activities during the nine months ended September 30, 2024 and 2023:


	Nine Months Ended September 30,
	2024						2023
	CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC
	(in millions)
Cash provided by (used in):
Operating activities	$	1,250	$	306	$	858	$	3,069	$	858	$	2,270
Investing activities	(2,559)		(1,044)		(982)		(3,190)		(2,132)		(1,320)
Financing activities	1,329		759		124		168		1,312		(949)

Operating Activities. The following items contributed to increased (decreased) net cash provided by operating activities for the nine months ended September 30, 2024 compared to the nine months ended September 30, 2023:


	CenterPoint Energy		Houston Electric		CERC
	(in millions)
Changes in net income after adjusting for non-cash items	$	219	$	(107)	$	294
Changes in working capital	(243)		23		(398)
Changes in current regulatory assets and liabilities (1)	(1,264)		(7)		(1,218)
Changes in non-current regulatory assets and liabilities	(482)		(408)		(83)



Higher pension contribution	25		—		—

Other	(74)		(53)		(7)
	$	(1,819)	$	(552)	$	(1,412)

(1)This change is primarily related to the receipt of proceeds at CenterPoint Energy and CERC from the Texas securitization program in 2023. 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 nine months ended September 30, 2024 compared to the nine months ended September 30, 2023:


	CenterPoint Energy		Houston Electric		CERC
	(in millions)


Net change in capital expenditures	$	822	$	553	$	192
Net change in notes receivable from affiliated companies	—		638		87


Proceeds from divestitures	(145)		—		—


Other	(46)		(103)		59
	$	631	$	1,088	$	338

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Financing Activities. The following items contributed to (increased) decreased net cash provided by (used in) financing activities for the nine months ended September 30, 2024 compared to the nine months ended September 30, 2023:


	CenterPoint Energy		Houston Electric		CERC
	(in millions)
Net changes in commercial paper outstanding	$	976	$	—	$	518

Net changes in proceeds from issuances of Common Stock	494		—		—
Net changes in long-term debt and term loans outstanding, excluding commercial paper	(1,167)		(702)		668


Net changes in debt issuance costs	25		8		9
Net changes in short-term borrowings	12		—		12
Redemption of Series A Preferred Stock	800		—		—

Increased payment of Common Stock dividends	(25)		—		—
Decreased payment of preferred stock dividends	49		—		—
Net change in notes payable from affiliated companies	—		713		—
Change in contribution from parent	—		(561)		(210)
Change in dividend to parent	—		(10)		77


Other	(3)		(1)		(1)
	$	1,161	$	(553)	$	1,073

Future Sources and Uses of Cash

The liquidity and capital requirements of the Registrants are affected primarily by results of operations, capital expenditures, storm restoration costs, debt service requirements, tax payments, working capital needs and various regulatory actions. Capital expenditures (other than expenditures associated with the May 2024 Storm Events and Hurricane Beryl) are expected to be used for investment in infrastructure. These capital expenditures are anticipated to enhance reliability and safety, increase resiliency and expand our systems through value-added projects. Substantial capital expenditures are also expected for restoration costs associated with the May 2024 Storm Events and Hurricane Beryl, as further described below. In addition to dividend payments on CenterPoint Energy’s Common Stock and interest payments on debt, the Registrants’ principal anticipated cash requirements for the remainder of 2024 include the following:


	CenterPoint Energy		Houston Electric		CERC
	(in millions)
Estimated capital expenditures (1)	$	1,248	$	805	$	322
Estimated restoration costs associated with May 2024 Storm Events (2)	8		8		—
Estimated restoration costs associated with Hurricane Beryl (2)	849		849		—
Scheduled principal payments on Securitization Bonds	88		81		—
Expected contributions to pension plans and other post-retirement plans	8		1		—

(1)Excludes expenditures for the restoration costs associated with the May 2024 Storm Events and Hurricane Beryl.

(2)Represents cash requirements associated with the estimated storm restoration costs for the remainder of 2024.

The Registrants expect that anticipated cash needs for the remainder of 2024 will be met with borrowings under their credit facilities, proceeds from the issuance of long-term debt, anticipated cash flows from operations, and, with respect to CenterPoint Energy and CERC, proceeds from commercial paper. Issuances of debt securities in the capital markets, funds raised in the commercial paper markets, term loans and additional credit facilities may not, however, be available on acceptable terms.

For more information regarding the May 2024 Storm Events and Hurricane Beryl, see Notes 6, 11 and 13 to the Interim Condensed Financial Statements as well as “Recent Events” in Part I, Item 2 and “Risk Factors” in Part II, Item 1A of this combined Form 10-Q.

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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

Hurricane Beryl

For additional information about Hurricane Beryl, see Note 6 to the Interim Condensed Financial Statements as well as “Recent Events” in Part I, Item 2 and “Risk Factors” in Part II, Item 1A of this combined Form 10-Q.

May 2024 Storm Events

For additional information about the May 2024 Storm Events, see Note 6 to the Interim Condensed Financial Statements as well as “Recent Events” in Part I, Item 2 and “Risk Factors” in Part II, Item 1A of this combined Form 10-Q.

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 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 requested that project costs, net of PTCs, be recovered in rate base rather than a levelized rate, through base rates or the CECA mechanism, depending on which provides more timely recovery. On September 6, 2023 the IURC issued an order approving the CPCN. The Posey Solar project is expected to be placed in service in 2025 and recovered through base rates.

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 authorizing 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 under applicable Indiana regulations, approved the proposed levelized rate and associated ratemaking and accounting treatment. Due to inflationary pressures, the developer disclosed that costs exceeded the agreed upon levels in the BTA. After negotiations, Indiana Electric and the developer were not able to agree upon updated pricing. As a result, on February 27, 2024, Indiana Electric provided notice that it was exercising its right to terminate the BTA, which terminated all further obligations of Indiana Electric with respect to the project.

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

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generation. The wind project is located in MISO’s Central Region. Indiana Electric received approval from the IURC to recover the costs of the wind facility via the CECA mechanism, which is expected to be placed in service by the end of 2026. On June 6, 2023 the IURC issued an order approving the CPCN, 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 fuel adjustment clause proceedings over the term of the amended PPA. On May 30, 2023, the IURC approved the Warrick County solar amended PPA; however, due to MISO interconnection study delays, the developer disclosed the project in-service date would be delayed to 2026.

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 February 22, 2023, the IURC approved the Knox County solar amended PPA; however, due to MISO interconnection delays, the project in-service date will be delayed from 2024 to 2026. 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 were approved to be recovered through the fuel adjustment clause proceedings over the term of the amended PPA with Oriden. On May 30, 2023, the IURC approved the Vermillion County solar amended PPA; however, due to MISO interconnection study delays, the developer disclosed the project in-service date would be delayed to 2026.

On May 1, 2024, Indiana Electric filed with the IURC seeking approval to purchase 147 MW of wind power under a 25-year PPA with an affiliate of NextEra Energy, Inc., which is developing a wind project in Knox County, IL. The facility is targeted to be in operation in early 2026. Indiana Electric expects a decision from the IURC in the fourth quarter of 2024. If Indiana Electric’s request is approved, the purchase power costs will be recovered through the fuel adjustment clause proceedings over the term of the PPA.

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 being constructed at the previous site of the A.B. Brown power plant in Posey County, Indiana and is expected to 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 Electric’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. FERC granted a certificate to construct the pipeline on October 20, 2022. The period to challenge FERC’s certificate in a federal district court expired on February 20, 2023. 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-year 2025. Recovery of the proposed natural gas combustion turbines and regulatory asset is included in the forecasted test year in the Indiana Electric rate case, which was filed with the IURC on December 5, 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. In testimony filed September 13, 2023, the OUCC and an intervenor that represents industrial customers filed testimony with the IURC alleging that Indiana Electric did not act prudently which led to the unplanned outage and

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recommended disallowances between $21 million to $27 million. On July 3, 2024, the IURC issued an order finding Indiana Electric acted reasonably and prudently with respect to the events that gave rise to the Culley Unit 3 outage and, in addition, did not approve the intervenors proposed disallowance. The order is now final and non-appealable.

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

On December 17, 2020, Houston Electric filed a CCN 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. In November 2021, the PUCT approved a route that was estimated to cost $25 million and issued a final order on January 12, 2022. There have been project delays due to supply chain constraints in the developer acquiring solar panels. Houston Electric substantially completed construction in the fall of 2023, and the transmission line is expected to be energized shortly after the generation facility is complete, which is anticipated to occur in the first half of 2025.

Kilgore Transmission Project (CenterPoint Energy and Houston Electric)

On August 30, 2023, Houston Electric filed a CCN application with the PUCT for approval to build a 138 kV double circuit transmission line in Chambers County, Texas that will loop the existing 138 kV Chevron to Langston circuit number 86 on Houston Electric’s transmission system to Houston Electric’s planned Kilgore substation. On March 7, the PUCT issued a final order approving a route that was estimated to cost $60 million, including substation costs. The actual capital costs of the project, including the transmission line and the planned Kilgore substation, will depend on actual land acquisition costs, construction costs, and other factors. Completion of construction and energization of the line and substation is anticipated to occur in the second quarter of 2026.

Mill Creek Transmission Project (CenterPoint Energy and Houston Electric)

On November 17, 2023, Houston Electric filed a CCN application with the PUCT for approval to build a 138 kV double circuit transmission line in Harris and Montgomery counties, Texas that will connect Houston Electric’s transmission system to Houston Electric’s planned Mill Creek substation. The actual capital costs of the project, including the transmission line and the planned Mill Creek substation, will depend on actual land acquisition costs, construction costs, and other factors and have been estimated to be $62 million to $98 million, based on an amended CCN application filed by Houston Electric on February 26, 2024 and subsequent errata filed on May 9, 2024. On October 24, 2024, the PUCT heard oral arguments and indicated that they will issue a decision on this project on November 14, 2024.

Texas Legislation (CenterPoint Energy, Houston Electric and CERC)

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

House Bill 1500 became effective on 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 became effective on June 12, 2023 and authorizes LDCs to offer programs to promote energy conservation and to recover costs prudently incurred to implement such programs under Railroad Commission authority;
House Bill 2555 became effective on June 13, 2023 and allows an electric utility to file a transmission and distribution system resiliency plan with the PUCT and associated cost recovery to enhance its system through hardening, modernization, undergrounding certain lines, lightning mitigation measures, flood mitigation measures, information technology, cybersecurity, physical security, vegetation management and wildfire mitigation. On January 18, 2024, the PUCT issued an Order adopting its Resiliency Plan Rule (16 Tex. Admin. Code § 25.62);
Senate Bill 947 became effective on September 1, 2023 and creates severe criminal offenses for intentional damage to critical infrastructure facilities that create extended power outages;
Senate Bill 1015 became effective on 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 became effective on 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

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Senate Bill 1076 became effective on June 2, 2023 and moves the timeline for the PUCT to approve CCN 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 GHG 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 GHG 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 requested comments by September 15, 2023 if parties believe that the filing is incomplete based on the reporting requirements or if parties do not believe that that the MPUC’s standard informal proceeding process is appropriate. No parties filed comments regarding completeness or raising concerns that the MPUC’s standard informal procedural process is inappropriate. The initial comment period closed January 15, 2024, the reply comment period closed March 15, 2024 and the supplemental comment period closed May 15, 2024. On July 25, 2024, the MPUC voted to approve the plan with some minor modifications during its agenda meeting and a formal order was issued on October 9, 2024.

Solar Panel Issues (CenterPoint Energy)

CenterPoint Energy’s current and future solar projects have been impacted by delays and/or increased costs. The potential delays and inflationary cost pressures communicated from the developers of our solar projects have been primarily due to (i) unavailability of solar panels and other uncertainties related to DOC anti-dumping and countervailing duties investigation(s), (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 May 15, 2024, based on a petition filed by the American Alliance for Solar Manufacturing Trade Committee, the DOC announced the initiation of antidumping and countervailing duty investigations of silicon photovoltaic cells from Cambodia, Malaysia, Thailand, and Vietnam. On October 1, 2024, the DOC’s preliminary countervailing duty determination affirmed the petition and established preliminary duty rates. The DOC is expected to issue a preliminary antidumping determination in the fourth quarter of 2024 with final determinations expected in the first quarter of 2025. These impacts could result in cost increases for certain projects, and such impacts may require that we 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 “Risk Factors” in Item 1A of Part I of the Registrants’ combined 2023 Form 10-K.

TDSIC 2.0 (CenterPoint Energy)

On May 24, 2023, Indiana Electric filed its petition and case-in-chief with the IURC requesting, among other things, approval of its five-year plan for transmission, distribution, and storage improvements (TDSIC Plan). Intervenors filed their case-in-chief on August 16, 2023 and Indiana Electric filed rebuttal on August 29, 2023. A hearing was held on September 13, 2023 and an order approving the TDSIC Plan was issued on December 27, 2023. The approved five-year TDSIC Plan, covering the period January 1, 2024 through December 31, 2028, consists of approximately $454 million in proposed investments across seven different programs: (1) Distribution 12kV Circuit Rebuild, (2) Distribution Underground Rebuild, (3) Distribution Automation, (4) Wood Pole Replacement, (5) Transmission Line Rebuild, (6) Substation Rebuild, and (7) Substation Physical Security.

Transmission and Distribution System Resiliency Plan (CenterPoint Energy and Houston Electric)

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House Bill 2555, codified as Tex. Util. Code § 38.078, was passed by the 88th Texas Legislature in 2023 and allows an electric utility to file a transmission and distribution system resiliency plan with the PUCT to enhance the resiliency of the utility’s transmission system through at least one or more of the following measures: hardening, modernization, undergrounding certain lines, lightning mitigation measures, flood mitigation measures, information technology, cybersecurity measures, physical security measures, vegetation management, and wildfire mitigation and response. House Bill 2555 also allows an electric utility to establish a regulatory asset for distribution-related costs, including depreciation expense and carrying costs at the electric utility’s weighted average cost of capital, relating to the implementation of a transmission and distribution system resiliency plan.

On April 29, 2024, Houston Electric filed its first transmission and distribution system resiliency plan with the PUCT, which proposed to implement 25 resiliency measures over a three-year period. On August 1, 2024, Houston Electric announced that it was withdrawing its application for approval of its transmission and distribution system resiliency plan in order to focus on addressing the impacts of Hurricane Beryl and accelerating preparedness and resiliency efforts for the remaining storm season. The ALJ granted Houston Electric’s request for withdrawal of the transmission and distribution system resiliency plan on August 16, 2024.

On August 28, 2024, Houston Electric announced a series of resiliency actions, including a proposal for approximately $5 billion in resiliency investment from 2026 to 2028, which Houston Electric intends to include in a transmission and distribution system resiliency plan that is expected to be filed with the PUCT on or before January 31, 2025 following feedback from customers, external experts and other stakeholders, including elected officials and local agencies.

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, ECA, CECA 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).

Texas Gas Rate Case. On October 30, 2023, CERC filed an application with the Railroad Commission and municipal regulatory authorities to set new natural gas base rates that would be applied consistently across the approximately 1.9 million customers. The need for a rate change was primarily driven by the continuing investment in the safety and reliability of the natural gas system, including new Intelis natural gas meters that feature an integrated safety shutoff valve, changes to depreciation rates that better reflect the actual life and salvage characteristics of assets, and changes in other costs to serve customers. A settlement agreement was filed on April 23, 2024. The settlement agreement was approved by the Railroad Commission on June 25, 2024 and provides for a $5 million annual increase in current revenues, establishes a 9.80% ROE and a 60.61% equity ratio for future GRIP filings. New rates will be effective beginning the month of December 2024.

Minnesota Rate Case. On November 1, 2023, CERC filed an application with the MPUC requesting an adjustment to delivery charges in 2024 and 2025 for the natural gas business in Minnesota. The requested increase is approximately 6.5% or $85 million for 2024 and an additional approximately 3.7% or $52 million for 2025. The need for a rate change is primarily driven by the continuing investment in the safety and reliability of the natural gas system, including new Intelis natural gas meters that feature an integrated safety shutoff valve, changes to depreciation rates that better reflect the actual life and salvage characteristics of assets, and changes in other costs to serve customers. The request reflects a proposed 10.3% ROE on a 52.5% equity ratio. Interim rates for 2024 of $69 million, subject to refund, were implemented as of January 1, 2024. A request for interim rates of $33 million for 2025 was filed on September 30, 2024 and decision on 2025 interim rates is expected in the fourth quarter of 2024. A pretrial and settlement conference is scheduled for December 16, 2024 and the anticipated decision date of the rate case is July 1, 2025.

Indiana Electric Rate Case. On December 5, 2023, Indiana Electric filed a petition with the IURC for authority to modify its rates and charges for electric utility service through a phase-in of rates. The requested increase is approximately 16% or $119 million based on a forward looking 2025 test year. The need for a rate increase is primarily driven by the continuing investment that is being made to bolster the safety and reliability of the system and normal increases in operating expenses. The initial filing of the rate case reflected a proposed 10.4% ROE on a 55% equity ratio. On April 9, 2024 Indiana Electric filed rebuttal in the rate case. Indiana Electric reached a settlement agreement with less than all parties and submitted the agreement to the IURC on May 20, 2024. The settlement reflects a proposed 9.8% ROE on a 55% equity ratio. The requested increase was lowered to 11% with an updated requested increase of $80 million. A hearing took place on September 10, 2024 through September 11, 2024. A final order is expected in the first half of 2025.

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Houston Electric Rate Case. On March 6, 2024, Houston Electric filed an application with the PUCT requesting authority to change rates and charges for electric transmission and distribution service. The requested increase is approximately $17 million (1%) for retail customers and $43 million (6.6%) for wholesale transmission service, excluding TCRF and rate case expenses. Texas law mandates that electric utilities file a base rate proceeding no later than every four years from the date of their last base rate proceeding final order. Houston Electric’s most recent base rate proceeding order was approved by the PUCT on March 9, 2020, in Docket No. 49421. Therefore, Houston Electric was required to file its next base rate proceeding no later than March 9, 2024. The need for a rate increase is primarily driven by the continuing investment that has been made to support customer growth and to bolster the safety and reliability of Houston Electric’s transmission and distribution system. The request reflects a proposed 10.4% ROE and a 45% equity ratio. Errata testimony was filed to correct minor errors included in the initial filing which reduced the requested increase to $56 million compared to current rates. Intervenor and PUCT staff testimony was filed in June 2024. Rebuttal testimony was due on July 12, 2024 and Houston Electric filed rebuttal testimony from 13 witnesses that covered issues other than operations; however, due to their significant operational responsibilities associated with Houston Electric’s emergency operations plan and response to Hurricane Beryl, an extension was requested (and granted) for the operations witnesses. A hearing on the merits was scheduled to start in late July 2024. On July 17, 2024, Houston Electric filed an unopposed motion to abate the pending deadlines in order to provide additional time to facilitate the continued settlement discussions; the motion was granted on the same day. On August 1, 2024, Houston Electric announced that it was withdrawing its base rate application with the PUCT requesting authority to change rates and charges for electric transmission and distribution service in order to focus on addressing the impacts of Hurricane Beryl in its service territory and accelerating preparedness and resiliency efforts for the remaining storm season. Intervenors filed a motion to challenge the withdrawal of the base rate proceeding. PUCT staff and the Office of Public Utility Counsel filed a letter in support of such withdrawal. On August 16, 2024, the ALJ issued an order denying the requested withdrawal of the base rate proceeding, leaving the base rate proceeding abated. On August 23, 2024, Houston Electric filed an appeal of the ALJ’s order to the PUCT. On September 12, 2024, the PUCT issued an order extending the time to act on Houston Electric’s appeal. On October 24, 2024, the PUCT heard oral arguments on the appeal and indicated that they will decide the appeal on November 14, 2024.

Ohio CEP. On March 1, 2024, CEOH filed an application with the PUCO for authority to modify its CEP rates and charges. The requested increase is approximately $3 million resulting in a proposed CEP rate for residential customers of $1.54 per month. Per the PUCO’s Opinion and Order in the 2018 general rate case, the CEP rate is capped at $1.50 per month for residential customers. CEOH requested deferral of the 2023 CEP revenue requirement above the CEP rate cap of approximately $155,000. On June 20, 2024, PUCO staff filed comments recommending that CEOH be permitted to collect $1.50 in this annual rider. However, PUCO staff recommended that CEOH be denied the opportunity to collect deferrals that exceed $1.50. PUCO staff also recommended that CEOH cease accruing deferrals until such time as a new CEP alternative regulation case has been approved and asserted the $1.50 cap was reached at some point in 2023. CEOH filed comments on July 15, 2024, providing additional clarification on its interpretation of the 2018 rate case stipulation language. CEOH’s interpretation is that CEOH has complied with the PUCO’s Opinion and Order from the 2018 general rate case, and CEOH plans to file a Notice of Intent to file a rate case application prior to the $1.50 cap being reached, allowing for the deferral to be maintained. CEOH filed a statement of resolution on July 30, 2024, indicating CEOH and PUCO staff agree to certain statements including: CEOH’s existing deferral authority has not expired and will continue uninterrupted, provided CEOH files its notice of intent for its base rate case prior to the new CEP Rider charges taking effect. PUCO issued a Finding & Order on August 21, 2024, finding that the parties’ resolution of the rate cap and deferral authority issues were reasonable.

Ohio Gas Rate Case. On August 27, 2024, CEOH filed a Notice of Intent with PUCO to begin the process of requesting an adjustment in natural gas base rates. CEOH plans to file its Application and Standard Filing Requirement by the end of October 2024 based on a hybrid test year of January through March 2024 results and April through December 2024 estimated financial data. Direct testimony will be filed with PUCO 14 days after the application filing. The need for a rate increase is primarily driven by the continuing investment that is being made to provide safe and reliable service of the system. CEOH’s last base rate case was filed in 2018 with final PUCO approval August 28, 2019.

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The table below reflects significant applications pending or completed since the Registrants’ combined 2023 Form 10-K was filed with the SEC through the date of the filing of this Form 10-Q:


Mechanism	Annual Increase (1) (in millions)	Filing Date	Effective Date	Approval Date	Additional Information
CenterPoint Energy and Houston Electric (PUCT)
DCRF	73	December 2023	April 2024	March 2024	Based on the net change in distribution invested capital since its last base rate proceeding of approximately $2.5 billion for the period January 1, 2019 through September 30, 2023 for an incremental revenue increase of $86 million, adjusted for load growth. On February 5, 2024, Houston Electric notified the ALJ that the parties reached an agreement in principle on all issues in this proceeding, and filed an agreed expedited motion for interim rates. On February 13, 2024, interim rates designed to collect $220 million ($73 million incremental) were approved by the ALJ, to be effective April 2024. A final order was issued by the PUCT March 7, 2024.

Rate Case	56	March 2024	TBD	TBD	See discussion above under Houston Electric Rate Case.
EECRF	15	May 2024	TBD	TBD	The requested $65 million is comprised primarily of the following: 2025 program costs of $50 million; a credit of $0.5 million related to the over-recovery of 2023 program costs; the 2023 earned bonus of $15 million; and 2025 projected evaluation, measurement and verification costs of $0.5 million. On August 21, 2024, Houston Electric requested the proceeding be abated to facilitate settlement negotiations with the parties. On September 6, 2024, Houston Electric notified the ALJ that the parties reached an agreement in principal and requested the proceeding continue in abatement; the stipulation and settlement agreement was filed on October 17, 2024.




CenterPoint Energy and CERC - Beaumont/East Texas, South Texas, Houston and Texas Coast (Railroad Commission)

Rate Case	5	October 2023	December 2024	June 2024	See discussion above under Texas Gas Rate Case.
Tax Act Rider	20	August 2024	TBD	TBD	Resulting from the Texas Gas Rate Case, the first Tax Act Rider Calculation was filed on August 1, 2024 pursuant to Docket No. OS-23-00015513 to recover the effects of the Inflation Reduction Act (“Tax Act 2022”) and certain other tax-related costs for rates to become effective January 1, 2025. These effects include the return on the CAMT deferred tax asset (“DTA”) resulting from the Tax Act 2022, income tax credits resulting from the Tax Act 2022, and the return on the increment or decrement in the NOL DTA included in rate base and in the standard service base revenue requirement approved in the Texas Gas Rate Case. CERC believes its filing is consistent with the Tax Act Rider tariff approved in Docket No. OS-23-00015513. On October 1, 2024, certain parties filed comments disputing the application. The Railroad Commission is currently seeking comments and a procedural schedule for review.
CenterPoint Energy and CERC - Minnesota (MPUC)
CIP Financial Incentive	8	May 2024	TBD	TBD	CIP Financial Incentive based on 2023 CIP program activity.
Rate Case	136	November 2023	TBD	TBD	See discussion above under Minnesota Rate Case.
CenterPoint Energy and CERC - Louisiana (LPSC)
RSP	12	September/October 2023	June 2024	April 2024	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 and completion of COVID-19 asset recovery, is $8 million based on a test year ended June 2023 and adjusted ROE of 3.67%. The South Louisiana increase, net of TCJA effects considered outside of the earnings band and completion of COVID-19 asset recovery, is $5 million based on a test year ended June 2023 and adjusted ROE of 5.47%. The TCJA refund impact to North Louisiana and South Louisiana was $0.6 million and $0.4 million, respectively. South Louisiana interim rates were implemented on December 28, 2023, subject to refund. North Louisiana interim rates were implemented on January 29, 2024. Staff reports issued on January 31, 2024 recommended disallowances of $0.3 million and $0.2 million in North and South Louisiana, respectively. LPSC voted to approve the January 2024 staff reports on April 19, 2024. Implementation occurred in June 2024.
RSP	13	October 2024	TBD	TBD	Based on ROE of 9.95% with 50 basis point (+/-) earnings band. The North Louisiana increase, inclusive of TCJA effects considered outside of the earnings band, is $7 million based on a test year ended June 2024 and adjusted ROE of 5.56%. The South Louisiana increase, inclusive of TCJA effects considered outside of the earnings band, is $6 million based on a test year ended June 2024 and adjusted ROE of 5.96%. Interim rates, subject to refund, will be implemented December 19, 2024.

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Mechanism	Annual Increase (1) (in millions)	Filing Date	Effective Date	Approval Date	Additional Information
CenterPoint Energy and CERC - Mississippi (MPSC)
RRA	9	May 2024	September 2024	September 2024	Based on ROE of 10.263% with 100 basis points (+/-) earnings band. Revenue increase of approximately $11 million based on 2023 test year adjusted earned ROE of 5.11%. Interim increase of approximately $1.3 million implemented May 31, 2024. On September 5, 2024, MPSC approved a settlement revenue adjustment of $9.4 million.
CenterPoint Energy - Indiana South - Gas (IURC)
CSIA	4	April 2024	August 2024	July 2024	Requested an increase of $35 million to rate base, which reflects approximately $3.6 million annual increase in current revenues. An 80% of revenue requirement is included in the requested rate increase and 20% is deferred until the next rate case. The mechanism also includes a change in (over)/under-recovery variance of $0.03 million annually. The Final IURC Order was issued July 31, 2024, approving CSIA rates as proposed effective August 1, 2024.
CSIA	2	October 2024	TBD	TBD	Requested an increase of $18 million to rate base, which reflects approximately $2.4 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 $(1.0) million annually. OUCC to file testimony on December 4, 2024. Indiana South Rebuttal due December 18, 2024. Evidentiary Hearing to be scheduled for week of January 6, 2025.
CenterPoint Energy and CERC - Indiana North - Gas (IURC)
CSIA	9	April 2024	August 2024	July 2024	Requested an increase of $97 million to rate base, which reflects approximately $9.4 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. Final IURC Order issued July 31, 2024, approving CSIA rates as proposed effective August 1, 2024.


CSIA	11	October 2024	TBD	TBD	Requested an increase of $84 million to rate base, which reflects approximately $11.0 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 $(3.0) million annually. OUCC to file testimony on December 4, 2024. Indiana South Rebuttal due December 18, 2024. Evidentiary Hearing to be scheduled for week of January 6, 2025.
CenterPoint Energy and CERC - Ohio - Gas (PUCO)
CEP	3	March 2024	September 2024	August 2024	See discussion above under Ohio Capital Expenditure Program.
DRR	12	May 2024	September 2024	August 2024	Requested an increase of $77 million to rate base for investments made in 2023, which reflects a $12 million annual increase in current revenues. A change in (over)/under-recovery variance of $0.8 million annually is also included in rates. PUCO Opinion & Order was issued August 21, 2024, approving DRR rates as proposed. Revised rates effective September 1, 2024.

CenterPoint Energy - Indiana Electric (IURC)





Rate Case	80	December 2023	TBD	TBD	See discussion above under Indiana Electric Rate Case.
TDSIC	5	February 2024	May 2024	May 2024	Requested an increase of $36 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. An order approving the request was issued on May 17, 2024 and was effective May 16, 2024.
CECA	—	February 2024	May 2024	June 2024	Requested a decrease of $1 million to rate base, which reflects no change in current revenues. The mechanism also includes a change in (over)/under-recovery variance of $0.1 million. The final order was issued May 29, 2024, approving rates effective June 1, 2024.
ECA	6	May 2024	August 2024	August 2024	Requested an increase of $48 million to rate base, which reflects a $6 million annual increase in current revenues. Eighty percent of the revenue requirement is included in the requested rate increase and 20% is deferred until next rate case. The mechanism also includes a reduction in the under-recovery variance of $1 million. The OUCC filed testimony on July 1, 2024 recommending approval. A final order approving the request was issued on August 28, 2024.

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Mechanism	Annual Increase (1) (in millions)	Filing Date	Effective Date	Approval Date	Additional Information
TDSIC	5	August 2024	TBD	TBD	Requested an increase of $30 million to rate base, which reflects a $5 million annual increase in current revenues. An 80% of the revenue requirement is included in the requested rate increase and 20% is deferred until the next rate case. The OUCC filed testimony on September 30, 2024. An evidentiary hearing is scheduled for October 28, 2024.

(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% CAMT based on the adjusted financial statement income of certain large corporations. Corporations are entitled to a CAMT credit to the extent CAMT liability exceeds regular tax liability, which can be carried forward indefinitely and used in future years when regular tax exceeds the CAMT. It is likely that the Registrants will owe CAMT in excess of their regular tax liability beginning in 2024. As a result, the Registrants may experience a temporary increase in federal cash tax liability due to this provision beginning in 2024. On September 12, 2024, the IRS issued proposed regulations addressing the application of the CAMT. The proposed regulations offer guidance for computing an entity’s adjusted financial statement income, in addition to addressing other provisions of the CAMT. At this time, the Company does not anticipate changes to the applicability of CAMT to the Registrants as a result of the proposed regulations.

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 11, 2023, the EPA announced proposed emission limits and guidelines for carbon dioxide from fossil fuel-fired power plants 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. On February 29, 2024, the EPA announced that it would be delaying the rulemaking as applied to existing natural gas-fired units. On April 25, 2024, the EPA released its New Source Performance Standards for Greenhouse Gas Emissions From New, Modified, Reconstructed Fossil Fuel-Fired Units; Emission Guidelines for Greenhouse Gas Emissions From Existing Fossil Fuel-Fired Electric Generating Units; and Repeal of the Affordable Clean Energy Rule. CenterPoint Energy is currently reviewing this rule, but would note that CenterPoint Energy does not currently have plans to operate any of its coal-fired units beyond December 2029.

The Biden administration recommitted the United States to the Paris Agreement, which has driven a renewed regulatory push to require further GHG emission reductions from the energy sector, and led 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 from a 2021 baseline, 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 emissions 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 emissions 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 emissions 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

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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.

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. 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. 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 natural 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 attention 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 likely become 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 expected 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 emissions 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

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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 626 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 cleaner 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. Under the proposed preferred portfolio, Indiana Electric plans to convert its last remaining coal unit to natural gas by the end of 2027 and to add a significant amount of additional renewable resources through 2033. For more information regarding CenterPoint Energy’s net zero emission goals and the risks associated with them, see “Risk Factors — Risk Factors Affecting Regulatory, Environmental and Legal Risks — CenterPoint Energy is subject to operational and financial risks...” in Part I, Item 1A of the Registrants’ combined 2023 Form 10-K.

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, the May 2024 Storm Events and Hurricane Beryl. Since many of the Registrants’ facilities are located along or near the Texas gulf coast, increased or more severe weather events, such as hurricanes, tornadoes or flooding, could increase costs to repair damaged facilities and restore service to customers. CenterPoint Energy’s current 10-year capital plan includes capital expenditures to enhance 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. Additionally, the May 2024 Storm Events and Hurricane Beryl caused significant damage to Houston Electric’s electric delivery system and resulted in electric service interruptions peaking at an estimated 922,000 customers and more than 2.1 million customers, respectively. 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.

On March 6, 2024, the SEC adopted final rules that require the Registrants to disclose certain climate-related information in registration statements and annual reports. The final rules require Registrants to disclose, among other things, material climate-related risks, activities to mitigate such risks and information about the Registrants’ board of directors’ oversight and management’s role in managing material climate-related risks. The final rule also requires the Registrants to provide information related to any climate-related targets or goals that are material to the Registrants’ businesses, results of operations, or financial condition. Litigation challenging the new rule was filed by multiple parties in multiple jurisdictions, which have been consolidated and assigned to the U.S. Court of Appeals for the Eighth Circuit. On April 4, 2024, the SEC announced that it is voluntarily delaying the implementation of the climate disclosure regulations while the U.S. Court of Appeals considers the litigation. While a majority of the reporting requirements would have been applicable to the Registrants in the fiscal year beginning in 2025, with the addition of assurance reporting for GHG inventories starting in 2029 for large accelerated filers, as of April 12, 2024, the effective date of the final rules has been delayed indefinitely and the SEC has indicated that it will publish a document in the Federal Register at the conclusion of the stay addressing a new effective date for the final rules. The Registrants continue to evaluate the impact of the final rules on their respective consolidated financial statements and related disclosures.

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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.

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 September 30, 2024. As of October 21, 2024, the Registrants had the following revolving credit facilities and utilization of such facilities:


			Amount Utilized as of October 21, 2024
Registrant	Size of Facility		Loans		Letters of Credit		Commercial Paper		Weighted Average Interest Rate	Termination Date
	(in millions)
CenterPoint Energy	$	2,400	$	—	$	—	$	899	4.92%	December 6, 2027
CenterPoint Energy (1)	250		—		—		—		—%	December 6, 2027


Houston Electric	300		—		—		—		—%	December 6, 2027
CERC	1,050		—		1		427		4.90%	December 6, 2027
Total	$	4,000	$	—	$	1	$	1,326

(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 2024, 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 2024, see Note 11 to the Interim Condensed Financial Statements.

Additionally, for information related to shares of Common Stock sold during the nine months ended September 30, 2024, see Note 18 to the Interim Condensed Financial Statements.

Temporary Investments

As of October 21, 2024, 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 October 21, 2024:


	Weighted Average Interest Rate	Houston Electric		CERC
		(in millions)
Money pool borrowings	4.98%	$	221	$	—

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 October 21, 2024, 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	Negative	BBB	Negative	BBB	Negative
CenterPoint Energy	Vectren Corp. Issuer Rating	n/a	Negative	BBB+	Negative	n/a	n/a
CenterPoint Energy	SIGECO Senior Secured Debt	A1	Stable	A	Negative	n/a	n/a
Houston Electric	Houston Electric Senior Secured Debt	A2	Negative	A	Negative	A	Negative
CERC	CERC Corp. Senior Unsecured Debt	A3	Stable	BBB+	Negative	A-	Negative
CERC	Indiana Gas Senior Unsecured Debt	n/a	n/a	BBB+	Negative	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 September 30, 2024, 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, CERC might need to provide cash or other collateral of up to $180 million as of September 30, 2024. The amount of collateral will depend on seasonal variations in transportation levels.

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ZENS and Securities Related to ZENS (CenterPoint Energy)

If CenterPoint Energy’s creditworthiness were to drop such that ZENS holders thought CenterPoint Energy’s 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 September 30, 2024, deferred taxes of approximately $787 million would have been payable in 2024. If all the ZENS-Related Securities had been sold on September 30, 2024, capital gains taxes of approximately $78 million would have been payable in 2024 based on 2024 tax rates in effect. For additional information about ZENS, see Note 10 to the Interim Condensed Financial Statements.

Cross Defaults

Under the Registrants’ respective revolving credit facilities, 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 has increased its planned capital expenditures in its Electric and Natural Gas businesses multiple times over the recent years to support rate base growth and may continue to do so in the future. 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 considerations listed above. For further information, see Note 3 to the Interim Condensed Financial Statements.

On February 19, 2024, CenterPoint Energy, through its subsidiary CERC Corp., entered into the LAMS Asset Purchase Agreement to sell its Louisiana and Mississippi natural gas LDC businesses. The transaction is expected to close in the first quarter of 2025. 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, weather events such as 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,

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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 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, including financings due to the May 2024 Storm Events and Hurricane Beryl;
various legislative or regulatory actions, including such actions in response to the May 2024 Storm Events and Hurricane Beryl;
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, such as the May 2024 Storm Events and Hurricane Beryl (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 and Hurricane Beryl;
contributions to pension and postretirement benefit plans;
recovery of any losses under applicable insurance policies;
restoration costs and revenue losses resulting from future natural disasters such as hurricanes or other severe weather events, such as the May 2024 Storm Events and Hurricane Beryl, and the timing of and amounts sought for recovery of such restoration costs; and
various other risks identified in “Risk Factors” in Part I, I tem 1A of the Registrants’ combined 2023 Form 10-K, which are incorporated herein by reference, in Item 1A of Part II of this combined Form 10-Q, and in other reports that the Registrants file from time to time with the SEC.

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. The accounting estimates described below require the Registrants to make assumptions about matters that are highly uncertain at the time the estimate is made. 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

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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.

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 nine months ended September 30, 2024, as described further in Note 3 to the Interim Condensed Financial Statements, certain assets and liabilities representing the Louisiana and Mississippi natural gas LDC businesses met the held for sale criteria. The sale will be considered an asset sale for tax purposes, requiring net deferred tax liabilities to be excluded from held for sale balances.

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.

Other than the assets held for sale analysis discussed above, there have been no significant changes in our critical accounting policies during the nine months ended September 30, 2024, 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 2023 Form 10-K.

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